10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period endedMarch 31, 2016

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from____ to_____

Commission File Number 1-3880

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

New Jersey	13-1086010
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
6363 Main Street
Williamsville, New York	14221
(Address of principal executive offices)	(Zip Code)

(716) 857-7000

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.  YES  þ     NO  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  YES  þ   NO  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting   company”   in   Rule   12b-2   of   the   Exchange   Act.    (Check  one):    

Large  Accelerated  Filer	þ	Accelerated Filer	¨
Non-Accelerated Filer	¨(Do not check if a smaller reporting company)	Smaller Reporting Company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  YES  ¨   NO  þ

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

Common stock, par value $1.00 per share, outstanding at April 30, 2016: 84,935,329 shares.

GLOSSARY OF TERMS

Frequently used abbreviations, acronyms, or terms used in this report:

National Fuel Gas Companies
Company	The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Distribution Corporation	National Fuel Gas Distribution Corporation
Empire	Empire Pipeline, Inc.
Midstream Corporation	National Fuel Gas Midstream Corporation
National Fuel	National Fuel Gas Company
NFR	National Fuel Resources, Inc.
Registrant	National Fuel Gas Company
Seneca	Seneca Resources Corporation
Supply Corporation	National Fuel Gas Supply Corporation

Regulatory Agencies
CFTC	Commodity Futures Trading Commission
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
NYDEC	New York State Department of Environmental Conservation
NYPSC	State of New York Public Service Commission
PaDEP	Pennsylvania Department of Environmental Protection
PaPUC	Pennsylvania Public Utility Commission
SEC	Securities and Exchange Commission

Other
2015 Form 10-K	The Company’s Annual Report on Form 10-K for the year ended September 30, 2015
Bbl	Barrel (of oil)
Bcf	Billion cubic feet (of natural gas)
Bcfe (or Mcfe) –  represents Bcf (or Mcf) Equivalent	The total heat value (Btu) of natural gas and oil expressed as a volume of  natural gas. The Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.
Btu	British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit
Capital expenditure	Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Cashout revenues	A cash resolution of a gas imbalance whereby a customer pays Supply Corporation and/or Empire for gas the customer receives in excess of amounts delivered into Supply Corporation’s and Empire’s systems by the customer’s shipper.
Degree day	A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative	A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.).  The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract.  Examples include futures contracts, forward contracts, options, no cost collars and swaps.
Development costs	Costs incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas

2

Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act.
Dth	Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Exchange Act	Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets	Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costs	Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
FERC 7(c) application	An application to the FERC under Section 7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.
Firm transportation and/or storage	The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP	Accounting principles generally accepted in the United States of America
Goodwill	An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging	A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub	Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
ICE	Intercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Interruptible transportation and/or storage	The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LDC	Local distribution company
LIBOR	London Interbank Offered Rate
LIFO	Last-in, first-out
Marcellus Shale	A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
Mbbl	Thousand barrels (of oil)
Mcf	Thousand cubic feet (of natural gas)
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth	Thousand decatherms (of natural gas)
MMBtu	Million British thermal units (heating value of one decatherm of natural gas)
MMcf	Million cubic feet (of natural gas)
NEPA	National Environmental Policy Act of 1969, as amended
NGA	The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NYMEX	New York Mercantile Exchange.  An exchange which maintains a futures market for crude oil and natural gas.
Open Season	A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.
Precedent Agreement	An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.

3

Proved developed reserves	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped (PUD) reserves	Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive.
Reserves	The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Revenue decoupling mechanism	A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.
S&P	Standard & Poor’s Rating Service
SAR	Stock appreciation right
Service agreement	The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.
Stock acquisitions	Investments in corporations
VEBA	Voluntary Employees’ Beneficiary Association
WNC	Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures.  If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs.  If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.

4

INDEX	Page
Part I. Financial Information
Item 1.  Financial Statements (Unaudited)	6
a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Six Months Ended March 31, 2016 and 2015	6
b. Consolidated Statements of Comprehensive Income – Three and Six Months Ended March 31, 2016 and 2015	7
c. Consolidated Balance Sheets – March 31, 2016 and September 30, 2015	8
d. Consolidated Statements of Cash Flows – Six Months Ended March 31, 2016 and 2015	10
e. Notes to Condensed Consolidated Financial Statements	11
Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.  Controls and Procedures	48
Part II. Other Information
Item 1.  Legal Proceedings	48
Item 1 A.  Risk Factors	48
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 3.  Defaults Upon Senior Securities	•
Item 4.  Mine Safety Disclosures	•
Item 5.  Other Information	•
Item 6.  Exhibits	51
Signatures	52

• The Company has nothing to report under this item.

All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.

5

Part I.  Financial Information

Item 1. Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)

	Three Months Ended   March 31,						Six Months Ended   March 31,
(Thousands of Dollars, Except Per Common Share Amounts)	2016			2015			2016			2015
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues	$	248,173		$	374,141		$	417,005		$	640,380
Exploration and Production and Other Revenues	144,570			166,139			297,454			371,917
Pipeline and Storage and Gathering Revenues	56,389			55,847			109,868			107,739
	449,132			596,127			824,327			1,120,036
Operating Expenses:
Purchased Gas	81,623			190,600			123,691			317,690
Operation and Maintenance:
Utility and Energy Marketing	57,309			62,764			104,858			112,461
Exploration and Production and Other	42,964			50,906			88,539			94,401
Pipeline and Storage and Gathering	21,541			19,575			41,109			38,965
Property, Franchise and Other Taxes	21,305			24,916			41,662			45,845
Depreciation, Depletion and Amortization	63,947			82,687			134,498			185,433
Impairment of Oil and Gas Producing Properties	397,443			120,348			832,894			120,348
	686,132			551,796			1,367,251			915,143
Operating Income (Loss)	(237,000		)	44,331			(542,924		)	204,893
Other Income (Expense):
Interest Income	278			46			2,077			1,303
Other Income	3,236			1,388			5,654			2,571
Interest Expense on Long-Term Debt	(28,994		)	(22,376		)	(59,366		)	(44,687		)
Other Interest Expense	(1,237		)	(1,584		)	(2,617		)	(2,375		)
Income (Loss) Before Income Taxes	(263,717		)	21,805			(597,176		)	161,705
Income Tax Expense (Benefit)	(116,030		)	5,136			(260,380		)	60,296
Net Income (Loss) Available for Common Stock	(147,687		)	16,669			(336,796		)	101,409
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	880,619			1,666,659			1,103,200			1,614,361
	732,932			1,683,328			766,404			1,715,770
Dividends on Common Stock	(33,533		)	(32,488		)	(67,005		)	(64,930		)
Balance at March 31	$	699,399		$	1,650,840		$	699,399		$	1,650,840
Earnings Per Common Share:
Basic:
Net Income (Loss) Available for Common Stock	$	(1.74	)	$	0.20		$	(3.97	)	$	1.20
Diluted:
Net Income (Loss) Available for Common Stock	$	(1.74	)	$	0.20		$	(3.97	)	$	1.19
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	84,806,982			84,317,508			84,728,680			84,262,471
Used in Diluted Calculation	84,806,982			85,133,142			84,728,680			85,175,961
Dividends Per Common Share:
Dividends Declared	$	0.395		$	0.385		$	0.790		$	0.770

See Notes to Condensed Consolidated Financial Statements

6

National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)

	Three Months Ended   March 31,						Six Months Ended   March 31,
(Thousands of Dollars)	2016			2015			2016			2015
Net Income (Loss) Available for Common Stock	$	(147,687	)	$	16,669		$	(336,796	)	$	101,409
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	(4		)	265			(642		)	(147		)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	33,768			61,165			99,139			304,994
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income	(388		)	—			(388		)	—
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(61,235		)	(54,130		)	(118,405		)	(78,395		)
Other Comprehensive Income (Loss), Before Tax	(27,859		)	7,300			(20,296		)	226,452
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	(16		)	99			(207		)	(61		)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	14,190			25,902			34,866			128,851
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income	(163		)	—			(163		)	—
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(25,600		)	(22,917		)	(43,606		)	(33,006		)
Income Taxes – Net	(11,589		)	3,084			(9,110		)	95,784
Other Comprehensive Income (Loss)	(16,270		)	4,216			(11,186		)	130,668
Comprehensive Income (Loss)	$	(163,957	)	$	20,885		$	(347,982	)	$	232,077

See Notes to Condensed Consolidated Financial Statements

7

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

	March 31, 2016		September 30, 2015
(Thousands of Dollars)
ASSETS
Property, Plant and Equipment	$	9,451,538	$	9,261,323
Less - Accumulated Depreciation, Depletion and Amortization	4,879,363		3,929,428
	4,572,175		5,331,895
Current Assets
Cash and Temporary Cash Investments	93,700		113,596
Hedging Collateral Deposits	9,963		11,124
Receivables – Net of Allowance for Uncollectible Accounts of $34,236 and $29,029, Respectively	137,718		105,004
Unbilled Revenue	35,140		20,746
Gas Stored Underground	8,599		34,252
Materials and Supplies - at average cost	33,430		30,414
Unrecovered Purchased Gas Costs	1,245		—
Other Current Assets	56,714		60,665
	376,509		375,801
Other Assets
Recoverable Future Taxes	172,417		168,214
Unamortized Debt Expense	1,953		2,218
Other Regulatory Assets	270,941		278,227
Deferred Charges	17,063		15,129
Other Investments	104,273		92,990
Goodwill	5,476		5,476
Prepaid Post-Retirement Benefit Costs	26,344		24,459
Fair Value of Derivative Financial Instruments	253,716		270,363
Other	157		167
	852,340		857,243
Total Assets	$	5,801,024	$	6,564,939

See Notes to Condensed Consolidated Financial Statements

8

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

	March 31, 2016		September 30, 2015
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value
Authorized  - 200,000,000 Shares; Issued And Outstanding – 84,892,747 Shares and 84,594,383 Shares, Respectively	$	84,893	$	84,594
Paid in Capital	756,001		744,274
Earnings Reinvested in the Business	699,399		1,103,200
Accumulated Other Comprehensive Income	82,186		93,372
Total Comprehensive Shareholders’ Equity	1,622,479		2,025,440
Long-Term Debt, Net of Unamortized Discount and Debt Issuance Costs	2,085,123		2,084,009
Total Capitalization	3,707,602		4,109,449
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	—		—
Current Portion of Long-Term Debt	—		—
Accounts Payable	111,054		180,388
Amounts Payable to Customers	42,217		56,778
Dividends Payable	33,533		33,415
Interest Payable on Long-Term Debt	34,900		36,200
Customer Advances	33		16,236
Customer Security Deposits	16,101		16,490
Other Accruals and Current Liabilities	104,925		96,557
Fair Value of Derivative Financial Instruments	9,864		10,076
	352,627		446,140
Deferred Credits
Deferred Income Taxes	844,916		1,137,962
Taxes Refundable to Customers	93,674		89,448
Unamortized Investment Tax Credit	557		731
Cost of Removal Regulatory Liability	189,421		184,907
Other Regulatory Liabilities	101,104		108,617
Pension and Other Post-Retirement Liabilities	216,852		202,807
Asset Retirement Obligations	171,991		156,805
Other Deferred Credits	122,280		128,073
	1,740,795		2,009,350
Commitments and Contingencies (Note 6)	—		—
Total Capitalization and Liabilities	$	5,801,024	$	6,564,939

See Notes to Condensed Consolidated Financial Statements

9

National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended   March 31,
(Thousands of Dollars)	2016			2015
OPERATING ACTIVITIES
Net Income (Loss) Available for Common Stock	$	(336,796	)	$	101,409
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties	832,894			120,348
Depreciation, Depletion and Amortization	134,498			185,433
Deferred Income Taxes	(283,912		)	10,351
Excess Tax Benefits Associated with Stock-Based Compensation Awards	(226		)	(9,024		)
Stock-Based Compensation	2,518			5,985
Other	6,106			4,709
Change in:
Hedging Collateral Deposits	1,161			(12,992		)
Receivables and Unbilled Revenue	(28,211		)	(88,339		)
Gas Stored Underground and Materials and Supplies	22,637			29,085
Unrecovered Purchased Gas Costs	(1,245		)	—
Other Current Assets	4,177			4,184
Accounts Payable	(31,786		)	62,832
Amounts Payable to Customers	(14,561		)	11,051
Customer Advances	(16,203		)	(18,735		)
Customer Security Deposits	(389		)	2,702
Other Accruals and Current Liabilities	22,420			53,491
Other Assets	3,754			1,826
Other Liabilities	(4,073		)	43,186
Net Cash Provided by Operating Activities	312,763			507,502
INVESTING ACTIVITIES
Capital Expenditures	(358,981		)	(493,341		)
Net Proceeds from Sale of Oil and Gas Producing Properties	104,938			—
Other	(18,249		)	(1,262		)
Net Cash Used in Investing Activities	(272,292		)	(494,603		)
FINANCING ACTIVITIES
Changes in Notes Payable to Banks and Commercial Paper	—			71,900
Excess Tax Benefits Associated with Stock-Based Compensation Awards	226			9,024
Dividends Paid on Common Stock	(66,887		)	(64,842		)
Net Proceeds from Issuance of Common Stock	6,294			3,574
Net Cash (Used in) Provided by Financing Activities	(60,367		)	19,656
Net Increase (Decrease) in Cash and Temporary Cash Investments	(19,896		)	32,555
Cash and Temporary Cash Investments at October 1	113,596			36,886
Cash and Temporary Cash Investments at March 31	$	93,700		$	69,441
Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	66,058		$	94,484
Receivable from Sale of Oil and Gas Producing Properties	$	10,297		$	—

 See Notes to Condensed Consolidated Financial Statements

10

National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 - Summary of Significant Accounting Policies

Principles of Consolidation.  The Company consolidates all entities in which it has a controlling financial interest.  All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Reclassification. Due to the adoption of the authoritative guidance regarding the presentation of deferred income taxes, certain prior year amounts have been reclassified to conform with current year presentation. The Company reclassified Deferred Income Taxes of $137.2 million previously shown as Current Assets in the Company's 2015 Form 10-K to Deferred Income Taxes shown as Deferred Credits on the Consolidated Balance Sheet at September 30, 2015.

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, 2015, 2014 and 2013 that are included in the Company's 2015 Form 10-K.  The consolidated financial statements for the year ended September 30, 2016 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.

The earnings for the six months ended March 31, 2016 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2016.  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 Statement of Cash Flows.  For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.

Hedging Collateral Deposits.  This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions.  In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances.

Gas Stored Underground.  In the Utility segment, gas stored underground is carried at lower of cost or market, 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 $17.5 million at March 31, 2016, 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 $163.4 million and $176.3 million at March 31, 2016 and September 30, 2015, 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.

11

Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter.  The book value of the oil and gas properties exceeded the ceiling at December 31, 2015 as well as March 31, 2016. As such, the Company recognized pre-tax impairment charges of $397.4 million and $832.9 million for the quarter and six months ended March 31, 2016, respectively. Deferred income tax benefits of $166.9 million and $349.8 million related to the impairment charges were also recognized for the quarter and six months ended March 31, 2016, respectively. In adjusting estimated future cash flows for hedging under the ceiling test at December 31, 2015 and March 31, 2016, estimated future net cash flows were increased by $253.7 million and $252.1 million, respectively.

On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. Under the terms of the agreement, Seneca and IOG will jointly participate in a program that will develop up to 80 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest and is obligated to participate in the first 42 wells, and has a one-time option to participate in the remaining 38 wells that can be exercised on or before July 1, 2016. With respect to the first 42 wells, IOG has committed to fund up to $231 million to develop the joint wells. As of March 31, 2016, Seneca had received $104.9 million of cash and had recorded a $10.3 million receivable in recognition of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the first 42 wells. The cash proceeds and receivable were recorded by Seneca as a $115.2 million reduction of property, plant and equipment. As the fee-owner of the property’s mineral rights, Seneca retains a 7.5% royalty interest and the remaining 20% working interest (26% net revenue interest) in the first 42 wells. If IOG exercises its option to participate in the remaining 38 wells, IOG has agreed to fund up to an additional $211 million to develop such joint wells. Seneca will retain a 10% royalty and the remaining 20% working interest (28% net revenue interest) in the remaining 38 wells. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.

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Accumulated Other Comprehensive Income (Loss).  The components of Accumulated Other Comprehensive Income (Loss) and changes for the quarter and six months ended March 31, 2016 and 2015, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): 

	Gains and Losses on Derivative Financial Instruments			Gains and Losses on Securities Available for Sale			Funded Status of the Pension and Other Post-Retirement Benefit Plans			Total
Three Months Ended March 31, 2016
Balance at January 1, 2016	$	162,728		$	5,522		$	(69,794	)	$	98,456
Other Comprehensive Gains and Losses Before Reclassifications	19,578			12			—			19,590
Amounts Reclassified From Other Comprehensive Income (Loss)	(35,635		)	(225		)	—			(35,860		)
Balance at March 31, 2016	$	146,671		$	5,309		$	(69,794	)	$	82,186
Six Months Ended March 31, 2016
Balance at October 1, 2015	$	157,197		$	5,969		$	(69,794	)	$	93,372
Other Comprehensive Gains and Losses Before Reclassifications	64,273			(435		)	—			63,838
Amounts Reclassified From Other Comprehensive Income (Loss)	(74,799		)	(225		)	—			(75,024		)
Balance at March 31, 2016	$	146,671		$	5,309		$	(69,794	)	$	82,186
Three Months Ended March 31, 2015
Balance at January 1, 2015	$	170,363		$	8,130		$	(56,020	)	$	122,473
Other Comprehensive Gains and Losses Before Reclassifications	35,263			166			—			35,429
Amounts Reclassified From Other Comprehensive Income (Loss)	(31,213		)	—			—			(31,213		)
Balance at March 31, 2015	$	174,413		$	8,296		$	(56,020	)	$	126,689
Six Months Ended March 31, 2015
Balance at October 1, 2014	$	43,659		$	8,382		$	(56,020	)	$	(3,979	)
Other Comprehensive Gains and Losses Before Reclassifications	176,143			(86		)	—			176,057
Amounts Reclassified From Other Comprehensive Income (Loss)	(45,389		)	—			—			(45,389		)
Balance at March 31, 2015	$	174,413		$	8,296		$	(56,020	)	$	126,689

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Reclassifications Outof Accumulated Other Comprehensive Income (Loss).  The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the quarter and six months ended March 31, 2016 and 2015 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

Details About Accumulated Other Comprehensive Income (Loss) Components	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income												Affected Line Item in the Statement Where Net Income (Loss) is Presented
	Three Months Ended March 31,						Six Months Ended March 31,
	2016			2015			2016			2015
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts		$57,914			$53,471			$114,242			$73,508		Operating Revenues
Commodity Contracts	3,530			659			4,450			4,887			Purchased Gas
Foreign Currency Contracts	(209		)	—			(287		)	—			Operation and Maintenance Expense
Gains (Losses) on Securities Available for Sale	388			—			388			—			Other Income
	61,623			54,130			118,793			78,395			Total Before Income Tax
	(25,763		)	(22,917		)	(43,769		)	(33,006		)	Income Tax Expense
		$35,860			$31,213			$75,024			$45,389		Net of Tax

Other Current Assets.  The components of the Company’s Other Current Assets are as follows (in thousands):

	At March 31, 2016		At September 30, 2015
Prepayments	$	5,923	$	10,743
Prepaid Property and Other Taxes	21,757		13,709
Fair Values of Firm Commitments	12,941		15,775
Regulatory Assets	16,093		20,438
	$	56,714	$	60,665

Other Accruals and Current Liabilities.  The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):

	At March 31, 2016		At September 30, 2015
Accrued Capital Expenditures	$	38,299	$	53,652
Regulatory Liabilities	20,786		5,346
Reserve for Gas Replacement	17,469		—
Federal Income Taxes Payable	4,102		5,686
State Income Taxes Payable	224		1,170
Other	24,045		30,703
	$	104,925	$	96,557

Earnings Per Common Share.  Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.  For purposes of determining earnings per common share, the potentially dilutive securities the Company has outstanding are stock options, SARs, restricted stock units and performance shares.  As the Company recognized a net loss for both the quarter and six months ended March 31, 2016, the aforementioned securities, amounting to 386,626 and 451,291 securities, were not recognized in the diluted earnings per share calculation for the quarter and six months ended March 31, 2016, respectively. For 2015, 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 5 and 2,565 securities excluded as being antidilutive for the quarter and six months ended March 31, 2015, respectively.

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Stock-Based Compensation.  The Company granted 309,996 performance shares during the six months ended March 31, 2016. The weighted average fair value of such performance shares was $30.71 per share for the six months ended March 31, 2016. 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 six months ended March 31, 2016 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2015 to September 30, 2018.  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 six months ended March 31, 2016 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2015 to September 30, 2018.  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 99,843 non-performance based restricted stock units during the six months ended March 31, 2016.  The weighted average fair value of such non-performance based restricted stock units was $35.57 per share for the six months ended March 31, 2016. 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.

No stock options, SARs or restricted share awards were granted by the Company during the six months ended March 31, 2016.

New Authoritative Accounting and Financial Reporting Guidance. In May 2014, the FASB issued authoritative guidance regarding revenue recognition. The authoritative guidance provides a single, comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The original effective date of this authoritative guidance was as of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements and disclosures.

In June 2014, the FASB issued authoritative guidance regarding accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the employee has completed the requisite service period. This authoritative guidance requires that such performance targets that affect vesting be treated as performance conditions, meaning that the performance target should not be factored in the calculation of the award at the grant date. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2017, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

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In July 2015, the FASB issued authoritative guidance simplifying inventory measurement by requiring companies to value inventory at the lower of cost and net realizable value. The authoritative guidance applies to all inventory other than inventory that is measured using last-in, first-out or the retail inventory method. The intention of this authoritative guidance is to eliminate some diversity in practice. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2018, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

In November 2015, the FASB issued authoritative guidance simplifying the presentation of deferred income taxes. The authoritative guidance requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The Company early adopted this guidance at December 31, 2015 on a retrospective basis.

In January 2016, the FASB issued authoritative guidance regarding the recognition and measurement of financial assets and liabilities. The authoritative guidance primarily affects the accounting for equity investments, financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. All equity investments in unconsolidated entities will be measured at fair value through earnings rather than through other comprehensive income. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2019. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

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 is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

In March 2016, the FASB issued authoritative guidance simplifying several aspects of the accounting for stock-based compensation. Among other things, the revised guidance specifies that the difference between the compensation recognized for financial reporting purposes and the deduction allowed for tax purposes (excess tax benefit or deficiency) shall be recognized as income tax expense or benefit in the income statement, as opposed to the current treatment where this difference is recognized as additional paid-in capital in the balance sheet. For statement of cash flows purposes, the revised guidance specifies that the excess tax benefit shall be classified along with other income tax cash flows as an item impacting cash flow from operating activities. The current guidance separates the excess tax benefit from other income tax cash flows and classifies the excess tax benefit as an item impacting cash flow from financing activities. The new authoritative guidance will be effective as of the Company’s first quarter of fiscal 2018, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

Note 2 – 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.

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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 March 31, 2016 and September 30, 2015.  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 March 31, 2016
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)			Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	65,530	$	—	$	—	$	—		$	65,530
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	2,754		—		—		(2,754		)	—
Over the Counter Swaps – Gas and Oil	—		255,867		—		(406		)	255,461
Foreign Currency Contacts	—		—		—		(1,745		)	(1,745		)
Other Investments:
Balanced Equity Mutual Fund	36,297		—		—		—			36,297
Fixed Income Mutual Fund	25,085		—		—		—			25,085
Common Stock – Financial Services Industry	3,942		—		—		—			3,942
Hedging Collateral Deposits	9,963		—		—		—			9,963
Total	$	143,571	$	255,867	$	—	$	(4,905	)	$	394,533
Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	10,311	$	—	$	—	$	(2,754	)	$	7,557
Over the Counter Swaps – Gas and Oil	—		2,713		—		(406		)	2,307
Foreign Currency Contracts	—		1,745		—		(1,745		)	—
Total	$	10,311	$	4,458	$	—	$	(4,905	)	$	9,864
Total Net Assets/(Liabilities)	$	133,260	$	251,409	$	—	$	—		$	384,669

Recurring Fair Value Measures	At fair value as of September 30, 2015
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)			Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	92,196	$	—	$	—	$	—		$	92,196
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	6,373		—		—		(6,373		)	—
Over the Counter Swaps – Gas and Oil	—		272,335		1,791		(808		)	273,318
Foreign Currency Contracts	—		—		—		(2,955		)	(2,955		)
Other Investments:
Balanced Equity Mutual Fund	34,884		—		—		—			34,884
Fixed Income Mutual Fund	8,004		—		—		—			8,004
Common Stock – Financial Services Industry	4,318		—		—		—			4,318
Other Common Stock	450		—		—		—			450
Hedging Collateral Deposits	11,124		—		—		—			11,124
Total	$	157,349	$	272,335	$	1,791	$	(10,136	)	$	421,339
Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	15,276	$	—	$	—	$	(6,373	)	$	8,903
Over the Counter Swaps – Gas and Oil	—		1,981		—		(808		)	1,173
Foreign Currency Contracts	—		2,955		—		(2,955		)	—
Total	$	15,276	$	4,936	$	—	$	(10,136	)	$	10,076
Total Net Assets/(Liabilities)	$	142,073	$	267,399	$	1,791	$	—		$	411,263

⁽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.

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Derivative Financial Instruments

At March 31, 2016 and September 30, 2015, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used in the Company’s Energy Marketing segment. Hedging collateral deposits of $10.0 million at March 31, 2016 and $11.1 million at September 30, 2015, which are associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at March 31, 2016 and September 30, 2015 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments, the majority of the crude oil price swap agreements used in the Company’s Exploration and Production segment and foreign currency contracts used in the Company's Exploration and Production segment. The fair value of the Level 2 price swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates. The derivative financial instruments reported in Level 3 consist of a small portion of the crude oil price swap agreements used in the Company’s Exploration and Production segment at September 30, 2015 that settled prior to December 31, 2015.  The fair value of the Level 3 crude oil price swap agreements was based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume). 

The 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 March 31, 2016, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation.  To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the quarters and six months ended March 31, 2016 and 2015, respectively. For the quarters and six months ended March 31, 2016 and March 31, 2015, no transfers in or out of Level 1 or Level 2 occurred. There were no purchases or sales of derivative financial instruments during the periods presented in the tables below.  All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below (amounts in parentheses indicate credits in the derivative asset/liability accounts).

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)			Total Gains/Losses
	October 1, 2015		Gains/Losses Realized and Included in Earnings				Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)		Transfer In/Out of Level 3		March 31, 2016
Derivative Financial Instruments(2)	$	1,791	$	(2,002	)	(1)	$	211	$	—	$	—

⁽¹⁾  Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the six months ended March 31, 2016. 

⁽²⁾  Derivative Financial Instruments are shown on a net basis.        

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)			Total Gains/Losses
	January 1, 2015		Gains/Losses Realized and Included in Earnings				Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)		Transfer In/Out of Level 3		March 31, 2015
Derivative Financial Instruments(2)	$	5,337	$	(2,949	)	(1)	$	2,438	$	—	$	4,826

⁽¹⁾  Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended March 31, 2015. 

⁽²⁾  Derivative Financial Instruments are shown on a net basis.

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Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)			Total Gains/Losses
	October 1, 2014		Gains/Losses Realized and Included in Earnings				Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)		Transfer In/Out of Level 3		March 31, 2015
Derivative Financial Instruments(2)	$	1,368	$	(6,804	)	(1)	$	10,262	$	—	$	4,826

⁽¹⁾  Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the six months ended March 31, 2015. 

⁽²⁾  Derivative Financial Instruments are shown on a net basis.

Note 3 – 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): 

	March 31, 2016				September 30, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,085,123	$	2,026,988	$	2,084,009	$	2,129,558

The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries/LIBOR for the risk free component and company specific credit spread information – generally obtained from recent trade activity in the debt).  As such, the Company considers the debt to be Level 2.

Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2.  Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.

Other Investments.  Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.

Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity and fixed income securities. The values of the insurance contracts amounted to $38.9 million at March 31, 2016 and $45.3 million at September 30, 2015. The fair value of the equity mutual fund was $36.3 million at March 31, 2016 and $34.9 million at September 30, 2015. The gross unrealized gain on this equity mutual fund was $6.2 million at March 31, 2016 and $6.5 million at September 30, 2015. The fair value of the fixed income mutual fund was $25.1 million at March 31, 2016 and $8.0 million at September 30, 2015. The gross unrealized loss on this fixed income mutual fund was $0.1 million at March 31, 2016. The fair value of the stock of an insurance company was $3.9 million at March 31, 2016 and $4.3 million at September 30, 2015. The gross unrealized gain on this stock was $2.2 million at March 31, 2016 and $2.6 million at September 30, 2015. The insurance contracts and marketable equity 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

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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 ten years. The Exploration and Production segment holds the majority of the Company’s derivative financial instruments. The derivative financial instruments held by the Energy Marketing segment are not considered to be material to the Company.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at March 31, 2016 and September 30, 2015.  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 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 March 31, 2016, the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding:

Commodity	Units
Natural Gas	139.5	Bcf (short positions)
Natural Gas	3.1	Bcf (long positions)
Crude Oil	1,467,000	Bbls (short positions)

As of March 31, 2016, the Company was hedging a total of $84.5 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).

As of March 31, 2016, the Company had $252.9 million ($146.7 million after tax) of net hedging gains included in the accumulated other comprehensive income balance. It is expected that $180.3 million ($104.6 million after tax) of such unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transaction are recorded in earnings.

Refer to Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments.

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The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended March 31, 2016 and 2015 (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 March 31,					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 March 31,					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 March 31,
	2016			2015			2016			2015			2016		2015
Commodity Contracts	$	30,876		$	60,571	Operating Revenue	$	57,914		$	53,471	Operating Revenue	$	31	$	1,469
Commodity Contracts	$	(214	)	$	594	Purchased Gas	$	3,530		$	659	Not Applicable	$	—	$	—
Foreign Currency Contracts	$	3,106		$	—	Operation and Maintenance Expense	$	(209	)	$	—	Not Applicable	$	—	$	—
Total	$	33,768		$	61,165		$	61,235		$	54,130		$	31	$	1,469

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Six Months Ended March 31, 2016 and 2015 (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 Six Months Ended March 31,				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 Six Months Ended March 31,					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 Six Months Ended March 31,
	2016		2015			2016			2015			2016		2015
Commodity Contracts	$	96,217	$	300,594	Operating Revenue	$	114,242		$	73,508	Operating Revenue	$	168	$	2,929
Commodity Contracts	$	1,999	$	4,400	Purchased Gas	$	4,450		$	4,887	Not Applicable	$	—	$	—
Foreign Currency Contracts	$	923	$	—	Operation and Maintenance Expense	$	(287	)	$	—	Not Applicable	$	—	$	—
Total	$	99,139	$	304,994		$	118,405		$	78,395		$	168	$	2,929

Fair Value Hedges

The Company utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or market writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of March 31, 2016, the Company’s Energy Marketing segment had fair value hedges covering approximately 13.8 Bcf (13.2 Bcf of fixed price sales commitments, 0.1 Bcf of fixed price purchase commitments and 0.5 Bcf of commitments related to the withdrawal of storage gas). For derivative instruments that are designated

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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 Six Months Ended March 31, 2016 (In Thousands)			Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Six Months Ended March 31, 2016 (In Thousands)
Commodity Contracts	Operating Revenues	$	5,557		$	(5,557	)
Commodity Contracts	Purchased Gas	$	(154	)	$	154
		$	5,403		$	(5,403	)

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 sixteen counterparties of which fifteen are in a net gain position.   On average, the Company had $16.8 million of credit exposure per counterparty in a gain position at March 31, 2016. The maximum credit exposure per counterparty in a gain position at March 31, 2016 was $43.2 million. The Company’s gain position on such derivative financial instruments for certain counterparties exceeded the established thresholds at which the counterparties would be required to post collateral. At March 31, 2016, collateral deposits from counterparties of $24.2 million were posted. These collateral deposits are recorded as a component of Accounts Payable on the Consolidated Balance Sheet.

As of March 31, 2016, twelve of the sixteen 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 March 31, 2016, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $162.9 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements).  For its over-the-counter swap agreements and foreign currency forward contracts, no hedging collateral deposits were required to be posted by the Company at March 31, 2016.    

For its exchange traded futures contracts, the Company was required to post $10.0 million in hedging collateral deposits as of March 31, 2016.   As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.

The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note 1 under Hedging Collateral Deposits.

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Note 4 - Income Taxes

The components of federal and state income taxes included in the Consolidated Statements of Income are as follows (in thousands):

	Six Months Ended   March 31,
	2016			2015
Current Income Taxes
Federal	$	7,995		$	36,746
State	15,537			13,199
Deferred Income Taxes
Federal	(197,982		)	13,242
State	(85,930		)	(2,891		)
	(260,380		)	60,296
Deferred Investment Tax Credit	(174		)	(208		)
Total Income Taxes	$	(260,554	)	$	60,088
Presented as Follows:
Other Income	(174		)	(208		)
Income Tax Expense (Benefit)	(260,380		)	60,296
Total Income Taxes	$	(260,554	)	$	60,088

Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income (loss) before income taxes.  The following is a reconciliation of this difference (in thousands):

	Six Months Ended   March 31,
	2016			2015
U.S. Income (Loss) Before Income Taxes	$	(597,350	)	$	161,497
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35%	$	(209,073	)	$	56,524
State Income Taxes (Benefit)	(45,756		)	6,700
Miscellaneous	(5,725		)	(3,136		)
Total Income Taxes	$	(260,554	)	$	60,088

As a result of a settlement reached during the quarter, the Company has reduced the balance of unrecognized tax benefits by $2.6 million, of which $0.5 million was recorded as an income tax benefit. As of March 31, 2016, the entire balance of unrecognized tax benefits would favorably impact the effective tax rate, if recognized.

Note 5 -Capitalization

Common Stock.  During the six months endedMarch 31, 2016, the Company issued 138,060 original issue shares of common stock as a result of stock option and SARs exercises and 61,150 original issue shares of common stock for restricted stock units that vested.  In addition, the Company issued 72,358 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 65,046 original issue shares of common stock for the Company’s 401(k) plans.  The Company also issued 8,538 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 six months endedMarch 31, 2016.  Holders of stock options, SARs, restricted share awards or restricted stock units will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding

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taxes.  During the six months endedMarch 31, 2016, 46,788 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.    None of the Company’s long-term debt at March 31, 2016 will mature within the following twelve-month period.

Note 6 - 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 March 31, 2016, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be approximately $4.7 million.  The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 12 years.

The Company's estimated liability for clean-up costs discussed above includes a $3.6 million estimated liability to remediate a former manufactured gas plant site located in New York. In February 2009, the Company received approval from the NYDEC of a Remedial Design Work Plan (RDWP) for this site. In October 2010, the Company submitted a RDWP addendum to conduct additional Preliminary Design Investigation field activities necessary to design a successful remediation. As a result of this work, the Company submitted to the NYDEC a proposal to amend the NYDEC’s Record of Decision remedy for the site.  In April 2013, the NYDEC approved the Company’s proposed amendment.  Final remedial design work for the site was completed, and active remedial work has recently been completed. Restoration work is underway. 

The Company is currently not aware of any material additional exposure to environmental liabilities.  However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company.

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.

Note 7 – 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 2015 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 2015 Form 10-K.  A listing of segment assets at March 31, 2016 and September 30, 2015 is shown in the tables below.  

Quarter Ended March 31, 2016 (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	$143,783	$56,276	$113	$212,737	$35,436	$448,345	$561	$226	$449,132
Intersegment Revenues	$—	$23,292	$21,545	$5,364	$312	$50,513	$—	$(50,513)	$—
Segment Profit: Net Income (Loss)	$(213,335)	$21,194	$7,568	$31,960	$3,484	$(149,129)	$(23)	$1,465	$(147,687)

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Six Months Ended March 31, 2016 (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	$295,749	$109,630	$238	$356,585	$60,420	$822,622	$1,266	$439	$824,327
Intersegment Revenues	$—	$45,477	$40,184	$9,028	$624	$95,313	$—	$(95,313)	$—
Segment Profit: Net Income (Loss)	$(450,421)	$42,470	$12,490	$50,566	$4,707	$(340,188)	$166	$3,226	$(336,796)

(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 March 31, 2016	$1,622,264	$1,664,920	$487,421	$1,984,921	$91,671	$5,851,197	$77,689	$(127,862)	$5,801,024
At September 30, 2015	$2,439,801	$1,590,525	$444,358	$1,934,730	$90,676	$6,500,090	$77,350	$(12,501)	$6,564,939

Quarter Ended March 31, 2015 (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	$165,521	$55,758	$89	$309,974	$64,167	$595,509	$388	$230	$596,127
Intersegment Revenues	$—	$23,054	$17,365	$6,521	$211	$47,151	$—	$(47,151)	$—
Segment Profit: Net Income (Loss)	$(53,562)	$23,377	$6,405	$38,238	$3,373	$17,831	$98	$(1,260)	$16,669

Six Months Ended March 31, 2015 (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	$370,186	$107,504	$235	$520,047	$120,333	$1,118,305	$1,271	$460	$1,120,036
Intersegment Revenues	$—	$44,515	$41,793	$11,055	$417	$97,780	$—	$(97,780)	$—
Segment Profit: Net Income (Loss)	$(26,842)	$44,155	$18,028	$60,831	$6,199	$102,371	$93	$(1,055)	$101,409

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Note 8 – Retirement Plan and Other Post-Retirement Benefits

Components of Net Periodic Benefit Cost (in thousands):

	Retirement Plan						Other Post-Retirement Benefits
Three Months Ended March 31,	2016			2015			2016			2015
Service Cost	$	2,928		$	3,012		$	583		$	673
Interest Cost	10,579			10,304			5,096			4,821
Expected Return on Plan Assets	(14,842		)	(14,904		)	(7,883		)	(8,522		)
Amortization of Prior Service Cost (Credit)	308			46			(228		)	(478		)
Amortization of Losses	8,062			9,032			1,382			1,037
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	5,609			7,055			6,599			7,396
Net Periodic Benefit Cost	$	12,644		$	14,545		$	5,549		$	4,927

	Retirement Plan						Other Post-Retirement Benefits
Six Months Ended March 31,	2016			2015			2016			2015
Service Cost	$	5,855		$	6,024		$	1,166		$	1,346
Interest Cost	21,158			20,608			10,193			9,642
Expected Return on Plan Assets	(29,685		)	(29,808		)	(15,768		)	(17,044		)
Amortization of Prior Service Cost (Credit)	617			92			(456		)	(956		)
Amortization of Losses	16,124			18,065			2,765			2,074
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	7,516			8,346			10,720			12,316
Net Periodic Benefit Cost	$	21,585		$	23,327		$	8,620		$	7,378

⁽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 six months endedMarch 31, 2016, the Company contributed $4.0 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $1.8 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits.  In the remainder of 2016, the Company expects to make no additional contributions to the Retirement Plan. In the remainder of 2016, the Company expects to contribute approximately $0.8 million to its VEBA trusts and 401(h) accounts.

Note 9– Regulatory Matters

Following negotiations and other proceedings, on December 6, 2013, Distribution Corporation filed an agreement, also executed by the Department of Public Service and intervenors, extending existing rates through, at a minimum, September 30, 2015. Although customer rates were not changed, the parties agreed that the allowed rate of return on equity would be set, for ratemaking purposes, at 9.1%.  Following conventional practice in New York, the agreement authorizes an “earnings sharing mechanism” (“ESM”).  The ESM distributes earnings above the allowed rate of return as follows:  from 9.5% to 10.5%, 50% would be allocated to shareholders, and 50% will be deferred for the benefit of customers; above 10.5%, 20% would be allocated to shareholders and 80% will be deferred for the benefit of customers.  The agreement further authorizes, and rates reflect, an increase in Distribution Corporation’s pipeline replacement spending by $8.2 million per year of the agreement.  The agreement contains other terms and conditions of service that are customary for settlement agreements recently approved by the NYPSC.  A $7.5 million refund provision was passed back to customers during 2014 after the NYPSC approved the settlement agreement without modification in an order issued on May 8, 2014. All significant terms of the agreement, including existing rates, continue in effect beyond September 30, 2015 until modified by the NYPSC. The agreement also states that nothing in the agreement

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precludes the parties from meeting to discuss extending the agreement on mutually acceptable terms, and presenting such extension to the NYPSC for approval. On May 22, 2015, Distribution Corporation filed with the NYPSC a Notice of Impending Settlement Discussions stating that settlement discussions would be scheduled in the near future, and that such discussions might include, among other things, the possible extension of the agreement on mutually acceptable terms, and on October 21, 2015, Distribution Corporation filed with the NYPSC a Supplemental Notice of Impending Settlement Discussions.

Settlement discussions did not lead to a settlement and, on April 28, 2016, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by approximately $41.7 million. Distribution Corporation explained in the filing that its request for rate relief was necessitated by a revenue requirement driven primarily by rate base growth, higher operating expense and higher depreciation expense that are not reflected in current rates, among other things. The rate filing includes a proposal for system infrastructure modernization that includes the acceleration of Distribution Corporation’s replacement of certain gas mains, which are of a type generically classified by the NYPSC as “leak prone pipe”. The NYPSC may accept, reject or modify the Company’s filing. Assuming standard procedure, new rates, if accepted, would become effective on or about April 1, 2017. The outcome of the proceeding cannot be ascertained at this time.

FERC Rate Proceedings

Supply Corporation's current rate settlement requires a rate case filing no later than December 31, 2019 and prohibits any party from seeking to initiate a rate case proceeding before September 30, 2017.

Empire does not have a rate case currently on file with the FERC, but by order dated January 21, 2016, the FERC began a NGA Section 5 rate review of Empire's rates. As required by that order, Empire filed a Cost and Revenue Study on April 5, 2016. Pursuant to the Procedural Schedule, discovery began April 6, 2016, with a hearing scheduled to commence on November 8, 2016.

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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report.

The Company is a diversified energy company engaged principally in the production, gathering, transportation, distribution and marketing of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused in the Marcellus Shale. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Marcellus Shale to markets in Canada and the eastern United States. The Company also develops and produces oil reserves, primarily in California. The Company reports financial results for five business segments.

The Company continues to develop its natural gas reserves in the Marcellus Shale, but at a slower pace than previous years given the current low commodity price environment. The Marcellus Shale is a Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.  The Company controls the natural gas interests associated with approximately 785,000 net acres within the Marcellus Shale area, with a majority of the interests held in fee, carrying no royalty and no lease expirations. In March 2016, the Company reduced its Marcellus Shale development program to one drilling rig, down from three drilling rigs at the beginning of fiscal 2016. Capital expenditures in the Exploration and Production segment are expected to be approximately $175 million during fiscal 2016, which is net of a $115.2 million reimbursement from IOG CRV-Marcellus, LLC under a joint development agreement for Marcellus Shale natural gas assets located in Elk, McKean and Cameron counties in north-central Pennsylvania.

Given the slower development pace in the Exploration and Production segment, capital expenditures in the Pipeline and Storage segment and the Gathering segment are expected to be lower than originally forecasted for fiscal 2016. Pipeline and Storage segment capital expenditures are expected to be approximately $145 million while Gathering segment capital expenditures are expected to be approximately $80 million. As previously noted, the in-service date for the Northern Access 2016 project has been delayed to November 2017 from its originally targeted late 2016 in-service date.

For the quarter and six months ended March 31, 2016, the Company recorded losses of $147.7 million and $336.8 million, respectively.  The losses for both periods were driven largely by impairment charges of $397.4 million ($230.5 million after-tax) and $832.9 million ($483.1 million after-tax) recorded in the Exploration and Production segment during the quarter and six months ended March 31, 2016, respectively. 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. Such costs are subject to a quarterly ceiling test prescribed by SEC Regulation S-X Rule 4-10 that determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. Due to significant declines in crude oil and natural gas commodity prices over the previous twelve months, the book value of the Company’s oil and gas properties exceeded the ceiling at December 31, 2015 as well as March 31, 2016, resulting in the impairment charges mentioned above. Given the current commodity price environment, the Company expects to record additional significant ceiling test impairments during both of the remaining quarters of fiscal 2016. An impairment in the first quarter of fiscal 2017 is also possible. For further discussion of the ceiling test and a sensitivity analysis concerning changes in crude oil and natural gas commodity prices and their impact on the ceiling test, refer to the Critical Accounting Estimates section below. For further discussion of the Company’s earnings, refer to the Results of Operations section below.

Under the Company’s existing 1974 indenture covenants, given the significant ceiling test impairments recorded during the year ended September 30, 2015 and the quarters ended December 31, 2015 and March 31, 2016, the Company expects to be precluded from issuing additional long-term unsecured indebtedness until the third quarter of fiscal 2017. Given the current commodity price environment, the Company expects to record additional significant ceiling test impairments during both of the remaining quarters of fiscal 2016. An impairment in the first quarter of fiscal 2017 is also possible. As a result, the Company expects to be precluded from issuing incremental long-term debt throughout much of fiscal 2017. However, with the reduction in forecasted capital expenditures discussed above, the Company does not anticipate a need for the issuance of additional long-term debt during fiscal 2016. The Company expects to use cash from operations and, if necessary, short-term borrowings to meet its capital expenditure needs for fiscal 2016. As for fiscal 2017, the Company does not expect to issue incremental long-term debt during that period and would anticipate using cash from operations and short-term borrowings under its revolving credit facility, which was undrawn as of March 31, 2016. The Company does not have any long-term debt maturing until fiscal 2018. The 1974 indenture would not preclude the Company from issuing new long-term debt to replace maturing long-term debt. 

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CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2015 Form 10-K.  There have been no material changes to that disclosure other than as set forth below.  The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K.

Oil and Gas Exploration and Development Costs.  The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties.  In accordance with this methodology, the Company is required to perform a quarterly ceiling test.  Under the ceiling test, the present value of future revenues from the Company's oil and gas reserves 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 (the “ceiling”) is compared with the book value of the Company’s oil and gas properties at the balance sheet date.  If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling.  The book value of the oil and gas properties exceeded the ceiling at December 31, 2015 as well as March 31, 2016, resulting in cumulative impairment charges of $832.9 million ($483.1 million after-tax) for the six months ended March 31, 2016. The impairment charge for the quarter ended March 31, 2016 was $397.4 million ($230.5 million after-tax). The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended March 31, 2016, based on posted Midway Sunset prices, was $41.69 per Bbl.  The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended March 31, 2016, based on the quoted Henry Hub spot price for natural gas, was $2.40 per MMBtu.  (Note – because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the actual prices received for such production is utilized to calculate the ceiling, rather than the Midway Sunset and HenryHub prices, which are only indicative of 12-month average prices for the twelve months ended March 31, 2016.)  The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the additional impairment that the Company would have recorded at March 31, 2016 if natural gas prices were $0.25 per MMBtu lower than the average used at March 31, 2016, the additional impairment the Company would have recorded at March 31, 2016 if crude oil prices were $5 per Bbl lower than the average used at March 31, 2016, and the additional impairment that the Company would have recorded at March 31, 2016 if both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl lower than the average prices used at March 31, 2016 (all amounts are presented after-tax). These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.  

Ceiling Testing Sensitivity to Commodity Price Changes
(Millions)	$0.25/MMBtu Decrease in Natural Gas Prices		$5.00/Bbl Decrease in Crude Oil Prices		$0.25/MMBtu Decrease in Natural Gas Prices and $5.00/Bbl Decrease in Crude Oil Prices
Calculated Impairment under Sensitivity Analysis	$	354.0	$	270.4	$	393.7
Actual Impairment Recorded at March 31, 2016	230.5		230.5		230.5
Additional Impairment	$	123.5	$	39.9	$	163.2

Looking ahead, the first day of the month Midway Sunset price for crude oil in April 2016 was $29.93 per Bbl. The first day of the month Henry Hub spot price for natural gas in April 2016 was $1.93 per MMBtu. Given these April prices, the potential that prices could stay at this level in future months, and the expected loss of significantly higher oil and gas prices from the 12-month average that will be used in the ceiling test at June 30, 2016 and September 30, 2016, the Company expects to experience significant ceiling test impairments in both of those quarters. An impairment is also possible in the first quarter of fiscal 2017. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2015 Form 10-K.

RESULTS OF OPERATIONS

Earnings

The Company recorded a loss of $147.7 million for the quarter ended March 31, 2016 compared to earnings of $16.7 million for the quarter ended March 31, 2015.  The decrease in earnings is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the Pipeline and Storage segment, Utility segment and All Other category also

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contributed to the decrease. Higher earnings in the Gathering segment, Energy Marketing segment and Corporate category partially offset these decreases.    

The Company recorded a loss of $336.8 million for the six months ended March 31, 2016 compared to earnings of $101.4 million for the six months ended March 31, 2015.  The decrease in earnings is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the Pipeline and Storage segment, Gathering segment, Utility segment and Energy Marketing segment also contributed to the decrease. Higher earnings in the Corporate and All Other categories partially offset these decreases.  

The Company's earnings for the quarter and six months ended March 31, 2016 include non-cash impairment charges of $397.4 million ($230.5 million after-tax) and $832.9 million ($483.1 million after-tax), respectively, recorded during the quarter and six months ended March 31, 2016 for the Exploration and Production segment's oil and gas producing properties, as discussed above. The Company's earnings for the quarter and six months ended March 31, 2015 included a non-cash $120.3 million impairment charge ($69.5 million after-tax) recorded during the quarter ended March 31, 2015 for the Exploration and Production segment's oil and gas producing properties. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.  Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.

Earnings (Loss) by Segment

	Three Months Ended   March 31,									Six Months Ended   March 31,
(Thousands)	2016			2015			Increase (Decrease)			2016			2015			Increase (Decrease)
Exploration and Production	$	(213,335	)	$	(53,562	)	$	(159,773	)	$	(450,421	)	$	(26,842	)	$	(423,579	)
Pipeline and Storage	21,194			23,377			(2,183		)	42,470			44,155			(1,685		)
Gathering	7,568			6,405			1,163			12,490			18,028			(5,538		)
Utility	31,960			38,238			(6,278		)	50,566			60,831			(10,265		)
Energy Marketing	3,484			3,373			111			4,707			6,199			(1,492		)
Total Reportable Segments	(149,129		)	17,831			(166,960		)	(340,188		)	102,371			(442,559		)
All Other	(23		)	98			(121		)	166			93			73
Corporate	1,465			(1,260		)	2,725			3,226			(1,055		)	4,281
Total Consolidated	$	(147,687	)	$	16,669		$	(164,356	)	$	(336,796	)	$	101,409		$	(438,205	)

Exploration and Production

Exploration and Production Operating Revenues

	Three Months Ended   March 31,							Six Months Ended   March 31,
(Thousands)	2016		2015		Increase (Decrease)			2016		2015		Increase (Decrease)
Gas (after Hedging)	$	104,356	$	114,507	$	(10,151	)	$	210,530	$	256,164	$	(45,634	)
Oil (after Hedging)	38,304		48,752		(10,448		)	83,034		108,917		(25,883		)
Gas Processing Plant	636		714		(78		)	1,273		1,773		(500		)
Other	487		1,548		(1,061		)	912		3,332		(2,420		)
	$	143,783	$	165,521	$	(21,738	)	$	295,749	$	370,186	$	(74,437	)

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Production Volumes

	Three Months Ended   March 31,				Six Months Ended   March 31,
	2016	2015	Increase (Decrease)		2016	2015	Increase (Decrease)
Gas Production(MMcf)
Appalachia	34,113	30,592	3,521		66,900	73,391	(6,491	)
West Coast	764	795	(31	)	1,547	1,567	(20	)
Total Production	34,877	31,387	3,490		68,447	74,958	(6,511	)
Oil Production(Mbbl)
Appalachia	5	5	—		11	15	(4	)
West Coast	718	721	(3	)	1,460	1,482	(22	)
Total Production	723	726	(3	)	1,471	1,497	(26	)

Average Prices

	Three Months Ended   March 31,							Six Months Ended   March 31,
	2016		2015		Increase (Decrease)			2016		2015		Increase (Decrease)
Average Gas Price/Mcf
Appalachia	$	1.85	$	2.46	$	(0.61	)	$	1.91	$	2.75	$	(0.84	)
West Coast	$	2.87	$	3.81	$	(0.94	)	$	3.27	$	4.70	$	(1.43	)
Weighted Average	$	1.87	$	2.50	$	(0.63	)	$	1.94	$	2.79	$	(0.85	)
Weighted Average After Hedging	$	2.99	$	3.65	$	(0.66	)	$	3.08	$	3.42	$	(0.34	)
Average Oil Price/Bbl
Appalachia	$	32.81	$	46.18	$	(13.37	)	$	36.74	$	65.09	$	(28.35	)
West Coast	$	27.02	$	43.93	$	(16.91	)	$	31.61	$	55.71	$	(24.10	)
Weighted Average	$	27.06	$	43.95	$	(16.89	)	$	31.65	$	55.80	$	(24.15	)
Weighted Average After Hedging	$	53.01	$	67.14	$	(14.13	)	$	56.45	$	72.78	$	(16.33	)

2016 Compared with 2015

Operating revenues for the Exploration and Production segment decreased $21.7 million for the quarter ended March 31, 2016 as compared with the quarter ended March 31, 2015.  Gas production revenue after hedging decreased $10.2 million primarily due to a $0.66 per Mcf decrease in the weighted average price of gas after hedging, partially offset by the impact of increased gas production. Oil production revenue after hedging decreased $10.4 million due to a $14.13 per Bbl decrease in the weighted average price of oil after hedging as crude oil production was largely flat. In addition, other revenue decreased $1.1 million primarily due to mark-to-market adjustments related to hedging ineffectiveness that occurred during the quarter ended March 31, 2015 that did not recur during the quarter ended March 31, 2016.

Operating revenues for the Exploration and Production segment decreased $74.4 million for the six months ended March 31, 2016 as compared with the six months ended March 31, 2015. Gas production revenue after hedging decreased $45.6 million primarily due to a decrease in production, which was caused by pricing-related curtailments and a $0.34 per Mcf decrease in the weighted average price of gas after hedging. Oil production revenue after hedging decreased $25.9 million due to a $16.33 per Bbl decrease in the weighted average price of oil after hedging. Crude oil production was largely flat. In addition, other revenue decreased $2.4 million primarily due to mark-to-market adjustments related to hedging ineffectiveness that occurred during the six months ended March 31, 2015 that did not recur during the six months ended March 31, 2016.

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The Exploration and Production segment's loss for the quarter ended March 31, 2016 was $213.3 million compared with a loss of $53.6 million for the quarter ended March 31, 2015.  The increased loss can be attributed to higher impairment charges ($161.0 million), as discussed above, lower crude oil prices after hedging ($6.6 million), lower natural gas prices after hedging ($14.9 million), lower crude oil production ($0.2 million), the impact of mark-to-market adjustments ($0.9 million) and higher interest expense ($1.6 million). The increase in interest expense was largely due to the Exploration and Production segment's share of the Company's $450 million long-term debt issuance in June 2015. These were partially offset by the impact of higher natural gas production ($8.3 million), lower depletion expense ($13.1 million), lower production costs ($2.5 million) and lower other taxes ($1.5 million). The decrease in depletion expense is primarily due to the impact of impairment charges recognized in fiscal 2015 and fiscal 2016. The decrease in production costs is largely due to the decrease in steam fuel costs associated with crude oil production in the West Coast region (due to lower fuel prices) and a decrease in seasonal road maintenance in the Appalachian region (due to a milder winter). The decrease in other taxes was largely due to IOG being billed for its share of previously incurred impact fees in accordance with the joint development agreement executed in December 2015.

The Exploration and Production segment's loss for the six months ended March 31, 2016 was $450.4 million compared with a loss of $26.8 million for the six months ended March 31, 2015.  The increased loss can be attributed to higher impairment charges ($413.6 million), as discussed above, joint development agreement professional fees ($3.0 million), lower crude oil prices after hedging ($15.6 million), lower natural gas prices after hedging ($15.2 million), lower natural gas production ($14.5 million), lower crude oil production ($1.2 million), the impact of mark-to-market adjustments ($1.8 million) and higher interest expense ($4.4 million). The joint development agreement professional fees incurred were related to professional services associated with the Marcellus Shale drilling joint development agreement with IOG that was executed in December 2015. The increase in interest expense was largely due to the Exploration and Production segment's share of the Company's $450 million long-term debt issuance in June 2015. These were partially offset by the impact of lower depletion expense ($36.5 million), lower production costs ($7.6 million) and lower other taxes ($1.8 million). The decrease in depletion expense is primarily due to the impact of impairment charges recognized in fiscal 2015 and fiscal 2016 and a decrease in production due to pricing-related curtailments. The decrease in production costs is largely due to the decrease in transportation costs associated with production volumes transported by Midstream Corporation due to pricing-related curtailments, a decrease in seasonal road maintenance in the Appalachian region (due to a milder winter), and decreases in various costs associated with a reduction in Appalachian production (e.g. compressor costs, equipment rental costs, and salt water disposal costs). The decrease in other taxes was largely due to the decrease in impact fees, as discussed above, coupled with a decrease in Kern and Ventura County taxes that was due to a decrease in crude oil prices.

Pipeline and Storage

Pipeline and Storage Operating Revenues

	Three Months Ended   March 31,							Six Months Ended   March 31,
(Thousands)	2016		2015		Increase (Decrease)			2016		2015		Increase (Decrease)
Firm Transportation	$	59,900	$	59,025	$	875		$	116,405	$	113,218	$	3,187
Interruptible Transportation	1,047		785		262			2,022		1,532		490
	60,947		59,810		1,137			118,427		114,750		3,677
Firm Storage Service	18,100		18,150		(50		)	35,379		35,639		(260		)
Interruptible Storage Service	19		2		17			70		3		67
Other	502		850		(348		)	1,231		1,627		(396		)
	$	79,568	$	78,812	$	756		$	155,107	$	152,019	$	3,088

Pipeline and Storage Throughput

	Three Months Ended   March 31,				Six Months Ended   March 31,
(MMcf)	2016	2015	Increase (Decrease)		2016	2015	Increase (Decrease)
Firm Transportation	208,950	230,311	(21,361	)	384,781	416,633	(31,852	)
Interruptible Transportation	6,483	3,627	2,856		12,115	5,729	6,386
	215,433	233,938	(18,505	)	396,896	422,362	(25,466	)

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2016 Compared with 2015

Operating revenues for the Pipeline and Storage segment increased $0.8 million for the quarter ended March 31, 2016 as compared with the quarter ended March 31, 2015.  The increase was primarily due to an increase in transportation revenues of $1.1 million.  The increase in transportation revenues was largely due to demand charges for transportation service from Supply Corporation’s Westside Expansion and Modernization Project, Supply Corporation's Northern Access 2015 project, which were both fully placed in service during the first quarter of fiscal 2016 and Empire's Tuscarora Lateral Project, which was placed in service in November 2015. The increase in transportation revenues was partially offset by a decrease in Empire and Supply Corporation's short-term seasonal contracts. Operating revenues were also impacted by a 2% reduction in Supply Corporation's rates associated with the rate case settlement, which became effective November 1, 2015.

Operating revenues for the Pipeline and Storage segment increased $3.1 million for the six months ended March 31, 2016 as compared with the six months ended March 31, 2015. The increase was primarily due to an increase in transportation revenues of $3.7 million.  The increase in transportation revenues was largely due to demand charges for transportation service from Supply Corporation’s Westside Expansion and Modernization Project, Supply Corporation's Northern Access 2015 project, which were both fully placed in service during the first quarter of fiscal 2016 and Empire's Tuscarora Lateral Project, which was placed in service in November 2015. The increase in transportation revenues was partially offset by a decrease in short-term contracts for both Empire and Supply Corporation. Operating revenues were also impacted by a 2% reduction in Supply Corporation's rates associated with the rate case settlement, which became effective November 1, 2015.

Transportation volume for the quarter ended March 31, 2016 decreased by 18.5 Bcf from the prior year’s quarter. For the six months ended March 31, 2016, transportation volume decreased by 25.5 Bcf from the prior year's six-month period. The decrease in transportation volume for the quarter and six-month period primarily reflects warmer weather. Volume fluctuations, other than those caused by the addition or deletion of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2016 were $21.2 million, a decrease of $2.2 million when compared with earnings of $23.4 million for the quarter ended March 31, 2015.  The decrease in earnings is primarily due to higher operating expenses ($0.9 million), an increase in depreciation expense ($0.7 million) and higher interest expense ($1.1 million). The increase in operating expenses primarily reflect higher other post-retirement benefit costs and higher legal costs. The increase in depreciation expense was attributable to projects that were placed in service within the last year. The increase in interest expense was largely due to Supply Corporation's share of the Company's $450 million long-term debt issuance in June 2015. The factors contributing to the earnings decrease were partially offset by the positive earnings impact of higher transportation revenues ($0.7 million), as discussed above.

The Pipeline and Storage segment’s earnings for the six months ended March 31, 2016 were $42.5 million, a decrease of $1.7 million when compared with earnings of $44.2 million for the six months ended March 31, 2015. The decrease in earnings is primarily due to higher operating expenses ($0.7 million), an increase in depreciation expense ($1.5 million), an increase in property taxes ($0.5 million) and higher interest expense ($2.1 million). The increase in operating expenses primarily reflects higher other post-retirement benefit costs, higher pipeline integrity program expenses and higher legal costs, offset slightly by lower personnel costs. The increase in depreciation expense was attributable to projects that were placed in service within the last year. The increase in property taxes was attributable to various expansion projects constructed over the last few years. The increase in interest expense was largely due to Supply Corporation's share of the Company's $450 million long-term debt issuance in June 2015. The factors contributing to the earnings decrease were partially offset by the positive earnings impact of higher transportation revenues ($2.4 million), as discussed above, combined with an increase in the equity component of the allowance for funds used during construction ($1.1 million). The increase in the equity component of the allowance for funds used during construction is attributable to higher Construction Work in Progress balances related to this segment's ongoing expansion projects.

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Gathering

Gathering Operating Revenues

	Three Months Ended   March 31,						Six Months Ended   March 31,
(Thousands)	2016		2015		Increase (Decrease)		2016		2015		Increase (Decrease)
Gathering	$	21,545	$	17,365	$	4,180	$	40,184	$	41,793	$	(1,609	)
Processing and Other Revenues	113		89		24		238		235		3
	$	21,658	$	17,454	$	4,204	$	40,422	$	42,028	$	(1,606	)

Gathering Volume

	Three Months Ended   March 31,			Six Months Ended   March 31,
	2016	2015	Increase (Decrease)	2016	2015	Increase (Decrease)
Gathered Volume - (MMcf)	39,195	31,175	8,020	72,995	76,047	(3,052	)

2016 Compared with 2015

Operating revenues for the Gathering segment increased $4.2 million for the quarter ended March 31, 2016 as compared with the quarter ended March 31, 2015. This increase was due to an increase in gathering revenues driven by an 8.0 Bcf increase in gathered volume.  The overall increase in gathered volume was largely due to a 12.1 Bcf increase in gathered volume on Midstream Corporation’s Clermont Gathering System (Clermont), largely attributable to increased usage of the Clermont Gathering System due to the completion of the Northern Access 2015 project in November and December 2015. In addition, there was a marginal increase in gathered volume on Midstream Corporation’s Covington Gathering System (Covington) of 0.6 Bcf and a marginal increase on Midstream Corporation's Mt. Jewett Gathering System (Mt. Jewett) of 0.3 Bcf. These increases in gathered volume were partially offset by a 5.0 Bcf decrease in gathered volume on Midstream Corporation's Trout Run Gathering System (Trout Run). This decrease in gathered volume is primarily attributable to a decrease in Seneca's Marcellus Shale production largely due to pricing-related curtailments.

Operating revenues for the Gathering segment decreased $1.6 million for the six months ended March 31, 2016 as compared with the six months ended March 31, 2015. This decrease was due to a decrease in gathering revenues driven by a 3.1 Bcf decrease in gathered volume.  The overall decrease in gathered volume was largely due to a 17.8 Bcf decrease in gathered volume on Trout Run, and a 4.2 Bcf decrease in gathered volume on Covington. Most of these decreases in gathered volume are attributable to a decrease in Seneca's Marcellus Shale production largely due to pricing-related curtailments. These decreases in gathered volume were partially offset by a 18.9 Bcf increase in gathered volume on Clermont. This increase in gathered volume is primarily attributable to increased usage of the Clermont Gathering System due to the completion of the Northern Access 2015 project in November and December 2015.

The Gathering segment’s earnings for the quarter ended March 31, 2016 were $7.6 million, an increase of $1.2 million when compared with earnings of $6.4 million for the quarter ended March 31, 2015.  The increase in earnings is mainly due to the earnings impact of higher gathering revenues ($2.7 million).  The increase in gathering revenues is due to the increases in gathered volume on Clermont, Covington and Mt. Jewett, partially offset by the decrease in gathered volume on Trout Run, as discussed above. This increase in gathering revenue is partially offset by higher interest expense ($1.2 million). The increase in interest expense is largely due to the Gathering segment's share of the Company's $450 million long-term debt issuance in June 2015 coupled with a decrease in capitalized interest, which was due to various Clermont projects being placed in service.  

The Gathering segment’s earnings for the six months ended March 31, 2016 were $12.5 million, a decrease of $5.5 millionwhen compared with earnings of $18.0 million for the six months ended March 31, 2015. The decrease in earnings is mainly due to higher interest expense ($3.0 million), higher depreciation expense ($1.3 million), the earnings impact of lower gathering revenues ($1.0 million) and higher operating expenses ($0.7 million).  The increase in interest expense is largely due to the Gathering segment's share of the Company's $450 million long-term debt issuance in June 2015 coupled with a decrease in capitalized interest, which was due to various Clermont projects being placed in service.  A large increase in plant balances (largely due to various Clermont projects being placed in service), partially offset by the non-recurrence of long-lived asset impairment

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charges recorded in March 2015 related to the gathering facilities at Midstream Corporation's Tionesta Gathering System, led to an overall increase in depreciation expense. The decrease in gathering revenues is due to the decreases in gathered volume on Trout Run and Covington, partially offset by the increase in gathered volume on Clermont, as discussed above. The increase in operating expenses was largely due to the significant growth of Clermont.

Utility

Utility Operating Revenues

	Three Months Ended   March 31,							Six Months Ended   March 31,
(Thousands)	2016		2015		Increase (Decrease)			2016		2015		Increase (Decrease)
Retail Sales Revenues:
Residential	$	145,456	$	214,449	$	(68,993	)	$	243,909	$	361,135	$	(117,226	)
Commercial	19,362		29,765		(10,403		)	31,466		48,062		(16,596		)
Industrial	930		1,299		(369		)	1,419		2,050		(631		)
	165,748		245,513		(79,765		)	276,794		411,247		(134,453		)
Transportation	47,108		56,223		(9,115		)	81,010		96,111		(15,101		)
Off-System Sales	1,877		5,848		(3,971		)	1,877		11,773		(9,896		)
Other	3,368		8,911		(5,543		)	5,932		11,971		(6,039		)
	$	218,101	$	316,495	$	(98,394	)	$	365,613	$	531,102	$	(165,489	)

Utility Throughput

	Three Months Ended   March 31,				Six Months Ended   March 31,
(MMcf)	2016	2015	Increase (Decrease)		2016	2015	Increase (Decrease)
Retail Sales:
Residential	24,486	31,561	(7,075	)	37,619	48,029	(10,410	)
Commercial	3,688	4,813	(1,125	)	5,515	7,097	(1,582	)
Industrial	167	194	(27	)	233	282	(49	)
	28,341	36,568	(8,227	)	43,367	55,408	(12,041	)
Transportation	27,297	33,567	(6,270	)	44,913	54,516	(9,603	)
Off-System Sales	1,243	2,118	(875	)	1,243	3,787	(2,544	)
	56,881	72,253	(15,372	)	89,523	113,711	(24,188	)

Degree Days

Three Months Ended March 31,				Percent Colder (Warmer) Than
	Normal	2016	2015	Normal(1)		Prior Year(1)
Buffalo	3,326	2,963	3,984	(10.9	)%	(25.6	)%
Erie	3,142	2,739	3,815	(12.8	)%	(28.2	)%
Six Months Ended March 31,
Buffalo	5,579	4,640	6,120	(16.8	)%	(24.2	)%
Erie	5,186	4,223	5,806	(18.6	)%	(27.3	)%

⁽¹⁾  Percents compare actual 2016 degree days to normal degree days and actual 2016 degree days to actual 2015 degree days.

35

2016 Compared with 2015

Operating revenues for the Utility segment decreased $98.4 million for the quarter ended March 31, 2016 as compared with the quarter ended March 31, 2015.  This decrease largely resulted from a $79.8 million decrease in retail gas sales revenues. In addition, there was a $4.0 million decrease in off-system sales, a $9.1 million decrease in transportation revenues, and a $5.5 million decrease in other revenues. The decrease in retail gas sales revenue was largely a result of a decrease in the cost of gas sold (per Mcf) coupled with lower volumes due to warmer weather. The $9.1 million decrease in transportation revenues was primarily due to a 6.3 Bcf decrease in transportation throughput due to warmer weather. The decrease in off-system sales was due to market conditions that have continued to reduce the price at which off-system gas could be sold as well as the opportunity for such sales. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal. The decrease in other revenues was largely due to a regulatory adjustment recorded during fiscal 2015 to recognize an under collection of a New York State regulatory assessment from customers.

Operating revenues for the Utility segment decreased $165.5 million for the six months ended March 31, 2016 as compared with the six months ended March 31, 2015. This decrease largely resulted from a $134.5 million decrease in retail gas sales revenues. In addition, there was a $9.9 million decrease in off-system sales, a $15.1 million decrease in transportation revenues, and a $6.0 decrease in other revenues. The decrease in retail gas sales revenue was largely a result of a decrease in the cost of gas sold (per Mcf) coupled with lower volumes due to warmer weather. The $15.1 million decrease in transportation revenues was primarily due to a 9.6 Bcf decrease in transportation throughput due to warmer weather. The decrease in off-system sales was due to market conditions that have continued to reduce the price at which off-system gas could be sold as well as the opportunity for such sales. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal. The decrease in other revenues was largely due to a regulatory adjustment recorded during fiscal 2015 to recognize an under collection of a New York State regulatory assessment from customers.

The Utility segment’s earnings for the quarter ended March 31, 2016 were $32.0 million, a decrease of $6.2 million when compared with earnings of $38.2 million for the quarter ended March 31, 2015. The decrease in earnings was largely attributable to the impact of warmer weather in fiscal 2016 compared to fiscal 2015 ($6.9 million) and $3.2 million of regulatory adjustments (discussed above). The negative earnings impact associated with these factors was partially offset by the positive earnings impact associated with a decrease in operating expenses of $2.6 million primarily due to a reduction in personnel costs, and lower income tax expense of $0.7 million primarily due to a reduction in state income taxes.

The impact of weather variations on earnings in the Utility segment’s New York rate jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC).  The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction.  In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers.  For the quarter ended March 31, 2016, the WNC increased earnings by approximately $2.3 million as the weather was warmer than normal.  For the quarter ended March 31, 2015, the WNC reduced earnings by approximately $2.9 million, as the weather was colder than normal.

The Utility segment’s earnings for the six months ended March 31, 2016 were $50.6 million, a decrease of $10.2 million when compared with earnings of $60.8 million for the six months ended March 31, 2015.  The decrease in earnings was largely attributable to the impact of warmer weather in fiscal 2016 compared to fiscal 2015 ($12.8 million) and $3.7 million of regulatory adjustments (discussed above). The negative earnings impact associated with these factors was partially offset by the positive earnings impact associated with a decrease in operating expenses of $3.6 million primarily due to a reduction in personnel costs, lower income tax expense of $2.0 million primarily due to a reduction in state income taxes, and higher usage per account ($1.1 million). The phrase “usage per account” refers to the average gas consumption per account after factoring out any impact that weather may have had on consumption.

For the six months ended March 31, 2016, the WNC increased earnings by approximately $4.3 million, as the weather was warmer than normal.  For the six months ended March 31, 2015, the WNC reduced earnings by approximately $2.6 million, as the weather was colder than normal.

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Energy Marketing

Energy Marketing Operating Revenues

	Three Months Ended   March 31,							Six Months Ended   March 31,
(Thousands)	2016		2015		Increase (Decrease)			2016		2015		Increase (Decrease)
Natural Gas (after Hedging)	$	35,742	$	64,365	$	(28,623	)	$	60,939	$	120,696	$	(59,757	)
Other	6		13		(7		)	105		54		51
	$	35,748	$	64,378	$	(28,630	)	$	61,044	$	120,750	$	(59,706	)

Energy Marketing Volume

	Three Months Ended   March 31,				Six Months Ended   March 31,
	2016	2015	Increase (Decrease)		2016	2015	Increase (Decrease)
Natural Gas – (MMcf)	15,165	19,337	(4,172	)	25,263	31,926	(6,663	)

2016 Compared with 2015

Operating revenues for the Energy Marketing segment decreased $28.6 million for the quarter ended March 31, 2016 as compared with the quarter ended March 31, 2015.  Operating revenues for the Energy Marketing segment decreased $59.7 million for the six months ended March 31, 2016 as compared with the six months ended March 31, 2015. The decrease for the quarter and six-month period is primarily due to a decline in gas sales revenue due to a lower average price of natural gas period over period and a decrease in volume sold to retail customers as a result of warmer weather.

The Energy Marketing segment’s earnings for the quarter ended March 31, 2016 were $3.5 million, an increase of $0.1 million when compared with earnings of $3.4 million for the quarter ended March 31, 2015. The increase is primarily due to higher margin of $0.1 million. The increase in margin reflects an increase in the benefit the Energy Marketing segment realized from its contracts for storage capacity, almost all of which was offset by a decline in margin associated with the decrease in volume sold to retail customers. The decrease in volume was attributable to warmer weather during the quarter ended March 31, 2016 compared to the quarter ended March 31, 2015.

The Energy Marketing segment’s earnings for the six months ended March 31, 2016 were $4.7 million, a decrease of $1.5 million when compared with earnings of $6.2 million for the six months ended March 31, 2015.  This decrease in earnings was largely attributable to lower margin of $1.5 million. The decrease in margin largely reflects the margin impact associated with the decrease in volume sold to retail customers as a result of warmer weather during the six months ended March 31, 2016 compared to the six months ended March 31, 2015. This decrease was partially offset by an increase to margin due to an increase in the benefit the Energy Marketing segment realized from its contracts for storage capacity.

Corporate and All Other

2016 Compared with 2015

Corporate and All Other operations recorded earnings of $1.4 million for the quarter ended March 31, 2016, an increase of $2.6 million when compared to a loss of $1.2 million for the quarter ended March 31, 2015. For the six months ended March 31, 2016, Corporate and All Other operations recorded earnings of $3.4 million, an increase of $4.4 million when compared to a loss of $1.0 million recorded for the six months ended March 31, 2015. The earnings increase for the quarter and six-month periods can be attributed to lower income tax expense of $1.1 million and $2.1 million, respectively, and a death benefit gain on life insurance of $1.6 million that was recognized during the quarter ended March 31, 2016. In addition, lower operating expenses of $0.7 million (primarily due to a decrease in personnel costs) further increased earnings during the six months ended March 31, 2016.

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Interest Expense on Long-Term Debt (amounts below are pre-tax amounts)

Interest on long-term debt increased $6.6 million for the quarter ended March 31, 2016 as compared with the quarter ended March 31, 2015.  For the six months ended March 31, 2016, interest on long-term debt increased $14.7 million as compared with the six months ended March 31, 2015. This increase is primarily due to additional long-term debt that was issued in fiscal 2015. The Company issued $450 million of 5.20% notes in June 2015.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary sources of cash during the six-month period ended March 31, 2016 consisted of cash provided by operating activities and proceeds from Seneca's joint development agreement with IOG. Proceeds from IOG are reflected as net proceeds from the sale of oil and gas producing properties on the Statement of Cash Flows.  The Company’s primary source of cash during the six-month period ended March 31, 2015 consisted of cash provided by operating activities and net proceeds from short-term borrowings. These sources of cash were supplemented by net proceeds from the issuance of common stock for both the six months ended March 31, 2016 and March 31, 2015, including the issuance of original issue shares for the Direct Stock Purchase and Dividend Reinvestment Plan.

Operating Cash Flow

Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, deferred income taxes and stock-based compensation.

Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.

Because of the seasonal nature of the heating business in the Utility and Energy Marketing segments, revenues in these segments are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances at September 30.

The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters.  For storage gas inventory accounted for under the LIFO method, 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 is reduced as the inventory is replenished.

Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil as well as changes in production.  The Company uses various derivative financial instruments, including price swap agreements and futures contracts in an attempt to manage this energy commodity price risk.

Net cash provided by operating activities totaled $312.8 million for the six months ended March 31, 2016, a decrease of $194.7 million compared with $507.5 million provided by operating activities for the six months ended March 31, 2015. Thedecrease in cash provided by operating activities reflects lower cash provided by operating activities in the Exploration and Production segment. The decrease in the Exploration and Production segment is primarily due to lower cash receipts from crude oil and natural gas production as a result of lower crude oil and natural gas prices and curtailed production.

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Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $306.1 million during the six months endedMarch 31, 2016 and $451.2 million during the six months endedMarch 31, 2015.  The table below presents these expenditures:

Total Expenditures for Long-Lived Assets
Six Months Ended March 31,	2016			2015			Increase(Decrease)
(Millions)
Exploration and Production:
Capital Expenditures	$	167.7	(1)	$	301.1	(2)	$	(133.4	)
Pipeline and Storage:
Capital Expenditures	57.7		(1)	57.7		(2)	—
Gathering:
Capital Expenditures	34.5		(1)	50.5		(2)	(16.0		)
Utility:
Capital Expenditures	46.0		(1)	41.7		(2)	4.3
All Other:
Capital Expenditures	0.2		(1)	0.2		(2)	—
	$	306.1		$	451.2		$	(145.1	)

(1) At March 31, 2016, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $34.0 million, $10.2 million, $12.6 million and $9.3 million, respectively, of non-cash capital expenditures. At September 30, 2015, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $46.2 million, $33.9 million, $22.4 million and $16.5 million, respectively, of non-cash capital expenditures.  The capital expenditures for the Exploration and Production segment do not include any proceeds received from the sale of oil and gas assets.  

(2) At March 31, 2015, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $63.5 million, $8.2 million, $14.1 million and $8.7 million, respectively, of non-cash capital expenditures.  At September 30, 2014, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $80.1 million, $28.1 million, $20.1 million and $8.3 million, respectively, of non-cash capital expenditures.

Exploration and Production

The Exploration and Production segment capital expenditures for the six months ended March 31, 2016 were primarily well drilling and completion expenditures and included approximately $146.6 million for the Appalachian region (including $138.3 million in the Marcellus Shale area) and $21.1 million for the West Coast region.  These amounts included approximately $77.8 million spent to develop proved undeveloped reserves. 

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. Under the terms of the agreement, Seneca and IOG will jointly participate in a program that will develop up to 80 Marcellus wells, with Seneca serving as program operator. As of March 31, 2016, Seneca had received cash of $104.9 million from IOG and recorded a $10.3 million receivable in recognition of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the first 42 wells. The cash proceeds and receivable were recorded by Seneca as a $115.2 million reduction of property, plant and equipment. For further discussion of the joint development agreement, refer to Item 1 at Note 1 - Summary of Significant Accounting Policies under the heading “Property, Plant and Equipment.”

The Exploration and Production segment capital expenditures for the six months endedMarch 31, 2015 were primarily well drilling and completion expenditures and included approximately $260.9 million for the Appalachian region (including $235.7 million in the Marcellus Shale area) and $40.2 million for the West Coast region.  These amounts included approximately $110.9 million spent to develop proved undeveloped reserves.

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Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the six months endedMarch 31, 2016 were mainly for expenditures related to Empire and Supply Corporation's Northern Access 2016 Project ($15.7 million), Supply Corporation's Northern Access 2015 Project ($11.2 million), Supply Corporation's Westside Expansion and Modernization Project ($6.8 million) and Empire and Supply Corporation's Tuscarora Lateral Project ($5.3 million). In addition, the Pipeline and Storage segment capital expenditures for the six months ended March 31, 2016 also include additions, improvements and replacements to this segment’s transmission and gas storage systems.   The majority of the Pipeline and Storage capital expenditures for the six months endedMarch 31, 2015 were mainly for expenditures related to Supply Corporation's Westside Expansion and Modernization Project ($13.8 million), Supply Corporation's Northern Access 2015 Project ($9.5 million), Supply Corporation's Mercer Expansion Project ($7.1 million) and Empire and Supply Corporation's Tuscarora Lateral Project ($3.5 million) and also included additions, improvements, and replacements to this segment’s transmission and gas storage systems.

In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus and Utica Shale producing areas — Supply Corporation and Empire are actively pursuing several expansion projects and paying for preliminary survey and investigation costs, which are initially recorded as Deferred Charges on the Consolidated Balance Sheet. An offsetting reserve is established as those preliminary survey and investigation costs are incurred, which reduces the Deferred Charges balance and increases Operation and Maintenance Expense on the Consolidated Statement of Income. The Company reviews all projects on a quarterly basis, and if it is determined that it is highly probable that the project will be built, the reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the original balance in Deferred Charges. After the reversal of the reserve, the amounts remain in Deferred Charges until such time as capital expenditures for the project have been incurred and activities that are necessary to get the construction project ready for its intended use are in progress. At that point, the balance is transferred from Deferred Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet.  As of March 31, 2016, the total amount reserved for the Pipeline and Storage segment’s preliminary survey and investigation costs was $8.0 million.

Supply Corporation and Empire are moving forward with, or have recently completed, several projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. Projects where the Company has begun to make significant investments of preliminary survey and investigation costs and/or where shipper agreements have been executed are described below.

The Westside Expansion and Modernization Project, which further increases Supply Corporation's capacity to move gas north and south on its Line N system to Texas Eastern Transmission, LP (“TETCO”) at Holbrook and Tennessee Gas Pipeline ("TGP") at Mercer, was fully placed in service during the first quarter of fiscal 2016. The cost estimate for this project is $82.3 million, of which $43.3 million is related to expansion and the remainder is for replacement.  As of March 31, 2016, approximately $74.7 million has been spent on the Westside Expansion and Modernization Project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2016.  

Supply Corporation and TGP jointly developed the Northern Access 2015 project that combines expansions on both pipeline systems, providing a seamless transportation path from TGP’s 300 Line in the Marcellus fairway to the TransCanada Pipeline delivery point at Niagara.  Northern Access 2015 was fully placed in service during the first quarter of fiscal 2016. The cost estimate for the Northern Access 2015 project is $67.1 million.  As of March 31, 2016, approximately $62.7 million has been spent on the Northern Access 2015 project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2016.  

Supply Corporation and Empire have been working with Seneca to develop a project which would move significant prospective Marcellus production from Seneca's Western Development Area at Clermont to an Empire interconnection with TransCanada Pipeline at Chippawa (“Northern Access 2016”) and an interconnection with TGP's 200 Line in East Aurora, New York. Similar to the goal of the Northern Access 2015 project, the separate and distinct Northern Access 2016 project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access 2016 project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. As a result of Seneca's slowed drilling activity and other considerations, the Company has revised the target in-service date for this project to November 1, 2017 (from the originally scheduled late calendar 2016). The revised project timeline allows the Company additional time to complete all development activities and prepare for efficient construction of the project facilities. The preliminary cost estimate for the Northern Access 2016 project is $455 million.  Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On July 24, 2014, Supply Corporation and Empire initiated the FERC NEPA Pre-filing process on this project and both parties filed a joint FERC 7(b) and 7(c) application in early March 2015 and amended that application on November 2, 2015. As of

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March 31, 2016, approximately $34.2 million has been spent on the Northern Access 2016 project, including $12.6 million that has been spent to study the project. The Company has determined it is highly probable that the project will be built. Accordingly, previous reserves have been reversed and this $12.6 million of project costs has been reestablished as a Deferred Charge on the Consolidated Balance Sheet. The remaining $21.6 million spent on the project has been capitalized as Construction Work in Progress.

On November 21, 2014, Supply Corporation concluded an Open Season for an expansion of its Line D pipeline (“Line D Expansion”) that is intended to allow growing on-system markets to avail themselves of economical gas supply on the TGP 300 line, at an existing interconnect at Lamont, Pennsylvania, and provide increased capacity into the Erie, Pennsylvania market area. Following negotiations with prospective shippers, Supply Corporation executed five precedent agreements for a total of 77,500 Dth per day for terms of ten years. The project involves construction of a new 4,152 horsepower Keelor Compressor Station and modifications to the Roystone and Bowen compressor stations at an estimated capital cost of approximately $27.9 million. The project will also provide system modernization benefits. Supply Corporation filed on December 22, 2015 for authorization to construct this project under its FERC blanket certificate and completed the FERC notice period on February 26, 2016. Based on the anticipated timing of the PaDEP Air Permit, the target in-service date is April 1, 2017. As of March 31, 2016, approximately $2.0 million has been capitalized as Construction Work in Progress for the Line D Expansion project.

Empire and Supply Corporation's Tuscarora Lateral Project, which allows Empire to provide firm no-notice storage and transportation services to new and existing shippers on its system, was placed in service in November 2015. The cost estimate for the Tuscarora Lateral Project is $65.2 million.  As of March 31, 2016, approximately $60.8 million has been spent on the Tuscarora Lateral Project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2016.  

Empire is developing an expansion of its system, and concluded an Open Season on November 18, 2015, that would allow for the transportation of approximately 300,000 Dth per day of additional Marcellus supplies from Millennium Pipeline at Corning, from Supply Corporation at Tuscarora, or from new interconnections in Tioga County, Pennsylvania, to the TransCanada Pipeline and the TGP 200 Line (“Empire North Project”). The preliminary cost estimate for the Empire North Project is approximately $185 million dependent on final receipt and delivery point selections.  As of March 31, 2016, approximately $0.3 million has been spent to study this project, all of which has been included in preliminary survey and investigation charges and has been fully reserved for at March 31, 2016.

Gathering

The majority of the Gathering segment capital expenditures for the six months endedMarch 31, 2016 and March 31, 2015 were for the construction of Midstream Corporation’s Clermont Gathering System, as discussed below.  

NFG Midstream Clermont, LLC, a wholly owned subsidiary of Midstream Corporation, is building an extensive gathering system with compression in the Pennsylvania counties of McKean, Elk and Cameron. The total cost estimate for the continued buildout will be dependent on the nature and timing of Seneca's long-term plans. As of March 31, 2016, approximately $247.0 million has been spent on the Clermont Gathering System, including approximately $30.5 million spent during the six months ended March 31, 2016, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2016.

NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream Corporation, continues to develop its Trout Run Gathering System in Lycoming County, Pennsylvania. The Trout Run Gathering System was initially placed in service in May 2012. The current system consists of approximately 42 miles of backbone and in-field gathering pipelines and two compressor stations.  As of March 31, 2016, the Company has spent approximately $166.3 million in costs related to this project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2016.

Utility

The majority of the Utility segment capital expenditures for the six months endedMarch 31, 2016 and March 31, 2015 were made for replacement of mains and main extensions, as well as for the replacement of service lines.  The capital expenditures for the six months endedMarch 31, 2016 and March 31, 2015 also include $7.9 million and $9.6 million, respectively, related to the replacement of the Utility segment’s customer information system, which is scheduled to be placed in service in the spring of 2016.  

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Project Funding

The Company has been financing the Pipeline and Storage segment and Gathering segment projects mentioned above, as well as the Exploration and Production segment capital expenditures, with cash from operations and both short and long-term borrowings.  Going forward, while the Company expects to use cash on hand and cash from operations as the first means of financing these projects, the Company may issue short-term debt as necessary during fiscal 2016 to help meet its capital expenditures needs. The level of short-term borrowings will depend upon the amounts of cash provided by operations, which, in turn, will likely be impacted by natural gas and crude oil prices combined with production from existing wells.  As disclosed above, the Company expects to be precluded from issuing new long-term debt until the third quarter of fiscal 2017 as a means of financing projects. Given the current commodity price environment, the Company expects to record additional significant ceiling test impairments during both of the remaining quarters of fiscal 2016. An impairment is also possible in the first quarter of fiscal 2017. The significant impairments could preclude the Company from issuing incremental long-term debt throughout much of fiscal 2017. However, the Company does not anticipate a need for the issuance of additional long-term debt during either fiscal 2016 or fiscal 2017.

The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, natural gas storage facilities and the expansion of natural gas transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.

Financing Cash Flow

The Company had no consolidated short-term debt outstanding at March 31, 2016 and September 30, 2015. The maximum amount of short-term debt outstanding during the six months ended March 31, 2016 was $62.4 million. While the Company did not have any outstanding commercial paper and short-term notes payable to banks at March 31, 2016, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt.

On December 5, 2014, the Company entered into an Amended and Restated Credit Agreement with a syndicate of 14 banks. The agreement replaced the Company's previous $750.0 million committed credit facility with a substantially similar facility totaling $750.0 million. On September 30, 2015, the Company entered into a Second Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of the same 14 banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through December 5, 2019, plus a $500.0 million 364-day unsecured committed revolving credit facility through September 29, 2016. The Company also has a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under the uncommitted lines of credit are made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines.

The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through December 5, 2019. At March 31, 2016, the Company’s debt to capitalization ratio (as calculated under the facility) was .56. The constraints specified in the Credit Agreement would have permitted an additional $928.0 million in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.

A downgrade in the Company's credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources, including cash provided by operations.

The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any

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principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of March 31, 2016, the Company did not have any debt outstanding under the Credit Agreement.

None of the Company’s long-term debt at March 31, 2016 and 2015 had a maturity date within the following twelve-month period.

The Company’s embedded cost of long-term debt was 5.53% and 5.61% at March 31, 2016 and March 31, 2015, respectively.

Under the Company’s existing indenture covenants, at March 31, 2016, the Company expects to be precluded from issuing additional long-term unsecured indebtedness until the third quarter of fiscal 2017 as a result of impairments of its oil and gas properties recognized during the year ended September 30, 2015 and the six months ended March 31, 2016, as discussed above. The 1974 indenture would not preclude the Company from issuing new indebtedness to replace maturing debt. If the Company experiences additional impairments of its oil and gas properties in the third and fourth quarters of fiscal 2016, and possibly the first quarter of fiscal 2017, the Company, under its 1974 indenture, expects to continue to be precluded from issuing incremental long-term debt throughout much of fiscal 2017. However, the Company expects that it could borrow under its credit facilities. The Company's present liquidity position is believed to be adequate to satisfy known demands. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

The Company’s 1974 indenture pursuant to which $98.6 million (or 4.7%) of the Company’s long-term debt (as of March 31, 2016) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

OFF-BALANCE SHEET ARRANGEMENTS

The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Exploration and Production segment and Corporate operations, having a remaining lease commitment of approximately $32.6 million. These leases have been entered into for the use of compressors, drilling rigs, buildings, meters and other items and are accounted for as operating leases.  

OTHER MATTERS

In addition to the legal proceedings disclosed in Part II, Item 1 of this report, 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 or 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 normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company's present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

During the six months endedMarch 31, 2016, the Company contributed $4.0 million to its Retirement Plan and $1.8 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits.  In the remainder of 2016, the Company does not expect to make any additional contributions to the Retirement Plan.  In the remainder of 2016, the Company expects to contribute $0.8 million to its VEBA trusts and 401(h) accounts.

Market Risk Sensitive Instruments

On July 21, 2010, the Dodd-Frank Act was signed into law.  The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets.  Certain provisions of the Dodd-Frank Act related to derivatives became effective July 16, 2011, but other provisions related to derivatives have or will become effective as federal agencies (including the CFTC, various banking regulators and the SEC) adopt rules to implement the law.  Among other things, the Dodd-Frank Act (1) regulates certain participants in the swaps markets, including new entities defined as “swap dealers” and “major swap participants,” (2) requires

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clearing and exchange-trading of certain swaps that the CFTC determines must be cleared, (3) requires reporting and recordkeeping of swaps, and (4) enhances the CFTC’s enforcement authority, including the authority to establish position limits on derivatives and increases penalties for violations of the Commodity Exchange Act.  For purposes of the Dodd-Frank Act, under rules adopted by the SEC and/or CFTC, the Company believes that it qualifies as a non-financial end user of derivatives, that is, as a non-financial entity that uses derivatives to hedge or mitigate commercial risk.  Nevertheless, other rules that have been adopted or are being developed could have a significant impact on the Company.  For example, the CFTC has imposed numerous registration, swaps documentation, business conduct, reporting, and recordkeeping requirements on swap dealers and major swap participants, which frequently are counterparties to the Company’s derivative hedging transactions. While many of the final rules adopted by the CFTC and other regulators place specific conditions on the operations of swap dealers and major swap participants, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from the final and proposed rules through higher transaction costs and prices or other direct or indirect costs. For example, the Dodd-Frank Act requires that certain swaps be cleared and traded on exchanges or swap execution facilities, with certain exceptions for swaps that end-users such as the Company use to hedge or mitigate commercial risk. While the Company expects to be excluded from these clearing and trading requirements for swaps used to hedge its commercial risks, there may be increased transaction costs or decreased liquidity with respect to entering into such uncleared and non-exchange traded swaps. Also, during the fourth calendar quarter of 2015, the bank regulators and the CFTC, respectively, adopted final margin rules that apply to swap dealers and major swap participants with respect to uncleared swaps. While these rules do not impose a requirement on swap dealers and major swap participants to collect margin for uncleared swaps from non-financial end users such as the Company, the obligations may increase the costs of uncleared swaps. For example, among other things, to fulfill obligations imposed on them under the rules, swap dealers may seek to negotiate collateral or other credit arrangements in their swap agreements with counterparties, which would increase the cost of transactions in uncleared swaps.  The Dodd-Frank Act may also increase costs for derivative recordkeeping, reporting, documentation, position limit compliance, and other compliance; cause parties to materially alter the terms of derivative contracts; cause parties to restructure certain derivative contracts; reduce the availability of derivatives to protect against risks that the Company encounters or to optimize assets; reduce the Company’s ability to monetize or restructure existing derivative contracts; and increase the Company’s exposure to less creditworthy counterparties, all of which could increase the Company’s business costs.  The Company continues to monitor these developments but cannot predict the impact the Dodd-Frank Act may ultimately have on its operations.

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 March 31, 2016, 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 a complete discussion of market risk sensitive instruments, refer to "Market Risk Sensitive Instruments" in Item 7 of the Company's 2015 Form 10-K.  There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.

Rate and Regulatory Matters

Utility Operation

Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” Although the Pennsylvania division does not have a rate case on file, see below for a description of the current rate proceedings affecting the New York division.  In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.

New YorkJurisdiction

Customer delivery rates charged by Distribution Corporation’s New York division were established in a rate order issued on December 21, 2007 by the NYPSC.  In connection with an efficiency and conservation program, the rate order approved a revenue decoupling mechanism. The revenue decoupling mechanism “decouples” revenues from throughput by enabling the Company to collect from small volume customers its allowed margin on average weather normalized usage per customer. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation.

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Following negotiations and other proceedings, on December 6, 2013, Distribution Corporation filed an agreement, also executed by the Department of Public Service and intervenors, extending existing rates through, at a minimum, September 30, 2015. Although customer rates were not changed, the parties agreed that the allowed rate of return on equity would be set, for ratemaking purposes, at 9.1%.  Following conventional practice in New York, the agreement authorizes an “earnings sharing mechanism” (“ESM”).  The ESM distributes earnings above the allowed rate of return as follows: from 9.5% to 10.5%, 50% would be allocated to shareholders, and 50% will be deferred for the benefit of customers; above 10.5%, 20% to shareholders and 80% will be deferred for the benefit of customers.  The agreement further authorizes, and rates reflect, an increase in Distribution Corporation’s pipeline replacement spending by $8.2 million per year of the agreement.  The agreement contains other terms and conditions of service that are customary for settlement agreements recently approved by the NYPSC.  A $7.5 million ($4.9 million after-tax) refund provision was passed back to customers during 2014 after the NYPSC approved the settlement agreement without modification in an order issued on May 8, 2014. All significant terms of the agreement, including existing rates, continue in effect beyond September 30, 2015 until modified by the NYPSC. The agreement also states that nothing in the agreement precludes the parties from meeting to discuss extending the agreement on mutually acceptable terms, and presenting such extension to the NYPSC for approval. On May 22, 2015, Distribution Corporation filed with the NYPSC a Notice of Impending Settlement Discussions stating that settlement discussions would be scheduled in the near future, and that such discussions might include, among other things, the possible extension of the agreement on mutually acceptable terms, and on October 21, 2015, Distribution Corporation filed with the NYPSC a Supplemental Notice of Impending Settlement Discussions.

Settlement discussions did not lead to a settlement and, on April 28, 2016, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by approximately $41.7 million. Distribution Corporation explained in the filing that its request for rate relief was necessitated by a revenue requirement driven primarily by rate base growth, higher operating expense and higher depreciation expense that are not reflected in current rates, among other things. The rate filing includes a proposal for system infrastructure modernization that includes the acceleration of Distribution Corporation’s replacement of certain gas mains, which are of a type generically classified by the NYPSC as “leak prone pipe”. The NYPSC may accept, reject or modify the Company’s filing. Assuming standard procedure, new rates, if accepted, would become effective on or about April 1, 2017. The outcome of the proceeding cannot be ascertained at this time.

In an unrelated action, on February 23, 2016 the NYPSC issued an Order Resetting Retail Energy Markets and Establishing Further Process, in which the NYPSC states it is taking action to address certain unfair business practices currently found in the energy services industry and to ensure residential and small non-residential commercial customers are receiving value from the retail energy markets (“Resetting Order”). Distribution Corporation and NFR are carefully monitoring industry impacts stemming from the Resetting Order, which may result in the migration of a significant number of residential and small non-residential customers back to Distribution Corporation as the provider of last resort.

Pennsylvania Jurisdiction

Distribution Corporation’s current delivery charges in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007.

Pipeline and Storage

Supply Corporation's current rate settlement requires a rate case filing no later than December 31, 2019 and prohibits any party from seeking to initiate a rate case proceeding before September 30, 2017.

Empire does not have a rate case currently on file with the FERC, but by order dated January 21, 2016, the FERC began a NGA Section 5 rate review of Empire's rates. As required by that order, Empire filed a Cost and Revenue Study on April 5, 2016. Pursuant to the Procedural Schedule, discovery began April 6, 2016, with a hearing scheduled to commence on November 8, 2016.

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 comply with regulatory requirements. 

For further discussion of the Company's environmental exposures, refer to Item 1 at Note 6 — Commitments and Contingencies under the heading “Environmental Matters.”

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Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. In the United States, these efforts include legislative proposals and EPA regulations at the federal level, actions at the state level, and private party litigation related to greenhouse gas emissions. While the U.S. Congress has from time to time considered legislation aimed at reducing emissions of greenhouse gases, Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA is regulating greenhouse gas emissions pursuant to the authority granted to it by the federal Clean Air Act. For example, in April 2012, the EPA adopted rules which restrict emissions associated with oil and natural gas drilling. In 2015, the EPA proposed new rules regulating methane and volatile organic compound emissions from new or modified oil and gas emissions sources. If adopted as proposed, these new rules would impose more stringent leak detection and repair requirements, and would further address reporting and control of methane and volatile organic compound emissions. In addition, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. With respect to its operations in California, the Company currently complies with California cap-and-trade guidelines, which increases the Company's cost of environmental compliance in its Exploration and Production segment operations. Legislation or regulation that aims to reduce greenhouse gas emissions could also include carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Federal, state or local governments may, for example, provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. These climate change and greenhouse gas initiatives could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, impose additional monitoring and reporting requirements, and reduce demand for oil and natural gas. But legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

New Authoritative Accounting and Financial Reporting Guidance

For discussion of the recently issued authoritative accounting and financial reporting guidance, refer to Item 1 at Note 1 — Summary of Significant Accounting Policies under the heading “New Authoritative Accounting and Financial Reporting Guidance.”

Safe Harbor for Forward-Looking Statements

The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

1. Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;

2. Changes in the price of natural gas or oil;

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3. Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;

4. Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;

5. Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations;

6. Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing;

7. Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal;

8. Changes in price differential between similar quantities of natural gas or oil at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations;

9. Other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date;

10. The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;

11. Uncertainty of oil and gas reserve estimates;

12. Significant differences between the Company’s projected and actual production levels for natural gas or oil;

13. Changes in demographic patterns and weather conditions;

14. Changes in the availability, price or accounting treatment of derivative financial instruments;

15. Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;

16. The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;

17. Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation;

18. Significant differences between the Company’s projected and actual capital expenditures and operating expenses;

19. Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;

20. Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or

21. Increasing costs of insurance, changes in coverage and the ability to obtain insurance.

The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Refer to the "Market Risk Sensitive Instruments" section in Item 2 – MD&A.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act.  These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.  The Company's management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report.  Based upon that evaluation, the Company's Chief Executive Officer and Principal Financial Officer concluded that the Company's disclosure controls and procedures were effective as of March 31, 2016.   

Changes in Internal Control Over Financial Reporting

In May 2016, Distribution Corporation plans to implement SAP Customer Relationship and Billing as its new customer information and billing system.  This system change is a result of an evaluation of the capability of the legacy CIS (Customer Information System) used to support the evolving needs of the Utility segment and is not the result of any actual or perceived deficiency in the current system.  This implementation may result in certain changes to Distribution Corporation’s processes and internal controls impacting financial reporting.  While there are inherent risks involved with the implementation of any new system, management believes that it is adequately monitoring and managing the transition, and adequately testing the system prior to implementation.

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended March 31, 2016 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II.  Other Information

Item 1. Legal Proceedings

For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 6 — Commitments and Contingencies, and Part I, Item 2 - MD&A of this report under the heading “Other Matters – Environmental Matters.”

For a discussion of certain rate matters involving the NYPSC, refer to Part I, Item 1 of this report at Note 9 — Regulatory Matters.

Item 1A. Risk Factors

The risk factors in Item 1A of the Company’s 2015 Form 10-K, as amended by Item 1A of Part II of the Company's Form 10-Q for the quarter ended December 31, 2015, have not materially changed other than as set forth below. The risk factors presented below supersede the risk factors having the same captions in the 2015 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2015 Form 10-K and the December 31, 2015 Form 10-Q.

The Company is dependent on capital and credit markets to successfully execute its business strategies.

The Company relies upon short-term bank borrowings, commercial paper markets and longer-term capital markets to finance capital requirements not satisfied by cash flow from operations. The Company is dependent on these capital sources to provide capital to its subsidiaries to fund operations, acquire, maintain and develop properties, and execute growth strategies. The availability and cost of credit sources may be cyclical and these capital sources may not remain available to the Company. Turmoil in credit markets may make it difficult for the Company to obtain financing on acceptable terms or at all for working capital, capital expenditures and other investments, or to refinance maturing debt on favorable terms. These difficulties could adversely affect the Company's growth strategies, operations and financial performance. The Company's ability to borrow under its credit facilities and commercial paper agreements, and its ability to issue long-term debt under its indentures, depend on the Company's compliance with its obligations under the facilities, agreements and indentures. Under the Company’s 1974 indenture, the Company has been precluded since October 1, 2015 from issuing incremental long-term debt as a result of impairments (i.e., write-downs) of its oil and gas properties. Given the impairments recognized through March 31, 2016, the Company expects to be precluded from issuing incremental long-term debt through March 2017, absent amendment or waiver by existing noteholders of a covenant

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in the 1974 indenture. Additionally, the Company expects to record additional impairments of its oil and gas properties in the third and fourth quarters of fiscal 2016, and possibly the first quarter of fiscal 2017, which could preclude the Company from issuing incremental long-term debt throughout much of fiscal 2017. The 1974 indenture would not preclude the Company from issuing new long-term debt to replace maturing long-term debt.

In addition, the Company's short-term bank loans are in the form of floating rate debt or debt that may have rates fixed for very short periods of time, resulting in exposure to interest rate fluctuations in the absence of interest rate hedging transactions. The cost of long-term debt, the interest rates on the Company's short-term bank loans and the ability of the Company to issue commercial paper are affected by its debt credit ratings published by S&P, Moody's Investors Service, Inc. and Fitch Ratings. A downgrade in the Company's credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets.

Financial accounting requirements regarding exploration and production activities are expected to negatively affect the Company's profitability.

The Company accounts for its exploration and production activities under the full cost method of accounting. Each quarter, the Company must perform a "ceiling test" calculation, comparing the level of its unamortized investment in oil and natural gas properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses a 12-month historical average price for oil and natural gas (based on first day of the month prices and adjusted for hedging). If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be "impaired," and the full cost accounting rules require that the investment must be written down to the calculated net present value. Such an instance would require the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be material. For the fiscal year ended September 30, 2015, the Company recognized pre-tax impairment charges on its oil and natural gas properties of $1.1 billion. For the six-months ended March 31, 2016, the Company recognized a pre-tax impairment charge on its oil and natural gas properties of $832.9 million. Given the potential that oil and natural gas prices could stay at low levels in future months, and the expected loss of significantly higher prices from the 12-month historical average that will be used in the ceiling test for the remaining quarters of fiscal 2016, the Company expects to experience additional significant ceiling test impairments in each of those quarters (the third and fourth quarters of fiscal 2016). An impairment is also possible in the first quarter of fiscal 2017.

Environmental regulation significantly affects the Company’s business.

The Company’s business operations are subject to federal, state, and local laws and regulations relating to environmental protection. These laws and regulations concern the generation, storage, transportation, disposal, emission or discharge of pollutants, contaminants, hazardous substances and greenhouse gases into the environment, the reporting of such matters, and the general protection of public health, natural resources, wildlife and the environment. For example, currently applicable environmental laws and regulations restrict the types, quantities and concentrations of materials that can be released into the environment in connection with regulated activities, limit or prohibit activities in certain protected areas, and may require the Company to investigate and/or remediate contamination at certain current and former properties regardless of whether such contamination resulted from the Company’s actions or whether such actions were in compliance with applicable laws and regulations at the time they were taken. Moreover, spills or releases of regulated substances or the discovery of currently unknown contamination could expose the Company to material losses, expenditures and environmental, health and safety liabilities. Such liabilities could include penalties, sanctions or claims for damages to persons, property or natural resources brought on behalf of the government or private litigants that could cause the Company to incur substantial costs or uninsured losses.

In addition, the Company must obtain, maintain and comply with numerous permits, leases, approvals, consents and certificates from various governmental authorities before commencing regulated activities. In connection with such activities, the Company may need to make significant capital and operating expenditures to detect, repair and/or control air emissions, to control water discharges or to perform certain corrective actions to meet the conditions of the permits issued pursuant to applicable environmental laws and regulations. Any failure to comply with applicable environmental laws and regulations and the terms and conditions of its environmental permits and authorizations could result in the assessment of significant administrative, civil and/or criminal penalties, the imposition of investigatory or remedial obligations and corrective actions, the revocation of required permits, or the issuance of injunctions limiting or prohibiting certain of the Company’s operations.

Costs of compliance and liabilities could negatively affect the Company’s results of operations, financial condition and cash flows. In addition, compliance with environmental laws and regulations could require unexpected capital expenditures at the Company’s facilities, temporarily shut down the Company’s facilities or delay or cause the cancellation of expansion projects or oil and natural gas drilling activities. Because the costs of complying with environmental regulations are significant, additional regulation could negatively affect the Company’s business. Although the Company cannot predict the impact of the interpretation

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or enforcement of EPAstandards or other federal, state and local laws or regulations, the Company’s costs could increase if environmental laws and regulations change.

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. Under the Federal Clean Air Act, the EPA requires that new stationary sources of significant greenhouse gas emissions or major modifications of existing facilities obtain permits covering such emissions. The EPA recently proposed, and is expected to finalize, regulations that will set methane emissions standards for new oil and natural gas emission sources. In addition, the EPA issued draft guidelines for voluntarily reducing emissions from existing equipment and processes in the oil and natural gas industry. Although the EPA’s proposed rules are primarily directed at new or modified oil and gas emission sources, the EPA is moving toward the regulation of emissions from existing sources as well. In addition, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. With respect to its operations in California, the Company currently complies with California cap-and-trade guidelines, which increases the Company’s cost of environmental compliance in its Exploration and Production segment operations. Legislation or regulation that aims to reduce greenhouse gas emissions could also include carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Federal, state or local governments may, for example, provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. These climate change and greenhouse gas initiatives could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, impose additional monitoring and reporting requirements, and reduce demand for oil and natural gas.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On January 4, 2016, the Company issued a total of 4,200 unregistered shares of Company common stock to seven non-employee directors of the Company then serving on the Board of Directors of the Company, 600 shares to each such director. On March 16, 2016, the Company issued 138 unregistered shares of Company common stock to David F. Smith, a non-employee director of the Company. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended March 31, 2016.  These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as transactions not involving a public offering.

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased (a)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs (b)
Jan. 1 - 31, 2016	184	$45.11	—	6,971,019
Feb. 1 - 29, 2016	10,362	$45.97	—	6,971,019
Mar. 1 - 31, 2016	154	$50.79	—	6,971,019
Total	10,700	$46.03	—	6,971,019

^(a)  Represents shares of common stock of the Company tendered to the Company by holders of stock options, SARs, restricted stock units or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes.  During the quarter ended March 31, 2016, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program.    

^(b)  In September 2008, the Company’s Board of Directors authorized the repurchase of eight million shares of the Company’s common stock.  The repurchase program has no expiration date.  The Company, however, stopped repurchasing shares after September 17, 2008. Since that time, the Company has increased its emphasis on Marcellus Shale development and pipeline expansion. As such, the Company does not anticipate repurchasing any shares in the near future.

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Item 6. Exhibits

Exhibit Number	Description of Exhibit
•	National Fuel Gas Company By-Laws as amended March 10, 2016 (Exhibit 3.1, Form 8-K dated March 16, 2016).
10.1	Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated effective January 1, 2016.
10.2	National Fuel Gas Company 2009 Non-Employee Director Equity Compensation Plan, as amended and reapproved March 10, 2016.
12	Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the Twelve Months Ended March 31, 2016 and the Fiscal Years Ended September 30, 2012 through 2015.
31.1	Written statements of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act.
31.2	Written statements of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act.
32••	Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99	National Fuel Gas Company Consolidated Statements of Income for the Twelve Months Ended March 31, 2016 and 2015.
101	Interactive data files submitted pursuant to Regulation S-T: (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the three and six months ended March 31, 2016 and 2015, (ii) the Consolidated Statements of Comprehensive Income for the three and six months ended March 31, 2016 and 2015, (iii) the Consolidated Balance Sheets at March 31, 2016 and September 30, 2015, (iv) the Consolidated Statements of Cash Flows for the six months ended March 31, 2016 and 2015 and (v) the Notes to Condensed Consolidated Financial Statements.

•   Incorporated herein by reference as indicated.

••  In accordance with Item 601(b)(32)(ii) of Regulation S-K and SEC Release Nos. 33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

NATIONAL FUEL GAS COMPANY

(Registrant)

/s/ D. P. Bauer

D. P. Bauer

Treasurer and Principal Financial Officer

/s/ K. M. Camiolo

K. M. Camiolo

Controller and Principal Accounting Officer

Date:  May 4, 2016

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EX-10.1

Exhibit 10.1

Administrative Rules

of the

Compensation Committee

of the

Board of Directors

of

National Fuel Gas Company

As amended and restated

effective January 1, 2016

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TABLE OF CONTENTS

I.	Meetings					1
II .	Quorum and Voting; Delegation					2
III .	Grants and Awards Under the Plans					2
	A.	General Rules Regarding Awards Under the 1997 and 2010 Plans				3
		1.	Making of An Award			3
		2.	Contemporaneous Awards			3
		3.	Stock-Based Awards			3
			a.	Source		3
			b.	Cash Dividends and Cash Dividend Equivalents		3
				i.	Stock Based Awards Other Than Restricted Stock	3
				ii.	Restricted Stock Awards	4
			c.	Payment		4
		4.	Withholding Taxes			4
		5.	Deferral of Payment			5
	B.	Stock Options Under the 1997 and 2010 Plans				6
		1.	Designation			6
		2.	Price			6
		3.	Exercise Period/Duration			6
			a.	Non-Qualified Stock Options		6
			b.	Incentive Stock Options		7
		4.	Death or Other Termination of Employment			7
			a.	Definitions		7
			b.	Non-Qualified Stock Options Under the 1997 Plan		7
		5.	Mechanics of Exercise			8
		6.	Reload Options			8
	C.	SARs Under the 1997 or 2010 Plan				8
	D.	Restricted Stock, Restricted Stock Units and Performance Shares Under the 1997 and 2010 Plans				9
		1.	Restrictions on Transferability; Vesting			9
		2.	Mechanics of Grant			9
	E.	Suspension of Exercisability or Payment of Awards				10

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		1.	Authority to Suspend	10
		2.	Delegation of Authority	10
IV .	Procedures For Exercising Stock Options and SARs			11
	A.	Authority and Scope		11
	B.	Notice of Exercise		11
		1.	Form and Delivery	11
		2.	Exercise Date	11
	C.	Payment of Exercise Price		12
		1.	Cash Payment	12
		2.	Payment with Existing Company Stock	12
		3.	Additional Time to Pay Exercise Price	13
		4.	Cashless Exercise	14
	D.	Restrictions Relating to Possession of Material Nonpublic Information		14

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ADMINISTRATIVE

RULES OF THE

COMPENSATION COMMITTEE

OF THE

BOARD OF DIRECTORS

OF

NATIONAL FUEL GAS COMPANY

As amended and restated

effective January 1, 2016

I.    MEETINGS

Each meeting ("Meeting") of the Compensation Committee ("Committee") of the Board of Directors of National Fuel Gas Company ("Company") shall be held as indicated in a notice made in accordance with these rules. Notice of each Meeting, stating the place, date and hour thereof, shall be given to each member of the Committee ("Member") by e-mailing, faxing, telephoning or personally delivering the same to him at least one day before the meeting, if there is no reason to believe it was not received, or by mailing the same to him at least five days before the Meeting, in all cases to the Member’s last known address or addresses as the same appears upon the records of the Company. All such notices shall be effective when sent, including the leaving of a message recorded at, or spoken to any individual answering, the Member’s designated telephone number(s). The attendance of any Member at a Meeting without protesting prior to the end of the Meeting the lack of notice of such meeting shall constitute a waiver of notice by that Member.

Any one or more Members of the Committee may participate in a Meeting by means of a conference telephone or similar equipment. Participation by such means shall constitute presence in person at a Meeting.

The Committee may also take action by unanimous written consent.

II.    QUORUM AND VOTING; DELEGATION

At all Meetings, a quorum shall be required for the transaction of business and shall consist of a majority of the entire Committee. The majority vote of the Members at a Meeting at which a quorum is present shall decide any question that may come before the meeting.

Consistently with limitations imposed by the Plans (as defined below), the Committee may delegate in these rules or by resolution any or all of its authority to the Chief Executive Officer, to the Secretary and to any other officer of the Company (individually, "Delegate"), so long as the Delegate has no potential conflict of interest which would cause him or her not to exercise his or her good faith independent business judgment in respect of a delegated matter. Subject to such limitations, the Committee hereby delegates the power to implement its decisions to appropriate officers of the Company.

III.    GRANTS AND AWARDS UNDER THE PLANS

The following rules and regulations shall apply with respect to grants and awards made under the Company's 1997 Award and Option Plan ("1997 Plan") or the Company's 2010 Equity Compensation Plan ("2010 Plan") (as amended, each individually a "Plan;" together the "Plans"), including without limitation grants and awards of stock options, stock appreciation rights ("SARs"), shares of restricted stock ("Restricted Stock"), restricted stock units ("Restricted Stock Units") and performance shares (“Performance Shares”).

Any capitalized term not defined in these rules shall have the same meaning as in the applicable Plan. The following rules are intended to supplement the Plans and, to the extent that any rule is determined to be inconsistent with any Plan, the Plan shall control.

These rules may be amended by the Committee at any time and from time to time. Except to the extent otherwise specified in the particular Award Notice or at the time these rules

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are amended, any grant or award under the Plans shall be subject to these rules as in effect on the date of the grant or award.

A. GENERAL RULES REGARDING AWARDS UNDER THE 1997 AND 2010 PLANS

1.    Making of An Award

An Award within the meaning of these rules occurs upon the grant by the Committee of any stock option, SAR, Restricted Stock, Restricted Stock Unit, Performance Share or other Award under a Plan. An Award Notice within the meaning of these rules means a written notice from the Company to a Participant (including a notice provided to the recipient in an electronic form or by a link to cite of the notice) that sets forth the terms and conditions of an Award in addition to those conditions established in the applicable Plan and by the Committee's exercise of its administrative powers.

2.    Contemporaneous Awards

Unless the Committee shall otherwise expressly provide at the time of grant, an Award of one type granted contemporaneously with an Award of any other type shall be treated as having been granted in combination, and not in the alternative, with the Award of the other type.

3.    Stock-based Awards

a.    Source. Stock-based Awards, to the extent actually paid in Common Stock, shall reduce treasury shares (if any) first and thereafter authorized but unissued shares.

b.    Cash Dividends and Cash Dividend Equivalents.

(i) Stock-Based Awards Other Than Restricted Stock. No stock-based Award other than Restricted Stock carries with it the entitlement to receive cash

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dividends or cash dividend equivalents until such stock-based Award is exercised (in the case of a stock option or stock-settled SAR) or earned (in the case of an RSU, Performance Share or other stock-based Award). If a stock-based Award is exercised or earned prior to or on the record date for determination of stockholders entitled to receive a cash dividend, then such stock-based Award or the securities resulting from the exercise thereof, as the case may be, shall be entitled to receive such cash dividend (or, if the shares related thereto have not been issued as of the record date, to receive a dividend equivalent in respect thereof).

(ii) Restricted Stock Awards. Notwithstanding clause (i) of this paragraph (b) or Section 24 of the 1997 Plan or Section 14(e) of the 2010 Plan, dividends shall be payable with respect to each outstanding Award of Restricted Stock whether or not the restrictions in such Award have been satisfied or have lapsed.

c.    Payment. Payment of stock-based Awards shall be made with Common Stock.

4.    Withholding Taxes

At the time a Participant is taxable with respect to stock options, SARs, Restricted Stock, Restricted Stock Units, Performance Shares or other Awards granted under the Plans, or the exercise or surrender of the same, the Company (or, if applicable, an employer other than the Company) shall have the right to withhold from amounts payable to the Participant under the Plan or from other compensation payable to the Participant in its sole discretion, or require the Participant to pay to it, an amount sufficient to satisfy all federal, state and/or local (including foreign) withholding tax requirements. With respect to the vesting of Restricted Stock and the vesting (and settlement in shares of Common Stock) of Restricted Stock Units and Performance Shares, the Company shall withhold from amounts payable to the Participant a number of whole shares of Common Stock sufficient to satisfy all federal, state and/or local (including foreign) withholding tax requirements, provided that the Participant may, at a time

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when he or she is not in possession of material nonpublic information relating to the Company and not subject to any quarterly or other “blackout period” imposed under the Company’s Policy on Insider Trading in National Fuel Gas Company Securities, elect to pay such tax withholding amounts in cash. With respect to the exercise of stock options or SARs, the Participant may, subject to Section IV(D) below, pay tax withholding amounts by requesting that the Company withhold from the amounts owed to the Participant a number of whole shares of Common Stock sufficient to satisfy all federal, state and/or local (including foreign) withholding tax requirements, or by delivering as payment to the Company a number of whole shares of Common Stock sufficient to satisfy such withholding tax requirements. Notwithstanding anything to the contrary herein, to the extent that any tax withholding is satisfied by the Company’s withholding and/or canceling any shares of Common Stock, the Fair Market Value of the Common Stock withheld and/or canceled may not exceed the amount required to be withheld at law by more than the value of a fraction of one share of Common Stock.

5.    Deferral of Payment

The Committee intends to permit Participants to elect, at such time or times as the Committee shall permit, to defer the receipt of payment of Awards that are payable in cash; provided, however, that (1) under the then applicable income tax rules the Participant is not in constructive receipt of, and subject to income tax on, the payment prior to its actual receipt, (2) such deferral does not result in any of the Plans being subject to the Employee Retirement Income Security Act of 1974, as amended, (3) if the Participant is an Executive Officer (i.e., is subject to Section 16 of the Securities Exchange Act of 1934, including a retired officer who is, at the relevant time, a director), such election shall comply with Rule 16b-3 promulgated pursuant to the Securities Exchange Act of 1934, as then in effect, and (4) such election would not result in the imposition of an additional tax under Section 409A of the Code

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on the Participant. The Committee hereby delegates to the Chief Executive Officer, President, Treasurer, Secretary and General Counsel of the Company, and each of them, the Committee’s authority to establish the time or times at which deferral elections may be permitted in respect of any Award.

B.    STOCK OPTIONS UNDER THE 1997 AND 2010 PLANS

1.    Designation

The Award Notice setting forth the terms and conditions of a grant of a stock option shall indicate the applicable Plan under which the stock option is granted and whether the stock option is an incentive stock option (within the meaning of Section 422 of the Code, an “ISO”) or a non-qualified stock option (“NSO”). The Committee hereby delegates to the Chief Executive Officer, President, Treasurer, Secretary and General Counsel of the Company, and each of them, the authority to prepare, execute and deliver Award Notices consistent with actions taken by the Committee. The Committee hereby directs that any action taken by the Committee granting stock options without specifying whether the stock options are ISOs be interpreted as follows: an award of stock options under the 1997 Plan or the 2010 Plan shall be deemed to be awards of NSOs only.

2.    Price

The price at which Common Stock may be purchased upon exercise of a stock option (the “exercise price”) shall be the Fair Market Value of the Common Stock on the date of the Award.

3.    Exercise Period/Duration

a.    Non-Qualified Stock Options. Except as may otherwise be expressly provided in the Plan or in Section III(B)(4) of these rules, a non-qualified stock option first may be exercised twelve months after the date of grant.

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b.    Incentive Stock Options. Except as may otherwise be expressly provided in the Plan, an ISO first may be exercised twelve months after the date of grant, or, if earlier, on the date of the optionee's death.

4.    Death or Other Termination of Employment

a.    Definitions. For purposes of these rules, the following terms shall have the following meanings:

(i)    For purposes of the 1997 Plan, "Disability" shall mean that the Participant is eligible to receive disability benefits under Article 3 of The National Fuel Gas Company Retirement Plan ("Retirement Plan"), as from time to time amended, or that the Participant would be eligible to receive such benefits if he or she were a participant in the Retirement Plan.

(ii)    "Subsidiary" shall mean a corporation or other business entity in which the Company directly or indirectly has an ownership interest of fifty percent (50%) or more.

b.    Non-Qualified Stock Options Under the 1997 Plan. All NSOs outstanding under the 1997 Plan are currently exercisable.

(i)    If termination of employment occurs by reason of death, each NSO awarded under the 1997 Plan shall remain exercisable for five years from such termination or the balance of its unexpired term, whichever is less.

(ii)    If termination of employment occurs by reason of discharge by the Company for cause, or voluntary resignation of the Participant prior to age 60, each NSO awarded under the 1997 Plan shall lapse unless extended by the Committee in its discretion.

(iii)    If termination of employment occurs by reason of voluntary resignation (including retirement) at or after age 60, by reason of Disability, or for any other

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reason, each NSO awarded under the 1997 Plan shall remain exercisable for five years from such termination (or such greater period as the Committee deems appropriate) or the balance of its unexpired term, whichever is less.

5.    Mechanics of Exercise

To exercise a stock option, the Participant shall provide a signed exercise notice to an appropriate officer or other designee of the Company, which notice shall indicate which stock options are being exercised, how the exercise price is to be paid and any other appropriate information. Appropriate delivery of a signed notice of exercise binds the Participant to pay the exercise price. Part IV of these rules contains procedures for exercising stock options.

6.    Reload Options

No optionee shall be issued a new stock option automatically upon exercise of a stock option. However, if the Award Notice provides for the issuance of such new stock option, the new stock option shall have an exercise price equal to the Fair Market Value of the Common Stock on the date the new stock option is issued and shall otherwise be subject, as nearly as possible, to the same terms and conditions as the exercised stock option.

C.     SARs UNDER THE 1997 OR 2010 PLAN

The base price or grant price of a SAR shall be the Fair Market Value of the Common Stock on the date of the grant of the SAR. Each SAR shall otherwise be subject to the terms and conditions imposed (i) by the Award Notice upon the SAR, (ii) by the applicable Plan, and (iii) by these rules upon SARs and NSOs, as applicable. A SAR shall be outstanding and exercisable during the entire exercise period otherwise applicable to an NSO if the NSO had been granted on the same day as the SAR (as adjusted in accordance with Section III(B)(4) above in the event of death or other termination of employment). All SARs outstanding under the 1997 Plan are currently exercisable.

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To exercise a SAR, the Participant shall deliver a signed exercise notice to an appropriate officer or other designee of the Company, which notice shall indicate which SARs are being exercised, and any other appropriate information. Part IV of these rules contains procedures for exercising SARs. Any SAR not already exercised shall be deemed to be exercised at the close of business on the scheduled expiration date of such SAR, if at such time the SAR by its terms remains exercisable and, if so exercised, would result in a payment to the holder of such SAR. If upon any such deemed exercise the payment to the holder of such SAR is to be made in shares of Common Stock, the holder of such SAR shall be deemed to have elected to pay the minimum required tax withholding in shares of Common Stock.

D. RESTRICTED STOCK, RESTRICTED STOCK UNITS AND PERFORMANCE SHARES UNDER THE 1997 AND 2010 PLANS

1.    Restrictions on Transferability; Vesting

The restrictions on transferability and vesting and all other terms and conditions of Restricted Stock, Restricted Stock Units and Performance Shares granted under either the 1997 Plan or the 2010 Plan shall be specified in the Award Notice. Except as otherwise provided in the applicable Plan, all shares of Restricted Stock and all Restricted Stock Units and Performance Shares shall be subject to the Participant's continued employment with the Company or a Subsidiary until vesting. The Committee may accelerate the vesting of Restricted Stock, Restricted Stock Units or Performance Shares on its own motion as it deems appropriate and in the best interests of the Company.

2.    Mechanics of Grant

The Committee hereby delegates to appropriate officers of the Company the authority to establish and revise appropriate procedures with respect to the issuance of shares

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of Restricted Stock (whether represented by certificates or issued in book entry form) and the payment of dividends thereon.

E.    SUSPENSION OF EXERCISABILITY OR PAYMENT OF AWARDS

1.    Authority to Suspend

The Committee may, among other things, suspend or limit the exercisability or the payment of any Award under either Plan during any period:

(a)    for which counsel for the Company advises in writing that exercise or payment of such Award would violate federal or state securities laws or other applicable laws, rules, regulations, judgments, or orders; or

(b)    during which management is investigating an allegation that the Participant has engaged in any act which would permit the Committee to forfeit the Participant’s Award pursuant to Section 18 of the 1997 Plan or Section 14(c) of the 2010 Plan.

Suspension of the payment of any Award may include, without limitation, suspension of the lapse of any restrictions on Restricted Stock and suspension of the expiration of any Restricted Period.

2.    Delegation of Authority

The Committee hereby delegates to the Chief Executive Officer, President, Treasurer, Secretary and General Counsel of the Company, and each of them, the Committee’s authority to suspend or limit the exercisability or the payment of any Award under either Plan during the periods described in Section III(E)(1) above. Management shall report to the Committee at each Committee meeting any suspension actions taken or ongoing since the previous meeting, and the Committee shall adopt a resolution ratifying, continuing and/or discontinuing each such suspension.

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IV.    PROCEDURES FOR EXERCISING STOCK OPTIONS AND SARS

A.    AUTHORITY AND SCOPE

Notwithstanding any provision of any Award Notice issued before 1998, these are the exercise procedures for ISOs, NSOs and SARs issued under the 1997 Plan, the 2010 Plan, and (unless the Compensation Committee specifically orders otherwise) any other compensation plan which in the future is adopted by the Company.

B.    NOTICE OF EXERCISE

1.    Form and Delivery

A Participant holding stock options or SARs granted under any of the Plans elects to exercise stock options or SARs by delivering (by personal delivery, fax or e-mail) a Notice of Exercise to the office of the Company’s Secretary or Assistant Secretary or to a designee of such officers. A Notice of Exercise is a writing signed by the Participant indicating that the Participant thereby elects to exercise the stock options or SARs identified in the Notice (including the quantity and either the stock option exercise price or the SAR base price), and describing the method by which the Participant will pay the exercise price of the stock options (there is no exercise price payment due in connection with the exercise of a SAR). Appropriate delivery of a Notice of Exercise binds the Participant to pay the exercise price. Optional forms of Notice of Exercise are attached to these rules as Exhibit A (stock options) and Exhibit B (SARs).

2.    Exercise Date

The effective date of a Notice of Exercise (the “Exercise Date”) will be the date the Notice of Exercise is received by the office of the Secretary or Assistant Secretary or by a designee of such officers; provided, however, that:

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(i)    a Notice of Exercise received on a trading day before trading opens that day on the New York Stock Exchange may validly designate the Exercise Date to be the preceding trading day;

(ii)    a Notice of Exercise may validly designate the Exercise Date to be any date later than the date the Notice of Exercise is received; and

(iii)    if the exercise of a stock option is accomplished through a “cashless exercise” as described in Section IV(C)(4) below, the Exercise Date shall be the date the broker sells Company stock into the market regarding that exercise.

C.    PAYMENT OF EXERCISE PRICE

1.    Cash Payment

To pay the exercise price of a stock option in cash, a Participant must deliver to the Secretary or Assistant Secretary or to a designee of such officers payment in full, in cash or by check payable in immediately available U.S. funds to the Company, within three business days after the Exercise Date (except as additional time may be allowed under Section IV(C)(3) below). For purposes of these rules, the term “business day” shall mean any day other than a Saturday, Sunday, federal holiday or day on which the Company’s principal office is closed for business. Subject to Section IV(D) below, payment of the exercise price may be partly in cash and partly in Company stock as described in Section IV(C)(2) below, or may be accomplished through a “cashless exercise” as described in Section IV(C)(4) below.

2.    Payment with Existing Company Stock

To pay the exercise price in shares of Company stock already owned by a Participant, the Participant must surrender to the Company shares having a total Fair Market Value (as of the Exercise Date) of at least the total exercise price, or pay any shortfall in cash.

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The Participant must, within three business days after the Exercise Date (except as additional time may be allowed under Section IV(C)(3) below) do one or both of the following:

a. regarding shares in the Company’s Direct Registration System, comply with the Company’s procedures (including signature guarantee requirements) for transferring book-entry shares to the Company; or

b. regarding shares that are evidenced by a paper stock certificate, deliver the certificate to the Secretary, Assistant Secretary or a designee of such officers. Each certificate delivered must have a guaranteed signature either on the back or on a stock power to be attached. The recommended procedure for mailing certificates is to mail the certificate and signed stock power separately.

3.    Additional Time to Pay Exercise Price

If the Participant’s payment of the exercise price would otherwise be required pursuant to Section IV(C)(1) or (2) above, and a Participant either

a. is traveling away from his or her usual place of Company employment, or

b. has a Disability as defined in the applicable Plan or these rules,

then, to the extent permitted by applicable law, the Participant may pay the exercise price on or before the first business day after the Participant’s return to his or her usual place of Company employment, but no later than the tenth business day after the Exercise Date. However, the President, Chief Executive Officer, Treasurer or General Counsel of the Company shall have the authority to grant such additional time to pay the exercise price as is reasonably necessary to accommodate the travel or Disability of the Participant.

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4.    Cashless Exercise

The broker-assisted method of exercising stock options described in this Section IV(C)(4) (“cashless exercise”) requires no cash outlay by the Participant. A Participant wishing to effect a cashless exercise must first establish a trading account with a registered securities broker-dealer. Establishing that trading account will likely include the Participant’s commitment to pay the broker as described in their agreement. Upon request by a Participant, the Secretary or Assistant Secretary will provide information that may help the Participant find a broker who has previously done cashless exercises with the Company and/or may be willing to do so at a discounted commission rate. The Participant must provide the Secretary or Assistant Secretary with the Participant’s broker’s name, firm, address, telephone and fax numbers.

To effect a cashless exercise, the Participant must deliver a Notice of Exercise as described in Section IV(B)(1), and notify the Participant’s broker to proceed with the exercise and to notify the Company of the date the stock is sold. The Participant’s broker will sell Company stock for the Participant’s account and pay to the Company the exercise price, plus any necessary tax withholding. The Company will have share certificates delivered to the Participant’s broker within three business days after the Exercise Date, unless the Company elects to retain the certificates pending receipt of the exercise price. The Participant will be required to pay the Participant’s broker according to the agreement between them, typically a few days’ interest on the exercise price plus a commission on the shares sold.

D. RESTRICTIONS RELATING TO POSSESSION OF MATERIAL NON-PUBLIC INFORMATION

Notwithstanding anything to the contrary provided above in these rules, a Participant may not, while in possession of material nonpublic information relating to the Company, or while subject to any quarterly or other “blackout period” imposed under the

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Company’s Policy on Insider Trading in National Fuel Gas Company Securities, (i) pay the exercise price of a stock option with Company stock, (ii) pay tax withholding in connection with the exercise of a stock option by having Company stock withheld and/or canceled, (iii) exercise SARs, or (iv) effect a cashless exercise of stock options. For a Participant subject to a quarterly or other blackout period, these prohibited transactions include any transaction the effective date of which occurs within the blackout period.

The restrictions set forth in this Section IV(D) shall not apply to any deemed exercise of SARs or deemed payment of tax withholding in connection therewith pursuant to a Plan or these rules, or to any transaction effected pursuant to an instruction, contract or written plan that meets the requirements of Rule 10b5-1(c) under the Securities Exchange Act of 1934, which provides a defense against insider trading liability. An instruction, contract or written plan relating to any transactions set forth in this Section IV(D) and intended by a Participant to comply with Rule 10b5‑1 (such as a written 10b5-1 plan on a form provided by a stockbroker) must meet the requirements of Rule 10b5-1(c) andshould be pre-approved by the Legal Department before the Participant enters into any transactions under that instruction, contract or written plan.

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EX-10.2

Exhibit 10.2

NATIONAL FUEL GAS COMPANY

2009 NON-EMPLOYEE DIRECTOR EQUITY COMPENSATION PLAN

Amended and Restated December 8, 2015

1.  Purpose

The purpose of the Plan is to advance the interests of the Company and its stockholders, by enhancing the Company’s ability to attract and retain highly qualified individuals to serve as non-employee members of the Board, and by encouraging such directors to acquire a proprietary interest in the long-term success of the Company, thereby aligning their financial interests with those of the Company’s stockholders.

2.  Definitions

2.1 “1997 Retainer Policy” means the Retainer Policy for Non-Employee Directors approved by the Company’s stockholders at the 1997 Annual Meeting of Stockholders.

2.2 “Board” means the Board of Directors of the Company.

2.3 “Code” means the Internal Revenue Code of 1986, and the rules, regulations and interpretations promulgated thereunder, as amended from time to time.

2.4 “Common Stock” means the common stock of the Company.

2.5 “Company” means National Fuel Gas Company.

2.6 “Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time.

2.7 “Participant” means any individual to whom shares of Common Stock have been issued under this Plan.

2.8 “Plan” means the National Fuel Gas Company 2009 Non-Employee Director Equity Compensation Plan, as amended from time to time. Any reference in the Plan to a paragraph number refers to that portion of the Plan.

3.  Administration

The Plan shall be administered by the Board. The Board shall have the authority to: (a) interpret the Plan; (b) establish such administrative rules, regulations and procedures as it deems necessary for the proper administration of the Plan; (c) grant waivers of Plan terms and conditions when any such action would be in the best interest of the Company; and (d) take any and all other action it deems advisable for the proper administration of the Plan. All determinations of the Board shall be made by a majority of its members, and its determinations shall be final, binding and conclusive. For the avoidance of doubt, the Board shall not take any action under the Plan, including without limitation pursuant to this paragraph 3, which would result in the imposition of an additional tax under Section 409A of the Code on the Participant holding shares issued hereunder.

4.  Participants

All non-employee directors of the Company are Participants in the Plan, and may receive shares of Common Stock under the Plan, except as otherwise provided in this section. Shares of Common Stock will not be issued under the Plan to any non-employee director who declines receipt of such shares or whose

compensation as a non-employee director is otherwise determined by written agreement between the Company and the non-employee director.

5.  Shares Available

The number of shares of Common Stock which shall be available for issuance under the Plan shall be 200,000, subject to adjustment as provided in paragraph 8. The shares of Common Stock available for issuance under the Plan may be authorized and unissued shares or treasury shares.

6.  Term

The Plan became effective as of March 12, 2009, the date of the Company’s 2009 Annual Meeting of Stockholders, upon approval by the Company’s stockholders at such meeting. Unless earlier terminated by the Board pursuant to the provisions of the Plan, the Plan shall expire when all of the shares of Common Stock available for issuance under the Plan have been issued. The expiration of the Plan shall not adversely affect any rights of any Participant, without such Participant’s consent.

7.  Shares Issued Under the Plan

(a) Shares of Common Stock will be issued to Participants on a quarterly basis, in advance (as of the first business day of the quarter), as compensation in whole or in part for the Participants’ service on the Board during the quarter. Shares will be issued in such amounts as the Board shall determine from time to time in its discretion, provided that the aggregate number of shares to be issued to any one Participant in any 12 month period shall not exceed 5,000. The number of shares to be issued to a Participant will be prorated as applicable for the quarter in which the Participant joins the Board and the quarter in which the Participant is scheduled to retire or resign from the Board, but shares actually issued under the Plan to a Participant shall not be subject to forfeiture or cancellation for any reason.

(b) Each share of Common Stock issued under the Plan shall be non-transferable until the later of two years after its issuance or six months after the Participant’s cessation of service on the Board; provided, however, that upon a Participant’s death, whether in office or after his or her service as a director ceases, any restrictions on transferability imposed hereunder shall lapse.

(c) Participants shall be entitled to all of the rights of stockholders with respect to shares issued under the Plan, including, but not by way of limitation, the right to vote such shares, the right to receive dividends and the right to reinvest dividends into additional shares of Common Stock. Shares acquired by reinvesting dividends are not subject to the transferability restrictions in paragraphs 7(b) and/or 8.

(d) Shares of Common Stock issued under the Plan may be evidenced in such manner as the Board deems appropriate, including, without limitation, book-entry registration or issuance of a stock certificate or certificates.

8.  Adjustment of Shares Available

(a) Changes in Stock.  In the event of changes in the Common Stock by reason of a Common Stock dividend, stock split, reverse stock split or other combination, appropriate adjustment shall be made by the Board in the aggregate number of shares available under the Plan and in the rate of payment of shares under the Plan. Such proper adjustment as may be deemed equitable may be made by the Board in its discretion to give effect to any other change affecting the Common Stock. Any shares of Common Stock or other securities acquired by a Participant as a dividend shall (i) be deemed to have been acquired at the same time as the securities on which the dividend or, if more than one, the initial dividend was paid, and (ii) be subject to the same terms and conditions, including restrictions on transfer, that apply to the securities on which the dividend or, if more than one, the initial dividend was paid. Any shares of Common Stock or other securities acquired by a Participant pursuant to a stock split, reverse stock split or other combination shall (i) be deemed to have been acquired at the same time as the securities involved in the stock split, reverse

2

stock split or other combination, and (ii) be subject to the same terms and conditions, including restrictions on transfer, that apply to the securities involved in the stock split, reverse stock split or other combination.

(b) Changes in Capitalization.  In case of a merger or consolidation of the Company with another corporation, a reorganization of the Company, a reclassification of the Common Stock of the Company, a spinoff of a significant asset or other changes in the capitalization of the Company, appropriate provision may be made with respect to shares of Common Stock issued under the Plan for (i) the substitution, on an equitable basis, of appropriate stock or other securities or other consideration to which holders of Common Stock of the Company will be entitled pursuant to such transaction or succession of transactions, or (ii) adjustment in the number of shares issuable pursuant to the Plan and in the rate of payment of shares under the Plan, in each case as deemed appropriate by the Committee. Any securities acquired by a Participant pursuant to this paragraph shall (i) be deemed to have been acquired at the same time as the securities surrendered in or otherwise subject to the transaction or succession of transactions described in this paragraph, and (ii) be subject to the same terms and conditions, including restrictions on transfer, that apply to the securities surrendered in or otherwise subject to such transaction or succession of transactions.

9.  Regulatory Approvals and Listings

Notwithstanding anything contained in this Plan to the contrary, the Company shall have no obligation to issue or deliver shares of Common Stock prior to (a) the obtaining of any approval from any governmental agency which the Company shall, in its sole discretion, determine to be necessary or advisable, (b) the admission of such shares to listing on the stock exchange on which the Common Stock may be listed, and (c) the completion of any registration or other qualification of said shares under any state or federal law or ruling of any governmental body which the Company shall, in its sole discretion, determine to be necessary or advisable.

10.  No Right to Continued Service on Board

Participation in the Plan shall not give any Participant any right to remain on the Board.

11.  Other Compensation of Non-Employee Directors

The Plan is not the only means of compensating Participants for their service on the Board. The Board may provide, outside of the Plan, for payment of non-equity compensation for such service, including cash, on terms and in amounts as determined by the Board in its discretion. The 1997 Retainer Policy is hereby amended so as to provide that all restrictions on the transferability of shares ever issued under the 1997 Retainer Policy shall lapse upon the death of the holder of those shares.

12.  Amendment

The Board may suspend or terminate the Plan at any time. In addition, the Board may, from time to time, amend the Plan in any manner, provided however, that any such amendment shall be subject to stockholder approval (i) at the discretion of the Board and (ii) to the extent that shareholder approval may be required by law or under the applicable requirements of any exchange on which the Common Stock is listed to trade. Notwithstanding the foregoing, the Board may not amend the Plan in any manner that would either (i) result in the imposition of an additional tax under section 409A of the Code on any Participant, or (ii) adversely affect any Participant with respect to shares already issued under the Plan, without that Participant’s consent.

13.  No Right, Title or Interest in Company Assets

To the extent any person acquires a right to receive payments from the Company under this Plan, such rights shall be no greater than the rights of an unsecured creditor of the Company.

3

EX-12

EXHIBIT 12

NATIONAL FUEL GAS COMPANY

COMPUTATION OF RATIO OF

EARNINGS TO FIXED CHARGES

UNAUDITED

	For the Twelve Months Ended			Fiscal Year Ended September 30,
	March 31, 2016			2015			2014			2013			2012
(Dollars in Thousands)
EARNINGS:
Net Income (Loss) Available for Common Stock	$	(817,633	)	$	(379,427	)	$	299,413		$	260,001		$	220,077
Plus Income Tax Expense (Benefit)	(639,812		)	(319,136		)	189,614			172,758			150,554
Less Investment Tax Credit (A)	(380		)	(414		)	(434		)	(426		)	(581		)
(Less Income) Plus Loss from Unconsolidated Subsidiaries	—			—			(397		)	204			1,442
Plus Distributions from Unconsolidated Subsidiaries	—			—			—			—			—
Plus Interest Expense on Long-Term Debt	110,595			95,916			90,194			90,273			82,002
Plus Other Interest Expense	3,798			3,555			4,083			3,838			4,238
Less Amortization of Loss on Reacquired Debt	(529		)	(529		)	(529		)	(721		)	(1,093		)
Plus (Less) Allowance for Borrowed Funds Used in Construction	2,544			1,964			900			827			1,231
Plus (Less) Other Capitalized Interest	1,423			4,191			3,560			1,801			2,992
Plus Rentals (B)	13,288			13,866			13,700			14,204			12,958
	$	(1,326,706	)	$	(580,014	)	$	600,104		$	542,759		$	473,820
FIXED CHARGES:
Interest & Amortization of Premium and Discount of Funded Debt	$	110,595		$	95,916		$	90,194		$	90,273		$	82,002
Plus Other Interest Expense	3,798			3,555			4,083			3,838			4,238
Less Amortization of Loss on Reacquired Debt	(529		)	(529		)	(529		)	(721		)	(1,093		)
Plus (Less) Allowance for Borrowed Funds Used in Construction	2,544			1,964			900			827			1,231
Plus (Less) Other Capitalized Interest	1,423			4,191			3,560			1,801			2,992
Plus Rentals (B)	13,288			13,866			13,700			14,204			12,958
	$	131,119		$	118,963		$	111,908		$	110,222		$	102,328
RATIO OF EARNINGS TO FIXED CHARGES	(D)			(C)			5.36			4.92			4.63

(A) Investment Tax Credit is included in Other Income.

(B) Rentals shown above represent the portion of all rentals (other than delay rentals) deemed representative of the interest factor.

(C) The ratio coverage for the fiscal year ended September 30, 2015 was less than 1:1. The Company would have needed to generate additional earnings of $698,977 to achieve a coverage of 1:1 for the fiscal year ended September 30, 2015.

(D) The ratio coverage for the twelve months ended March 31, 2016 was less than 1:1. The Company would have needed to generate additional earnings of $1,457,825 to achieve a coverage of 1:1 for the twelve months ended March 31, 2016.

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, R. J. Tanski, certify that:

1.I have reviewed this quarterly report on Form 10-Q of National Fuel Gas Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: May 4, 2016

/s/ R. J. Tanski

R. J. Tanski

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, D. P. Bauer, certify that:

1.I have reviewed this quarterly report on Form 10-Q of National Fuel Gas Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: May 4, 2016

/s/ D. P. Bauer

D. P. Bauer

Treasurer and Principal Financial Officer

EX-32

EXHIBIT 32

NATIONAL FUEL GAS COMPANY

Certification Pursuant to Section 906

of the Sarbanes-Oxley Act of 2002

Each of the undersigned, R. J. TANSKI, President and Chief Executive Officer and D. P. BAUER, the Treasurer and Principal Financial Officer of NATIONAL FUEL GAS COMPANY (the "Company"), DOES HEREBY CERTIFY that:

1.    The Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2016 (the "Report") fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934, as amended; and

2.    Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, each of the undersigned has executed this statement this 4thday of May, 2016.

/s/ R. J. Tanski

President and Chief Executive Officer

/s/ D. P. Bauer

Treasurer and Principal Financial Officer

EX-99

Exhibit 99
NATIONAL FUEL GAS
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
	Twelve Months Ended
	March 31,
(Thousands of Dollars)	2016			2015
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues	$	637,243		$	937,830
Exploration and Production and Other Revenues	622,246			785,110
Pipeline and Storage and Gathering Revenues	205,715			203,863
	1,465,204			1,926,803
Operating Expenses:
Purchased Gas	155,985			433,151
Operation and Maintenance:
Utility and Energy Marketing	195,647			198,289
Exploration and Production and Other	178,161			186,107
Pipeline and Storage and Gathering	84,874			78,948
Property, Franchise and Other Taxes	85,380			89,925
Depreciation, Depletion and Amortization	285,223			386,126
Impairment of Oil and Gas Producing Properties	1,838,803			120,348
	2,824,073			1,492,894
Operating Income (Loss)	(1,358,869		)	433,909
Other Income (Expense):
Interest Income	4,695			4,523
Other Income	11,122			6,682
Interest Expense on Long-Term Debt	(110,595		)	(89,230		)
Other Interest Expense	(3,798		)	(4,134		)
Income (Loss) Before Income Taxes	(1,457,445		)	351,750
Income Tax Expense (Benefit)	(639,812		)	128,390
Net Income (Loss) Available for Common Stock	$	(817,633	)	$	223,360
Earnings Per Common Share:
Basic:
Net Income (Loss) Available for Common Stock	$	(9.66	)	$	2.65
Diluted:
Net Income (Loss) Available for Common Stock	$	(9.66	)	$	2.62
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	84,620,502			84,170,033
Used in Diluted Calculation	84,620,502			85,102,075

XML

Document And Entity Information - shares	6 Months Ended
	Mar. 31, 2016	Apr. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Entity Registrant Name	NATIONAL FUEL GAS CO
Entity Central Index Key	0000070145
Current Fiscal Year End Date	--09-30
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		84,935,329
Trading Symbol	nfg

XML

Consolidated Statements Of Income And Earnings Reinvested In The Business (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
INCOME
Operating Revenues	$ 449,132	$ 596,127	$ 824,327	$ 1,120,036
Operating Expenses:
Purchased Gas	81,623	190,600	123,691	317,690
Property, Franchise and Other Taxes	21,305	24,916	41,662	45,845
Depreciation, Depletion and Amortization	63,947	82,687	134,498	185,433
Impairment of Oil and Gas Producing Properties	397,443	120,348	832,894	120,348
Total Operating Expenses	686,132	551,796	1,367,251	915,143
Operating Income (Loss)	(237,000)	44,331	(542,924)	204,893
Other Income (Expense):
Interest Income	278	46	2,077	1,303
Other Income	3,236	1,388	5,654	2,571
Interest Expense on Long-Term Debt	(28,994)	(22,376)	(59,366)	(44,687)
Other Interest Expense	(1,237)	(1,584)	(2,617)	(2,375)
Income (Loss) Before Income Taxes	(263,717)	21,805	(597,176)	161,705
Income Tax Expense (Benefit)	(116,030)	5,136	(260,380)	60,296
Net Income (Loss) Available for Common Stock	(147,687)	16,669	(336,796)	101,409
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	880,619	1,666,659	1,103,200	1,614,361
Beginning Retained Earnings Unappropriated And Current Period Net Income Loss	732,932	1,683,328	766,404	1,715,770
Dividends on Common Stock	(33,533)	(32,488)	(67,005)	(64,930)
Balance at March 31	$ 699,399	$ 1,650,840	$ 699,399	$ 1,650,840
Earnings Per Common Share, Basic:
Net Income (Loss) Available for Common Stock (in dollars per share)	$ (1.74)	$ 0.20	$ (3.97)	$ 1.20
Earnings Per Common Share, Diluted:
Net Income (Loss) Available for Common Stock (in dollars per share)	$ (1.74)	$ 0.20	$ (3.97)	$ 1.19
Weighted Average Common Shares Outstanding:
Used in Basic Calculation (shares)	84,806,982	84,317,508	84,728,680	84,262,471
Used in Diluted Calculation (shares)	84,806,982	85,133,142	84,728,680	85,175,961
Dividends Per Common Share:
Dividends Declared (in dollars per share)	$ 0.395	$ 0.385	$ 0.790	$ 0.770
Utility and Energy Marketing [Member]
INCOME
Operating Revenues	$ 248,173	$ 374,141	$ 417,005	$ 640,380
Operating Expenses:
Operation and Maintenance	57,309	62,764	104,858	112,461
Exploration and Production and Other [Member]
INCOME
Operating Revenues	144,570	166,139	297,454	371,917
Operating Expenses:
Operation and Maintenance	42,964	50,906	88,539	94,401
Pipeline and Storage and Gathering [Member]
INCOME
Operating Revenues	56,389	55,847	109,868	107,739
Operating Expenses:
Operation and Maintenance	$ 21,541	$ 19,575	$ 41,109	$ 38,965

XML

Consolidated Statements Of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Net Income (Loss) Available for Common Stock	$ (147,687)	$ 16,669	$ (336,796)	$ 101,409
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	(4)	265	(642)	(147)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	33,768	61,165	99,139	304,994
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income	(388)	0	(388)	0
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(61,235)	(54,130)	(118,405)	(78,395)
Other Comprehensive Income (Loss), Before Tax	(27,859)	7,300	(20,296)	226,452
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	(16)	99	(207)	(61)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	14,190	25,902	34,866	128,851
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income	(163)	0	(163)	0
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(25,600)	(22,917)	(43,606)	(33,006)
Income Taxes – Net	(11,589)	3,084	(9,110)	95,784
Other Comprehensive Income (Loss)	(16,270)	4,216	(11,186)	130,668
Comprehensive Income (Loss)	$ (163,957)	$ 20,885	$ (347,982)	$ 232,077

XML

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Mar. 31, 2016	Sep. 30, 2015
ASSETS
Property, Plant and Equipment		$ 9,451,538	$ 9,261,323
Less - Accumulated Depreciation, Depletion and Amortization		4,879,363	3,929,428
Property, Plant and Equipment, Net, Total		4,572,175	5,331,895
Current Assets
Cash and Temporary Cash Investments		93,700	113,596
Hedging Collateral Deposits	[1]	9,963	11,124
Receivables – Net of Allowance for Uncollectible Accounts of $34,236 and $29,029, Respectively		137,718	105,004
Unbilled Revenue		35,140	20,746
Gas Stored Underground		8,599	34,252
Materials and Supplies - at average cost		33,430	30,414
Unrecovered Purchased Gas Costs		1,245	0
Other Current Assets		56,714	60,665
Total Current Assets		376,509	375,801
Other Assets
Recoverable Future Taxes		172,417	168,214
Unamortized Debt Expense		1,953	2,218
Other Regulatory Assets		270,941	278,227
Deferred Charges		17,063	15,129
Other Investments		104,273	92,990
Goodwill		5,476	5,476
Prepaid Post-Retirement Benefit Costs		26,344	24,459
Fair Value of Derivative Financial Instruments		253,716	270,363
Other		157	167
Total Other Assets		852,340	857,243
Total Assets		5,801,024	6,564,939
Capitalization:
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 84,892,747 Shares and 84,594,383 Shares, Respectively		84,893	84,594
Paid in Capital		756,001	744,274
Earnings Reinvested in the Business		699,399	1,103,200
Accumulated Other Comprehensive Income		82,186	93,372
Total Comprehensive Shareholders’ Equity		1,622,479	2,025,440
Long-term Debt, Net of Unamortized Discount and Debt Issuance Costs		2,085,123	2,084,009
Total Capitalization		3,707,602	4,109,449
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		0	0
Current Portion of Long-Term Debt		0	0
Accounts Payable		111,054	180,388
Amounts Payable to Customers		42,217	56,778
Dividends Payable		33,533	33,415
Interest Payable on Long-Term Debt		34,900	36,200
Customer Advances		33	16,236
Customer Security Deposits		16,101	16,490
Other Accruals and Current Liabilities		104,925	96,557
Fair Value of Derivative Financial Instruments		9,864	10,076
Total Current and Accrued Liabilities		352,627	446,140
Deferred Credits
Deferred Income Taxes		844,916	1,137,962
Taxes Refundable to Customers		93,674	89,448
Unamortized Investment Tax Credit		557	731
Cost of Removal Regulatory Liability		189,421	184,907
Other Regulatory Liabilities		101,104	108,617
Pension and Other Post-Retirement Liabilities		216,852	202,807
Asset Retirement Obligations		171,991	156,805
Other Deferred Credits		122,280	128,073
Total Deferred Credits		1,740,795	2,009,350
Commitments and Contingencies (Note 6)		0	0
Total Capitalization and Liabilities		$ 5,801,024	$ 6,564,939

[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.

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2016	Sep. 30, 2015
Statement of Financial Position [Abstract]
Receivables, Allowance for Uncollectible Accounts	$ 34,236	$ 29,029
Common Stock, Par Value	$ 1	$ 1
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares Issued	84,892,747	84,594,383
Common Stock, Shares Outstanding	84,892,747	84,594,383

XML

Consolidated Statements Of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
OPERATING ACTIVITIES
Net Income (Loss) Available for Common Stock	$ (336,796)	$ 101,409
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties	832,894	120,348
Depreciation, Depletion and Amortization	134,498	185,433
Deferred Income Taxes	(283,912)	10,351
Excess Tax Benefits Associated with Stock-Based Compensation Awards	(226)	(9,024)
Stock-Based Compensation	2,518	5,985
Other	6,106	4,709
Change in:
Hedging Collateral Deposits	1,161	(12,992)
Receivables and Unbilled Revenue	(28,211)	(88,339)
Gas Stored Underground and Materials and Supplies	22,637	29,085
Unrecovered Purchased Gas Costs	(1,245)	0
Other Current Assets	4,177	4,184
Accounts Payable	(31,786)	62,832
Amounts Payable to Customers	(14,561)	11,051
Customer Advances	(16,203)	(18,735)
Customer Security Deposits	(389)	2,702
Other Accruals and Current Liabilities	22,420	53,491
Other Assets	3,754	1,826
Other Liabilities	(4,073)	43,186
Net Cash Provided by Operating Activities	312,763	507,502
INVESTING ACTIVITIES
Capital Expenditures	(358,981)	(493,341)
Net Proceeds from Sale of Oil and Gas Producing Properties	104,938	0
Other	(18,249)	(1,262)
Net Cash Used in Investing Activities	(272,292)	(494,603)
Financing Activities
Changes in Notes Payable to Banks and Commercial Paper	0	71,900
Excess Tax Benefits Associated with Stock-Based Compensation Awards	226	9,024
Dividends Paid on Common Stock	(66,887)	(64,842)
Net Proceeds from Issuance of Common Stock	6,294	3,574
Net Cash (Used in) Provided by Financing Activities	(60,367)	19,656
Net Increase (Decrease) in Cash and Temporary Cash Investments	(19,896)	32,555
Cash and Temporary Cash Investments at October 1	113,596	36,886
Cash and Temporary Cash Investments at March 31	93,700	69,441
Supplemental Disclosure of Cash Flow Information, Non-Cash Investing Activities:
Non-Cash Capital Expenditures	66,058	94,484
Receivable from Sale of Oil and Gas Producing Properties	$ 10,297	$ 0

XML

Summary Of Significant Accounting Policies

6 Months Ended

Mar. 31, 2016

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

Summary of Significant Accounting Policies

Principles of Consolidation.  The Company consolidates all entities in which it has a controlling financial interest.  All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Reclassification. Due to the adoption of the authoritative guidance regarding the presentation of deferred income taxes, certain prior year amounts have been reclassified to conform with current year presentation. The Company reclassified Deferred Income Taxes of $137.2 million previously shown as Current Assets in the Company's 2015 Form 10-K to Deferred Income Taxes shown as Deferred Credits on the Consolidated Balance Sheet at September 30, 2015.

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, 2015, 2014 and 2013 that are included in the Company's 2015 Form 10-K.  The consolidated financial statements for the year ended September 30, 2016 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.

The earnings for the six months ended March 31, 2016 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2016.  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 Statement of Cash Flows.  For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.

Hedging Collateral Deposits.  This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions.  In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances.

Gas Stored Underground.  In the Utility segment, gas stored underground is carried at lower of cost or market, 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 $17.5 million at March 31, 2016, 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 $163.4 million and $176.3 million at March 31, 2016 and September 30, 2015, 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.  The book value of the oil and gas properties exceeded the ceiling at December 31, 2015 as well as March 31, 2016. As such, the Company recognized pre-tax impairment charges of $397.4 million and $832.9 million for the quarter and six months ended March 31, 2016, respectively. Deferred income tax benefits of $166.9 million and $349.8 million related to the impairment charges were also recognized for the quarter and six months ended March 31, 2016, respectively. In adjusting estimated future cash flows for hedging under the ceiling test at December 31, 2015 and March 31, 2016, estimated future net cash flows were increased by $253.7 million and $252.1 million, respectively.

On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. Under the terms of the agreement, Seneca and IOG will jointly participate in a program that will develop up to 80 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest and is obligated to participate in the first 42 wells, and has a one-time option to participate in the remaining 38 wells that can be exercised on or before July 1, 2016. With respect to the first 42 wells, IOG has committed to fund up to $231 million to develop the joint wells. As of March 31, 2016, Seneca had received $104.9 million of cash and had recorded a $10.3 million receivable in recognition of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the first 42 wells. The cash proceeds and receivable were recorded by Seneca as a $115.2 million reduction of property, plant and equipment. As the fee-owner of the property’s mineral rights, Seneca retains a 7.5% royalty interest and the remaining 20% working interest (26% net revenue interest) in the first 42 wells. If IOG exercises its option to participate in the remaining 38 wells, IOG has agreed to fund up to an additional $211 million to develop such joint wells. Seneca will retain a 10% royalty and the remaining 20% working interest (28% net revenue interest) in the remaining 38 wells. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.

Accumulated Other Comprehensive Income (Loss).  The components of Accumulated Other Comprehensive Income (Loss) and changes for the quarter and six months ended March 31, 2016 and 2015, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): 

	Gains and Losses on Derivative Financial Instruments			Gains and Losses on Securities Available for Sale			Funded Status of the Pension and Other Post-Retirement Benefit Plans			Total
Three Months Ended March 31, 2016
Balance at January 1, 2016	$	162,728		$	5,522		$	(69,794	)	$	98,456
Other Comprehensive Gains and Losses Before Reclassifications	19,578			12			—			19,590
Amounts Reclassified From Other Comprehensive Income (Loss)	(35,635		)	(225		)	—			(35,860		)
Balance at March 31, 2016	$	146,671		$	5,309		$	(69,794	)	$	82,186
Six Months Ended March 31, 2016
Balance at October 1, 2015	$	157,197		$	5,969		$	(69,794	)	$	93,372
Other Comprehensive Gains and Losses Before Reclassifications	64,273			(435		)	—			63,838
Amounts Reclassified From Other Comprehensive Income (Loss)	(74,799		)	(225		)	—			(75,024		)
Balance at March 31, 2016	$	146,671		$	5,309		$	(69,794	)	$	82,186
Three Months Ended March 31, 2015
Balance at January 1, 2015	$	170,363		$	8,130		$	(56,020	)	$	122,473
Other Comprehensive Gains and Losses Before Reclassifications	35,263			166			—			35,429
Amounts Reclassified From Other Comprehensive Income (Loss)	(31,213		)	—			—			(31,213		)
Balance at March 31, 2015	$	174,413		$	8,296		$	(56,020	)	$	126,689
Six Months Ended March 31, 2015
Balance at October 1, 2014	$	43,659		$	8,382		$	(56,020	)	$	(3,979	)
Other Comprehensive Gains and Losses Before Reclassifications	176,143			(86		)	—			176,057
Amounts Reclassified From Other Comprehensive Income (Loss)	(45,389		)	—			—			(45,389		)
Balance at March 31, 2015	$	174,413		$	8,296		$	(56,020	)	$	126,689

Reclassifications Outof Accumulated Other Comprehensive Income (Loss).  The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the quarter and six months ended March 31, 2016 and 2015 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

Details About Accumulated Other Comprehensive Income (Loss) Components	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income												Affected Line Item in the Statement Where Net Income (Loss) is Presented
	Three Months Ended March 31,						Six Months Ended March 31,
	2016			2015			2016			2015
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts		$57,914			$53,471			$114,242			$73,508		Operating Revenues
Commodity Contracts	3,530			659			4,450			4,887			Purchased Gas
Foreign Currency Contracts	(209		)	—			(287		)	—			Operation and Maintenance Expense
Gains (Losses) on Securities Available for Sale	388			—			388			—			Other Income
	61,623			54,130			118,793			78,395			Total Before Income Tax
	(25,763		)	(22,917		)	(43,769		)	(33,006		)	Income Tax Expense
		$35,860			$31,213			$75,024			$45,389		Net of Tax

Other Current Assets.  The components of the Company’s Other Current Assets are as follows (in thousands):

	At March 31, 2016		At September 30, 2015
Prepayments	$	5,923	$	10,743
Prepaid Property and Other Taxes	21,757		13,709
Fair Values of Firm Commitments	12,941		15,775
Regulatory Assets	16,093		20,438
	$	56,714	$	60,665

Other Accruals and Current Liabilities.  The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):

	At March 31, 2016		At September 30, 2015
Accrued Capital Expenditures	$	38,299	$	53,652
Regulatory Liabilities	20,786		5,346
Reserve for Gas Replacement	17,469		—
Federal Income Taxes Payable	4,102		5,686
State Income Taxes Payable	224		1,170
Other	24,045		30,703
	$	104,925	$	96,557

Earnings Per Common Share.  Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.  For purposes of determining earnings per common share, the potentially dilutive securities the Company has outstanding are stock options, SARs, restricted stock units and performance shares.  As the Company recognized a net loss for both the quarter and six months ended March 31, 2016, the aforementioned securities, amounting to 386,626 and 451,291 securities, were not recognized in the diluted earnings per share calculation for the quarter and six months ended March 31, 2016, respectively. For 2015, 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 5 and 2,565 securities excluded as being antidilutive for the quarter and six months ended March 31, 2015, respectively.

Stock-Based Compensation.  The Company granted 309,996 performance shares during the six months ended March 31, 2016. The weighted average fair value of such performance shares was $30.71 per share for the six months ended March 31, 2016. 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 six months ended March 31, 2016 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2015 to September 30, 2018.  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 six months ended March 31, 2016 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2015 to September 30, 2018.  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 99,843 non-performance based restricted stock units during the six months ended March 31, 2016.  The weighted average fair value of such non-performance based restricted stock units was $35.57 per share for the six months ended March 31, 2016. 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.

No stock options, SARs or restricted share awards were granted by the Company during the six months ended March 31, 2016.

New Authoritative Accounting and Financial Reporting Guidance. In May 2014, the FASB issued authoritative guidance regarding revenue recognition. The authoritative guidance provides a single, comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The original effective date of this authoritative guidance was as of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements and disclosures.

In June 2014, the FASB issued authoritative guidance regarding accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the employee has completed the requisite service period. This authoritative guidance requires that such performance targets that affect vesting be treated as performance conditions, meaning that the performance target should not be factored in the calculation of the award at the grant date. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2017, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

In July 2015, the FASB issued authoritative guidance simplifying inventory measurement by requiring companies to value inventory at the lower of cost and net realizable value. The authoritative guidance applies to all inventory other than inventory that is measured using last-in, first-out or the retail inventory method. The intention of this authoritative guidance is to eliminate some diversity in practice. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2018, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

In November 2015, the FASB issued authoritative guidance simplifying the presentation of deferred income taxes. The authoritative guidance requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The Company early adopted this guidance at December 31, 2015 on a retrospective basis.

In January 2016, the FASB issued authoritative guidance regarding the recognition and measurement of financial assets and liabilities. The authoritative guidance primarily affects the accounting for equity investments, financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. All equity investments in unconsolidated entities will be measured at fair value through earnings rather than through other comprehensive income. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2019. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

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 is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

In March 2016, the FASB issued authoritative guidance simplifying several aspects of the accounting for stock-based compensation. Among other things, the revised guidance specifies that the difference between the compensation recognized for financial reporting purposes and the deduction allowed for tax purposes (excess tax benefit or deficiency) shall be recognized as income tax expense or benefit in the income statement, as opposed to the current treatment where this difference is recognized as additional paid-in capital in the balance sheet. For statement of cash flows purposes, the revised guidance specifies that the excess tax benefit shall be classified along with other income tax cash flows as an item impacting cash flow from operating activities. The current guidance separates the excess tax benefit from other income tax cash flows and classifies the excess tax benefit as an item impacting cash flow from financing activities. The new authoritative guidance will be effective as of the Company’s first quarter of fiscal 2018, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

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Fair Value Measurements

6 Months Ended

Mar. 31, 2016

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 March 31, 2016 and September 30, 2015.  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 March 31, 2016
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)			Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	65,530	$	—	$	—	$	—		$	65,530
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	2,754		—		—		(2,754		)	—
Over the Counter Swaps – Gas and Oil	—		255,867		—		(406		)	255,461
Foreign Currency Contacts	—		—		—		(1,745		)	(1,745		)
Other Investments:
Balanced Equity Mutual Fund	36,297		—		—		—			36,297
Fixed Income Mutual Fund	25,085		—		—		—			25,085
Common Stock – Financial Services Industry	3,942		—		—		—			3,942
Hedging Collateral Deposits	9,963		—		—		—			9,963
Total	$	143,571	$	255,867	$	—	$	(4,905	)	$	394,533
Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	10,311	$	—	$	—	$	(2,754	)	$	7,557
Over the Counter Swaps – Gas and Oil	—		2,713		—		(406		)	2,307
Foreign Currency Contracts	—		1,745		—		(1,745		)	—
Total	$	10,311	$	4,458	$	—	$	(4,905	)	$	9,864
Total Net Assets/(Liabilities)	$	133,260	$	251,409	$	—	$	—		$	384,669

Recurring Fair Value Measures	At fair value as of September 30, 2015
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)			Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	92,196	$	—	$	—	$	—		$	92,196
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	6,373		—		—		(6,373		)	—
Over the Counter Swaps – Gas and Oil	—		272,335		1,791		(808		)	273,318
Foreign Currency Contracts	—		—		—		(2,955		)	(2,955		)
Other Investments:
Balanced Equity Mutual Fund	34,884		—		—		—			34,884
Fixed Income Mutual Fund	8,004		—		—		—			8,004
Common Stock – Financial Services Industry	4,318		—		—		—			4,318
Other Common Stock	450		—		—		—			450
Hedging Collateral Deposits	11,124		—		—		—			11,124
Total	$	157,349	$	272,335	$	1,791	$	(10,136	)	$	421,339
Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	15,276	$	—	$	—	$	(6,373	)	$	8,903
Over the Counter Swaps – Gas and Oil	—		1,981		—		(808		)	1,173
Foreign Currency Contracts	—		2,955		—		(2,955		)	—
Total	$	15,276	$	4,936	$	—	$	(10,136	)	$	10,076
Total Net Assets/(Liabilities)	$	142,073	$	267,399	$	1,791	$	—		$	411,263

⁽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 March 31, 2016 and September 30, 2015, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used in the Company’s Energy Marketing segment. Hedging collateral deposits of $10.0 million at March 31, 2016 and $11.1 million at September 30, 2015, which are associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at March 31, 2016 and September 30, 2015 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments, the majority of the crude oil price swap agreements used in the Company’s Exploration and Production segment and foreign currency contracts used in the Company's Exploration and Production segment. The fair value of the Level 2 price swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates. The derivative financial instruments reported in Level 3 consist of a small portion of the crude oil price swap agreements used in the Company’s Exploration and Production segment at September 30, 2015 that settled prior to December 31, 2015.  The fair value of the Level 3 crude oil price swap agreements was based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume). 

The 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 March 31, 2016, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation.  To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the quarters and six months ended March 31, 2016 and 2015, respectively. For the quarters and six months ended March 31, 2016 and March 31, 2015, no transfers in or out of Level 1 or Level 2 occurred. There were no purchases or sales of derivative financial instruments during the periods presented in the tables below.  All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below (amounts in parentheses indicate credits in the derivative asset/liability accounts).

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)			Total Gains/Losses
	October 1, 2015		Gains/Losses Realized and Included in Earnings				Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)		Transfer In/Out of Level 3		March 31, 2016
Derivative Financial Instruments(2)	$	1,791	$	(2,002	)	(1)	$	211	$	—	$	—

⁽¹⁾  Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the six months ended March 31, 2016. 

⁽²⁾  Derivative Financial Instruments are shown on a net basis.        

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)			Total Gains/Losses
	January 1, 2015		Gains/Losses Realized and Included in Earnings				Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)		Transfer In/Out of Level 3		March 31, 2015
Derivative Financial Instruments(2)	$	5,337	$	(2,949	)	(1)	$	2,438	$	—	$	4,826

⁽¹⁾  Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended March 31, 2015. 

⁽²⁾  Derivative Financial Instruments are shown on a net basis.

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)			Total Gains/Losses
	October 1, 2014		Gains/Losses Realized and Included in Earnings				Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)		Transfer In/Out of Level 3		March 31, 2015
Derivative Financial Instruments(2)	$	1,368	$	(6,804	)	(1)	$	10,262	$	—	$	4,826

⁽¹⁾  Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the six months ended March 31, 2015. 

⁽²⁾  Derivative Financial Instruments are shown on a net basis.

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Financial Instruments

6 Months Ended

Mar. 31, 2016

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): 

	March 31, 2016				September 30, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,085,123	$	2,026,988	$	2,084,009	$	2,129,558

The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries/LIBOR for the risk free component and company specific credit spread information – generally obtained from recent trade activity in the debt).  As such, the Company considers the debt to be Level 2.

Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2.  Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.

Other Investments.  Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.

Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity and fixed income securities. The values of the insurance contracts amounted to $38.9 million at March 31, 2016 and $45.3 million at September 30, 2015. The fair value of the equity mutual fund was $36.3 million at March 31, 2016 and $34.9 million at September 30, 2015. The gross unrealized gain on this equity mutual fund was $6.2 million at March 31, 2016 and $6.5 million at September 30, 2015. The fair value of the fixed income mutual fund was $25.1 million at March 31, 2016 and $8.0 million at September 30, 2015. The gross unrealized loss on this fixed income mutual fund was $0.1 million at March 31, 2016. The fair value of the stock of an insurance company was $3.9 million at March 31, 2016 and $4.3 million at September 30, 2015. The gross unrealized gain on this stock was $2.2 million at March 31, 2016 and $2.6 million at September 30, 2015. The insurance contracts and marketable equity 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 ten years. The Exploration and Production segment holds the majority of the Company’s derivative financial instruments. The derivative financial instruments held by the Energy Marketing segment are not considered to be material to the Company.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at March 31, 2016 and September 30, 2015.  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 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 March 31, 2016, the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding:

Commodity	Units
Natural Gas	139.5	Bcf (short positions)
Natural Gas	3.1	Bcf (long positions)
Crude Oil	1,467,000	Bbls (short positions)

As of March 31, 2016, the Company was hedging a total of $84.5 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).

As of March 31, 2016, the Company had $252.9 million ($146.7 million after tax) of net hedging gains included in the accumulated other comprehensive income balance. It is expected that $180.3 million ($104.6 million after tax) of such unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transaction are recorded in earnings.

Refer to Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments.

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended March 31, 2016 and 2015 (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 March 31,					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 March 31,					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 March 31,
	2016			2015			2016			2015			2016		2015
Commodity Contracts	$	30,876		$	60,571	Operating Revenue	$	57,914		$	53,471	Operating Revenue	$	31	$	1,469
Commodity Contracts	$	(214	)	$	594	Purchased Gas	$	3,530		$	659	Not Applicable	$	—	$	—
Foreign Currency Contracts	$	3,106		$	—	Operation and Maintenance Expense	$	(209	)	$	—	Not Applicable	$	—	$	—
Total	$	33,768		$	61,165		$	61,235		$	54,130		$	31	$	1,469

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Six Months Ended March 31, 2016 and 2015 (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 Six Months Ended March 31,				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 Six Months Ended March 31,					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 Six Months Ended March 31,
	2016		2015			2016			2015			2016		2015
Commodity Contracts	$	96,217	$	300,594	Operating Revenue	$	114,242		$	73,508	Operating Revenue	$	168	$	2,929
Commodity Contracts	$	1,999	$	4,400	Purchased Gas	$	4,450		$	4,887	Not Applicable	$	—	$	—
Foreign Currency Contracts	$	923	$	—	Operation and Maintenance Expense	$	(287	)	$	—	Not Applicable	$	—	$	—
Total	$	99,139	$	304,994		$	118,405		$	78,395		$	168	$	2,929

Fair Value Hedges

The Company utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or market writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of March 31, 2016, the Company’s Energy Marketing segment had fair value hedges covering approximately 13.8 Bcf (13.2 Bcf of fixed price sales commitments, 0.1 Bcf of fixed price purchase commitments and 0.5 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 Six Months Ended March 31, 2016 (In Thousands)			Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Six Months Ended March 31, 2016 (In Thousands)
Commodity Contracts	Operating Revenues	$	5,557		$	(5,557	)
Commodity Contracts	Purchased Gas	$	(154	)	$	154
		$	5,403		$	(5,403	)

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 sixteen counterparties of which fifteen are in a net gain position.   On average, the Company had $16.8 million of credit exposure per counterparty in a gain position at March 31, 2016. The maximum credit exposure per counterparty in a gain position at March 31, 2016 was $43.2 million. The Company’s gain position on such derivative financial instruments for certain counterparties exceeded the established thresholds at which the counterparties would be required to post collateral. At March 31, 2016, collateral deposits from counterparties of $24.2 million were posted. These collateral deposits are recorded as a component of Accounts Payable on the Consolidated Balance Sheet.

As of March 31, 2016, twelve of the sixteen 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 March 31, 2016, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $162.9 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements).  For its over-the-counter swap agreements and foreign currency forward contracts, no hedging collateral deposits were required to be posted by the Company at March 31, 2016.    

For its exchange traded futures contracts, the Company was required to post $10.0 million in hedging collateral deposits as of March 31, 2016.   As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.

The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note 1 under Hedging Collateral Deposits.

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Income Taxes

6 Months Ended

Mar. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The components of federal and state income taxes included in the Consolidated Statements of Income are as follows (in thousands):

	Six Months Ended   March 31,
	2016			2015
Current Income Taxes
Federal	$	7,995		$	36,746
State	15,537			13,199
Deferred Income Taxes
Federal	(197,982		)	13,242
State	(85,930		)	(2,891		)
	(260,380		)	60,296
Deferred Investment Tax Credit	(174		)	(208		)
Total Income Taxes	$	(260,554	)	$	60,088
Presented as Follows:
Other Income	(174		)	(208		)
Income Tax Expense (Benefit)	(260,380		)	60,296
Total Income Taxes	$	(260,554	)	$	60,088

Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income (loss) before income taxes.  The following is a reconciliation of this difference (in thousands):

	Six Months Ended   March 31,
	2016			2015
U.S. Income (Loss) Before Income Taxes	$	(597,350	)	$	161,497
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35%	$	(209,073	)	$	56,524
State Income Taxes (Benefit)	(45,756		)	6,700
Miscellaneous	(5,725		)	(3,136		)
Total Income Taxes	$	(260,554	)	$	60,088

As a result of a settlement reached during the quarter, the Company has reduced the balance of unrecognized tax benefits by $2.6 million, of which $0.5 million was recorded as an income tax benefit. As of March 31, 2016, the entire balance of unrecognized tax benefits would favorably impact the effective tax rate, if recognized.

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Capitalization

6 Months Ended

Mar. 31, 2016

Capitalization, Long-term Debt and Equity [Abstract]

Capitalization

Capitalization

Common Stock.  During the six months endedMarch 31, 2016, the Company issued 138,060 original issue shares of common stock as a result of stock option and SARs exercises and 61,150 original issue shares of common stock for restricted stock units that vested.  In addition, the Company issued 72,358 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 65,046 original issue shares of common stock for the Company’s 401(k) plans.  The Company also issued 8,538 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 six months endedMarch 31, 2016.  Holders of stock options, SARs, restricted share awards or restricted stock units will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes.  During the six months endedMarch 31, 2016, 46,788 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.    None of the Company’s long-term debt at March 31, 2016 will mature within the following twelve-month period.

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Commitments And Contingencies

6 Months Ended

Mar. 31, 2016

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 March 31, 2016, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be approximately $4.7 million.  The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 12 years.

The Company's estimated liability for clean-up costs discussed above includes a $3.6 million estimated liability to remediate a former manufactured gas plant site located in New York. In February 2009, the Company received approval from the NYDEC of a Remedial Design Work Plan (RDWP) for this site. In October 2010, the Company submitted a RDWP addendum to conduct additional Preliminary Design Investigation field activities necessary to design a successful remediation. As a result of this work, the Company submitted to the NYDEC a proposal to amend the NYDEC’s Record of Decision remedy for the site.  In April 2013, the NYDEC approved the Company’s proposed amendment.  Final remedial design work for the site was completed, and active remedial work has recently been completed. Restoration work is underway. 

The Company is currently not aware of any material additional exposure to environmental liabilities.  However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company.

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.

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Business Segment Information

6 Months Ended

Mar. 31, 2016

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 2015 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 2015 Form 10-K.  A listing of segment assets at March 31, 2016 and September 30, 2015 is shown in the tables below.  

Quarter Ended March 31, 2016 (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	$143,783	$56,276	$113	$212,737	$35,436	$448,345	$561	$226	$449,132
Intersegment Revenues	$—	$23,292	$21,545	$5,364	$312	$50,513	$—	$(50,513)	$—
Segment Profit: Net Income (Loss)	$(213,335)	$21,194	$7,568	$31,960	$3,484	$(149,129)	$(23)	$1,465	$(147,687)

Six Months Ended March 31, 2016 (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	$295,749	$109,630	$238	$356,585	$60,420	$822,622	$1,266	$439	$824,327
Intersegment Revenues	$—	$45,477	$40,184	$9,028	$624	$95,313	$—	$(95,313)	$—
Segment Profit: Net Income (Loss)	$(450,421)	$42,470	$12,490	$50,566	$4,707	$(340,188)	$166	$3,226	$(336,796)

(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 March 31, 2016	$1,622,264	$1,664,920	$487,421	$1,984,921	$91,671	$5,851,197	$77,689	$(127,862)	$5,801,024
At September 30, 2015	$2,439,801	$1,590,525	$444,358	$1,934,730	$90,676	$6,500,090	$77,350	$(12,501)	$6,564,939

Quarter Ended March 31, 2015 (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	$165,521	$55,758	$89	$309,974	$64,167	$595,509	$388	$230	$596,127
Intersegment Revenues	$—	$23,054	$17,365	$6,521	$211	$47,151	$—	$(47,151)	$—
Segment Profit: Net Income (Loss)	$(53,562)	$23,377	$6,405	$38,238	$3,373	$17,831	$98	$(1,260)	$16,669

Six Months Ended March 31, 2015 (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	$370,186	$107,504	$235	$520,047	$120,333	$1,118,305	$1,271	$460	$1,120,036
Intersegment Revenues	$—	$44,515	$41,793	$11,055	$417	$97,780	$—	$(97,780)	$—
Segment Profit: Net Income (Loss)	$(26,842)	$44,155	$18,028	$60,831	$6,199	$102,371	$93	$(1,055)	$101,409

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Retirement Plan And Other Post-Retirement Benefits

6 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [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 March 31,	2016			2015			2016			2015
Service Cost	$	2,928		$	3,012		$	583		$	673
Interest Cost	10,579			10,304			5,096			4,821
Expected Return on Plan Assets	(14,842		)	(14,904		)	(7,883		)	(8,522		)
Amortization of Prior Service Cost (Credit)	308			46			(228		)	(478		)
Amortization of Losses	8,062			9,032			1,382			1,037
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	5,609			7,055			6,599			7,396
Net Periodic Benefit Cost	$	12,644		$	14,545		$	5,549		$	4,927

	Retirement Plan						Other Post-Retirement Benefits
Six Months Ended March 31,	2016			2015			2016			2015
Service Cost	$	5,855		$	6,024		$	1,166		$	1,346
Interest Cost	21,158			20,608			10,193			9,642
Expected Return on Plan Assets	(29,685		)	(29,808		)	(15,768		)	(17,044		)
Amortization of Prior Service Cost (Credit)	617			92			(456		)	(956		)
Amortization of Losses	16,124			18,065			2,765			2,074
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	7,516			8,346			10,720			12,316
Net Periodic Benefit Cost	$	21,585		$	23,327		$	8,620		$	7,378

⁽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 six months endedMarch 31, 2016, the Company contributed $4.0 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $1.8 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits.  In the remainder of 2016, the Company expects to make no additional contributions to the Retirement Plan. In the remainder of 2016, the Company expects to contribute approximately $0.8 million to its VEBA trusts and 401(h) accounts.

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Regulatory Matters

6 Months Ended

Mar. 31, 2016

Regulatory Assets and Liabilities, Other Disclosures [Abstract]

Regulatory Matters

Regulatory Matters

Following negotiations and other proceedings, on December 6, 2013, Distribution Corporation filed an agreement, also executed by the Department of Public Service and intervenors, extending existing rates through, at a minimum, September 30, 2015. Although customer rates were not changed, the parties agreed that the allowed rate of return on equity would be set, for ratemaking purposes, at 9.1%.  Following conventional practice in New York, the agreement authorizes an “earnings sharing mechanism” (“ESM”).  The ESM distributes earnings above the allowed rate of return as follows:  from 9.5% to 10.5%, 50% would be allocated to shareholders, and 50% will be deferred for the benefit of customers; above 10.5%, 20% would be allocated to shareholders and 80% will be deferred for the benefit of customers.  The agreement further authorizes, and rates reflect, an increase in Distribution Corporation’s pipeline replacement spending by $8.2 million per year of the agreement.  The agreement contains other terms and conditions of service that are customary for settlement agreements recently approved by the NYPSC.  A $7.5 million refund provision was passed back to customers during 2014 after the NYPSC approved the settlement agreement without modification in an order issued on May 8, 2014. All significant terms of the agreement, including existing rates, continue in effect beyond September 30, 2015 until modified by the NYPSC. The agreement also states that nothing in the agreement precludes the parties from meeting to discuss extending the agreement on mutually acceptable terms, and presenting such extension to the NYPSC for approval. On May 22, 2015, Distribution Corporation filed with the NYPSC a Notice of Impending Settlement Discussions stating that settlement discussions would be scheduled in the near future, and that such discussions might include, among other things, the possible extension of the agreement on mutually acceptable terms, and on October 21, 2015, Distribution Corporation filed with the NYPSC a Supplemental Notice of Impending Settlement Discussions.

Settlement discussions did not lead to a settlement and, on April 28, 2016, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by approximately $41.7 million. Distribution Corporation explained in the filing that its request for rate relief was necessitated by a revenue requirement driven primarily by rate base growth, higher operating expense and higher depreciation expense that are not reflected in current rates, among other things. The rate filing includes a proposal for system infrastructure modernization that includes the acceleration of Distribution Corporation’s replacement of certain gas mains, which are of a type generically classified by the NYPSC as “leak prone pipe”. The NYPSC may accept, reject or modify the Company’s filing. Assuming standard procedure, new rates, if accepted, would become effective on or about April 1, 2017. The outcome of the proceeding cannot be ascertained at this time.

FERC Rate Proceedings

Supply Corporation's current rate settlement requires a rate case filing no later than December 31, 2019 and prohibits any party from seeking to initiate a rate case proceeding before September 30, 2017.

Empire does not have a rate case currently on file with the FERC, but by order dated January 21, 2016, the FERC began a NGA Section 5 rate review of Empire's rates. As required by that order, Empire filed a Cost and Revenue Study on April 5, 2016. Pursuant to the Procedural Schedule, discovery began April 6, 2016, with a hearing scheduled to commence on November 8, 2016.

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Summary Of Significant Accounting Policies (Policy)

6 Months Ended

Mar. 31, 2016

Accounting Policies [Abstract]

Principles Of Consolidation

Principles of Consolidation.  The Company consolidates all entities in which it has a controlling financial interest.  All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Reclassification

Reclassification. Due to the adoption of the authoritative guidance regarding the presentation of deferred income taxes, certain prior year amounts have been reclassified to conform with current year presentation. The Company reclassified Deferred Income Taxes of $137.2 million previously shown as Current Assets in the Company's 2015 Form 10-K to Deferred Income Taxes shown as Deferred Credits on the Consolidated Balance Sheet at September 30, 2015.

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, 2015, 2014 and 2013 that are included in the Company's 2015 Form 10-K.  The consolidated financial statements for the year ended September 30, 2016 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.

The earnings for the six months ended March 31, 2016 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2016.  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 Statement Of Cash Flows

Consolidated Statement of Cash Flows.  For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.

Hedging Collateral Deposits

Hedging Collateral Deposits.  This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions.  In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial 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 market, 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 $17.5 million at March 31, 2016, 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 $163.4 million and $176.3 million at March 31, 2016 and September 30, 2015, 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.  The book value of the oil and gas properties exceeded the ceiling at December 31, 2015 as well as March 31, 2016. As such, the Company recognized pre-tax impairment charges of $397.4 million and $832.9 million for the quarter and six months ended March 31, 2016, respectively. Deferred income tax benefits of $166.9 million and $349.8 million related to the impairment charges were also recognized for the quarter and six months ended March 31, 2016, respectively. In adjusting estimated future cash flows for hedging under the ceiling test at December 31, 2015 and March 31, 2016, estimated future net cash flows were increased by $253.7 million and $252.1 million, respectively.

On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. Under the terms of the agreement, Seneca and IOG will jointly participate in a program that will develop up to 80 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest and is obligated to participate in the first 42 wells, and has a one-time option to participate in the remaining 38 wells that can be exercised on or before July 1, 2016. With respect to the first 42 wells, IOG has committed to fund up to $231 million to develop the joint wells. As of March 31, 2016, Seneca had received $104.9 million of cash and had recorded a $10.3 million receivable in recognition of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the first 42 wells. The cash proceeds and receivable were recorded by Seneca as a $115.2 million reduction of property, plant and equipment. As the fee-owner of the property’s mineral rights, Seneca retains a 7.5% royalty interest and the remaining 20% working interest (26% net revenue interest) in the first 42 wells. If IOG exercises its option to participate in the remaining 38 wells, IOG has agreed to fund up to an additional $211 million to develop such joint wells. Seneca will retain a 10% royalty and the remaining 20% working interest (28% net revenue interest) in the remaining 38 wells. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss).  The components of Accumulated Other Comprehensive Income (Loss) and changes for the quarter and six months ended March 31, 2016 and 2015, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): 

	Gains and Losses on Derivative Financial Instruments			Gains and Losses on Securities Available for Sale			Funded Status of the Pension and Other Post-Retirement Benefit Plans			Total
Three Months Ended March 31, 2016
Balance at January 1, 2016	$	162,728		$	5,522		$	(69,794	)	$	98,456
Other Comprehensive Gains and Losses Before Reclassifications	19,578			12			—			19,590
Amounts Reclassified From Other Comprehensive Income (Loss)	(35,635		)	(225		)	—			(35,860		)
Balance at March 31, 2016	$	146,671		$	5,309		$	(69,794	)	$	82,186
Six Months Ended March 31, 2016
Balance at October 1, 2015	$	157,197		$	5,969		$	(69,794	)	$	93,372
Other Comprehensive Gains and Losses Before Reclassifications	64,273			(435		)	—			63,838
Amounts Reclassified From Other Comprehensive Income (Loss)	(74,799		)	(225		)	—			(75,024		)
Balance at March 31, 2016	$	146,671		$	5,309		$	(69,794	)	$	82,186
Three Months Ended March 31, 2015
Balance at January 1, 2015	$	170,363		$	8,130		$	(56,020	)	$	122,473
Other Comprehensive Gains and Losses Before Reclassifications	35,263			166			—			35,429
Amounts Reclassified From Other Comprehensive Income (Loss)	(31,213		)	—			—			(31,213		)
Balance at March 31, 2015	$	174,413		$	8,296		$	(56,020	)	$	126,689
Six Months Ended March 31, 2015
Balance at October 1, 2014	$	43,659		$	8,382		$	(56,020	)	$	(3,979	)
Other Comprehensive Gains and Losses Before Reclassifications	176,143			(86		)	—			176,057
Amounts Reclassified From Other Comprehensive Income (Loss)	(45,389		)	—			—			(45,389		)
Balance at March 31, 2015	$	174,413		$	8,296		$	(56,020	)	$	126,689

Reclassifications Out Of Accumulated Other Comprehensive Income (Loss)

Reclassifications Outof Accumulated Other Comprehensive Income (Loss).  The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the quarter and six months ended March 31, 2016 and 2015 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

Details About Accumulated Other Comprehensive Income (Loss) Components	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income												Affected Line Item in the Statement Where Net Income (Loss) is Presented
	Three Months Ended March 31,						Six Months Ended March 31,
	2016			2015			2016			2015
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts		$57,914			$53,471			$114,242			$73,508		Operating Revenues
Commodity Contracts	3,530			659			4,450			4,887			Purchased Gas
Foreign Currency Contracts	(209		)	—			(287		)	—			Operation and Maintenance Expense
Gains (Losses) on Securities Available for Sale	388			—			388			—			Other Income
	61,623			54,130			118,793			78,395			Total Before Income Tax
	(25,763		)	(22,917		)	(43,769		)	(33,006		)	Income Tax Expense
		$35,860			$31,213			$75,024			$45,389		Net of Tax

Other Current Assets

Other Current Assets.  The components of the Company’s Other Current Assets are as follows (in thousands):

	At March 31, 2016		At September 30, 2015
Prepayments	$	5,923	$	10,743
Prepaid Property and Other Taxes	21,757		13,709
Fair Values of Firm Commitments	12,941		15,775
Regulatory Assets	16,093		20,438
	$	56,714	$	60,665

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 March 31, 2016		At September 30, 2015
Accrued Capital Expenditures	$	38,299	$	53,652
Regulatory Liabilities	20,786		5,346
Reserve for Gas Replacement	17,469		—
Federal Income Taxes Payable	4,102		5,686
State Income Taxes Payable	224		1,170
Other	24,045		30,703
	$	104,925	$	96,557

Earnings Per Common Share

Earnings Per Common Share.  Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.  For purposes of determining earnings per common share, the potentially dilutive securities the Company has outstanding are stock options, SARs, restricted stock units and performance shares.  As the Company recognized a net loss for both the quarter and six months ended March 31, 2016, the aforementioned securities, amounting to 386,626 and 451,291 securities, were not recognized in the diluted earnings per share calculation for the quarter and six months ended March 31, 2016, respectively. For 2015, 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 5 and 2,565 securities excluded as being antidilutive for the quarter and six months ended March 31, 2015, respectively.

Stock-Based Compensation

Stock-Based Compensation.  The Company granted 309,996 performance shares during the six months ended March 31, 2016. The weighted average fair value of such performance shares was $30.71 per share for the six months ended March 31, 2016. 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 six months ended March 31, 2016 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2015 to September 30, 2018.  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 six months ended March 31, 2016 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2015 to September 30, 2018.  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 99,843 non-performance based restricted stock units during the six months ended March 31, 2016.  The weighted average fair value of such non-performance based restricted stock units was $35.57 per share for the six months ended March 31, 2016. 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.

No stock options, SARs or restricted share awards were granted by the Company during the six months ended March 31, 2016.

New Authoritative Accounting And Financial Reporting Guidance

New Authoritative Accounting and Financial Reporting Guidance. In May 2014, the FASB issued authoritative guidance regarding revenue recognition. The authoritative guidance provides a single, comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The original effective date of this authoritative guidance was as of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements and disclosures.

In June 2014, the FASB issued authoritative guidance regarding accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the employee has completed the requisite service period. This authoritative guidance requires that such performance targets that affect vesting be treated as performance conditions, meaning that the performance target should not be factored in the calculation of the award at the grant date. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2017, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

In July 2015, the FASB issued authoritative guidance simplifying inventory measurement by requiring companies to value inventory at the lower of cost and net realizable value. The authoritative guidance applies to all inventory other than inventory that is measured using last-in, first-out or the retail inventory method. The intention of this authoritative guidance is to eliminate some diversity in practice. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2018, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

In November 2015, the FASB issued authoritative guidance simplifying the presentation of deferred income taxes. The authoritative guidance requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The Company early adopted this guidance at December 31, 2015 on a retrospective basis.

In January 2016, the FASB issued authoritative guidance regarding the recognition and measurement of financial assets and liabilities. The authoritative guidance primarily affects the accounting for equity investments, financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. All equity investments in unconsolidated entities will be measured at fair value through earnings rather than through other comprehensive income. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2019. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

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 is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

In March 2016, the FASB issued authoritative guidance simplifying several aspects of the accounting for stock-based compensation. Among other things, the revised guidance specifies that the difference between the compensation recognized for financial reporting purposes and the deduction allowed for tax purposes (excess tax benefit or deficiency) shall be recognized as income tax expense or benefit in the income statement, as opposed to the current treatment where this difference is recognized as additional paid-in capital in the balance sheet. For statement of cash flows purposes, the revised guidance specifies that the excess tax benefit shall be classified along with other income tax cash flows as an item impacting cash flow from operating activities. The current guidance separates the excess tax benefit from other income tax cash flows and classifies the excess tax benefit as an item impacting cash flow from financing activities. The new authoritative guidance will be effective as of the Company’s first quarter of fiscal 2018, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

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Summary Of Significant Accounting Policies (Tables)

6 Months Ended

Mar. 31, 2016

Accounting Policies [Abstract]

Components Of Accumulated Other Comprehensive Income (Loss)

The components of Accumulated Other Comprehensive Income (Loss) and changes for the quarter and six months ended March 31, 2016 and 2015, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): 

	Gains and Losses on Derivative Financial Instruments			Gains and Losses on Securities Available for Sale			Funded Status of the Pension and Other Post-Retirement Benefit Plans			Total
Three Months Ended March 31, 2016
Balance at January 1, 2016	$	162,728		$	5,522		$	(69,794	)	$	98,456
Other Comprehensive Gains and Losses Before Reclassifications	19,578			12			—			19,590
Amounts Reclassified From Other Comprehensive Income (Loss)	(35,635		)	(225		)	—			(35,860		)
Balance at March 31, 2016	$	146,671		$	5,309		$	(69,794	)	$	82,186
Six Months Ended March 31, 2016
Balance at October 1, 2015	$	157,197		$	5,969		$	(69,794	)	$	93,372
Other Comprehensive Gains and Losses Before Reclassifications	64,273			(435		)	—			63,838
Amounts Reclassified From Other Comprehensive Income (Loss)	(74,799		)	(225		)	—			(75,024		)
Balance at March 31, 2016	$	146,671		$	5,309		$	(69,794	)	$	82,186
Three Months Ended March 31, 2015
Balance at January 1, 2015	$	170,363		$	8,130		$	(56,020	)	$	122,473
Other Comprehensive Gains and Losses Before Reclassifications	35,263			166			—			35,429
Amounts Reclassified From Other Comprehensive Income (Loss)	(31,213		)	—			—			(31,213		)
Balance at March 31, 2015	$	174,413		$	8,296		$	(56,020	)	$	126,689
Six Months Ended March 31, 2015
Balance at October 1, 2014	$	43,659		$	8,382		$	(56,020	)	$	(3,979	)
Other Comprehensive Gains and Losses Before Reclassifications	176,143			(86		)	—			176,057
Amounts Reclassified From Other Comprehensive Income (Loss)	(45,389		)	—			—			(45,389		)
Balance at March 31, 2015	$	174,413		$	8,296		$	(56,020	)	$	126,689

Schedule Of Reclassifications Out Of Accumulated Other Comprehensive Income (Loss)

The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the quarter and six months ended March 31, 2016 and 2015 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

Details About Accumulated Other Comprehensive Income (Loss) Components	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income												Affected Line Item in the Statement Where Net Income (Loss) is Presented
	Three Months Ended March 31,						Six Months Ended March 31,
	2016			2015			2016			2015
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts		$57,914			$53,471			$114,242			$73,508		Operating Revenues
Commodity Contracts	3,530			659			4,450			4,887			Purchased Gas
Foreign Currency Contracts	(209		)	—			(287		)	—			Operation and Maintenance Expense
Gains (Losses) on Securities Available for Sale	388			—			388			—			Other Income
	61,623			54,130			118,793			78,395			Total Before Income Tax
	(25,763		)	(22,917		)	(43,769		)	(33,006		)	Income Tax Expense
		$35,860			$31,213			$75,024			$45,389		Net of Tax

Schedule Of Other Current Assets

The components of the Company’s Other Current Assets are as follows (in thousands):

	At March 31, 2016		At September 30, 2015
Prepayments	$	5,923	$	10,743
Prepaid Property and Other Taxes	21,757		13,709
Fair Values of Firm Commitments	12,941		15,775
Regulatory Assets	16,093		20,438
	$	56,714	$	60,665

Schedule Of Other Accruals And Current Liabilities

The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):

	At March 31, 2016		At September 30, 2015
Accrued Capital Expenditures	$	38,299	$	53,652
Regulatory Liabilities	20,786		5,346
Reserve for Gas Replacement	17,469		—
Federal Income Taxes Payable	4,102		5,686
State Income Taxes Payable	224		1,170
Other	24,045		30,703
	$	104,925	$	96,557

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Fair Value Measurements (Tables)

6 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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 March 31, 2016 and September 30, 2015.  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 March 31, 2016
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)			Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	65,530	$	—	$	—	$	—		$	65,530
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	2,754		—		—		(2,754		)	—
Over the Counter Swaps – Gas and Oil	—		255,867		—		(406		)	255,461
Foreign Currency Contacts	—		—		—		(1,745		)	(1,745		)
Other Investments:
Balanced Equity Mutual Fund	36,297		—		—		—			36,297
Fixed Income Mutual Fund	25,085		—		—		—			25,085
Common Stock – Financial Services Industry	3,942		—		—		—			3,942
Hedging Collateral Deposits	9,963		—		—		—			9,963
Total	$	143,571	$	255,867	$	—	$	(4,905	)	$	394,533
Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	10,311	$	—	$	—	$	(2,754	)	$	7,557
Over the Counter Swaps – Gas and Oil	—		2,713		—		(406		)	2,307
Foreign Currency Contracts	—		1,745		—		(1,745		)	—
Total	$	10,311	$	4,458	$	—	$	(4,905	)	$	9,864
Total Net Assets/(Liabilities)	$	133,260	$	251,409	$	—	$	—		$	384,669

Recurring Fair Value Measures	At fair value as of September 30, 2015
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)			Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	92,196	$	—	$	—	$	—		$	92,196
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	6,373		—		—		(6,373		)	—
Over the Counter Swaps – Gas and Oil	—		272,335		1,791		(808		)	273,318
Foreign Currency Contracts	—		—		—		(2,955		)	(2,955		)
Other Investments:
Balanced Equity Mutual Fund	34,884		—		—		—			34,884
Fixed Income Mutual Fund	8,004		—		—		—			8,004
Common Stock – Financial Services Industry	4,318		—		—		—			4,318
Other Common Stock	450		—		—		—			450
Hedging Collateral Deposits	11,124		—		—		—			11,124
Total	$	157,349	$	272,335	$	1,791	$	(10,136	)	$	421,339
Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	15,276	$	—	$	—	$	(6,373	)	$	8,903
Over the Counter Swaps – Gas and Oil	—		1,981		—		(808		)	1,173
Foreign Currency Contracts	—		2,955		—		(2,955		)	—
Total	$	15,276	$	4,936	$	—	$	(10,136	)	$	10,076
Total Net Assets/(Liabilities)	$	142,073	$	267,399	$	1,791	$	—		$	411,263

⁽¹⁾  Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Fair Value Measurements Using Unobservable Inputs (Level 3)

The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the quarters and six months ended March 31, 2016 and 2015, respectively. For the quarters and six months ended March 31, 2016 and March 31, 2015, no transfers in or out of Level 1 or Level 2 occurred. There were no purchases or sales of derivative financial instruments during the periods presented in the tables below.  All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below (amounts in parentheses indicate credits in the derivative asset/liability accounts).

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)			Total Gains/Losses
	October 1, 2015		Gains/Losses Realized and Included in Earnings				Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)		Transfer In/Out of Level 3		March 31, 2016
Derivative Financial Instruments(2)	$	1,791	$	(2,002	)	(1)	$	211	$	—	$	—

⁽¹⁾  Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the six months ended March 31, 2016. 

⁽²⁾  Derivative Financial Instruments are shown on a net basis.        

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)			Total Gains/Losses
	January 1, 2015		Gains/Losses Realized and Included in Earnings				Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)		Transfer In/Out of Level 3		March 31, 2015
Derivative Financial Instruments(2)	$	5,337	$	(2,949	)	(1)	$	2,438	$	—	$	4,826

⁽¹⁾  Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended March 31, 2015. 

⁽²⁾  Derivative Financial Instruments are shown on a net basis.

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)			Total Gains/Losses
	October 1, 2014		Gains/Losses Realized and Included in Earnings				Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)		Transfer In/Out of Level 3		March 31, 2015
Derivative Financial Instruments(2)	$	1,368	$	(6,804	)	(1)	$	10,262	$	—	$	4,826

⁽¹⁾  Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the six months ended March 31, 2015. 

⁽²⁾  Derivative Financial Instruments are shown on a net basis.

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Financial Instruments (Tables)

6 Months Ended

Mar. 31, 2016

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): 

	March 31, 2016				September 30, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,085,123	$	2,026,988	$	2,084,009	$	2,129,558

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 March 31, 2016 and 2015 (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 March 31,					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 March 31,					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 March 31,
	2016			2015			2016			2015			2016		2015
Commodity Contracts	$	30,876		$	60,571	Operating Revenue	$	57,914		$	53,471	Operating Revenue	$	31	$	1,469
Commodity Contracts	$	(214	)	$	594	Purchased Gas	$	3,530		$	659	Not Applicable	$	—	$	—
Foreign Currency Contracts	$	3,106		$	—	Operation and Maintenance Expense	$	(209	)	$	—	Not Applicable	$	—	$	—
Total	$	33,768		$	61,165		$	61,235		$	54,130		$	31	$	1,469

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Six Months Ended March 31, 2016 and 2015 (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 Six Months Ended March 31,				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 Six Months Ended March 31,					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 Six Months Ended March 31,
	2016		2015			2016			2015			2016		2015
Commodity Contracts	$	96,217	$	300,594	Operating Revenue	$	114,242		$	73,508	Operating Revenue	$	168	$	2,929
Commodity Contracts	$	1,999	$	4,400	Purchased Gas	$	4,450		$	4,887	Not Applicable	$	—	$	—
Foreign Currency Contracts	$	923	$	—	Operation and Maintenance Expense	$	(287	)	$	—	Not Applicable	$	—	$	—
Total	$	99,139	$	304,994		$	118,405		$	78,395		$	168	$	2,929

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 Six Months Ended March 31, 2016 (In Thousands)			Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Six Months Ended March 31, 2016 (In Thousands)
Commodity Contracts	Operating Revenues	$	5,557		$	(5,557	)
Commodity Contracts	Purchased Gas	$	(154	)	$	154
		$	5,403		$	(5,403	)

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Income Taxes (Tables)

6 Months Ended

Mar. 31, 2016

Income Tax Disclosure [Abstract]

Components Of Federal And State Income Taxes Included In The Consolidated Statements Of Income

The components of federal and state income taxes included in the Consolidated Statements of Income are as follows (in thousands):

	Six Months Ended   March 31,
	2016			2015
Current Income Taxes
Federal	$	7,995		$	36,746
State	15,537			13,199
Deferred Income Taxes
Federal	(197,982		)	13,242
State	(85,930		)	(2,891		)
	(260,380		)	60,296
Deferred Investment Tax Credit	(174		)	(208		)
Total Income Taxes	$	(260,554	)	$	60,088
Presented as Follows:
Other Income	(174		)	(208		)
Income Tax Expense (Benefit)	(260,380		)	60,296
Total Income Taxes	$	(260,554	)	$	60,088

Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate

Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income (loss) before income taxes.  The following is a reconciliation of this difference (in thousands):

	Six Months Ended   March 31,
	2016			2015
U.S. Income (Loss) Before Income Taxes	$	(597,350	)	$	161,497
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35%	$	(209,073	)	$	56,524
State Income Taxes (Benefit)	(45,756		)	6,700
Miscellaneous	(5,725		)	(3,136		)
Total Income Taxes	$	(260,554	)	$	60,088

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Business Segment Information (Tables)

6 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Financial Segment Information By Segment

Quarter Ended March 31, 2016 (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	$143,783	$56,276	$113	$212,737	$35,436	$448,345	$561	$226	$449,132
Intersegment Revenues	$—	$23,292	$21,545	$5,364	$312	$50,513	$—	$(50,513)	$—
Segment Profit: Net Income (Loss)	$(213,335)	$21,194	$7,568	$31,960	$3,484	$(149,129)	$(23)	$1,465	$(147,687)

Six Months Ended March 31, 2016 (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	$295,749	$109,630	$238	$356,585	$60,420	$822,622	$1,266	$439	$824,327
Intersegment Revenues	$—	$45,477	$40,184	$9,028	$624	$95,313	$—	$(95,313)	$—
Segment Profit: Net Income (Loss)	$(450,421)	$42,470	$12,490	$50,566	$4,707	$(340,188)	$166	$3,226	$(336,796)

(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 March 31, 2016	$1,622,264	$1,664,920	$487,421	$1,984,921	$91,671	$5,851,197	$77,689	$(127,862)	$5,801,024
At September 30, 2015	$2,439,801	$1,590,525	$444,358	$1,934,730	$90,676	$6,500,090	$77,350	$(12,501)	$6,564,939

Quarter Ended March 31, 2015 (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	$165,521	$55,758	$89	$309,974	$64,167	$595,509	$388	$230	$596,127
Intersegment Revenues	$—	$23,054	$17,365	$6,521	$211	$47,151	$—	$(47,151)	$—
Segment Profit: Net Income (Loss)	$(53,562)	$23,377	$6,405	$38,238	$3,373	$17,831	$98	$(1,260)	$16,669

Six Months Ended March 31, 2015 (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	$370,186	$107,504	$235	$520,047	$120,333	$1,118,305	$1,271	$460	$1,120,036
Intersegment Revenues	$—	$44,515	$41,793	$11,055	$417	$97,780	$—	$(97,780)	$—
Segment Profit: Net Income (Loss)	$(26,842)	$44,155	$18,028	$60,831	$6,199	$102,371	$93	$(1,055)	$101,409

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Retirement Plan And Other Post-Retirement Benefits (Tables)

6 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost

Components of Net Periodic Benefit Cost (in thousands):

	Retirement Plan						Other Post-Retirement Benefits
Three Months Ended March 31,	2016			2015			2016			2015
Service Cost	$	2,928		$	3,012		$	583		$	673
Interest Cost	10,579			10,304			5,096			4,821
Expected Return on Plan Assets	(14,842		)	(14,904		)	(7,883		)	(8,522		)
Amortization of Prior Service Cost (Credit)	308			46			(228		)	(478		)
Amortization of Losses	8,062			9,032			1,382			1,037
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	5,609			7,055			6,599			7,396
Net Periodic Benefit Cost	$	12,644		$	14,545		$	5,549		$	4,927

	Retirement Plan						Other Post-Retirement Benefits
Six Months Ended March 31,	2016			2015			2016			2015
Service Cost	$	5,855		$	6,024		$	1,166		$	1,346
Interest Cost	21,158			20,608			10,193			9,642
Expected Return on Plan Assets	(29,685		)	(29,808		)	(15,768		)	(17,044		)
Amortization of Prior Service Cost (Credit)	617			92			(456		)	(956		)
Amortization of Losses	16,124			18,065			2,765			2,074
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	7,516			8,346			10,720			12,316
Net Periodic Benefit Cost	$	21,585		$	23,327		$	8,620		$	7,378

⁽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.

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Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended			6 Months Ended		12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015	Sep. 30, 2015	Sep. 30, 2016	Dec. 01, 2015
Summary Of Significant Accounting Policies [Line Items]
Reclassification of Current Assets						$ 137,200
Gas stored underground	$ (8,599)			$ (8,599)		(34,252)
Capitalized costs of unproved properties excluded from amortization				$ 163,400		176,300
Full cost ceiling test discount factor	10.00%			10.00%
Impairment of Oil and Gas Producing Properties	$ 397,443		$ 120,348	$ 832,894	$ 120,348
Increase estimated future net cash flows	$ 252,100	$ 253,700
Net Proceeds from Sale of Oil and Gas Producing Properties				$ 104,938	$ 0
Antidilutive securities	386,626		5	451,291	2,565
Receivable from Sale of Oil and Gas Producing Properties				$ 10,297	$ 0
Reserve For Gas Replacement [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground	$ 17,469			17,469		$ 0
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%
Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Net Proceeds from Sale of Oil and Gas Producing Properties				104,900
Receivable from Sale of Oil and Gas Producing Properties				10,300
Reduction in Property, Plant and Equipment	115,200			115,200
Impairment of Oil and Gas Producing Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Deferred Income Tax Benefit	$ 166,900			$ 349,800
Stock Options [Member]
Summary Of Significant Accounting Policies [Line Items]
Stock options granted				0
Restricted Shares [Member]
Summary Of Significant Accounting Policies [Line Items]
Share based compensation other than options grants in period				0
Stock Appreciation Right [Member]
Summary Of Significant Accounting Policies [Line Items]
Share based compensation other than options grants in period				0
Non-performance Based Restricted Stock Units [Member]
Summary Of Significant Accounting Policies [Line Items]
Share based compensation other than options grants in period				99,843
Granted in fiscal year, weighted average grant date fair value				$ 35.57
Performance Shares [Member]
Summary Of Significant Accounting Policies [Line Items]
Share based compensation other than options grants in period				309,996
Granted in fiscal year, weighted average grant date fair value				$ 30.71
Subsequent Event [Member] | Reserve For Gas Replacement [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground							$ 0
Maximum [Member] | IOG-CRV Marcellus, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed								80
Partner Commitment to Develop Joint Wells								$ 231,000
Initial Participation [Member] | IOG-CRV Marcellus, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed								42
Initial Participation [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Royalty Interest								7.50%
Partner Working Interest In Joint Wells								20.00%
Partner Net Revenue Interest in Joint Wells								26.00%
Additional Option to Participate [Member] | IOG-CRV Marcellus, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed								38
Partner Commitment to Develop Joint Wells								$ 211,000
Additional Option to Participate [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Royalty Interest								10.00%
Partner Working Interest In Joint Wells								20.00%
Partner Net Revenue Interest in Joint Wells								28.00%
After Internal Rate of Return Achieved [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Partner Working Interest In Joint Wells								85.00%

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Summary Of Significant Accounting Policies (Components Of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Accumulated Other Comprehensive Income [Roll Forward]
Balance at Beginning of Period	$ 98,456	$ 122,473	$ 93,372	$ (3,979)
Other Comprehensive Gains and Losses Before Reclassification	19,590	35,429	63,838	176,057
Amounts Reclassified From Other Comprehensive Income (Loss)	(35,860)	(31,213)	(75,024)	(45,389)
Balance at End of Period	82,186	126,689	82,186	126,689
Gains And Losses On Derivative Financial Instruments [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Balance at Beginning of Period	162,728	170,363	157,197	43,659
Other Comprehensive Gains and Losses Before Reclassification	19,578	35,263	64,273	176,143
Amounts Reclassified From Other Comprehensive Income (Loss)	(35,635)	(31,213)	(74,799)	(45,389)
Balance at End of Period	146,671	174,413	146,671	174,413
Gains And Losses On Securities Available For Sale [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Balance at Beginning of Period	5,522	8,130	5,969	8,382
Other Comprehensive Gains and Losses Before Reclassification	12	166	(435)	(86)
Amounts Reclassified From Other Comprehensive Income (Loss)	(225)	0	(225)	0
Balance at End of Period	5,309	8,296	5,309	8,296
Funded Status Of The Pension And Other Post-Retirement Benefit Plans [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Balance at Beginning of Period	(69,794)	(56,020)	(69,794)	(56,020)
Other Comprehensive Gains and Losses Before Reclassification	0	0	0	0
Amounts Reclassified From Other Comprehensive Income (Loss)	0	0	0	0
Balance at End of Period	$ (69,794)	$ (56,020)	$ (69,794)	$ (56,020)

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Summary Of Significant Accounting Policies (Reclassification Out Of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating Revenues	$ 449,132	$ 596,127	$ 824,327	$ 1,120,036
Purchased Gas	81,623	190,600	123,691	317,690
Other Income	3,236	1,388	5,654	2,571
Income Before Income Taxes	(263,717)	21,805	(597,176)	161,705
Income Tax Expense	116,030	(5,136)	260,380	(60,296)
Net Income (Loss) Available for Common Stock	(147,687)	16,669	(336,796)	101,409
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income Before Income Taxes	61,623	54,130	118,793	78,395
Income Tax Expense	(25,763)	(22,917)	(43,769)	(33,006)
Net Income (Loss) Available for Common Stock	35,860	31,213	75,024	45,389
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income [Member] | Gains (Losses) on Securities Available for Sale [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other Income	388	0	388	0
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income [Member] | Commodity Contracts [Member] | Gains And Losses On Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating Revenues	57,914	53,471	114,242	73,508
Purchased Gas	3,530	659	4,450	4,887
Foreign Currency Contracts [Member] | Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income [Member] | Gains And Losses On Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operation and Maintenance	$ (209)	$ 0	$ (287)	$ 0

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Summary Of Significant Accounting Policies (Components Of Other Current Assets) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Sep. 30, 2015
Summary Of Significant Accounting Policies [Line Items]
Prepayments	$ 5,923	$ 10,743
Prepaid Property and Other Taxes	21,757	13,709
Fair Values of Firm Commitments	12,941	15,775
Regulatory Assets	16,093	20,438
Other Current Assets	$ 56,714	$ 60,665

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Summary Of Significant Accounting Policies (Schedule Of Other Accruals And Current Liabilities) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Sep. 30, 2015
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liabilities	$ 20,786	$ 5,346
Reserve for Gas Replacement	(8,599)	(34,252)
Other	24,045	30,703
Other Accruals and Current Liabilities	104,925	96,557
Accrued Capital Expenditures [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	38,299	53,652
Reserve For Gas Replacement [Member]
Summary Of Significant Accounting Policies [Line Items]
Reserve for Gas Replacement	17,469	0
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Payable	4,102	5,686
State [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Payable	$ 224	$ 1,170

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Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Sep. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits	[1]	$ 9,963	$ 11,124
Fair value measured on recurring basis, net	[1]	(384,669)	(411,263)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits		0	0
Fair value measured on recurring basis, net		0	(1,791)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits		9,963	11,124
Fair value measured on recurring basis, net		(133,260)	(142,073)
Fair Value, Inputs, Level 1 [Member] | Futures [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits		$ 10,000	$ 11,100

[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.

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Fair Value Measurements (Recurring Fair Value Measures Of Assets And Liabilities) (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Sep. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds	[1]	$ 65,530	$ 92,196
Hedging Collateral Deposits	[1]	9,963	11,124
Total Assets	[1]	394,533	421,339
Total Liabilities	[1]	9,864	10,076
Total Net Assets/(Liabilities)	[1]	384,669	411,263
Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	0	0
Derivative Liability	[1]	7,557	8,903
Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	255,461	273,318
Derivative Liability	[1]	2,307	1,173
Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(1,745)	(2,955)
Derivative Liability	[1]	0	0
Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	36,297	34,884
Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	25,085	8,004
Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	3,942	4,318
Other Common Stock [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]		450
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds		65,530	92,196
Hedging Collateral Deposits		9,963	11,124
Total Assets		143,571	157,349
Total Liabilities		10,311	15,276
Total Net Assets/(Liabilities)		133,260	142,073
Fair Value, Inputs, Level 1 [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		2,754	6,373
Derivative Liability		10,311	15,276
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		36,297	34,884
Fair Value, Inputs, Level 1 [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		25,085	8,004
Fair Value, Inputs, Level 1 [Member] | Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		3,942	4,318
Fair Value, Inputs, Level 1 [Member] | Other Common Stock [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments			450
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		255,867	272,335
Total Liabilities		4,458	4,936
Total Net Assets/(Liabilities)		251,409	267,399
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		255,867	272,335
Derivative Liability		2,713	1,981
Fair Value, Inputs, Level 2 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		1,745	2,955
Fair Value, Inputs, Level 2 [Member] | Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 2 [Member] | Fixed Income 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 2 [Member] | Other Common Stock [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments			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	1,791
Total Liabilities		0	0
Total Net Assets/(Liabilities)		0	1,791
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	1,791
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
Fair Value, Inputs, Level 3 [Member] | Other Common Stock [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments			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]	(4,905)	(10,136)
Total Liabilities	[1]	(4,905)	(10,136)
Total Net Assets/(Liabilities)	[1]	0	0
Netting Adjustments [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(2,754)	(6,373)
Derivative Liability	[1]	(2,754)	(6,373)
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]	(406)	(808)
Derivative Liability	[1]	(406)	(808)
Netting Adjustments [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(1,745)	(2,955)
Derivative Liability	[1]	(1,745)	(2,955)
Netting Adjustments [Member] | Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	0	0
Netting Adjustments [Member] | Fixed Income 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
Netting Adjustments [Member] | Other Common Stock [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]		$ 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.

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Fair Value Measurements (Fair Value Measurements Using Unobservable Inputs (Level 3)) (Details) - Derivative Financial Instruments [Member] - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Mar. 31, 2015		Mar. 31, 2016		Mar. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Roll Forward]
Beginning Balance	[1]	$ 5,337		$ 1,791		$ 1,368
Total Gains/Losses, Realized and Included in Earnings	[1]	(2,949)	[2]	(2,002)	[3]	(6,804)	[4]
Total Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)	[1]	2,438		211		10,262
Transfer In/Out of Level 3	[1]	0		0		0
Ending Balance	[1]	$ 4,826		$ 0		$ 4,826

[1] Derivative Financial Instruments are shown on a net basis.

[2] Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended March 31, 2015.

[3] Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the six months ended March 31, 2016.

[4] Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the six months ended March 31, 2015.

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Financial Instruments (Narrative) (Details) $ in Thousands		6 Months Ended
		Mar. 31, 2016 USD ($) counterparty bbl MMcf	Sep. 30, 2015 USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Cash surrender value of life insurance		$ 38,900	$ 45,300
Net hedging gains/losses in accumulated other comprehensive income (loss)		252,900
After tax net hedging gains (losses) in accumulated other comprehensive income (loss)		146,700
Pre-Tax Net Hedging Gains (Losses) Reclassified Within Twelve Months		180,300
After Tax Net Hedging Gains (Losses) Reclassified Within Twelve Months		104,600
Collateral Received from Counterparties by the Company		24,200
Hedging collateral deposits	[1]	9,963	11,124
Fair market value of derivative asset with a credit-risk related contingency		162,900
Over-The-Counter Swap Position
Derivative Instruments, Gain (Loss) [Line Items]
Maximum credit risk exposure per counterparty		$ 43,200
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		16
Number of counterparties in net gain position | counterparty		15
Credit risk exposure per counterparty		$ 16,800
Hedging collateral deposits		$ 0
Fixed Price Purchase 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		100
Withdrawal of Storage Mmcf [Member] | Energy Marketing [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas | MMcf		500
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		13,800
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		13,200
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		139,500
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		3,100
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		1,467,000
Exchange Traded Futures Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Hedging collateral deposits		$ 10,000
Equity Mutual Fund [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair value		36,300	34,900
Gross unrealized gain		6,200	6,500
Fixed Income Mutual Fund [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair value		25,100	8,000
Gross unrealized loss		100
Insurance Company Stock [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair value		3,900	4,300
Gross unrealized gain		2,200	2,600
Foreign Currency Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Liability	[1]	0	$ 0
Derivative, Notional Amount		$ 84,500
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		12

[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.

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Financial Instruments (Long-Term Debt) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Sep. 30, 2015
Financial Instruments, Owned, at Fair Value [Abstract]
Carrying Amount	$ 2,085,123	$ 2,084,009
Fair Value	$ 2,026,988	$ 2,129,558

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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		6 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion)	$ 33,768	$ 61,165	$ 99,139	$ 304,994
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)	61,235	54,130	118,405	78,395
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	31	1,469	168	2,929
Foreign Currency Contracts [Member] | Operation and Maintenance Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion)	3,106	0	923	0
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	(209)	0	(287)	0
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)	30,876	60,571	96,217	300,594
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)	57,914	53,471	114,242	73,508
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	31	1,469	168	2,929
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)	(214)	594	1,999	4,400
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)	3,530	659	4,450	4,887
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	$ 0	$ 0	$ 0	$ 0

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Financial Instruments (Schedule Of Derivatives And Hedged Items In Fair Value Hedging Relationships) (Details) $ in Thousands	6 Months Ended
	Mar. 31, 2016 USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on the Derivative Recognized in the Consolidated Statement of Income	$ 5,403
Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income	(5,403)
Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on the Derivative Recognized in the Consolidated Statement of Income	5,557
Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income	(5,557)
Purchased Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on the Derivative Recognized in the Consolidated Statement of Income	(154)
Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income	$ 154

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Income Taxes Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits Decrease			$ 2,600
Income Tax Expense (Benefit)	$ (116,030)	$ 5,136	(260,380)	$ 60,296
Settlement with Taxing Authority [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Income Tax Expense (Benefit)			$ (500)

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Income Taxes (Components Of Federal And State Income Taxes Included In The Consolidated Statements Of Income) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Current Income Taxes [Abstract]
Federal			$ 7,995	$ 36,746
State			15,537	13,199
Deferred Income Taxes [Abstract]
Federal			(197,982)	13,242
State			(85,930)	(2,891)
Income Tax Expense (Benefit)	$ (116,030)	$ 5,136	(260,380)	60,296
Deferred Investment Tax Credit			(174)	(208)
Total Income Taxes			(260,554)	60,088
Presented as Follows [Abstract]
Other Income			(174)	(208)
Income Tax Expense (Benefit)	$ (116,030)	$ 5,136	$ (260,380)	$ 60,296

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Income Taxes (Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate) (Details) - USD ($) $ in Thousands	6 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Tax Disclosure [Abstract]
U.S. Income (Loss) Before Income Taxes	$ (597,350)	$ 161,497
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35%	(209,073)	56,524
State Income Taxes (Benefit)	(45,756)	6,700
Miscellaneous	(5,725)	(3,136)
Total Income Taxes	$ (260,554)	$ 60,088
Federal Statutory Rate	35.00%	35.00%

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Capitalization (Details)	6 Months Ended
	Mar. 31, 2016 shares
Debt Instrument [Line Items]
Common stock shares issued due to stock option exercises	138,060
Issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan	72,358
Shares tendered	46,788
Issue shares of common stock for the 401(k) plans	65,046
Restricted Stock Units [Member]
Debt Instrument [Line Items]
Common stock issued	61,150
Board Of Directors [Member]
Debt Instrument [Line Items]
Common stock issued	8,538

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Commitments And Contingencies (Details) $ in Millions	6 Months Ended
	Mar. 31, 2016 USD ($)
Site Contingency [Line Items]
Estimated minimum liability for environmental remediation	$ 4.7
Rate recovery period	12 years
Former Manufactured Gas Plant Site [Member]
Site Contingency [Line Items]
Estimated minimum liability for environmental remediation	$ 3.6

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Business Segment Information (Narrative) (Details)	6 Months Ended
	Mar. 31, 2016 segment
Segment Reporting [Abstract]
Number of reportable segments	5

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Business Segment Information (Financial Segment Information By Segment) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015	Sep. 30, 2015
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	$ (147,687)	$ 16,669	$ (336,796)	$ 101,409
Segment Assets	5,801,024		5,801,024		$ 6,564,939
Revenue From External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	449,132	596,127	824,327	1,120,036
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)	(213,335)	(53,562)	(450,421)	(26,842)
Segment Assets	1,622,264		1,622,264		2,439,801
Exploration And Production [Member] | Revenue From External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	143,783	165,521	295,749	370,186
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)	21,194	23,377	42,470	44,155
Segment Assets	1,664,920		1,664,920		1,590,525
Pipeline And Storage [Member] | Revenue From External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	56,276	55,758	109,630	107,504
Pipeline And Storage [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	23,292	23,054	45,477	44,515
Gathering [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	7,568	6,405	12,490	18,028
Segment Assets	487,421		487,421		444,358
Gathering [Member] | Revenue From External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	113	89	238	235
Gathering [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	21,545	17,365	40,184	41,793
Utility [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	31,960	38,238	50,566	60,831
Segment Assets	1,984,921		1,984,921		1,934,730
Utility [Member] | Revenue From External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	212,737	309,974	356,585	520,047
Utility [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	5,364	6,521	9,028	11,055
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	3,484	3,373	4,707	6,199
Segment Assets	91,671		91,671		90,676
Energy Marketing [Member] | Revenue From External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	35,436	64,167	60,420	120,333
Energy Marketing [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	312	211	624	417
Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	(149,129)	17,831	(340,188)	102,371
Segment Assets	5,851,197		5,851,197		6,500,090
Total Reportable Segments [Member] | Revenue From External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	448,345	595,509	822,622	1,118,305
Total Reportable Segments [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	50,513	47,151	95,313	97,780
All Other [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	(23)	98	166	93
Segment Assets	77,689		77,689		77,350
All Other [Member] | Revenue From External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	561	388	1,266	1,271
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)	1,465	(1,260)	3,226	(1,055)
Segment Assets	(127,862)		(127,862)		$ (12,501)
Corporate And Intersegment Eliminations [Member] | Revenue From External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	226	230	439	460
Corporate And Intersegment Eliminations [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	$ (50,513)	$ (47,151)	$ (95,313)	$ (97,780)

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Retirement Plan And Other Post-Retirement Benefits (Narrative) (Details)	6 Months Ended
	Mar. 31, 2016 USD ($)
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	$ 4,000,000
Estimated future contributions in remainder of fiscal year	0
VEBA Trusts And 401(h) Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	1,800,000
Estimated future contributions in remainder of fiscal year	$ 800,000

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Retirement Plan And Other Post-Retirement Benefits (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost		$ 2,928	$ 3,012	$ 5,855	$ 6,024
Interest Cost		10,579	10,304	21,158	20,608
Expected Return on Plan Assets		(14,842)	(14,904)	(29,685)	(29,808)
Amortization of Prior Service Cost (Credit)		308	46	617	92
Amortization of Losses		8,062	9,032	16,124	18,065
Net Amortization and Deferral For Regulatory Purposes (Including Volumetric Adjustments)	[1]	5,609	7,055	7,516	8,346
Net Periodic Benefit Cost		12,644	14,545	21,585	23,327
Other Post-Retirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost		583	673	1,166	1,346
Interest Cost		5,096	4,821	10,193	9,642
Expected Return on Plan Assets		(7,883)	(8,522)	(15,768)	(17,044)
Amortization of Prior Service Cost (Credit)		(228)	(478)	(456)	(956)
Amortization of Losses		1,382	1,037	2,765	2,074
Net Amortization and Deferral For Regulatory Purposes (Including Volumetric Adjustments)	[1]	6,599	7,396	10,720	12,316
Net Periodic Benefit Cost		$ 5,549	$ 4,927	$ 8,620	$ 7,378

[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.

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Regulatory Matters (Details) $ in Millions	6 Months Ended
	Mar. 31, 2016 USD ($)
Regulatory Matters [Line Items]
Rate proceeding refund provision pre tax	$ 7.5
Allowed rate of return on equity	9.10%
Authorized Increase in Distribution Corporation's pipeline relacement spending	$ 8.2
Amount of requested increase to annual revenues	$ 41.7
Maximum [Member]
Regulatory Matters [Line Items]
Allowed rate of return on equity range	10.50%
Minimum [Member]
Regulatory Matters [Line Items]
Allowed rate of return on equity range	9.50%
Shareholder Allocation [Member] | 9.5 Percent To 10.5 Percent Rate Of Return On Equity [Member]
Regulatory Matters [Line Items]
Earnings sharing mechanism allocation of earnings	50.00%
Shareholder Allocation [Member] | Above 10.5 Percent Rate Of Return On Equity [Member]
Regulatory Matters [Line Items]
Earnings sharing mechanism allocation of earnings	20.00%
Deferred For The Benefit Of Customers [Member] | 9.5 Percent To 10.5 Percent Rate Of Return On Equity [Member]
Regulatory Matters [Line Items]
Earnings sharing mechanism allocation of earnings	50.00%
Deferred For The Benefit Of Customers [Member] | Above 10.5 Percent Rate Of Return On Equity [Member]
Regulatory Matters [Line Items]
Earnings sharing mechanism allocation of earnings	80.00%