UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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

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 o

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 o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o 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, $1 par value, outstanding at January 31, 2011: 82,345,955 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.
ESNE		Energy Systems North East, LLC
Highland		Highland Forest Resources, Inc.
Horizon		Horizon Energy Development, Inc.
Horizon B.V.		Horizon Energy Development B.V.
Horizon LFG		Horizon LFG, Inc.
Horizon Power		Horizon Power, Inc.
Midstream Corporation		National Fuel Gas Midstream Corporation
Model City		Model City Energy, LLC
National Fuel		National Fuel Gas Company
NFR		National Fuel Resources, Inc.
Registrant		National Fuel Gas Company
Seneca		Seneca Resources Corporation
Seneca Energy		Seneca Energy II, LLC
Supply Corporation		National Fuel Gas Supply Corporation
Regulatory Agencies
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
PaPUC		Pennsylvania Public Utility Commission
SEC		Securities and Exchange Commission
Other
2010 Form 10-K		The Company’s Annual Report on Form 10-K for the year ended September 30, 2010
Bbl		Barrel (of oil)
Bcf Bcfe (or Mcfe) – represents		Billion cubic feet (of natural gas)
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.
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 reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
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

GLOSSARY OF TERMS (Cont.)

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.
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.
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.
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
MMcf		Million cubic feet (of natural gas)
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.
PCB		Polychlorinated Biphenyl
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.
Proved developed reserves		Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped 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.
Restructuring		Generally referring to partial “deregulation” of the pipeline and/or utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundling”) of gas commodity service from transportation service for wholesale and large-volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.

GLOSSARY OF TERMS (Concl.)

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
Stock acquisitions		Investments in corporations.
Unbundled service		A service that has been separated from other services, with rates charged that reflect only the cost of the separated service.
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.

INDEX

		Page
Part I. Financial Information
Item 1. Financial Statements (Unaudited)			6
a. Consolidated Statements of Income and Earnings Reinvested in the Business — Three Months Ended December 31, 2010 and 2009			6
b. Consolidated Balance Sheets — December 31, 2010 and September 30, 2010			7 - 8
c. Consolidated Statements of Cash Flows — Three Months Ended December 31, 2010 and 2009			9
d. Consolidated Statements of Comprehensive Income — Three Months Ended December 31, 2010 and 2009			10
e. Notes to Condensed Consolidated Financial Statements			11 - 27
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28 - 49
Item 3. Quantitative and Qualitative Disclosures About Market Risk			49
Item 4. Controls and Procedures			49
Part II. Other Information
Item 1. Legal Proceedings			50
Item 1 A. Risk Factors			50 - 53
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			53
Item 3. Defaults Upon Senior Securities			•
Item 5. Other Information			•
Item 6. Exhibits			54
Signatures			55
EX-10.1
EX-10.2
EX-10.3
EX-10.4
EX-10.5
EX-12
EX-31.1
EX-31.2
EX-32
EX-99
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

• 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.

     This Form 10-Q contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2 — MD&A, under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, 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 and other 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.

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
		December 31,
		2010				2009
(Thousands of Dollars, Except Per Common Share Amounts)
INCOME
Operating Revenues		$	450,948			$	454,135
Operating Expenses
Purchased Gas			163,038				171,290
Operation and Maintenance			97,450				93,770
Property, Franchise and Other Taxes			19,736				18,650
Depreciation, Depletion and Amortization			53,313				44,788
			333,537				328,498
Operating Income			117,411				125,637
Other Income (Expense):
Income (Loss) from Unconsolidated Subsidiaries			(1,100	)			401
Interest Income			884				1,154
Other Income			993				356
Interest Expense on Long-Term Debt			(20,192	)			(22,063	)
Other Interest Expense			(1,401	)			(1,377	)
Income from Continuing Operations Before Income Taxes			96,595				104,108
Income Tax Expense			38,052				39,883
Income from Continuing Operations			58,543				64,225
Income from Discontinued Operations, Net of Tax			—				274
Net Income Available for Common Stock			58,543				64,499
EARNINGS REINVESTED IN THE BUSINESS
Balance at October 1			1,063,262				948,293
			1,121,805				1,012,792
Dividends on Common Stock (2010 - $0.345 per share; 2009 - $0.335 per share)			(28,407	)			(27,129	)
Balance at December 31		$	1,093,398			$	985,663
Earnings Per Common Share:
Basic:
Income from Continuing Operations		$	0.71			$	0.80
Income from Discontinued Operations			—				—
Net Income Available for Common Stock		$	0.71			$	0.80
Diluted:
Income from Continuing Operations		$	0.70			$	0.78
Income from Discontinued Operations			—				—
Net Income Available for Common Stock		$	0.70			$	0.78
Weighted Average Common Shares Outstanding:
Used in Basic Calculation			82,223,428				80,612,303
Used in Diluted Calculation			83,420,351				82,172,649

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Balance Sheets
(Unaudited)

		December 31,				September 30,
(Thousands of Dollars)		2010				2010
ASSETS
Property, Plant and Equipment		$	5,837,365			$	5,637,498
Less — Accumulated Depreciation, Depletion and Amortization			2,236,152				2,187,269
			3,601,213				3,450,229
Current Assets
Cash and Temporary Cash Investments			79,622				395,171
Cash Held in Escrow			—				2,000
Hedging Collateral Deposits			31,446				11,134
Receivables — Net of Allowance for Uncollectible Accounts of $35,870 and $30,961, Respectively			147,829				132,136
Unbilled Utility Revenue			59,211				20,920
Gas Stored Underground			47,839				48,584
Materials and Supplies — at average cost			31,560				24,987
Other Current Assets			107,201				115,969
Deferred Income Taxes			20,901				24,476
			525,609				775,377
Other Assets
Recoverable Future Taxes			150,865				149,712
Unamortized Debt Expense			12,036				12,550
Other Regulatory Assets			534,146				542,801
Deferred Charges			10,219				9,646
Other Investments			80,701				77,839
Investments in Unconsolidated Subsidiaries			13,728				14,828
Goodwill			5,476				5,476
Fair Value of Derivative Financial Instruments			46,152				65,184
Other			1,836				1,983
			855,159				880,019
Total Assets		$	4,981,981			$	5,105,625

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)

		December 31,				September 30,
(Thousands of Dollars)		2010				2010
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares;
Issued and Outstanding - 82,338,454 Shares and 82,075,470 Shares, Respectively		$	82,338			$	82,075
Paid in Capital			643,856				645,619
Earnings Reinvested in the Business			1,093,398				1,063,262
Total Common Shareholder Equity Before Items of Other Comprehensive Loss			1,819,592				1,790,956
Accumulated Other Comprehensive Loss			(64,650	)			(44,985	)
Total Comprehensive Shareholders’ Equity			1,754,942				1,745,971
Long-Term Debt, Net of Current Portion			899,000				1,049,000
Total Capitalization			2,653,942				2,794,971
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper			20,500				—
Current Portion of Long-Term Debt			150,000				200,000
Accounts Payable			181,564				145,223
Amounts Payable to Customers			23,914				38,109
Dividends Payable			28,407				28,316
Interest Payable on Long-Term Debt			15,953				30,512
Customer Advances			27,633				27,638
Customer Security Deposits			18,508				18,320
Other Accruals and Current Liabilities			30,838				16,046
Fair Value of Derivative Financial Instruments			34,500				20,160
			531,817				524,324
Deferred Credits
Deferred Income Taxes			821,001				800,758
Taxes Refundable to Customers			69,589				69,585
Unamortized Investment Tax Credit			3,112				3,288
Cost of Removal Regulatory Liability			125,862				124,032
Other Regulatory Liabilities			88,263				89,334
Pension and Other Post-Retirement Liabilities			433,010				446,082
Asset Retirement Obligations			100,580				101,618
Other Deferred Credits			154,805				151,633
			1,796,222				1,786,330
Commitments and Contingencies			—				—
Total Capitalization and Liabilities		$	4,981,981			$	5,105,625

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

		Three Months Ended
		December 31,
(Thousands of Dollars)		2010				2009
|		|
OPERATING ACTIVITIES
Net Income Available for Common Stock		$	58,543			$	64,499
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation, Depletion and Amortization			53,313				44,955
Deferred Income Taxes			36,600				21,092
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions			1,100				1,599
Excess Tax Benefits Associated with Stock-Based
Compensation Awards			—				(13,437	)
Other			2,443				7,958
Change in:
Hedging Collateral Deposits			(20,312	)			(244	)
Receivables and Unbilled Utility Revenue			(53,984	)			(67,882	)
Gas Stored Underground and Materials and Supplies			(5,828	)			2,839
Prepayments and Other Current Assets			8,768				17,859
Accounts Payable			29,246				11,408
Amounts Payable to Customers			(14,195	)			(11,310	)
Customer Advances			(5	)			6,098
Customer Security Deposits			188				2,135
Other Accruals and Current Liabilities			1,387				(13,536	)
Other Assets			(10,463	)			16,967
Other Liabilities			670				(22,667	)
Net Cash Provided by Operating Activities			87,471				68,333
INVESTING ACTIVITIES
Capital Expenditures			(192,052	)			(62,205	)
Investment in Subsidiary, Net of Cash Acquired			(1,750	)			—
Cash Held in Escrow			2,000				—
Other			(298	)			(247	)
Net Cash Used in Investing Activities			(192,100	)			(62,452	)
FINANCING ACTIVITIES
Changes in Notes Payable to Banks and Commercial Paper			20,500				—
Excess Tax Benefits Associated with Stock-Based Compensation Awards			—				13,437
Reduction of Long-Term Debt			(200,000	)			—
Dividends Paid on Common Stock			(28,316	)			(26,967	)
Net Proceeds from Issuance (Repurchase) of Common Stock			(3,104	)			3,997
Net Cash Used in Financing Activities			(210,920	)			(9,533	)
Net Decrease in Cash and Temporary Cash Investments			(315,549	)			(3,652	)
Cash and Temporary Cash Investments at October 1			395,171				408,053
Cash and Temporary Cash Investments at December 31		$	79,622			$	404,401

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

		Three Months Ended
		December 31,
(Thousands of Dollars)		2010				2009
Net Income Available for Common Stock		$	58,543			$	64,499
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment			17				17
Reclassification Adjustment for Realized Foreign Currency Translation Loss in Net Income			34				—
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period			2,540				(713	)
Unrealized Loss on Derivative Financial Instruments Arising During the Period			(27,136	)			(4,853	)
Reclassification Adjustment for Realized Gains on Derivative Financial Instruments in Net Income			(9,053	)			(12,052	)
Other Comprehensive Loss, Before Tax			(33,598	)			(17,601	)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period			960				(271	)
Income Tax Benefit Related to Unrealized Loss on Derivative Financial Instruments Arising During the Period			(11,168	)			(2,062	)
Reclassification Adjustment for Income Tax Expense on Realized Gains from Derivative Financial Instruments In Net Income			(3,725	)			(4,962	)
Income Taxes — Net			(13,933	)			(7,295	)
Other Comprehensive Loss			(19,665	)			(10,306	)
Comprehensive Income		$	38,878			$	54,193

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

Note 1 — Summary of Significant Accounting Policies

Principles of Consolidation. The Company consolidates its majority owned entities. The equity method is used to account for minority owned entities. 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.

Reclassification. Certain prior year amounts have been reclassified to conform with current year presentation.

Earnings for Interim Periods. The Company, in its opinion, has included all adjustments 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, 2010, 2009 and 2008 that are included in the Company’s 2010 Form 10-K. The consolidated financial statements for the year ended September 30, 2011 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.

     The earnings for the three months ended December 31, 2010 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2011. 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 8 — Business Segment Information.

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

     At December 31, 2010, the Company accrued $60.7 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $2.0 million of capital expenditures in the Pipeline and Storage segment at December 31, 2010. These amounts were excluded from the Consolidated Statement of Cash Flows at December 31, 2010 since they represent non-cash investing activities at that date.

     At September 30, 2010, the Company accrued $55.5 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2010 and have been included in the Consolidated Statement of Cash Flows for the quarter ended December 31, 2010.

     At December 31, 2009, the Company accrued $15.4 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at December 31, 2009 since it represented a non-cash investing activity at that date.

Item 1. Financial Statements (Cont.)

     At September 30, 2009, the Company accrued $9.1 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $0.7 million of capital expenditures in the All Other category related to the construction of the Midstream Covington Gathering System at September 30, 2009. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represented non-cash investing activities at that date. These capital expenditures were paid during the quarter ended December 31, 2009 and have been included in the Consolidated Statement of Cash Flows for the quarter ended December 31, 2009.

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. At December 31, 2010, the Company had hedging collateral deposits of $6.6 million related to its exchange-traded futures contracts and $24.8 million related to its over-the-counter crude oil swap agreements. 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.

Cash Held in Escrow. On July 20, 2009, the Company’s wholly-owned subsidiary in the Exploration and Production segment, Seneca, acquired Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million in cash (including cash acquired of $4.3 million). The cash acquired at acquisition included $2 million held in escrow. Seneca placed this amount in escrow as part of the purchase price. In December 2010, the Company and Ivanhoe Energy negotiated a final settlement agreement in which Ivanhoe Energy was entitled to $1.75 million and the Company was entitled to $0.25 million of the cash held in escrow. For presentation purposes on the Consolidated Statement of Cash Flows, the Cash Held in Escrow line item within Investing Activities for the three months ended December 31, 2010 reflects the fact that $2.0 million is no longer held in escrow at December 31, 2010. The Investment in Subsidiary, Net of Cash Acquired line item within Investing Activities for the three months ended December 31, 2010 reflects the $1.75 million paid to Ivanhoe Energy.

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 $17.1 million at December 31, 2010, 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 $184.0 million and $151.2 million at December 31, 2010 and September 30, 2010, 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

Item 1. Financial Statements (Cont.)

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. In accordance with the SEC final rule on Modernization of Oil and Gas Reporting, the natural gas and oil prices used to calculate the full cost ceiling (as of December 31, 2010) 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 December 31, 2010, the Company’s capitalized costs were below the full cost ceiling for the Company’s oil and gas properties. As a result, an impairment charge was not required at December 31, 2010.

Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss, net of related tax effect, are as follows (in thousands):

		At December 31, 2010				At September 30, 2010
Funded Status of the Pension and Other Post-Retirement Benefit Plans		$	(79,465	)		$	(79,465	)
Cumulative Foreign Currency Translation Adjustment			—				(51	)
Net Unrealized Gain on Derivative Financial Instruments			11,580				32,876
Net Unrealized Gain on Securities Available for Sale			3,235				1,655
Accumulated Other Comprehensive Loss		$	(64,650	)		$	(44,985	)

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

		At December 31, 2010				At September 30, 2010
Prepayments		$	10,873			$	13,884
Prepaid Property and Other Taxes			14,782				12,413
Federal Income Taxes Receivable			56,287				56,334
State Income Taxes Receivable			15,593				18,007
Fair Values of Firm Commitments			9,666				15,331
		$	107,201			$	115,969

Earnings Per Common Share. Basic earnings per common share is computed by dividing net 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 only potentially dilutive securities the Company has outstanding are stock options, SARs and restricted stock units. 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 and restricted stock units that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 23,478 and 24,000 SARs excluded as being antidilutive for the quarters ended December 31, 2010 and 2009, respectively. For the quarters ended December 31, 2010 and 2009, there were no stock options or restricted stock units excluded as being antidilutive.

Item 1. Financial Statements (Cont.)

Stock-Based Compensation. During the quarter ended December 31, 2010, the Company granted 180,000 non-performance based SARs having a weighted average exercise price of $63.87 per share. The weighted average grant date fair value of these SARs was $15.33 per share. These SARs may be settled in cash, in shares of common stock of the Company, or in a combination of cash and shares of common stock of the Company, as determined by the Company. These SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for those SARs is the same as the accounting for stock options. The non-performance based SARs granted during the quarter ended December 31, 2010 vest and become exercisable annually in one-third increments. The weighted average grant date fair value of these non-performance based SARs granted during the quarter ended December 31, 2010 was estimated on the date of grant using the same accounting treatment that is applied for stock options.

     There were no stock options granted during the quarter ended December 31, 2010. The Company did not recognize a tax benefit related to the exercise of stock options for the calendar year ended December 31, 2010 due to tax loss carryforwards. The Company expects to recognize a tax benefit of $18.1 million in Paid in Capital related to calendar 2010 stock option exercises in future years as the tax loss carryforward is utilized.

     The Company granted 47,250 restricted share awards (non-vested stock as defined by the current accounting literature) during the quarter ended December 31, 2010. The weighted average fair value of such restricted shares was $63.98 per share. In addition, the Company granted 28,900 restricted stock units during the quarter ended December 31, 2010. The weighted average fair value of such restricted stock units was $58.23 per share. 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 restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for these restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units must be reduced by the present value of forgone dividends over the vesting term of the award.

New Authoritative Accounting and Financial Reporting Guidance. In June 2009, the FASB issued amended authoritative guidance to improve and clarify financial reporting requirements by companies involved with variable interest entities. The new guidance requires a company to perform an analysis to determine whether the company’s variable interest or interests give it a controlling financial interest in a variable interest entity. The analysis also assists in identifying the primary beneficiary of a variable interest entity. This authoritative guidance became effective for the quarter ended December 31, 2010. Given the current organizational structure of the Company, the Company’s consolidated financial statements were not impacted by this guidance.

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 has the ability to 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 December 31, 2010 and September 30, 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Item 1.		Financial Statements (Cont.)

Recurring Fair Value Measures		At fair value as of December 31, 2010
(Thousands of Dollars)		Level 1				Level 2				Level 3				Total
| | | |
Assets:
Cash Equivalents — Money Market Mutual Funds		$	47,674			$	—			$	—			$	47,674
Derivative Financial Instruments:
Over the Counter Swaps — Oil			—				(392	)			—				(392	)
Over the Counter Swaps — Gas			—				46,544				—				46,544
Other Investments:
Balanced Equity Mutual Fund			18,280				—				—				18,280
Common Stock — Financial Services Industry			6,789				—				—				6,789
Other Common Stock			257				—				—				257
Hedging Collateral Deposits			31,446				—				—				31,446
Total		$	104,446			$	46,152			$	—			$	150,598
Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts — Gas		$	3,125			$	—			$	—			$	3,125
Over the Counter Swaps — Oil			—				—				37,407				37,407
Over the Counter Swaps — Gas			—				(6,032	)			—				(6,032	)
Total		$	3,125			$	(6,032	)		$	37,407			$	34,500
Total Net Assets/(Liabilities)		$	101,321			$	52,184			$	(37,407	)		$	116,098

Recurring Fair Value Measures		At fair value as of September 30, 2010
(Thousands of Dollars)		Level 1				Level 2				Level 3				Total
Assets:
Cash Equivalents — Money Market Mutual Funds		$	277,423			$	—			$	—			$	277,423
Derivative Financial Instruments:
Over the Counter Swaps — Gas			—				67,387				—				67,387
Over the Counter Swaps — Oil			—				—				(2,203	)			(2,203	)
Other Investments:
Balanced Equity Mutual Fund			17,256				—				—				17,256
Common Stock — Financial Services Industry			4,991				—				—				4,991
Other Common Stock			241				—				—				241
Hedging Collateral Deposits			11,134				—				—				11,134
Total		$	311,045			$	67,387			$	(2,203	)		$	376,229
Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts — Gas		$	5,840			$	—			$	—			$	5,840
Over the Counter Swaps — Oil			—				—				14,280				14,280
Over the Counter Swaps — Gas			—				40				—				40
Total		$	5,840			$	40			$	14,280			$	20,160
Total Net Assets/(Liabilities)		$	305,205			$	67,347			$	(16,483	)		$	356,069

Item 1.		Financial Statements (Cont.)

Derivative Financial Instruments

     At December 31, 2010 and September 30, 2010, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX futures contracts used in the Company’s Energy Marketing and Pipeline and Storage segments. Hedging collateral deposits of $6.6 million (at December 31, 2010) and $10.1 million (at September 30, 2010), which are associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at December 31, 2010 consist of crude oil and natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments. At September 30, 2010, the derivative financial instruments reported in Level 2 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments. The fair value of these 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 the majority of the Company’s Exploration and Production segment’s crude oil price swap agreements at December 31, 2010 and all of its crude oil price swap agreements at September 30, 2010. Hedging collateral deposits of $24.8 million and $1.0 million associated with these crude oil price swap agreements have been reported in Level 1 at December 31, 2010 and September 30, 2010, respectively. The fair value of the 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). Based on an assessment of the counterparties’ credit risk, the fair market value of the price swap agreements reported as Level 2 assets have been reduced by $0.5 million and $1.0 million at December 31, 2010 and September 30, 2010, respectively. The fair market value of the price swap agreements reported as Level 3 liabilities at December 31, 2010 have been reduced by less than $0.1 million and the price swap agreements reported as Level 2 and Level 3 liabilities at September 30, 2010 have been reduced by $0.3 million based on an assessment of the Company’s credit risk. These credit reserves were determined by applying default probabilities to the anticipated cash flows that the Company is either expecting from its counterparties or expecting to pay to its counterparties.

     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 ended December 31, 2010 and 2009, respectively. For the quarter ended December 31, 2010, no transfers in or out of Level 1 or Level 2 occurred.

Fair Value Measurements Using Unobservable Inputs (Level 3)

						Total Gains/Losses —
						Realized and Unrealized
		October 1,				Included in				Included in Other				Transfer
(Dollars in thousands)		2010				Earnings				Comprehensive Income				In/Out of Level 3				December 31, 2010
Derivative Financial Instruments(2)		$	(16,483	)		$	(2,803	)(1)		$	(18,121	)		$	—			$	(37,407	)

Item 1.		Financial Statements (Cont.)

Fair Value Measurements Using Unobservable Inputs (Level 3)

						Total Gains/Losses
						Realized and Unrealized
										Included in Other
		October 1,				Included in				Comprehensive				Transfer In/Out of
(Dollars in thousands)		2009				Earnings				Income				Level 3				December 31, 2009
Derivative Financial Instruments(2)		$	26,969			$	(3,135	)(1)		$	(23,983	)		$	—			$	(149	)

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):

		December 31, 2010								September 30, 2010
		Carrying								Carrying
		Amount				Fair Value				Amount				Fair Value
Long-Term Debt		$	1,049,000			$	1,196,215			$	1,249,000			$	1,423,349

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 $55.4 million at December 31, 2010 and September 30, 2010. The fair value of the equity mutual fund was $18.3 million at December 31, 2010 and $17.3 million at September 30, 2010. The gross unrealized gain on this equity mutual fund was $0.7 million at December 31, 2010. The unrealized gain on the equity mutual fund at September 30, 2010 was negligible as the fair value was approximately equal to the cost basis. The fair value of the stock of an insurance company was $6.8 million at December 31, 2010 and $5.0 million at September 30, 2010. The gross unrealized gain on this stock was $4.4 million at December 31, 2010 and $2.6 million at September 30, 2010. 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 is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk in the Exploration and Production, Energy Marketing and Pipeline and Storage segments. 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. The Company also enters into futures contracts and swaps to manage the risk associated with forecasted gas purchases, storage of gas, withdrawal of gas from storage to meet customer demand and the potential decline in the value of gas held in storage. The duration of the Company’s hedges do not typically exceed 3 years.

Item 1.		Financial Statements (Cont.)

     The Company has presented its net derivative assets and liabilities on its Consolidated Balance Sheets at December 31, 2010 and September 30, 2010 as shown in the table below.

Fair Values of Derivative Instruments

(Dollar Amounts in Thousands)

Derivatives

Asset Derivatives

Liability Derivatives

Designated as

Consolidated

Consolidated

Hedging

Balance Sheet

Balance Sheet

Instruments

Location

Fair Value

Location

Fair Value

Commodity Contracts — at December 31, 2010

Fair Value of Derivative Financial Instruments

$

46,152

Fair Value of Derivative Financial Instruments

$

34,500

Commodity Contracts — at September 30, 2010

Fair Value of Derivative Financial Instruments

$

65,184

Fair Value of Derivative Financial Instruments

$

20,160

     The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation on the Consolidated Balance Sheets at December 31, 2010 and September 30, 2010.

		Fair Values of Derivative Instruments
		(Dollar Amounts in Thousands)
		Gross Asset Derivatives				Gross Liability Derivatives
Derivatives Designated as Hedging Instruments		Fair Value				Fair Value
Commodity Contracts — at December 31, 2010		$	58,315			$	46,663
Commodity Contracts — at September 30, 2010		$	77,837			$	32,813

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 December 31, 2010, the Company’s Exploration and Production segment had the following commodity derivative contracts (swaps) outstanding to hedge forecasted sales (where the Company uses short positions (i.e. positions that pay-off in the event of commodity price decline) to mitigate the risk of decreasing revenues and earnings):

Commodity		Units
Natural Gas		41.9 Bcf (all short positions)
Crude Oil		2,727,000 Bbls (all short positions)

Item 1.		Financial Statements (Cont.)

     As of December 31, 2010, the Company’s Energy Marketing segment had the following commodity derivative contracts (futures contracts and swaps) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings) and purchases (where the Company uses long positions (i.e. positions that pay-off in the event of commodity price increases) to mitigate the risk of increasing natural gas prices, which would lead to increased purchased gas expense and decreased earnings):

Commodity		Units
Natural Gas		5.5 Bcf (4.2 Bcf short positions (forecasted storage withdrawals) and 1.3 Bcf long positions (forecasted storage injections))

     As of December 31, 2010, the Company’s Pipeline and Storage segment had the following commodity derivative contracts (futures contracts) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings):

Commodity		Units
Natural Gas		0.3 Bcf (all short positions)

     As of December 31, 2010, the Company’s Exploration and Production segment had $13.3 million ($7.9 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $10.3 million ($6.1 million after tax) of these gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).

     As of December 31, 2010, the Company’s Energy Marketing segment had $6.2 million ($3.8 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $6.1 million ($3.7 million after tax) of these gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the sales and purchases of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).

     As of December 31, 2010, the Company’s Pipeline and Storage segment had $0.1 million (less than $0.1 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).

Item 1. Financial Statements (Cont.)

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended December 31, 2010 and 2009 (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 December 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 December 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 December 31,
		2010				2009								2010				2009								2010				2009
Commodity Contracts — Exploration & Production segment		$	(26,781	)		$	(7,910	)		Operating Revenue				$	9,007			$	12,040			Operating Revenue				$	—			$	—
Commodity Contracts — Energy Marketing segment		$	(269	)		$	3,024			Purchased Gas				$	46			$	23			Operating Revenue				$	—			$	—
Commodity Contracts — Pipeline & Storage segment		$	(86	)		$	33			Operating Revenue				$	—			$	(11	)		Operating Revenue				$	—			$	—
Total		$	(27,136	)		$	(4,853	)						$	9,053			$	12,052							$	—			$	—

Fair value hedges

     The Company’s Energy Marketing segment utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of 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 December 31, 2010, the Company’s Energy Marketing segment had fair value hedges covering approximately 12.4 Bcf (11.5 Bcf of fixed price sales commitments (all long

Item 1. Financial Statements (Cont.)

positions), 0.8 Bcf of fixed price purchase commitments (all short positions), and 0.1 Bcf of commitments related to the withdrawal of storage gas (all short positions)). 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.

Consolidated
Statement of Income		Gain/(Loss) on Derivative				Gain/(Loss) on Commitment
Operating Revenues		$	7,511,054			$	(7,511,054	)
Purchased Gas		$	(841,956	)		$	841,956

						Amount of Derivative Gain or (Loss)
						Recognized in the Consolidated
Derivatives in		Location of Derivative Gain or (Loss)				Statement of Income
Fair Value Hedging		Recognized in the Consolidated				for the Three Months Ended
Relationships		Statement of Income				December 31, 2010
						(In thousands)
Commodity Contracts — Energy Marketing segment (1)		Operating Revenues				$	7,511
Commodity Contracts — Energy Marketing segment (2)		Purchased Gas				$	(649	)
Commodity Contracts — Energy Marketing segment (3)		Purchased Gas				$	(192	)
						$	6,670

     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 eleven counterparties of which nine are in a net gain position. The Company had derivative financial instruments that were in loss positions with the other two counterparties. On average, the Company had $5.1 million of credit exposure per counterparty in a gain position at December 31, 2010. The maximum credit exposure per counterparty in a gain position at December 31, 2010 was $9.2 million. The Company had not received any collateral from these counterparties at December 31, 2010 since the Company’s gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral.

     As of December 31, 2010, nine of the eleven 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 current liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits would be required. At December 31, 2010, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $27.5 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements). At December 31, 2010, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $31.4 million according to the Company’s internal model (discussed in

Item 1.		Financial Statements (Cont.)

Note 2 — Fair Value Measurements). The liability with one counterparty was $30.1 million. For its over-the-counter crude oil swap agreements, which are in a liability position, the Company was required to post $24.8 million in hedging collateral deposits at December 31, 2010. This is discussed in Note 1 under Hedging Collateral Deposits.

     For its exchange traded futures contracts which are in a liability position, the Company had posted $6.6 million in hedging collateral as of December 31, 2010. 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 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):

		Three Months Ended
		December 31,
		2010				2009
Current Income Taxes
Federal		$	—			$	15,070
State			1,452				3,916
Deferred Income Taxes
Federal			29,936				17,335
State			6,664				3,757
			38,052				40,078
Deferred Investment Tax Credit			(174	)			(174	)
Total Income Taxes		$	37,878			$	39,904
Presented as Follows:
Other Income		$	(174	)		$	(174	)
Income Tax Expense — Continuing Operations			38,052				39,883
Income from Discontinued Operations			—				195
Total Income Taxes		$	37,878			$	39,904

Item 1.		Financial Statements (Cont.)

     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):

		Three Months Ended
		December 31,
		2010				2009
U.S. Income Before Income Taxes		$	96,421			$	104,403
Income Tax Expense, Computed at Federal Statutory Rate of 35%		$	33,747			$	36,541
Increase (Reduction) in Taxes Resulting from:
State Income Taxes			5,275				4,987
Miscellaneous			(1,144	)			(1,624	)
Total Income Taxes		$	37,878			$	39,904
Significant components of the Company’s deferred tax liabilities and assets are as follows (in thousands):
		At December 31, 2010				At September 30, 2010
Deferred Tax Liabilities:
Property, Plant and Equipment		$	915,648			$	849,869
Pension and Other Post-Retirement Benefit Costs			180,595				177,853
Other			47,690				63,671
Total Deferred Tax Liabilities			1,143,933				1,091,393
Deferred Tax Assets:
Pension and Other Post-Retirement Benefit Costs			(222,713	)			(223,588	)
Tax Loss Carryforwards			(45,676	)			(9,772	)
Other			(75,444	)			(81,751	)
Total Deferred Tax Assets			(343,833	)			(315,111	)
Total Net Deferred Income Taxes		$	800,100			$	776,282
Presented as Follows:
Net Deferred Tax Liability/(Asset) — Current		$	(20,901	)		$	(24,476	)
Net Deferred Tax Liability — Non-Current			821,001				800,758
Total Net Deferred Income Taxes		$	800,100			$	776,282

     As a result of certain realization requirements of the authoritative guidance on stock-based compensation, the table of deferred tax liabilities and assets shown above does not include certain deferred tax assets at December 31, 2010 that arose directly from excess tax deductions related to stock-based compensation. A tax benefit of $18.1 million relating to the excess stock-based compensation deductions will be recorded in Paid in Capital in future years when such tax benefit is realized.

     Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $69.6 million at both December 31, 2010 and September 30, 2010. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $150.9 million and $149.7 million at December 31, 2010 and September 30, 2010, respectively.

Item 1.		Financial Statements (Cont.)

     The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 2010 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. While the federal statute of limitations remains open for fiscal 2007 and later years, IRS examinations for fiscal 2008 and prior years have been completed and the Company believes such years are effectively settled. During fiscal 2009, consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property. During fiscal 2010, local IRS examiners proposed to disallow most of the accounting method change recorded by the Company in fiscal 2009. The Company has filed a protest with the IRS Appeals Office disputing the local IRS findings.

     The Company is also subject to various routine state income tax examinations. The Company’s operating subsidiaries mainly operate in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.

Note 5 — Capitalization

Common Stock. During the three months ended December 31, 2010, the Company issued 482,109 original issue shares of common stock as a result of stock option exercises and 47,250 original issue shares for restricted stock awards (non-vested as defined by the current accounting literature for stock-based compensation). The Company also issued 3,600 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Company’s Retainer Policy for Non-Employee Directors or the Company’s 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors’ services during the three months ended December 31, 2010. Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the three months ended December 31, 2010, 269,975 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

Current Portion of Long-Term Debt. Current Portion of Long-Term Debt at December 31, 2010 consists of $150 million of 6.70% medium-term notes that mature in November 2011. Current Portion of Long-Term Debt at September 30, 2010 consisted of $200 million of 7.50% notes that matured in November 2010.

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 policies and procedures. 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.

     The Company has agreed with the NYDEC to remediate a former manufactured gas plant site located in New York. The Company has received approval from the NYDEC of a Remedial Design work plan for this site and has recorded an estimated minimum liability for remediation of this site of $14.6 million.

     At December 31, 2010, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $17.2 million to $21.4 million. The minimum estimated liability of $17.2 million, which includes the $14.6 million discussed above, has been recorded on the Consolidated Balance Sheet at December 31, 2010. The Company expects to recover its environmental clean-up costs through rate recovery.

Item 1.		Financial Statements (Cont.)

     The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact 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 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.

Note 7 — Discontinued Operations

     On September 1, 2010, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Those operations consisted of short distance landfill gas pipeline companies engaged in the purchase, sale and transportation of landfill gas. The Company’s landfill gas operations were maintained under the Company’s wholly-owned subsidiary, Horizon LFG. The decision to sell was based on progressing the Company’s strategy of divesting its smaller, non-core assets in order to focus on its core businesses, including the development of the Marcellus Shale and the construction of key pipeline infrastructure projects throughout the Appalachian region. As a result of the decision to sell the landfill gas operations, the Company began presenting these operations as discontinued operations during the fourth quarter of 2010.

     The following is selected financial information of the discontinued operations for the sale of the Company’s landfill gas operations:

		Three Months Ended
		December 31,
(Thousands)		2009
Operating Revenues		$	2,876
Operating Expenses			2,400
Operating Income			476
Other Interest Expense			(7	)
Income before Income Taxes			469
Income Tax Expense			195
Income from Discontinued Operations		$	274

Note 8 — Business Segment Information

     The Company reports financial results for four segments: Utility, Pipeline and Storage, Exploration and Production 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.

Item 1. Financial Statements (Cont.)

     The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. As stated in the 2010 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 been no changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2010 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the 2010 Form 10-K.

Quarter Ended December 31, 2010 (Thousands)
										Exploration								Total								Corporate and
										and				Energy				Reportable								Intersegment				Total
		Utility				Pipeline and Storage				Production				Marketing				Segments				All Other				Eliminations				Consolidated
Revenue from External Customers		$	242,842			$	33,513			$	120,168			$	53,652			$	450,175			$	549			$	224			$	450,948
Intersegment Revenues		$	4,570			$	19,882			$	—			$	—			$	24,452			$	1,678			$	(26,130	)		$	—
Segment Profit:
Net Income (Loss)		$	22,990			$	8,578			$	27,373			$	932			$	59,873			$	(574	)		$	(756	)		$	58,543

Quarter Ended December 31, 2009 (Thousands)
										Exploration								Total								Corporate and
										and				Energy				Reportable								Intersegment				Total
		Utility				Pipeline and Storage				Production				Marketing				Segments				All Other				Eliminations				Consolidated
Revenue from External Customers		$	232,404			$	34,504			$	106,351			$	71,736			$	444,995			$	8,929			$	211			$	454,135
Intersegment Revenues		$	4,514			$	20,257			$	—			$	—			$	24,771			$	—			$	(24,771	)		$	—
Segment Profit:
Income (Loss) from Continuing Operations		$	23,013			$	10,354			$	29,779			$	1,092			$	64,238			$	892			$	(905	)		$	64,225

Item 1. Financial Statements (Concl.)

Note 9 — Retirement Plan and Other Post-Retirement Benefits

     Components of Net Periodic Benefit Cost (in thousands):

		Retirement Plan								Other Post-Retirement Benefits
Three months ended December 31,		2010				2009				2010				2009
Service Cost		$	3,693			$	3,249			$	1,069			$	1,075
Interest Cost			10,669				11,077				5,471				6,254
Expected Return on Plan Assets			(14,776	)			(14,585	)			(7,291	)			(6,584	)
Amortization of Prior Service Cost			147				164				(427	)			(427	)
Amortization of Transition Amount			—				—				135				135
Amortization of Losses			8,718				5,410				5,948				6,470
Net Amortization and Deferral For Regulatory Purposes (Including Volumetric Adjustments) (1)			(1,793	)			(42	)			1,921				(100	)
Net Periodic Benefit Cost		$	6,658			$	5,273			$	6,826			$	6,823

Employer Contributions. During the three months ended December 31, 2010, the Company contributed $20.6 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $6.2 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2011, the Company expects to contribute at a minimum in the range of $19.0 million to $25.0 million to the Retirement Plan. Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in fiscal 2011 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2011, the Company expects to contribute in the range of $18.0 million to $24.0 million to its VEBA trusts and 401(h) accounts.

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

OVERVIEW

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

     The Company is a diversified energy holding company that owns a number of subsidiary operating companies, and reports financial results in four reportable business segments. For the quarter ended December 31, 2010 compared to the quarter ended December 31, 2009, the Company experienced a decrease in earnings of $6.0 million, primarily due to lower earnings in the Exploration and Production segment, the Pipeline and Storage segment and in the All Other category. For further discussion of the Company’s earnings, refer to the Results of Operations section below.

     The Company continues to focus on the development of its Marcellus Shale acreage in the Appalachian region of its Exploration and Production segment. 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. Due to the depth at which this formation is found, drilling and completion costs, including the drilling and completion of horizontal wells with hydraulic fracturing, are very expensive. However, independent geological studies have indicated that this formation could yield natural gas reserves measured in the trillions of cubic feet. The Company controls approximately 745,000 net acres within the Marcellus Shale area of Pennsylvania, with a majority of the acreage held in fee, carrying no royalty and no lease expirations. The Company’s reserve base has grown substantially from development in the Marcellus Shale. Natural gas proved developed and undeveloped reserves in the Appalachian region increased from 150 Bcf at September 30, 2009 to 331 Bcf at September 30, 2010. With this in mind, and with a natural desire to realize the value of these assets in a responsible and orderly fashion, the Company has spent significant amounts of capital in this region. For the quarter ended December 31, 2010, the Company spent $173.0 million towards the development of the Marcellus Shale. This includes paying $24.1 million in November 2010 for the acquisition of additional oil and gas properties in the Covington Township area of Tioga County, Pennsylvania from EOG Resources, Inc. These properties are producing natural gas from the Marcellus Shale and are also prospective for additional Marcellus reserves. As a result of the transaction, it is anticipated that the Appalachian region of the Exploration and Production segment will add approximately 42 Bcf of proved natural gas reserves, thereby having an immediate positive impact on the Company’s production and proved reserves.

     The Company has engaged Jefferies & Company to explore joint-venture opportunities across its Marcellus Shale acreage in its Exploration and Production segment. It is the Company’s goal to accelerate Marcellus Shale development faster than its current plans. By entering into a joint-venture agreement, the Company expects to enhance shareholder value by shifting a significant portion of the early drilling costs to a minority-interest partner while still allowing the Company to continue operating across most of its acreage. The Company’s position in the Marcellus Shale provides a competitive advantage for a potential joint-venture partner as a majority of the acreage is held in fee, carrying no royalty and no lease expirations, and large, contiguous acreage blocks allow for operating- and cost-efficiency through multi-well pad drilling. The Company will forgo any joint-venture opportunities that do not enhance shareholder value when compared to its current growth plans.

     Coincident with the development of its Marcellus Shale acreage, the Company’s Pipeline and Storage segment is building pipeline gathering and transmission facilities to connect Marcellus Shale production with existing pipelines in the region and is pursuing the development of additional pipeline and storage capacity in order to meet anticipated demand for the large amount of Marcellus Shale production expected to come on-line in the months and years to come. Two of the projects, the Tioga County Extension Project and the Northern Access expansion project, are considered significant for Empire and Supply Corporation. Both projects are designed to receive natural gas produced from the Marcellus Shale and transport it to Canada and the Northeast United States to meet growing demand in those areas. During the past year, Empire and Supply Corporation have experienced a decline in the volumes of natural gas received at the Canada/United States border at the Niagara River to be shipped across their systems. The historical price advantage for gas sold at the Niagara import points has declined as production in the Canadian producing regions has declined or been diverted to other demand areas, and

Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

as production from new shale plays has increased in the United States. This factor has been causing shippers to seek alternative gas supplies and consequently alternative transportation routes. The Tioga County Extension Project and the Northern Access expansion project are designed to provide an alternative gas supply source for the customers of Empire and Supply Corporation. These projects, which are discussed more completely in the Investing Cash Flow section that follows, will involve significant capital expenditures.

     From a capital resources perspective, the Company has been able to meet its capital expenditure needs for all of the above projects by using cash from operations and short-term borrowings. The Company had $79.6 million in Cash and Temporary Cash Investments at December 31, 2010, as shown on the Company’s Consolidated Balance Sheet. For the remainder of fiscal 2011, the Company expects that it will be able to use cash on hand and cash from operations as its first means of financing capital expenditures, with short-term borrowings and long-term borrowings being its next sources of funding. It is not expected that long-term financing will be required to meet capital expenditure needs until the later part of fiscal 2011 or in fiscal 2012.

     The possibility of environmental risks associated with a well completion technology referred to as hydraulic fracturing 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. Hydraulic fracturing is a well stimulation technique that has been used for many years, and in the Company’s experience, one that the Company believes has little impact to the environment. Nonetheless, 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. For example, New York State currently has a moratorium in place that prevents hydraulic fracturing of new horizontal wells in the Marcellus Shale. However, due to the small amount of Marcellus Shale acreage owned by the Company in New York State, the moratorium is not expected to have a significant impact on the Company’s plans for Marcellus Shale development. Please refer to the Risk Factors section of the Form 10-K for the year ended September 30, 2010 as well as updates to that section in this Form 10-Q for the quarter ended December 31, 2010 for further discussion.

     The Company is pursuing the sale of smaller, non-core assets in order to focus on its core businesses, including the development of the Marcellus Shale and the construction of key pipeline infrastructure projects throughout the Appalachian region. With this strategy in mind, the Company entered into a purchase and sale agreement in December 2010 whereby it intends to sell its 50% equity method investments in Seneca Energy and Model City. It is estimated that the Company will record a gain of approximately $28.0 million from this sale. The sale is expected to close during the quarter ended March 31, 2011.

CRITICAL ACCOUNTING ESTIMATES

     For a complete discussion of critical accounting estimates, refer to “Critical Accounting Estimates” in Item 7 of the Company’s 2010 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.

Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

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 December 31, 2010, the ceiling exceeded the book value of the oil and gas properties by approximately $232 million. The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended December 31, 2010, based on posted Midway Sunset prices was $72.25 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 December 31, 2010, based on the quoted Henry Hub spot price for natural gas, was $4.38 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 December 31, 2010.) If natural gas prices used in the ceiling test calculation at December 31, 2010 had been $1 per MMBtu lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $56 million. If crude oil prices used in the ceiling test calculation at December 31, 2010 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $125 million. If both natural gas and crude oil prices used in the ceiling test calculation at December 31, 2010 were lower by $1 per MMBtu and $5 per Bbl, respectively, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $8 million. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation. 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 2010 Form 10-K.

RESULTS OF OPERATIONS

Earnings

     The Company’s earnings were $58.5 million for the quarter ended December 31, 2010 compared to earnings of $64.5 million for the quarter ended December 31, 2009. As previously discussed, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana in September 2010. Accordingly, all financial results for these operations, which are part of the All Other category, have been presented as discontinued operations. The Company’s earnings from continuing operations were $58.5 million for the quarter ended December 31, 2010 compared with $64.2 million for the quarter ended December 31, 2009. The decrease in earnings from continuing operations of $5.7 million is primarily a result of lower earnings in the Exploration and Production segment, the Pipeline and Storage segment and the All Other category.

     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.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

Earnings (Loss) by Segment

										Increase
Three Months Ended December 31 (Thousands)		2010				2009				(Decrease)
Utility		$	22,990			$	23,013			$	(23	)
Pipeline and Storage			8,578				10,354				(1,776	)
Exploration and Production			27,373				29,779				(2,406	)
Energy Marketing			932				1,092				(160	)
Total Reportable Segments			59,873				64,238				(4,365	)
All Other			(574	)			892				(1,466	)
Corporate			(756	)			(905	)			149
Total Earnings from Continuing Operations			58,543				64,225				(5,682	)
Earnings from Discontinued Operations			—				274				(274	)
Total Consolidated		$	58,543			$	64,499			$	(5,956	)

Utility

Utility Operating Revenues

										Increase
Three Months Ended December 31 (Thousands)		2010				2009				(Decrease)
Retail Sales Revenues:
Residential		$	177,189			$	176,597			$	592
Commercial			22,545				24,406				(1,861	)
Industrial			1,244				1,288				(44	)
			200,978				202,291				(1,313	)
Transportation			35,412				30,695				4,717
Off-System Sales			8,889				1,691				7,198
Other			2,133				2,241				(108	)
		$	247,412			$	236,918			$	10,494