Edgar Filing: NATIONAL FUEL GAS CO

NFG-3.31.2015-10Q

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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 ended March 31, 2015

[ ] 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, 2015: 84,419,911 shares.

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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
2014 Form 10-K	The Company’s Annual Report on Form 10-K for the year ended September 30, 2014
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, 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

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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.

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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.

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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, 2015 and 2014		6
b. Consolidated Statements of Comprehensive Income – Three and Six Months Ended March 31, 2015 and 2014		7
c. Consolidated Balance Sheets – March 31, 2015 and September 30, 2014		8
d. Consolidated Statements of Cash Flows – Six Months Ended March 31, 2015 and 2014		10
e. Notes to Condensed Consolidated Financial Statements		11
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		26
Item 3. Quantitative and Qualitative Disclosures About Market Risk		45
Item 4. Controls and Procedures		45

Part II. Other Information

Item 1. Legal Proceedings		45
Item 1 A. Risk Factors		46
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		46
Item 3. Defaults Upon Senior Securities		•
Item 4. Mine Safety Disclosures		•
Item 5. Other Information		•
Item 6. Exhibits		47
Signatures		48

• The Company has nothing to report under this item.

Reference to "the Company" in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. 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.

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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)	2015			2014			2015			2014
INCOME
Operating Revenues	$	596,127		$	756,242		$	1,120,036		$	1,306,314

Operating Expenses
Purchased Gas	190,600			322,772			317,690			490,378
Operation and Maintenance	133,245			137,716			245,827			245,562
Property, Franchise and Other Taxes	24,916			25,704			45,845			46,630
Depreciation, Depletion and Amortization	82,687			89,975			185,433			183,089
Impairment of Oil and Gas Producing Properties	120,348			—			120,348			—
	551,796			576,167			915,143			965,659
Operating Income	44,331			180,075			204,893			340,655
Other Income (Expense):
Interest Income	46			249			1,303			951
Other Income	1,388			5,123			2,571			5,352
Interest Expense on Long-Term Debt	(22,376		)	(22,766		)	(44,687		)	(45,651		)
Other Interest Expense	(1,584		)	(1,375		)	(2,375		)	(2,324		)
Income Before Income Taxes	21,805			161,306			161,705			298,983
Income Tax Expense	5,136			66,095			60,296			121,520

Net Income Available for Common Stock	16,669			95,211			101,409			177,463

EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	1,666,659			1,493,466			1,614,361			1,442,617
	1,683,328			1,588,677			1,715,770			1,620,080

Dividends on Common Stock	(32,488		)	(31,493		)	(64,930		)	(62,896		)
Balance at March 31	$	1,650,840		$	1,557,184		$	1,650,840		$	1,557,184

Earnings Per Common Share:
Basic:
Net Income Available for Common Stock	$	0.20		$	1.14		$	1.20		$	2.12
Diluted:
Net Income Available for Common Stock	$	0.20		$	1.12		$	1.19		$	2.09
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	84,317,508			83,856,120			84,262,471			83,781,085
Used in Diluted Calculation	85,133,142			84,837,123			85,175,961			84,787,610
Dividends Per Common Share:
Dividends Declared	$	0.385		$	0.375		$	0.770		$	0.750

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)



	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands of Dollars)	2015			2014			2015			2014
Net Income Available for Common Stock	$	16,669		$	95,211		$	101,409		$	177,463
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	265			622			(147		)	3,120
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	61,165			(67,461		)	304,994			(64,682		)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(54,130		)	26,640			(78,395		)	16,457
Other Comprehensive Income (Loss), Before Tax	7,300			(40,199		)	226,452			(45,105		)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	99			231			(61		)	1,156
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	25,902			(28,583		)	128,851			(27,312		)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(22,917		)	11,170			(33,006		)	6,872
Income Taxes – Net	3,084			(17,182		)	95,784			(19,284		)
Other Comprehensive Income (Loss)	4,216			(23,017		)	130,668			(25,821		)
Comprehensive Income	$	20,885		$	72,194		$	232,077		$	151,642

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)



	March 31, 2015		September 30, 2014
(Thousands of Dollars)
ASSETS
Property, Plant and Equipment	$	8,691,487	$	8,245,791
Less - Accumulated Depreciation, Depletion and Amortization	2,794,981		2,502,700
	5,896,506		5,743,091
Current Assets
Cash and Temporary Cash Investments	69,441		36,886
Hedging Collateral Deposits	15,726		2,734
Receivables – Net of Allowance for Uncollectible Accounts of $40,922 and $31,811, Respectively	207,673		149,735
Unbilled Revenue	56,148		25,663
Gas Stored Underground	7,361		39,422
Materials and Supplies - at average cost	31,658		27,817
Other Current Assets	59,592		54,752
Deferred Income Taxes	39,260		40,323
	486,859		377,332

Other Assets
Recoverable Future Taxes	163,976		163,485
Unamortized Debt Expense	13,129		14,304
Other Regulatory Assets	217,369		224,436
Deferred Charges	10,923		14,212
Other Investments	88,246		86,788
Goodwill	5,476		5,476
Prepaid Post-Retirement Benefit Costs	43,400		36,512
Fair Value of Derivative Financial Instruments	301,884		72,606
Other	178		1,355
	844,581		619,174

Total Assets	$	7,227,946	$	6,739,597

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)



	March 31, 2015		September 30, 2014
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued And Outstanding – 84,385,366 Shares and 84,157,220 Shares, Respectively	$	84,385	$	84,157
Paid in Capital	737,335		716,144
Earnings Reinvested in the Business	1,650,840		1,614,361
Accumulated Other Comprehensive Income (Loss)	126,689		(3,979		)
Total Comprehensive Shareholders’ Equity	2,599,249		2,410,683
Long-Term Debt, Net of Current Portion	1,649,000		1,649,000
Total Capitalization	4,248,249		4,059,683

Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	157,500		85,600
Current Portion of Long-Term Debt	—		—
Accounts Payable	168,290		136,674
Amounts Payable to Customers	44,796		33,745
Dividends Payable	32,488		32,400
Interest Payable on Long-Term Debt	29,960		29,960
Customer Advances	270		19,005
Customer Security Deposits	18,463		15,761
Other Accruals and Current Liabilities	179,233		136,672
Fair Value of Derivative Financial Instruments	13,175		759
	644,175		490,576

Deferred Credits
Deferred Income Taxes	1,563,368		1,456,283
Taxes Refundable to Customers	90,214		91,736
Unamortized Investment Tax Credit	937		1,145
Cost of Removal Regulatory Liability	178,096		173,199
Other Regulatory Liabilities	119,631		81,152
Pension and Other Post-Retirement Liabilities	137,204		134,202
Asset Retirement Obligations	119,164		117,713
Other Deferred Credits	126,908		133,908
	2,335,522		2,189,338
Commitments and Contingencies	—		—

Total Capitalization and Liabilities	$	7,227,946	$	6,739,597

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)



	Six Months Ended March 31,
(Thousands of Dollars)	2015			2014
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	101,409		$	177,463
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties	120,348			—
Depreciation, Depletion and Amortization	185,433			183,089
Deferred Income Taxes	10,351			71,939
Excess Tax Benefits Associated with Stock-Based Compensation Awards	(9,024		)	(3,149		)
Stock-Based Compensation	5,985			8,045
Other	4,709			(118		)
Change in:
Hedging Collateral Deposits	(12,992		)	1,094
Receivables and Unbilled Revenue	(88,339		)	(198,277		)
Gas Stored Underground and Materials and Supplies	29,085			52,661
Unrecovered Purchased Gas Costs	—			10,583
Other Current Assets	4,184			(443		)
Accounts Payable	62,832			69,379
Amounts Payable to Customers	11,051			11,837
Customer Advances	(18,735		)	(21,878		)
Customer Security Deposits	2,702			(602		)
Other Accruals and Current Liabilities	53,491			102,222
Other Assets	1,826			23,445
Other Liabilities	43,186			15,946
Net Cash Provided by Operating Activities	507,502			503,236

INVESTING ACTIVITIES
Capital Expenditures	(493,341		)	(367,393		)
Other	(1,262		)	4,927
Net Cash Used in Investing Activities	(494,603		)	(362,466		)

FINANCING ACTIVITIES
Changes in Notes Payable to Banks and Commercial Paper	71,900			—
Excess Tax Benefits Associated with Stock-Based Compensation Awards	9,024			3,149
Dividends Paid on Common Stock	(64,842		)	(62,776		)
Net Proceeds from Issuance of Common Stock	3,574			4,863
Net Cash Provided by (Used) in Financing Activities	19,656			(54,764		)

Net Increase in Cash and Temporary Cash Investments	32,555			86,006

Cash and Temporary Cash Investments at October 1	36,886			64,858

Cash and Temporary Cash Investments at March 31	$	69,441		$	150,864

Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	94,484		$	109,355

See Notes to Condensed Consolidated Financial Statements

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

Earnings for Interim Periods. The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Form 10-Q) that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2014, 2013 and 2012 that are included in the Company's 2014 Form 10-K. The consolidated financial statements for the year ended September 30, 2015 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, 2015 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2015. 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 - Current. In the Utility segment, gas stored underground – current is carried at lower of cost or market, on a LIFO method. Gas stored underground – current 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 $50.2 million at March 31, 2015, 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 $148.8 million and $141.7 million at March 31, 2015 and September 30, 2014, 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

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date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. At March 31, 2015, the book value of the oil and gas properties exceeded the ceiling. As such, the Company recognized a pre-tax impairment charge of $120.3 million at March 31, 2015. A deferred income tax benefit of $50.8 million related to the impairment charge was also recognized. In adjusting estimated future cash flows for hedging under the ceiling test at March 31, 2015, estimated future net cash flows were increased by $97.0 million.

Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss) and changes for the quarter and six months ended March 31, 2015 and 2014, 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, 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
Three Months Ended March 31, 2014
Balance at January 1, 2014	$	26,345		$	7,910		$	(56,293	)	$	(22,038	)
Other Comprehensive Gains and Losses Before Reclassifications	(38,878		)	391			—			(38,487		)
Amounts Reclassified From Other Comprehensive Income (Loss)	15,470			—			—			15,470
Balance at March 31, 2014	$	2,937		$	8,301		$	(56,293	)	$	(45,055	)
Six Months Ended March 31, 2014
Balance at October 1, 2013	$	30,722		$	6,337		$	(56,293	)	$	(19,234	)
Other Comprehensive Gains and Losses Before Reclassifications	(37,370		)	1,964			—			(35,406		)
Amounts Reclassified From Other Comprehensive Income (Loss)	9,585			—			—			9,585
Balance at March 31, 2014	$	2,937		$	8,301		$	(56,293	)	$	(45,055	)

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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, 2015 and 2014 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):



Details About Accumulated Other Comprehensive Income (Loss) Components	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss)												Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended March 31,						Six Months Ended March 31,
	2015			2014			2015			2014
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts		$53,471			($22,611	)		$73,508			($12,825	)	Operating Revenues
Commodity Contracts	659			(4,029		)	4,887			(3,632		)	Purchased Gas
	54,130			(26,640		)	78,395			(16,457		)	Total Before Income Tax
	(22,917		)	11,170			(33,006		)	6,872			Income Tax Expense
		$31,213			($15,470	)		$45,389			($9,585	)	Net of Tax

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



	At March 31, 2015		At September 30, 2014

Prepayments	$	5,314	$	10,079
Prepaid Property and Other Taxes	22,266		13,743
Federal Income Taxes Receivable	—		8,211
Fair Values of Firm Commitments	14,694		—
Regulatory Assets	17,318		22,719
	$	59,592	$	54,752

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



	At March 31, 2015		At September 30, 2014

Accrued Capital Expenditures	$	69,419	$	80,348
Regulatory Liabilities	5,953		18,072
Reserve for Gas Replacement	50,152		—
Federal Income Taxes Payable	22,646		—
State Income Taxes Payable	1,838		5,798
Other	29,225		32,454
	$	179,233	$	136,672

Earnings Per Common Share. Basic earnings per common share is computed by dividing income available for common stock 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. 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. There were no securities excluded as being antidilutive for the quarter ended March 31, 2014. There were 265 securities excluded as being antidilutive for the six months ended March 31, 2014.

Stock-Based Compensation. The Company granted 107,044 performance shares during the six months ended March 31, 2015. The weighted average fair value of such performance shares was $65.26 per share for the six months ended March 31, 2015.

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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, 2015 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2014 to September 30, 2017. The performance 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, 2015 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2014 to September 30, 2017. The performance 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 88,899 non-performance based restricted stock units during the six months ended March 31, 2015. The weighted average fair value of such non-performance based restricted stock units was $64.04 per share for the six months ended March 31, 2015. 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, 2015.

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. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2018. However, the FASB has proposed a deferral of the effective date of the new revenue standard by one year. 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 February 2015, the FASB issued authoritative guidance that changes the rules regarding consolidation of certain types of legal entities. This authoritative guidance applies to entities in all industries and makes targeted amendments to the current

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consolidation guidance. 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 and disclosures.

In April 2015, the FASB issued authoritative guidance regarding the presentation of debt issuance costs. The authoritative guidance requires that all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. This authoritative guidance, which will be applied on a retrospective basis, will be effective as of the Company's first quarter of fiscal 2017, with early adoption permitted. The Company plans to early adopt by the end of fiscal 2015.

In April 2015, the FASB issued authoritative guidance regarding customer's accounting for fees paid in a cloud computing arrangement. The authoritative guidance provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, the guidance requires the software license element of the arrangement to be accounted for consistent with other software license agreements. 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.

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.

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, 2015 and September 30, 2014. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over the counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company.



Recurring Fair Value Measures	At fair value as of March 31, 2015
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	46,916	$	—	$	—	$	—		$	46,916
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	4,426		—		—		(4,426		)	—
Over the Counter Swaps – Gas and Oil	—		297,777		4,826		(719		)	301,884
Other Investments:
Balanced Equity Mutual Fund	37,090		—		—		—			37,090
Common Stock – Financial Services Industry	5,858		—		—		—			5,858
Other Common Stock	518		—		—		—			518
Hedging Collateral Deposits	15,726		—		—		—			15,726
Total	$	110,534	$	297,777	$	4,826	$	(5,145	)	$	407,992

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	16,510	$	—	$	—	$	(4,426	)	$	12,084
Over the Counter Swaps – Gas and Oil	—		1,810		—		(719		)	1,091
Total	$	16,510	$	1,810	$	—	$	(5,145	)	$	13,175

Total Net Assets/(Liabilities)	$	94,024	$	295,967	$	4,826	$	—		$	394,817

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Recurring Fair Value Measures	At fair value as of September 30, 2014
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	23,794	$	—	$	—	$	—		$	23,794
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	2,725		—		—		(1,987		)	738
Over the Counter Swaps – Gas and Oil	—		75,951		1,368		(5,451		)	71,868
Other Investments:
Balanced Equity Mutual Fund	35,331		—		—		—			35,331
Common Stock – Financial Services Industry	6,629		—		—		—			6,629
Other Common Stock	455		—		—		—			455
Hedging Collateral Deposits	2,734		—		—		—			2,734
Total	$	71,668	$	75,951	$	1,368	$	(7,438	)	$	141,549

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	2,674	$	—	$	—	$	(1,987	)	$	687
Over the Counter Swaps – Gas and Oil	—		5,523		—		(5,451		)	72
Total	$	2,674	$	5,523	$	—	$	(7,438	)	$	759

Total Net Assets/(Liabilities)	$	68,994	$	70,428	$	1,368	$	—		$	140,790


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

Derivative Financial Instruments

At March 31, 2015 and September 30, 2014, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used in the Company’s Energy Marketing segment. Hedging collateral deposits of $15.7 million at March 31, 2015 and $2.7 million at September 30, 2014, which are associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at March 31, 2015 and September 30, 2014 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments and the majority of the crude oil price swap agreements 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 derivative financial instruments reported in Level 3 consist of a portion of the crude oil price swap agreements used in the Company’s Exploration and Production segment at March 31, 2015 and September 30, 2014. The fair value of the Level 3 crude oil price swap agreements is based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume).

The significant unobservable input used in the fair value measurement of a portion of the Company’s over-the-counter crude oil swaps is the basis differential between Midway Sunset oil and NYMEX contracts. Significant changes in the assumed basis differential could result in a significant change in value of the derivative financial instruments. At March 31, 2015, it was assumed that Midway Sunset oil was 93.7% of NYMEX. This is based on a historical twelve month average of Midway Sunset oil sales verses NYMEX settlements. During this twelve-month period, the price of Midway Sunset oil ranged from 87.8% to 98.8% of NYMEX. If the price of Midway Sunset oil relative to NYMEX used in the fair value measurement calculation had been 10 percentage points higher, the fair value of the Level 3 crude oil price swap agreements asset would have been approximately $0.9 million lower at March 31, 2015. If the price of Midway Sunset oil relative to NYMEX used in the fair value measurement had been 10 percentage points lower, the fair value measurement of the Level 3 crude oil price swap agreements asset would have been approximately $0.9 million higher at March 31, 2015. These calculated amounts are based solely on basis differential changes and do not take into account any other changes to the fair value measurement calculation.

The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At

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March 31, 2015, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty (for an asset) or the Company’s (for a liability) 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, 2015 and 2014, respectively. For the quarters and six months ended March 31, 2015 and March 31, 2014, no transfers in or out of Level 1 or Level 2 occurred. There were no purchases or sales of derivative financial instruments during the periods presented in the tables below. All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below (amounts in parentheses indicate credits in the derivative asset/liability accounts).



Fair Value Measurements Using Unobservable Inputs (Level 3)
(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.



Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)				Total Gains/Losses
	January 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, 2014
Derivative Financial Instruments⁽²⁾	$	(1,842	)	$	763	⁽¹⁾	$	(292	)	$	—	$	(1,371	)


⁽¹⁾	Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended March 31, 2014.


⁽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, 2013			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, 2014
Derivative Financial Instruments⁽²⁾	$	(5,190	)	$	1,043	⁽¹⁾	$	2,776	$	—	$	(1,371	)


⁽¹⁾	Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the six months ended March 31, 2014.


⁽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, 2015				September 30, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,649,000	$	1,794,666	$	1,649,000	$	1,775,715

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

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

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

Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The values of the insurance contracts amounted to $44.8 million at March 31, 2015 and $44.4 million at September 30, 2014. The fair value of the equity mutual fund was $37.1 million at March 31, 2015 and $35.3 million at September 30, 2014. The gross unrealized gain on this equity mutual fund was $9.0 million at March 31, 2015 and $8.4 million at September 30, 2014. The fair value of the stock of an insurance company was $5.9 million at March 31, 2015 and $6.6 million at September 30, 2014. The gross unrealized gain on this stock was $3.8 million at March 31, 2015 and $4.5 million at September 30, 2014. 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. These instruments are accounted for as cash flow hedges. The Company also enters into futures contracts and swaps, which are accounted for as cash flow hedges, to manage the price risk associated with forecasted gas purchases. The Company enters into futures contracts and swaps to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in value of natural gas held in storage. These instruments are accounted for as fair value hedges. The duration of the Company’s combined cash flow and fair value hedges does not typically exceed 5 years. The Exploration and

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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, 2015 and September 30, 2014. All of the derivative financial instruments reported on those line items relate to commodity contracts.

Cash Flow Hedges

For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

As of March 31, 2015, the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding:



Commodity	Units
Natural Gas	157.4	Bcf (short positions)
Natural Gas	4.1	Bcf (long positions)
Crude Oil	2,568,000	Bbls (short positions)

As of March 31, 2015, the Company had $302.7 million ($174.4 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $167.4 million ($96.5 million after tax) of such unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodities occur.

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, 2015 and 2014 (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,
	2015		2014				2015		2014				2015		2014
Commodity Contracts	$	60,571	$	(64,237	)	Operating Revenue	$	53,471	$	(22,611	)	Operating Revenue	$	1,469	$	(660	)
Commodity Contracts	$	594	$	(3,224	)	Purchased Gas	$	659	$	(4,029	)	Not Applicable	$	—	$	—
Total	$	61,165	$	(67,461	)		$	54,130	$	(26,640	)		$	1,469	$	(660	)

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The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Six Months Ended March 31, 2015 and 2014 (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,
	2015		2014				2015		2014				2015		2014
Commodity Contracts	$	300,594	$	(59,117	)	Operating Revenue	$	73,508	$	(12,825	)	Operating Revenue	$	2,929	$	774
Commodity Contracts	$	4,400	$	(5,565	)	Purchased Gas	$	4,887	$	(3,632	)	Not Applicable	$	—	$	—
Total	$	304,994	$	(64,682	)		$	78,395	$	(16,457	)		$	2,929	$	774

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, 2015, the Company’s Energy Marketing segment had fair value hedges covering approximately 15.0 Bcf (14.9 Bcf of fixed price sales commitments and 0.1 Bcf of fixed price purchase commitments). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.



Derivatives in Fair Value Hedging Relationships	Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income	Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the Six Months Ended March 31, 2015 (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, 2015 (In Thousands)
Commodity Contracts	Operating Revenues	$	(12,549	)	$	12,549
Commodity Contracts	Purchased Gas	$	46		$	(46	)
		$	(12,503	)	$	12,503

Credit Risk

The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions with fifteen counterparties of which thirteen are in a net gain position. On average, the Company had $23.2 million of credit exposure per counterparty in a gain position at March 31, 2015. The maximum credit exposure per counterparty in a gain position at March 31, 2015 was $57.1 million. The Company’s gain

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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, 2015, collateral deposits of $50.9 million were posted. These collateral deposits are recorded as a component of Accounts Payable on the Consolidated Balance Sheet.

As of March 31, 2015, eleven of the fifteen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required. At March 31, 2015, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $189.5 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements). For its over-the-counter swap agreements, no hedging collateral deposits were required to be posted by the Company at March 31, 2015.

For its exchange traded futures contracts, the Company was required to post $15.7 million in hedging collateral deposits as of March 31, 2015. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.

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

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,
	2015			2014
Current Income Taxes
Federal	$	36,746		$	39,974
State	13,199			9,607

Deferred Income Taxes
Federal	13,242			50,110
State	(2,891		)	21,829
	60,296			121,520
Deferred Investment Tax Credit	(208		)	(218		)

Total Income Taxes	$	60,088		$	121,302
Presented as Follows:
Other Income	(208		)	(218		)
Income Tax Expense	60,296			121,520

Total Income Taxes	$	60,088		$	121,302

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



	Six Months Ended March 31,
	2015			2014
U.S. Income Before Income Taxes	$	161,497		$	298,765

Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35%	$	56,524		$	104,568

Increase (Reduction) in Taxes Resulting from:
State Income Taxes	6,700			20,433
Miscellaneous	(3,136		)	(3,699		)

Total Income Taxes	$	60,088		$	121,302

On December 19, 2014, President Obama signed into law the Tax Increase Prevention Act of 2014, which did not have a significant impact on income tax expense.

Note 5 - Capitalization

Common Stock. During the six months ended March 31, 2015, the Company issued 125,451 original issue shares of common stock as a result of stock option and SARs exercises and 42,990 original issue shares of common stock for restricted stock units that vested. In addition, the Company issued 51,620 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 43,255 original issue shares of common stock for the Company’s 401(k) plans. The Company also issued 7,584 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 ended March 31, 2015. 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 ended March 31, 2015, 42,754 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, 2015 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, 2015, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be approximately $13.8 million. The Company expects to recover such 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 $12.4 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 has been completed, and remedial work is expected to begin in the summer of 2015.

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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 2014 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 2014 Form 10-K. A listing of segment assets at March 31, 2015 and September 30, 2014 is shown in the tables below.



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



(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, 2015	$3,289,590	$1,446,247	$379,707	$2,022,373	$103,806	$7,241,723	$76,810	$(90,587)	$7,227,946
At September 30, 2014	$3,100,514	$1,367,181	$326,662	$1,862,850	$76,238	$6,733,445	$86,460	$(80,308)	$6,739,597

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Quarter Ended March 31, 2014 (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	$199,561	$53,571	$195	$377,647	$124,439	$755,413	$597	$232	$756,242
Intersegment Revenues	$—	$22,235	$15,452	$8,204	$5	$45,896	$—	$(45,896)	$—
Segment Profit: Net Income	$24,390	$21,372	$7,324	$35,545	$3,765	$92,396	$278	$2,537	$95,211



Six Months Ended March 31, 2014 (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	$392,607	$104,784	$429	$608,100	$197,598	$1,303,518	$2,298	$498	$1,306,314
Intersegment Revenues	$—	$42,974	$29,802	$12,911	$260	$85,947	$—	$(85,947)	$—
Segment Profit: Net Income	$55,487	$40,510	$13,471	$59,760	$5,369	$174,597	$954	$1,912	$177,463

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,	2015			2014			2015			2014

Service Cost	$	3,012		$	2,997		$	673		$	735
Interest Cost	10,304			10,893			4,821			5,327
Expected Return on Plan Assets	(14,904		)	(14,993		)	(8,522		)	(9,356		)
Amortization of Prior Service Cost (Credit)	46			52			(478		)	(534		)
Amortization of Losses	9,032			9,002			1,037			661
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾	7,055			8,557			7,396			7,928

Net Periodic Benefit Cost	$	14,545		$	16,508		$	4,927		$	4,761

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	Retirement Plan						Other Post-Retirement Benefits
Six Months Ended March 31,	2015			2014			2015			2014

Service Cost	$	6,024		$	5,993		$	1,346		$	1,469
Interest Cost	20,608			21,787			9,642			10,654
Expected Return on Plan Assets	(29,808		)	(29,986		)	(17,044		)	(18,712		)
Amortization of Prior Service Cost (Credit)	92			105			(956		)	(1,069		)
Amortization of Losses	18,065			18,003			2,074			1,323
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) ⁽¹⁾	8,346			10,135			12,316			13,988

Net Periodic Benefit Cost	$	23,327		$	26,037		$	7,378		$	7,653


⁽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 ended March 31, 2015, the Company contributed $18.0 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $1.5 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2015, the Company expects its contributions to the Retirement Plan to be in the range of zero to $2.0 million. In the remainder of 2015, the Company expects to contribute approximately $0.5 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 ratepayers during 2014 after the NYPSC approved the settlement agreement without modification in an order issued on May 8, 2014.

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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 model centered in western New York and Pennsylvania, an area critical to the production and transportation of natural gas from the Marcellus Shale basin. 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.

For the quarter ended March 31, 2015 compared to the quarter ended March 31, 2014, the Company experienced a decrease in earnings of $78.5 million. For the six months ended March 31, 2015 compared to the six months ended March 31, 2014, the Company experienced a decrease in earnings of $76.1 million. The earnings decrease for both the quarter and six months ended March 31, 2015 is driven largely by an impairment charge of $120.3 million ($69.5 million after-tax) recorded in the Exploration and Production segment. 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. At March 31, 2015, due to significant declines in crude oil and natural gas commodity prices, the book value of the Company’s oil and gas properties exceeded the ceiling, resulting in the impairment charge mentioned above. The Company expects that the book value of its oil and gas properties will also exceed the ceiling at June 30, 2015, September 30, 2015 and December 31, 2015, resulting in additional impairment charges. 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. The earnings decrease for the quarter ended March 31, 2015 also reflects lower earnings in Gathering segment and in the Corporate category, partly offset by higher earnings in the Pipeline and Storage segment and Utility segment. For the six months ended March 31, 2015, the earnings decrease also reflects lower earnings in the Corporate category, partly offset by higher earnings in the Pipeline and Storage segment, Gathering segment and Utility segment. For further discussion of the Company’s earnings, refer to the Results of Operations section below.

The Company continues to develop its natural gas reserves in the 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. The Company controls the natural gas interests associated with approximately 780,000 net acres within the Marcellus Shale area, with a majority of the interests held in fee, carrying no royalty and no lease expirations. Natural gas proved developed and undeveloped reserves in the Appalachian region increased from 1,239 Bcf at September 30, 2013 to 1,624 Bcf at September 30, 2014. The Company has spent significant amounts of capital in this region related to the development of such reserves. For the six months ended March 31, 2015, the Company’s Exploration and Production segment had capital expenditures of $260.9 million in the Appalachian region, of which $235.7 million was spent towards the development of the Marcellus Shale. The amount spent towards the development of the Marcellus Shale represented approximately 52% of the Company’s capital expenditures for the six months ended March 31, 2015. With the potential for continued low natural gas and crude oil prices, the Company is reducing its fiscal 2016 estimated capital expenditures in the Exploration and Production segment from approximately $715 million to approximately $440 million. Forecasted production in the Exploration and Production segment for fiscal 2015 is expected to be in the range of 155 to 175 Bcfe, down from the previous range of 155 to 190 Bcfe.

To facilitate the flow of natural gas from the Marcellus Shale, the Company continues to expand its gathering and pipeline infrastructure in the Gathering segment and the Pipeline and Storage segment. For the six months ended March 31, 2015, the Gathering segment had capital expenditures of $50.5 million. The Pipeline and Storage segment's capital expenditures for the six months ended March 31, 2015 were $57.7 million. The amount spent towards the development of gathering and pipeline infrastructure during the six months ended March 31, 2015 represented approximately 24% of the Company's capital expenditures.

From a capital resources perspective, the Company has largely been able to meet its capital expenditure needs by using cash from operations as well as both short and long-term debt. It is expected that the Company will use short-term debt as necessary during fiscal 2015 to help meet its capital expenditure needs. In addition, the Company intends to issue long-term debt in the near term. If the Company experiences additional impairments of its oil and gas properties in June 2015, September 2015, and December 2015, the Company, under its 1974 indenture, expects to be precluded from issuing incremental long-term debt for a period of twelve months or more, beginning in October 2015. However, the Company expects that it could borrow under its committed

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credit facility and uncommitted bank lines of credit. In addition, the 1974 indenture would not preclude the Company from issuing new long-term debt to replace maturing long-term debt. On December 5, 2014, the Company entered into an Amended and Restated Credit Agreement that replaced the Company’s existing $750.0 million committed credit facility with a substantially similar committed credit facility totaling $750.0 million that extends through December 5, 2019. The previous committed credit facility extended through January 6, 2017.

The well completion technology referred to as hydraulic fracturing used in conjunction with horizontal drilling continues to be debated. In Pennsylvania, where the Company is focusing its Marcellus Shale development efforts, the permitting and regulatory processes seem to strike a balance between the environmental concerns associated with hydraulic fracturing and the benefits of increased natural gas production. The potential for increased state or federal regulation of hydraulic fracturing could impact future costs of drilling in the Marcellus Shale and lead to operational delays or restrictions. There is also the risk that drilling could be prohibited on certain acreage that is prospective for the Marcellus Shale. Please refer to the Risk Factors section of the Company’s 2014 Form 10-K for further discussion.

CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2014 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. At March 31, 2015, the book value of the oil and gas properties exceeded the ceiling, which caused the Company to record an impairment charge of $120.3 million ($69.5 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, 2015, based on posted Midway Sunset prices, was $78.45 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, 2015, based on the quoted Henry Hub spot price for natural gas, was $3.88 per MMBtu. (Note – Because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for the twelve months ended March 31, 2015.) If natural gas average prices used in the ceiling test calculation at March 31, 2015 had been $1 per MMBtu lower, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $583.0 million (after-tax), which would have resulted in an additional impairment charge. If crude oil average prices used in the ceiling test calculation at March 31, 2015 had been $5 per Bbl lower, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $110.8 million (after-tax), which would have resulted in an additional impairment charge. If both natural gas and crude oil average prices used in the ceiling test calculation at March 31, 2015 were lower by $1 per MMBtu and $5 per Bbl, respectively, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $624.1 million (after-tax), which would have resulted in an additional impairment charge. 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. Looking ahead, the first day of the month Midway Sunset price for crude oil in April 2015 was $46.78 per Bbl. The first day of the month Henry Hub spot price for natural gas in April 2015 was $2.63 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, 2015, September 30, 2015 and December 31, 2015, the Company expects to experience significant ceiling test impairments in each of those quarters. 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 2014 Form 10-K.

RESULTS OF OPERATIONS

Earnings

The Company’s earnings were $16.7 million for the quarter ended March 31, 2015 compared to earnings of $95.2 million for the quarter ended March 31, 2014. The decrease in earnings of $78.5 million is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the Gathering segment, Energy Marketing segment and All Other category,

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as well as a loss in the Corporate category, also contributed to the decrease. Higher earnings in the Pipeline and Storage segment and the Utility segment partially offset these decreases.

The Company’s earnings were $101.4 million for the six months ended March 31, 2015 compared to earnings of $177.5 million for the six months ended March 31, 2014. The decrease in earnings of $76.1 million is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the All Other category and a loss in the Corporate category also contributed to the decrease. Higher earnings in the Pipeline and Storage segment, Gathering segment, Utility segment and Energy Marketing segment partially offset these decreases.

The Company's earnings for the quarter and six months ended March 31, 2015 include 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, as discussed above. 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,