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

For the quarterly period ended~~June 30,~~ December 31, 2009


o		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. YESþ NOo

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). YESo NOo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or 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~~ Accelerated Filerþ		Accelerated ~~filer~~ Filero	~~Non-accelerated filer~~	Non-Accelerated Filero (Do not check if a smaller reporting company)		Smaller ~~reporting company~~ Reporting Companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YESo NOþ

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 ~~July~~January 31, ~~2009: 80,234,282~~2010: 81,109,235 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

~~Data-Track~~		~~Data-Track Account Services, Inc.~~

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 LFG		Horizon LFG, Inc.

Horizon Power		Horizon Power, Inc.

~~Leidy Hub~~		~~Leidy Hub, 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

~~SECI~~		~~Seneca Energy Canada Inc.~~

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*

~~2008~~2009 Form 10-K		The Company’s Annual Report on Form 10-K for the year ended September 30, ~~2008, as amended~~

~~ARB 51~~		~~Accounting Research Bulletin No. 51, Consolidated Financial Statements~~
		2009
Bbl		Barrel (of oil)

Bcf		Billion cubic feet (of natural gas)

Board foot		A measure of lumber and/or timber equal to 12 inches in length by 12 inches in width by one inch in thickness.

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

-2-


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.

~~FIN~~		~~FASB Interpretation Number~~

~~FIN 48~~		~~FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of SFAS 109~~

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
~~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

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.
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 ~~industries~~industry by a statutory or regulatory process. Restructuring of federally regulated natural gas pipelines ~~has~~ 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.

S&P		Standard & Poor’s ~~Ratings~~Rating Service

SAR		Stock-settled stock appreciation right

~~SFAS~~		~~Statement of Financial Accounting Standards~~

~~SFAS 87~~		~~Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions~~

~~SFAS 88~~		~~Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits~~

~~SFAS 106~~		~~Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions~~

~~SFAS 109~~		~~Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes~~

~~-3-~~


~~GLOSSARY OF TERMS (Concl.)~~

~~SFAS 123R~~		~~Statement of Financial Accounting Standards No. 123R, Share-Based Payment~~

~~SFAS 131~~		~~Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information~~

~~SFAS 132R~~		~~Statement of Financial Accounting Standards No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits~~

~~SFAS 133~~		~~Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities~~

~~SFAS 141R~~		~~Statement of Financial Accounting Standards No. 141R, Business Combinations~~

~~SFAS 157~~		~~Statement of Financial Accounting Standards No. 157, Fair Value Measurements~~

~~SFAS 158~~		~~Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an Amendment of SFAS 87, 88, 106, and 132R~~

~~SFAS 160~~		~~Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB 51~~

~~SFAS 161~~		~~Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS 133~~

~~SFAS 165~~		~~Statement of Financial Accounting Standards No. 165, Subsequent Events~~

~~SFAS 168~~		~~Statement of Financial Accounting Standards No. 168, The FASB Accounting Standards Codification~~^TM~~and the Hierarchy of Generally Accepted Accounting Principles — a Replacement of FASB Statement No. 162~~

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

-3-

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						Three Months Ended
	June 30,						December 31,
(Thousands of Dollars, Except Per Common Share Amounts)	2009			2008			2009			2008

INCOME
Operating Revenues	$	367,111		$	548,382		$	457,011		$	607,163


Operating Expenses
Purchased Gas		126,969			272,893			172,787			328,733
Operation and Maintenance		90,821			102,602			94,497			100,887
Property, Franchise and Other Taxes		17,576			19,135			18,659			18,762
Depreciation, Depletion and Amortization		43,659			42,804			44,955			42,342
Impairment of Oil and Gas Producing Properties								—			182,811

		279,025			437,434			330,898			673,535

Operating Income		88,086			110,948
Operating Income (Loss)								126,113			(66,372	)
Other Income (Expense):
Income from Unconsolidated Subsidiaries		627			1,561			401			1,118
Impairment of Investment in Partnership								—			(1,804	)
Interest Income		1,460			3,086			1,154			1,892
Other Income		664			1,649			356			4,880
Interest Expense on Long-Term Debt		(21,756	)		(19,468	)		(22,063	)		(18,056	)
Other Interest Expense		(2,539	)		(1,199	)		(1,384	)		375

Income Before Income Taxes		66,542			96,577
Income Tax Expense		23,638			36,722
Income (Loss) Before Income Taxes								104,577			(77,967	)
Income Tax Expense (Benefit)								40,078			(35,289	)


Net Income Available for Common Stock		42,904			59,855
Net Income (Loss) Available for Common Stock								64,499			(42,678	)


EARNINGS REINVESTED IN THE BUSINESS
Balance at April 1		932,119			1,008,084
Balance at October 1								948,293			953,799

		975,023			1,067,939			1,012,792			911,121
Share Repurchases		—			(17,083	)
Dividends on Common Stock (2009 — $0.335 per share; 2008 — $0.325 per share)		(26,761	)		(26,479	)
Adoption of Authoritative Guidance for Defined Benefit Pension and Other Post-Retirement Plans								—			(804	)
Dividends on Common Stock (2009 - $0.335; 2008 - $0.325)								(27,129	)		(25,841	)

Balance at June 30	$	948,262		$	1,024,377
Balance at December 31							$	985,663		$	884,476


Earnings Per Common Share:
Basic:
Net Income Available for Common Stock	$	0.54		$	0.74
Net Income (Loss) Available for Common Stock							$	0.80		$	(0.54	)

Diluted:
Net Income Available for Common Stock	$	0.53		$	0.72
Net Income (Loss) Available for Common Stock							$	0.78		$	(0.53	)

Weighted Average Common Shares Outstanding:
Used in Basic Calculation		79,551,195			81,342,788			80,612,303			79,289,005

Used in Diluted Calculation		80,391,402			83,712,193			82,172,649			80,167,893

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated ~~Statements of Income and Earnings~~Balance Sheets
~~Reinvested in the Business~~

(Unaudited)

Nine Months Ended
June 30,
(Thousands of Dollars, Except Per Common Share Amounts) 2009 2008

INCOME

Operating Revenues
$ 1,778,919 $ 2,002,503

Operating Expenses

Purchased Gas 941,171 1,082,340
Operation and Maintenance 310,605 325,642
Property, Franchise and Other Taxes 56,709 58,206
Depreciation, Depletion and Amortization 127,715 129,337
Impairment of Oil and Gas Producing Properties 182,811 —

1,619,011 1,595,525

Operating Income
159,908 406,978
Other Income (Expense):

Income from Unconsolidated Subsidiaries 915 4,866
Interest Income 4,358 8,356
Other Income 6,459 4,982
Interest Expense on Long-Term Debt (57,357 ) (52,045 )
Other Interest Expense (5,013 ) (4,209 )

Income Before Income Taxes
109,270 368,928
Income Tax Expense 35,560 143,465

Net Income Available for Common Stock
73,710 225,463

EARNINGS REINVESTED IN THE BUSINESS

Balance at October 1 953,799 983,776

1,027,509 1,209,239
Share Repurchases — (106,647 )
Cumulative Effect of the Adoption of FIN 48 — (406 )
Adoption of SFAS 158 Measurement Date Provision (804 ) —
Dividends on Common Stock
(2009 — $0.985 per share; 2008 — $0.945 per share) (78,443 ) (77,809 )

Balance at June 30
$ 948,262 $ 1,024,377

Earnings Per Common Share:

Basic:
Net Income Available for Common Stock $ 0.93 $ 2.72

Diluted:
Net Income Available for Common Stock $ 0.92 $ 2.65

Weighted Average Common Shares Outstanding:

Used in Basic Calculation 79,450,838 82,789,748

Used in Diluted Calculation 80,248,787 85,000,381


	December 31,		September 30,
	2009		2009
(Thousands of Dollars)
ASSETS
Property, Plant and Equipment	$	5,245,050	$	5,183,527
Less — Accumulated Depreciation, Depletion and Amortization		2,078,625		2,051,482

		3,166,425		3,132,045

Current Assets
Cash and Temporary Cash Investments		404,401		408,053
Cash Held in Escrow		2,000		2,000
Hedging Collateral Deposits		1,092		848
Receivables — Net of Allowance for Uncollectible Accounts of $42,955 and $38,334, Respectively		176,202		144,466
Unbilled Utility Revenue		55,012		18,884
Gas Stored Underground		49,042		55,862
Materials and Supplies — at average cost		28,501		24,520
Other Current Assets		64,052		68,474
Deferred Income Taxes		48,621		53,863

		828,923		776,970


Other Assets
Recoverable Future Taxes		138,435		138,435
Unamortized Debt Expense		14,249		14,815
Other Regulatory Assets		522,669		530,913
Deferred Charges		3,507		2,737
Other Investments		77,692		78,503
Investments in Unconsolidated Subsidiaries		14,728		16,257
Goodwill		5,476		5,476
Intangible Assets		21,087		21,536
Fair Value of Derivative Financial Instruments		19,791		44,817
Other		4,719		6,625

		822,353		860,114


Total Assets	$	4,817,701	$	4,769,129

See Notes to Condensed Consolidated Financial Statements

-7-

Item 1.Financial Statements (Cont.)

National Fuel Gas Company
Consolidated Balance Sheets
(~~Unaudited)~~(Unaudited)


	June 30,		September 30,
	2009		2008
					December 31,			September 30,
(Thousands of Dollars)					2009			2009

CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value Authorized — 200,000,000 Shares; Issued and Outstanding — 79,881,482 Shares and 79,120,544 Shares, Respectively	$	79,881	$	79,121
Common Stock, $1 Par Value Authorized — 200,000,000 Shares; Issued And Outstanding �� 80,981,933 Shares And 80,499,915 Shares, Respectively					$	80,982		$	80,500
Paid in Capital		589,295		567,716		620,601			602,839
Earnings Reinvested in the Business		948,262		953,799		985,663			948,293

Total Common Shareholder Equity Before Items of Other Comprehensive Income		1,617,438		1,600,636
Accumulated Other Comprehensive Income		17,234		2,963
Total Common Shareholder Equity Before Items of Other Comprehensive Loss						1,687,246			1,631,632
Accumulated Other Comprehensive Loss						(52,702	)		(42,396	)

Total Comprehensive Shareholders’ Equity		1,634,672		1,603,599		1,634,544			1,589,236
Long-Term Debt, Net of Current Portion		1,249,000		999,000		1,049,000			1,249,000

Total Capitalization		2,883,672		2,602,599		2,683,544			2,838,236


Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		—		—		—			—
Current Portion of Long-Term Debt		—		100,000		200,000			—
Accounts Payable		69,762		142,520		108,404			90,723
Amounts Payable to Customers		45,772		2,753		94,468			105,778
Dividends Payable		26,761		25,714		27,129			26,967
Interest Payable on Long-Term Debt		18,722		22,114		17,203			32,031
Customer Advances		3,229		33,017		30,653			24,555
Customer Security Deposits						19,565			17,430
Other Accruals and Current Liabilities		198,057		45,220		19,451			18,875
Deferred Income Taxes		—		1,871
Fair Value of Derivative Financial Instruments		1,815		1,362		—			2,148

		364,118		374,571		516,873			318,507


Deferred Credits
Deferred Income Taxes		589,380		634,372		670,989			663,876
Taxes Refundable to Customers		18,459		18,449		67,050			67,046
Unamortized Investment Tax Credit		4,165		4,691		3,814			3,989
Cost of Removal Regulatory Liability		107,245		103,100		120,797			105,546
Other Regulatory Liabilities		115,617		91,933		116,035			120,229
Pension and Other Post-Retirement Liabilities		61,404		78,909		401,737			415,888
Asset Retirement Obligations		86,559		93,247		91,538			91,373
Other Deferred Credits		124,683		128,316		145,324			144,439

		1,107,512		1,153,017		1,617,284			1,612,386

Commitments and Contingencies		—		—		—			—


Total Capitalization and Liabilities	$	4,355,302	$	4,130,187	$	4,817,701		$	4,769,129

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Statements of Cash Flows
(Unaudited)


	Three Months Ended
	December 31,
(Thousands of Dollars)	2009			2008
OPERATING ACTIVITIES
Net Income (Loss) Available for Common Stock	$	64,499		$	(42,678	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties		—			182,811
Depreciation, Depletion and Amortization		44,955			42,342
Deferred Income Taxes		21,092			(69,626	)
Income from Unconsolidated Subsidiaries, Net of Cash Distributions		1,599			1,032
Impairment of Investment in Partnership		—			1,804
Excess Tax Benefits Associated with Stock-Based Compensation Awards		(13,437	)		(5,927	)
Other		7,958			6,628
Change in:
Hedging Collateral Deposits		(244	)		(3,742	)
Receivables and Unbilled Utility Revenue		(67,882	)		(98,914	)
Gas Stored Underground and Materials and Supplies		2,839			20,971
Unrecovered Purchased Gas Costs		—			10,992
Prepayments and Other Current Assets		17,859			14,958
Accounts Payable		11,408			3,705
Amounts Payable to Customers		(11,310	)		1,962
Customer Advances		6,098			(2,924	)
Customer Security Deposits		2,135			1,354
Other Accruals and Current Liabilities		(13,536	)		29,053
Other Assets		16,967			12,560
Other Liabilities		(22,667	)		(6,217	)

Net Cash Provided by Operating Activities		68,333			100,144


INVESTING ACTIVITIES
Capital Expenditures		(62,135	)		(84,268	)
Investment in Partnership		(70	)		—
Other		(247	)		(632	)

Net Cash Used in Investing Activities		(62,452	)		(84,900	)


FINANCING ACTIVITIES
Change in Notes Payable to Banks and Commercial Paper		—			66,000
Excess Tax Benefits Associated with Stock-Based Compensation Awards		13,437			5,927
Dividends Paid on Common Stock		(26,967	)		(25,714	)
Net Proceeds from Issuance of Common Stock		3,997			6,989

Net Cash Provided by (Used in) Financing Activities		(9,533	)		53,202

Net Increase (Decrease) in Cash and Temporary Cash Investments		(3,652	)		68,446

Cash and Temporary Cash Investments at October 1		408,053			68,239


Cash and Temporary Cash Investments at December 31	$	404,401		$	136,685

See Notes to Condensed Consolidated Financial Statements

-9-

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated ~~Statement~~Statements of ~~Cash Flows~~Comprehensive Income
(Unaudited)

Nine Months Ended
June 30,
(Thousands of Dollars) 2009 2008

OPERATING ACTIVITIES

Net Income Available for Common Stock $ 73,710 $ 225,463
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties 182,811 —
Depreciation, Depletion and Amortization 127,715 129,337
Deferred Income Taxes (85,494 ) 27,603
Income from Unconsolidated Subsidiaries, Net of Cash Distributions 180 1,340
Impairment of Investment in Partnership 1,804 —
Excess Tax Benefits Associated with Stock-Based Compensation Awards (5,927 ) (16,275 )
Other 9,365 (1,120 )
Change in:
Hedging Collateral Deposits (6,358 ) (26,712 )
Receivables and Unbilled Utility Revenue (5,520 ) (129,102 )
Gas Stored Underground and Materials and Supplies 71,491 14,819
Unrecovered Purchased Gas Costs 35,808 9,089
Prepayments and Other Current Assets 37,904 17,370
Accounts Payable (82,146 ) 53,081
Amounts Payable to Customers 43,019 2,455
Customer Advances (29,788 ) (22,863 )
Other Accruals and Current Liabilities 166,217 94,031
Other Assets (8,517 ) 19,178
Other Liabilities (14,453 ) 17,373

Net Cash Provided by Operating Activities
511,821 415,067

INVESTING ACTIVITIES

Capital Expenditures (237,126 ) (264,728 )
Investment in Partnership (800 ) —
Cash Held in Escrow (2,000 ) 58,397
Net Proceeds from Sale of Oil and Gas Producing Properties 3,701 5,675
Other (1,674 ) (3,414 )

Net Cash Used in Investing Activities
(237,899 ) (204,070 )

FINANCING ACTIVITIES

Excess Tax Benefits Associated with Stock-Based Compensation Awards 5,927 16,275
Shares Repurchased under Repurchase Plan — (129,592 )
Net Proceeds from Issuance of Long-Term Debt 247,780 296,655
Reduction of Long-Term Debt (100,000 ) (200,024 )
Dividends Paid on Common Stock (77,398 ) (77,204 )
Net Proceeds from Issuance of Common Stock 14,760 17,285

Net Cash Provided by (Used in) Financing Activities
91,069 (76,605 )

Net Increase in Cash and Temporary Cash Investments
364,991 134,392
Cash and Temporary Cash Investments at October 1
68,239 124,806

Cash and Temporary Cash Investments at June 30
$ 433,230 $ 259,198


	Three Months Ended
	December 31,
(Thousands of Dollars)	2009			2008
Net Income (Loss) Available for Common Stock	$	64,499		$	(42,678	)

Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment		17			8
Unrealized Loss on Securities Available for Sale Arising During the Period		(713	)		(10,032	)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		(4,853	)		118,880
Reclassification Adjustment for Realized Gains on Derivative Financial Instruments in Net Income		(12,052	)		(28,792	)

Other Comprehensive Income (Loss), Before Tax		(17,601	)		80,064

Income Tax Benefit Related to Unrealized Loss on Securities Available for Sale Arising During the Period		(271	)		(3,791	)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		(2,062	)		48,128
Reclassification Adjustment for Income Tax Expense on Realized Gains from Derivative Financial Instruments In Net Income		(4,962	)		(11,411	)

Income Taxes — Net		(7,295	)		32,926

Other Comprehensive Income (Loss)		(10,306	)		47,138

Comprehensive Income	$	54,193		$	4,460

See Notes to Condensed Consolidated Financial Statements

-10-

Item 1.Financial Statements (Cont.)

National Fuel Gas Company
~~Consolidated Statements of Comprehensive Income~~
~~(Unaudited)~~

Three Months Ended
June 30,
(Thousands of Dollars) 2009 2008

Net Income Available for Common Stock $ 42,904 $ 59,855

Other Comprehensive Loss, Before Tax:
Foreign Currency Translation Adjustment (42 ) 2
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period 3,775 (1,603 )
Unrealized Loss on Derivative Financial Instruments Arising During the Period (24,446 ) (139,684 )
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income (24,853 ) 33,082

Other Comprehensive Loss, Before Tax (45,566 ) (108,203 )

Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period 1,429 (608 )
Income Tax Benefit Related to Unrealized Loss on Derivative Financial Instruments Arising During the Period (9,950 ) (57,136 )
Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gains) Losses from Derivative Financial Instruments in Net Income (10,108 ) 13,546

Income Taxes — Net (18,629 ) (44,198 )

Other Comprehensive Loss (26,937 ) (64,005 )

Comprehensive Income (Loss) $ 15,967 $ (4,150 )

Nine Months Ended
June 30,
(Thousands of Dollars) 2009 2008

Net Income Available for Common Stock $ 73,710 $ 225,463

Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment (1 ) (72 )
Unrealized Loss on Securities Available for Sale Arising During the Period (9,202 ) (4,817 )
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 127,357 (208,256 )
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income (93,260 ) 45,242

Other Comprehensive Income (Loss), Before Tax 24,894 (167,903 )

Income Tax Benefit Related to Unrealized Loss on Securities Available for Sale Arising During the Period (3,475 ) (1,429 )
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 51,576 (85,300 )
Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gains) Losses on Derivative Financial Instruments in Net Income (37,478 ) 18,495

Income Taxes — Net 10,623 (68,234 )

Other Comprehensive Income (Loss) 14,271 (99,669 )

Comprehensive Income $ 87,981 $ 125,794

~~See Notes to Condensed Consolidated Financial Statements~~

~~-11-~~

~~Item 1.~~~~Financial Statements (Cont.)~~

~~National Fuel Gas Company~~
Notes to Condensed Consolidated Financial Statements
(Unaudited)

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, 2009, 2008 ~~2007~~ and ~~2006~~2007 that are included in the Company’s ~~2008~~2009 Form 10-K. The consolidated financial statements for the year ended September 30, ~~2009~~2010 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.

The earnings for the ~~nine~~three months ended ~~June 30,~~December 31, 2009 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, ~~2009.~~2010. 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~~investments purchased with a maturity of generally three months or less to be cash equivalents.

At ~~June 30,~~December 31, 2009, the Company accrued ~~$9.4~~$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 ~~June 30,~~December 31, 2009 since it ~~represents~~represented a non-cash investing activity at that date.

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. 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 at December 31, 2009.

At December 31, 2008, the Company accrued $51.7 million of capital expenditures in the Exploration and Production segment, the majority of which was for lease acquisitions in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at December 31, 2008 since it represented a non-cash investing activity at that date.

-11-

Item 1.Financial Statements (Cont.)

At September 30, 2008, the Company accrued $16.8 million of capital expenditures related to the construction of the Empire Connector project. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2008 and have been included in the Consolidated Statement of Cash Flows ~~for the nine months ended June 30, 2009.~~at December 31, 2008.

Hedging Collateral Deposits.This is an account title for cash held in margin accounts funded by the Company to serve as collateral for open hedging positions. At ~~June 30,~~December 31, 2009, the Company had hedging collateral deposits of ~~$6.4~~$0.2 million related to its exchange-traded futures ~~contracts.~~contracts and $0.9 million related to its over-the-counter crude oil swap agreements. It is the Company’s policy to not offset hedging collateral deposits paid or received against the derivative financial instruments liability or asset balances.

Cash Held in Escrow.On July 20, 2009, the ~~Company announced that~~Company’s wholly-owned subsidiary in ~~its~~the Exploration and Production segment, Seneca, ~~had purchased~~acquired Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million in cash (including cash acquired of ~~which~~$4.3 million). The cash acquired at acquisition includes $2 million ~~was~~held in escrow at December 31, 2009 and September 30, 2009. Seneca placed this amount in escrow as ~~a deposit~~part of the purchase price, and in accordance with the purchase agreement, this amount will remain in escrow for ~~the acquisition as of June 30, 2009.~~

~~-12-~~

~~Item 1.~~~~Financial Statements (Cont.)~~

~~On August 31, 2007, the Company received approximately $232.1 million of proceeds~~one year from the sale of SECI, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. The escrow account was a Canadian dollar denominated account. On a U.S. dollar basis, the value of this account was $62.0 million at September 30, 2007. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. To hedge against foreign currency exchange risk related to the cash being held in escrow, the Company held a forward contract to sell Canadian dollars. For presentation purposes on the Consolidated Statement of Cash Flows, for the nine months ended June 30, 2008, the Cash Held in Escrow line item within Investing Activities reflects the net proceeds to the Company (received on January 8, 2008) after adjusting for the impactclosing of the ~~foreign currency hedge.~~transaction provided there are no pending disputes or actions regarding obligations and liabilities required to be satisfied or discharged by Ivanhoe Energy. If no disputes occur, this cash will be released 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 ~~$116.5~~$8.9 million at ~~June 30,~~December 31, 2009, 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. 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 current market 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. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The Company’s capitalized costs exceeded the full cost ceiling for the Company’s oil and gas

-12-

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~~reflect 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 diluted earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options and stock-settled SARs. The diluted weighted average shares outstanding shown on the Consolidated ~~Statements~~Statement of Income reflects the potential dilution as a result of these stock options and stock-settled SARs as determined using the Treasury Stock Method. Stock options and stock-settled SARs that are antidilutive are excluded from the calculation of diluted earnings per common share. For ~~both~~ the quarter ended December 31, 2009, there were no stock options and ~~nine months~~24,000 stock-settled SARs excluded as being antidilutive. For the quarter ended ~~June 30, 2009,~~December 31, 2008, there were 765,000 stock options ~~excluded as being antidilutive. In addition, there were~~and 365,000 stock-settled SARs excluded as being antidilutive for both the quarter and nine months ended June 30, 2009. For the quarter and nine months ended June 30, 2008, there were 6,593 and 2,190 stock-settled SARs excluded as being antidilutive, respectively. There were no stock options excluded as being antidilutive for the quarter and nine months ended June 30, 2008.

~~Item 1.~~~~Financial Statements (Cont.)~~antidilutive.

New Authoritative Accounting ~~Pronouncements.~~and Financial Reporting Guidance.In September 2006, the FASB issued ~~SFAS 157, “Fair Value Measurements”. SFAS 157 provides~~authoritative guidance for using fair value to measure assets and liabilities. ~~The pronouncement~~This guidance serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. ~~SFAS 157~~This guidance is to be applied whenever ~~another standard requires or allows~~ assets or liabilities are to be measured at fair value. ~~In accordance with FASB Staff Position FAS No. 157-2, on~~On October 1, 2008, the Company adopted ~~SFAS 157~~this guidance for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis. The ~~same FASB Staff Position delays the effective date~~FASB’s authoritative guidance for using fair value to measure nonfinancial assets and nonfinancial liabilities ~~except for items that are recognized or disclosed at fair value~~ on a ~~recurring~~nonrecurring basis ~~until~~became effective during the ~~Company’s first~~ quarter ~~of fiscal 2010. For further discussion of the impact of the adoption of SFAS 157 for financial assets and financial liabilities, refer to Note 2 — Fair Value Measurements.~~ended December 31, 2009. The ~~Company is currently evaluating the impact that the adoption of SFAS 157 for~~Company’s nonfinancial assets and nonfinancial liabilities ~~will have on its consolidated financial statements.~~were not impacted by this guidance during the quarter ended December 31, 2009. The Company has identified Goodwill as being the major nonfinancial asset that may be impacted by the adoption of ~~SFAS 157.~~this guidance. The impact of this guidance will be known when the Company performs its annual test for goodwill impairment at the end of the fiscal year; however, at this time, it is not expected to be material. The Company ~~does not believe there are any~~has identified Asset Retirement Obligations as a nonfinancial ~~liabilities~~liability that ~~will~~may be impacted by the adoption of ~~SFAS 157.~~

~~In September 2006,~~ the ~~FASB issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” (an amendment~~guidance. The impact of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R). SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded statusthis guidance will be ~~measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158,~~known when the Company ~~has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158~~recognizes new asset retirement obligations. However, at ~~September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be fully adopted by~~this time, the Company by the end of fiscal 2009. The Company has historically measured its plan assets and benefit obligations using a June 30th measurement date. In anticipation of changing to a September 30th measurement date, the Company will be recording fifteen months of pension and other post-retirement benefit costs during fiscal 2009. In accordance with the provisions of SFAS 158, these costs have been calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $5.1 million and have been recorded by the Company during the quarter ended December 31, 2008 as a $3.8 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $1.3 million ($0.8 million after tax) adjustment to earnings reinvested in the business. For further discussion ofbelieves the impact of ~~adopting~~ the ~~measurement date provisions of SFAS 158, refer to Note 9 — Retirement Plan and Other Post-Retirement Benefits.~~guidance will be immaterial.

-13-

Item 1.Financial Statements (Cont.)

In December 2007, the FASB ~~issued SFAS 141R, “Business Combinations.” SFAS 141R will~~revised authoritative guidance that significantly ~~change~~changes the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies, acquisition costs, in process research and development and restructuring costs. In addition, under ~~SFAS 141R,~~this guidance, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income tax expense. ~~SFAS 141R is~~This authoritative guidance became effective for the Company as of ~~the Company’s first quarter of fiscal 2010.~~October 1, 2009. The Company will apply this guidance to future business combinations.

In December 2007, the FASB issued ~~SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB 51.” SFAS 160 will change~~authoritative guidance that changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests (NCI) and classified as a component of equity. This new consolidation method ~~will~~ significantly ~~change~~changed the accounting for transactions with minority interest holders. ~~SFAS 160 is~~This authoritative guidance became effective for the Company as of October 1, 2009. This guidance currently does not have an impact on the Company’s consolidated financial statements.

In June 2008, the FASB issued authoritative guidance concerning whether certain instruments granted in share-based payment transactions are participating securities. This guidance specified that unvested share-based payment awards that contain nonforfeitable rights to dividends are participating securities and shall be included in the computation of earnings per share pursuant to the “two-class” method. The “two class” method allocates undistributed earnings between common shares and participating securities. The Company adopted this guidance during the first quarter of fiscal ~~2010. The~~2010 and determined that its participating securities (restricted stock awards) have an immaterial impact on the Company’s earnings per share calculation. Therefore, the Company ~~currently does~~has not ~~have any NCI.~~

~~-15-~~

~~Item 1.~~~~Financial Statements (Cont.)~~

~~In March 2008,~~presented its earnings per share pursuant to the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS 133.” SFAS 161 requires entities to provide enhanced disclosures related to an entity’s derivative instruments and hedging activities in order to enable investors to better understand how derivative instruments and hedging activities impact an entity’s financial reporting. The additional disclosures include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The Company adopted the disclosure provisions of SFAS 161 during the quarter ended March 31, 2009. These disclosures may be found at Note 3 — Financial Instruments.“two class” method.

On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and gas reserves to a 12-month average of the first day of the month price for each month within the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. Additionally, on January 6, 2010, the FASB amended the oil and gas accounting standards to conform to the SEC final rule on Modernization of Oil and Gas Reporting. The revised reporting and disclosure requirements are effective for the Company’s Form 10-K for the period ended September 30, 2010. Early adoption is not permitted. The Company is currently evaluating the impact that adoption of these rules will have on its consolidated financial statements and MD&A disclosures.

~~Effective April 1,~~In March 2009, the ~~Company adopted~~ FASB ~~Staff Position FAS 107-1~~issued authoritative guidance that expands the disclosures required in an employer’s financial statements about pension and ~~APB 28-1, “Interim Disclosures about Fair Value~~other post-retirement benefit plan assets. The additional disclosures include more details on how investment allocation decisions are made, the plan’s investment policies and strategies, the major categories of ~~Financial Instruments.” This FASB Staff Position amends SFAS 107, “Disclosures about Fair Value of Financial Instruments,”~~plan assets, the inputs and valuation techniques used to ~~require disclosures about~~measure the fair value of ~~financial instruments~~plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for interim reporting periods of publicly traded companies as well as in annual financial statements. Refer to Note 3 — Financial Instruments under “Long-Term Debt” for additional disclosures included in accordance with this FASB Staff Position.

~~Effective with this June 30, 2009 Form 10-Q,~~ the ~~Company adopted SFAS 165, “Subsequent Events.” SFAS 165 establishes general standards of accounting for~~period, and disclosure regarding significant concentrations of ~~events~~risk within plan assets. The additional disclosure requirements are required for the Company’s Form 10-K for the period ended September 30, 2010. The Company is currently evaluating the impact that ~~occur after the balance sheet date but before financial statements are issued or are available to be issued. Refer to Note 10 — Subsequent Events for disclosures made as a result of the~~ adoption of ~~SFAS 165.~~this authoritative guidance will have on its consolidated financial statement disclosures.

In June 2009, the FASB issued ~~SFAS 168, “The FASB Accounting Standards Codification~~^TMamended 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 ~~Hierarchy~~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 ~~Generally Accepted Accounting Principles —~~ a ~~replacement of FASB Statement No. 162.” SFAS 168 establishes the FASB Accounting Standards Codification~~^TM~~(the Codification)~~variable interest entity. This authoritative guidance is effective as the source of authoritative GAAP recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. Rules and interpretive releases of the ~~SEC under authority~~Company’s first quarter of federal securities law are also sources of authoritative GAAP for SEC registrants. All other nongrandfathered, non-SEC accounting literature not included in the Codification will become nonauthoritative. SFAS 168 is effective for interim and annual periods ending after September 15, 2009.fiscal 2011. The Company is currently evaluating the impact that adoption of this authoritative guidance will ~~update~~have on its ~~disclosures to conform to the Codification in its annual report on Form 10-K for the year ending September 30, 2009. There will be no impact on the Company’s~~ consolidated financial ~~statements as the Codification does not change or alter existing GAAP.~~statements.

-14-

Item 1.Financial Statements (Cont.)

reported in Level 2 consist of natural gas and some of the crude oil swap agreements used in the Company’s Exploration and Production segment and natural gas swap agreements used in the Energy Marketing segment at December 31, 2009 (at September 30, 2009, the derivative financial instruments reported in Level 2 consist of natural gas swap agreements used in the Company’s Exploration and Production ~~segment~~ and ~~natural gas swap agreements used in the~~ Energy Marketing ~~segment.~~segments). The fair value of these ~~natural gas~~ swap agreements is based on an internal model that uses observable inputs. ~~The fair market value of~~At December 31, 2009, the ~~price swap agreements reported in Level 2 as assets has been reduced by $0.6 million based on an assessment of counterparty credit risk. The~~ derivative financial instruments reported in Level 3 consist of a majority of the Exploration and Production segment’s crude oil swap agreements (at September 30, 2009, all of the Exploration and Production segment’s crude oil swap agreements ~~and some of its natural gas swap agreements.~~were reported as Level 3). The fair value of the crude oil ~~and natural gas~~ swap agreements is based on an internal model that uses both observable and unobservable inputs. Based on an assessment of the counterparties’ credit risk, the fair market value of the price swap agreements reported as Level 2 and 3 assets have been reduced by $0.2 million and $0.9 million at December 31, 2009 and September 30, 2009, respectively. The fair market value of the price swap agreements reported inas Level ~~3 as assets~~2 liabilities at September 30, 2009 has been reduced by ~~$0.7~~less than $0.1 million based on an assessment of ~~counterparty~~the Company’s credit risk. ~~This~~These credit ~~reserve, as well as the credit reserve established for the Level 2 swap agreement assets, was~~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.

At December 31, 2009, $0.9 million in hedging collateral deposits reported in Level 1 are associated with the Level 3 derivative financial instruments used by the Exploration and Production segment. The Company’s internal model may yield a different fair value than the fair value determined by the Company’s counterparties. The Company’s requirement to post hedging collateral deposits is based on the fair value determined by the Company’s counterparties.

Other Investments

The other investments reported in Level 1 consist of publicly traded equity securities and a publicly traded balanced equity mutual fund.

The ~~table~~tables listed below ~~provides a reconciliation~~provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3.

~~-17-~~


Item 1.		Financial Statements (Cont.)


		Fair Value Measurements Using Unobservable Inputs (Level 3)


				Total Gains/Losses —
				Realized and Unrealized
	October 1,			Included in			Included in Other
(Dollars in thousands)	2008			Earnings			Comprehensive Income		Transfer In/Out of Level 3		December 31, 2008
Assets:
Derivative Financial Instruments	$	7,110		$	(3,716	)⁽¹⁾	$	79,636	$	—	$	83,030

Total	$	7,110		$	(3,716	)	$	79,636	$	—	$	83,030

Liabilities:
Derivative Financial Instruments	$	(777	)	$	(12,104	)⁽¹⁾	$	12,881	$	—	$	—

Total	$	(777	)	$	(12,104	)	$	12,881	$	—	$	—


⁽¹⁾		Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended December 31, 2008.

Note 3 — Financial Instruments

Long-Term Debt.In accordance with the Company’s adoption of FASB Staff Position FAS 107-1 and APB 28-1 “Disclosures about Fair Value of Financial Instruments”, the fair value of the Company’s long-term debt, including current portion, and the carrying amount is presented below:

June 30, 2009 September 30, 2008
Carrying Carrying
Amount Fair Value Amount Fair Value
Long-Term Debt $ 1,249,000 $ 1,285,890 $ 1,099,000 $ 1,027,098

At September 30, 2008, the fair market value of the Company’s long-term debt was determined based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit rating. At June 30, 2009, theThe fair market value of the Company’s debt, as presented in the table ~~above,~~below, was determined using a discounted cash flow model, which incorporates the Company’s credit risk 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:


	December 31, 2009				September 30, 2009
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Long-Term Debt	$	1,249,000	$	1,345,127	$	1,249,000	$	1,347,368

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 ~~$53.5~~$53.9 million at ~~June 30,~~December 31, 2009 and ~~$53.6~~$54.2 million at September 30, ~~2008.~~2009. The fair value of the equity mutual fund was ~~$12.6~~$16.4 million at ~~June 30,~~December 31, 2009 and ~~$12.4~~$15.8 million at September 30, ~~2008.~~2009. The gross unrealized loss on this equity mutual fund was ~~$2.7~~$0.7 million at ~~June 30,~~December 31, 2009 and ~~$1.1~~$1.0 million at September 30, 2008. Although this investment has been in an unrealized loss position for twelve months, management has the intent and ability to hold the investment for a sufficient period of time for the asset to recover in value. As such, management2009. Management does not consider this investment to be other than temporarily impaired. The fair value of the stock of an insurance company was ~~$6.9~~$7.2 million at ~~June 30,~~December 31, 2009 and ~~$14.5~~$8.3 million at September 30, ~~2008.~~2009. The gross unrealized gain on this stock was ~~$4.5~~$4.8 million at ~~June 30,~~December 31, 2009 and ~~$12.1~~$5.9 million at September 30, ~~2008.~~2009. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.

~~-18-~~


Item 1.		Financial Statements (Cont.)

risk associated with forecasted gas purchases, storage of gas, and withdrawal of gas from storage to meet customer demand. The duration of the Company’s hedges do not typically exceed 3 years and the majority of the positions settle within one year.

~~In accordance with the adoption of SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS 133”, the~~The Company has presented its ~~gross~~net derivative assets and liabilities on its Consolidated Balance Sheets at December 31, 2009 and September 30, 2009 as shown in the table below.

Fair Values of Derivative Instruments

(Dollar Amounts in Thousands)

Asset Derivatives

Liability Derivatives

Derivatives

Asset Derivatives

Liability Derivatives

Designated as

June 30, 2009

Consolidated

Hedging

Consolidated

Balance Sheet

Instruments

Balance

Location

Fair Value

Location

Fair Value

under

Sheet

SFAS 133

Location

Fair Value

Location

Fair Value

Commodity Contracts

Fair Value of

66,193

⁽¹⁾

Fair Value of

1,815

⁽²⁾

Commodity Contracts — at December 31, 2009

Fair Value of Derivative Financial Instruments

19,791

Fair Value of Derivative Financial Instruments

—

Derivative

Financial

Instruments

Commodity Contracts — at September 30, 2009

Fair Value of Derivative Financial Instruments

44,817

Fair Value of Derivative Financial Instruments

2,148

~~Item 1.~~~~Financial Statements (Cont.)~~

As of ~~June 30,~~December 31, 2009, 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		~~7.0~~4.1 Bcf ~~(5.5~~(3.7 Bcf short positions (forecasted storage withdrawals) and ~~1.5~~0.4 Bcf long positions (forecasted storage injections))

As of ~~June 30,~~December 31, 2009, the Company’s Pipeline and Storage segment have 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, 2009, the Company’s Exploration and Production segment had ~~$63.6~~$16.3 million ($~~37.6~~9.6 million after tax) of gains included in the accumulated other comprehensive ~~income~~loss balance. It is expected that ~~$51.4~~$17.7 million ($~~30.4~~10.4 million after tax) of these gains will be reclassified into ~~income~~the Consolidated Statement of Income within the next 12 months as the sales of the underlying commodities are expected to occur. See Note 1, under Accumulated Other Comprehensive ~~Income,~~Loss, for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain on Derivative Financial Instruments in Note 1 includes ~~both~~ the Exploration and Production, ~~and~~ Energy Marketing and Pipeline and Storage segments).

As of ~~June 30,~~December 31, 2009, the Company’s Energy Marketing segment had ~~$2.8~~$1.7 million ($~~1.7~~1.0 million after tax) of losses included in the accumulated other comprehensive ~~income~~loss balance. It is expected that ~~$2.8~~$1.8 million ($~~1.7~~1.1 million after tax) of these losses will be reclassified into ~~income~~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 on Derivative Financial Instruments in Note 1 includes ~~both~~ the Exploration and Production, ~~and~~ Energy Marketing and Pipeline and Storage segments).

As of December 31, 2009, the Company’s Pipeline and Storage segment had less than $0.1 million of gains included in the accumulated other comprehensive 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 sales with underlying commodities are expected to occur. See Note 1, under Accumulated Other Comprehensive Loss, for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).

~~-20-~~-19-

~~Item 1.~~~~Financial Statements (Cont.)~~

~~The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the~~
~~Nine Months Ended June 30, 2009 (Dollar Amounts in Thousands)~~

Amount of Amount of
Derivative Gain or Derivative Gain or
(Loss) Recognized Location of (Loss) Reclassfied Derivative Gain or
in Other Derivative Gain or from Accumulated Location of (Loss) Recognized
Comprehensive (Loss) Reclassified Other Comprehensive Derivative Gain or in the Consolidated
Income on the from Accumulated Income on the (Loss) Recognized Statement of Income
Consolidated Other Comprehensive Consolidated in the Consolidated (Ineffective
Statement of Income on the Balance Sheet into Statement of Income Portion and Amount
Comprehensive Consolidated the Consolidated (Ineffective Excluded from
Derivatives in SFAS Income (Effective Balance Sheet into Statement of Income Portion and Amount Effectiveness
133 Cash Flow Portion) for the the Consolidated (Effective Portion) Excluded from Testing) for the
Hedging Nine Months Ended Statement of Income for the Nine Months Effectiveness Nine Months Ended
Relationships June 30, 2009 (Effective Portion) Ended June 30, 2009 Testing) June 30, 2009
Commodity Contracts — Exploration & Production segment $ 117,764 Operating Revenue $ 71,324 Operating Revenue $ 424
Commodity Contracts — Energy Marketing segment $ 9,410 Purchased Gas $ 21,328 Operating Revenue $ —
Commodity Contracts — Pipeline & Storage segment⁽¹⁾
$ — Operating Revenue $ 1,290 Operating Revenue $ —
Commodity Contracts — All Other⁽¹⁾
$ 183 Purchased Gas $ (682 ) Purchased Gas $ —

Total $ 127,357 $ 93,260 $ 424


⁽¹⁾Item 1.		~~There were no open hedging positions at June 30, 2009. As such there is no mention of these positions in the preceding sections of this footnote.~~Financial Statements (Cont.)

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the

Three Months Ended December 31, 2009 (Dollar Amounts in Thousands)

Amount of

Derivative Gain or

(Loss) Reclassified

(Loss) Recognized

Location of

from Accumulated

Derivative Gain or

in Other

Derivative Gain or

Other Comprehensive

Location of

(Loss) Recognized

Comprehensive

(Loss) Reclassified

Income (Loss) on

Derivative Gain or

in the Consolidated

Income (Loss) on

from Accumulated

the Consolidated

(Loss) Recognized

Statement of Income

the Consolidated

Other Comprehensive

Balance Sheet into

in the Consolidated

(Ineffective

Statement of

Income (Loss) on

the Consolidated

Statement of Income

Portion and Amount

Comprehensive

the Consolidated

Statement of Income

(Ineffective

Excluded from

Income (Effective

Balance Sheet into

(Effective Portion)

Portion and Amount

Effectiveness Testing)

Derivatives in Cash

Portion) for the

the Consolidated

for the Three

Excluded from

for the Three Months

Flow Hedging

Three Months Ended

Statement of Income

Months Ended

Effectiveness

Ended

Relationships

December 31, 2009

(Effective Portion)

December 31, 2009

Testing)

December 31, 2009

Commodity Contracts — Exploration & Production segment

(7,910

)

Operating Revenue

12,040

Operating Revenue

—

Commodity Contracts — Energy Marketing segment

3,024

Purchased Gas

Operating Revenue

—

Commodity Contracts — Pipeline & Storage segment

Operating Revenue

(11

)

Operating Revenue

—

Total

(4,853

)

12,052

—

As of ~~June 30,~~December 31, 2009, eight of the ten 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 (the lower of the S&P or Moody’s Debt Rating), 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 and the Company’s credit rating declined, then additional hedging collateral deposits would be required. At ~~June 30,~~December 31, 2009, the fair market value of the derivative financial instrument assets related to these ~~credit-risk related contingency features would not have been triggered since~~eight counterparties was $14.2 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements). The Company’s internal model may yield a different fair value than the fair value determined by the Company’s counterparties. The Company’s requirement to post hedging collateral deposits is based on the fair value determined by the Company’s counterparties. For its over-the-counter crude oil swap agreements, the Company ~~had assets of $57.6~~was required to pay $0.9 million ~~related to derivative financial instruments with the eight counterparties.~~

~~Item 1.~~~~Financial Statements (Cont.)~~

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 ~~nine~~three months ended ~~June 30,~~December 31, 2009, ~~300,876~~249,705 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.

~~Shareholder Rights Plan.~~~~In 1996, the Company’s Board~~Current Portion of Directors adopted a shareholder rights plan (Plan). The Plan has been amended several times since it was adopted and is now embodied in an Amended and Restated Rights Agreement effective December 4, 2008, a copy of which was included as an exhibit to the Form 8-K filed by the Company on December 4, 2008.

Pursuant to the Plan, the holders of the Company’s common stock have one right (Right) for each of their shares. Each Right is initially evidenced by the Company’s common stock certificates representing the outstanding shares of common stock.

The Rights have anti-takeover effects because they will cause substantial dilution of the Company’s common stock if a person attempts to acquire the Company on terms not approved by the Board of Directors (an Acquiring Person).

The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date Rights that are owned by an Acquiring Person will be null and void. At any time following a Distribution Date, each holder of a Right may exercise its right to receive, upon payment of an amount calculated under the Rights Agreement, common stock of the Company (or, under certain circumstances, other securities or assets of the Company) having a value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.

A Distribution Date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company’s common stock or other voting stock (including Synthetic Long Positions as defined in the Plan) having 10% or more of the total voting power of the Company’s common stock and other voting stock and (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquiring, or obtaining the right to acquire, beneficial ownership of the Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s common stock and other voting stock.

In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company’s stock as described above, each holder of a Right will have the right to exercise its Rights to receive, upon exercise of the right, common stock of the acquiring company having a value equal to two times the amount paid to exercise the right. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company’s assets or earning power are sold or transferred.

At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company may redeem the Rights in whole, but not in part, at a price of $0.005 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company’s full Board of Directors. Also, at any time following the Distribution Date, 75% of the Company’s full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments.

Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2018, unless earlier than that date, they are exchanged or redeemed or the Plan is amended to extend the expiration date.

~~-25-~~

~~Item 1.~~~~Financial Statements (Cont.)~~

Long-Term Debt.~~In April~~Current Portion of Long-Term Debt at December 31, 2009 ~~the Company issued $250.0~~consists of $200 million of 8.75% notes due in May 2019. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $247.8 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including to replenish cash that was used to pay the $100 million due at the maturity of the Company’s 6.0%7.50% medium-term notes ~~on March 1, 2009.~~that mature 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.

~~As disclosed in Note H of the Company’s 2008 Form 10-K, the~~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 ~~$16.0~~$15.2 million.

At ~~June 30,~~December 31, 2009, 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 ~~$19.0~~$18.1 million to ~~$23.2~~$22.3 million. The minimum estimated liability of ~~$19.0~~$18.1 million, which includes the ~~$16.0~~$15.2 million discussed above, has been recorded on the Consolidated Balance Sheet at ~~June 30,~~December 31, 2009. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet.

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, or have a material adverse effect on the financial condition of the Company.

~~-26-~~-24-

~~Item 1.~~


Item 1.		Financial Statements (Cont.)

Note 7 — Business Segment Information

~~In the Company’s 2008 Form 10-K, the~~The Company ~~reported financial results for five business~~has four reportable segments: Utility, Pipeline and Storage, Exploration and Production and Energy ~~Marketing and Timber.~~Marketing. The division of the Company’s operations into the reported segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors. During the quarter ended December 31, 2008, management made the decision to eliminate the Timber segment as a reportable segment based on the fact that the Timber operations do not meet any of the quantitative thresholds specified by SFAS 131. Furthermore, from a qualitative standpoint, management’s focus has changed regarding the Timber operations. While the Timber segment will continue to harvest hardwood timber and process lumber products that are used in high-end furniture, cabinetry and flooring, management no longer considers the Timber operations to be integral to the overall operations of the Company. As a result of this change in focus and the fact that the Timber operations cannot be aggregated into one of the other four reportable business segments, the Timber operations have been included in the All Other category in the disclosures that follow. Prior year segment information shown below has been restated to reflect this change in presentation. In addition, refer to the Company’s Form 8-K filed on March 17, 2009 that updated its historical business segment information contained in the Company’s 2008 Form 10-K to reflect the change in reportable segments.

The data presented in the tables below reflect the ~~reportable~~reported segments and reconciliations to consolidated amounts. As stated in the ~~2008~~2009 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting ~~(where~~(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 ~~other than as noted above,~~ nor in the basis of measuring segment profit or loss from those used in the Company’s ~~2008~~2009 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the 2009 Form 10-K.

Quarter Ended December 31, 2009 (Thousands)


					Exploration				Total				Corporate and
			Pipeline and		and		Energy		Reportable				Intersegment			Total
	Utility		Storage		Production		Marketing		Segments		All Other		Eliminations			Consolidated

Revenue from External Customers	$	232,404	$	34,504	$	106,351	$	71,736	$	444,995	$	11,805	$	211		$	457,011

Intersegment Revenues	$	4,514	$	20,257	$	—	$	—	$	24,771	$	—	$	(24,771	)	$	—

Segment Profit:
Net Income (Loss)	$	23,013	$	10,354	$	29,779	$	1,092	$	64,238	$	1,166	$	(905	)	$	64,499

Quarter Ended December 31, 2008 (Thousands)


					Exploration					Total						Corporate and
			Pipeline and		and			Energy		Reportable						Intersegment			Total
	Utility		Storage		Production			Marketing		Segments			All Other			Eliminations			Consolidated

Revenue from External Customers	$	349,637	$	35,267	$	96,712		$	115,007	$	596,623		$	10,325		$	215		$	607,163

Intersegment Revenues	$	4,553	$	20,837	$	—		$	—	$	25,390		$	2,322		$	(27,712	)	$	—

Segment Profit:
Net Income (Loss)	$	22,088	$	17,176	$	(83,557	)	$	599	$	(43,694	)	$	(868	)	$	1,884		$	(42,678	)

~~-27-~~-25-

~~Item 1.~~~~Financial Statements (Cont.)~~

~~Quarter Ended June 30, 2009 (Thousands)~~

Pipeline Exploration Corporate and
and and Energy Total Reportable Intersegment Total
Utility Storage Production Marketing Segments All Other Eliminations Consolidated

Revenue from External Customers $ 158,310 $ 30,791 $ 97,619 $ 71,894 $ 358,614 $ 8,269 $ 228 $ 367,111

Intersegment Revenues $ 2,940 $ 20,033 $ — $ — $ 22,973 $ 374 $ (23,347 ) $ —

Segment Profit:
Net Income (Loss) $ 5,396 $ 9,221 $ 27,083 $ 1,331 $ 43,031 $ (1,086 ) $ 959 $ 42,904

~~Nine Months Ended June 30, 2009 (Thousands)~~

Pipeline Exploration Corporate and
and and Energy Total Reportable Intersegment Total
Utility Storage Production Marketing Segments All Other Eliminations Consolidated

Revenue from External Customers $ 1,009,962 $ 105,904 $ 281,410 $ 350,445 $ 1,747,721 $ 30,523 $ 675 $ 1,778,919

Intersegment Revenues $ 13,339 $ 62,026 $ — $ — $ 75,365 $ 3,890 $ (79,255 ) $ —

Segment Profit:
Net Income (Loss) $ 60,303 $ 41,582 $ (38,366 ) $ 7,509 $ 71,028 $ (46 ) $ 2,728 $ 73,710

~~Quarter Ended June 30, 2008 (Thousands)~~

Pipeline Exploration Corporate and
and and Energy Total Reportable Intersegment Total
Utility Storage Production Marketing Segments All Other Eliminations Consolidated

Revenue from External Customers $ 217,339 $ 32,054 $ 126,154 $ 162,129 $ 537,676 $ 10,509 $ 197 $ 548,382

Intersegment Revenues $ 3,154 $ 20,131 $ — $ — $ 23,285 $ 4,439 $ (27,724 ) $ —

Segment Profit:
Net Income (Loss) $ 7,848 $ 12,534 $ 39,791 $ 478 $ 60,651 $ (960 ) $ 164 $ 59,855

~~Nine Months Ended June 30, 2008 (Thousands)~~

Pipeline Exploration Corporate and
and and Energy Total Reportable Intersegment Total
Utility Storage Production Marketing Segments All Other Eliminations Consolidated

Revenue from External Customers $ 1,067,194 $ 101,871 $ 348,829 $ 440,111 $ 1,958,005 $ 44,002 $ 496 $ 2,002,503

Intersegment Revenues $ 13,567 $ 61,340 $ — $ — $ 74,907 $ 10,251 $ (85,158 ) $ —

Segment Profit:
Net Income (Loss) $ 62,228 $ 40,931 $ 108,385 $ 7,079 $ 218,623 $ 7,351 $ (511 ) $ 225,463

~~At June 30, 2009 (Thousands)~~

Pipeline Exploration Corporate and
And and Energy Total Reportable Intersegment Total
Utility Storage Production Marketing Segments All Other Eliminations Consolidated

Segment Assets $ 1,775,953 $ 1,003,362 $ 1,257,131 $ 61,653 $ 4,098,099 $ 208,069 $ 49,134 $ 4,355,302

~~-28-~~


Item 1.		Financial Statements (Cont.)

~~As indicated under “New Accounting Pronouncements” in Note 1 — Summary~~Prior to the adoption of ~~Significant Accounting Policies,~~authoritative guidance related to accounting for defined benefit pension and other postretirement plans, the Company used June 30th as the measurement date for financial reporting purposes. In 2009, in accordance with the ~~measurement date provisions of SFAS 158 that specifies that a plan’s~~current authoritative guidance for defined benefit pension and other postretirement plans, the Company began measuring the Plan’s assets and ~~obligations that determine~~liabilities for its ~~funded status be measured~~pension and other post-retirement benefit plans as of ~~the end of the Company’s~~September 30th, its fiscal year end. In making this change and as permitted by the current authoritative guidance, the Company ~~will be recording~~recorded fifteen months of pension and ~~other~~ post-retirement ~~benefit costs~~benefits expense during fiscal 2009. As allowed by ~~SFAS 158,~~the authoritative guidance, these costs ~~have been~~were calculated using June 30, 2008 measurement date data. Three of those months ~~pertain~~pertained to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $3.8 million and ~~have been~~were recorded by the Company during the ~~nine months~~quarter ended ~~June 30, 2009~~December 31, 2008 as a $3.4 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $0.4 million ($0.2 million after tax) adjustment to earnings reinvested in the business. In addition, for the Company’s non-qualified ~~pension~~benefit plan, benefit costs of $1.3 million ~~have been~~were recorded by the Company during the ~~nine months~~quarter ended ~~June 30, 2009~~December 31, 2008 as a $0.4 million increase to Other Regulatory Assets in the Company’s Utility segment and a $0.9 million ($0.6 million after tax) adjustment to earnings reinvested in the business. ~~The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be fully adopted by the Company by the end of fiscal 2009.~~

Employer Contributions.During the ~~nine~~three months ended ~~June 30,~~December 31, 2009, the Company contributed ~~$16.0~~$20.2 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and ~~$21.5~~$6.2 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of ~~2009,~~2010, the Company does not expect to contribute to ~~its retirement plan. As a result of~~ the ~~recent downturn in the stock markets and general economic conditions, it~~Retirement Plan. It is ~~expected~~likely that the Company will have to fund ~~in the range of $20 million to $40 million~~larger amounts to the ~~retirement plan~~Retirement Plan subsequent to fiscal ~~2009.~~2010 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of ~~2009,~~2010, the Company expects to contribute ~~approximately $5.0~~in the range of $19.0 million to $20.0 million to its VEBA trusts and 401(h) accounts.

Note 10 — Subsequent Events

In accordance with ~~SFAS 165, “Subsequent Events,”~~the authoritative guidance for subsequent events, the Company has evaluated subsequent events through ~~August 7, 2009,~~February 5, 2010, which represents the filing date of this Form 10-Q with the SEC, in order to ensure that this Form 10-Q includes appropriate disclosure of events both recognized in the financial statements as of ~~June 30,~~December 31, 2009, and events which occurred subsequent to ~~June 30,~~December 31, 2009 but were not recognized in the financial statements. As of ~~August 7, 2009,~~February 5, 2010, there were no subsequent events which required recognition or ~~disclosure other than as set forth below.~~disclosure.

~~-30-~~-27-

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

OVERVIEW

The Company is a diversified energy company consisting of four reportable business segments. For the quarter ended ~~June 30,~~December 31, 2009 compared to the quarter ended ~~June 30,~~December 31, 2008, the Company experienced ~~a decrease~~an increase in earnings of ~~$17.0~~$107.2 million, primarily due to ~~lower~~higher earnings in the Exploration and Production segment. ~~For~~During the ~~nine months~~quarter ended ~~June 30, 2009 compared to the nine months ended June 30,~~December 31, 2008, the Company ~~experienced a decrease in earnings of $151.8 million. The earnings decrease for the nine-month period was driven largely by~~recorded an impairment charge of $182.8 million ($108.2 million after tax) ~~recorded in~~that did not recur during the ~~Exploration and Production segment.~~quarter ended December 31, 2009. 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 December 31, 2008, due to significant declines in crude oil and natural gas commodity prices, (Cushing, Oklahoma West Texas Intermediate oil reported spot price of $44.60 per Bbl at December 31, 2008 versus a reported price of $100.70 per Bbl at September 30, 2008; Henry Hub natural gas reported spot price of $5.63 per MMBtu at December 31, 2008 versus a reported price of $7.12 per MMBtu at September 30, 2008), the book value of the Company’s oil and gas properties exceeded the ceiling, resulting in the impairment charge mentioned above. ~~(Note — Because actual pricing~~For further discussion of the ceiling test results at December 31, 2009 and a sensitivity analysis to changes in crude oil and natural gas commodity prices, refer to the Critical Accounting Estimates section below. For further discussion of the Company’s various producing properties varies depending on their location, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Cushing oil and Henry Hub prices, which are only indicative of current prices.) At June 30, 2009, the quoted Cushing, Oklahoma spot price for West Texas Intermediate oil was $69.82 per Bbl ($49.64 per Bbl at March 31, 2009) and the quoted spot price for natural gas was $3.88 per MMBtu ($3.63 per MMBtu at March 31, 2009). At June 30, 2009, the ceiling exceeded the book value of the Company’s oil and gas properties by approximately $247 million (and approximately $37 million at March 31, 2009). If natural gas prices used in the ceiling test calculation at June 30, 2009 had been $1 per MMBtu lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $197 million. If crude oil prices used in the ceiling test calculation at June 30, 2009 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $196 million. If both natural gas and crude oil prices used in the ceiling test calculation at June 30, 2009 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 $146 million. These calculated amounts are based solely on price changes and do not take into account any other changesearnings, refer to the ~~ceiling test calculation.~~Results of Operations section below.

~~Despite the decrease in earnings discussed above, the Company’s balance sheet consisted of~~From a ~~capitalization structure of 57% equity~~capital resources and ~~43% debt at June 30, 2009. With its April 2009 issuance of $250.0 million of 8.75% notes due in May 2019, management believes that it has enhanced its~~ liquidity ~~position at a time when there is still uncertainty in the credit markets. In addition to the proceeds from this debt issuance,~~perspective, the Company ~~has been able to borrow short-term funds under its credit lines and through~~spent $67.7 million on capital expenditures during the ~~commercial paper market to fund working capital needs throughout~~three months ended December 31, 2009, with approximately 70% being spent in the first nine months of 2009. At June 30, 2009, the Company did not have any short-term borrowings outstanding. However, the Company continues to maintain a number of individual uncommitted or discretionary lines of credit with financial institutions for general corporate purposes. These credit lines, which aggregate to $420.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed, or replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million, which commitment extends through September 30, 2010.

~~In the Company’s~~ Exploration and Production ~~segment, there continues to be a strong focus on exploring and developing the nearly one million acres~~segment. Approximately 82% of ~~oil and gas rights in the Appalachian region, including the 720,000 acres in the Marcellus Shale. However, the Company continues to look for growth opportunities in other areas as well. In July 2009,~~ the Exploration and Production segment ~~purchased Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million. This purchase complements this segment’s existing oil producing assets~~capital expenditures were spent in the ~~Midway Sunset Field in California. This acquisition was funded with cash on hand.~~

~~-32-~~

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

~~The~~Appalachian region, where the Company ~~through Midstream Corporation, is pursuing~~continues to emphasize the development of ~~gathering systems~~its acreage in ~~Tioga County~~the Marcellus Shale. The Company was recently the high bidder on two tracts of land in the Appalachian region of Pennsylvania at approximately $71.8 million. This transaction is expected to close in March 2010. With this expenditure and ~~Lycoming County~~other factors, it is expected that Exploration and Production segment capital expenditures in ~~Pennsylvania.~~2010 will be $345 million, compared to the previously reported amount of $255 million. The ~~project, called~~emphasis on Marcellus Shale development will carry over into the ~~Midstream Covington Gathering Project,~~Pipeline and Storage segment, which is ~~to be constructed~~anticipating the need for pipeline and storage capacity as Marcellus Shale production comes on line. While capital expenditures in the Pipeline and Storage segment were only $7.0 million during the three phases, with the first phase under construction and anticipated to be placed in service by the fall of 2009. The second phase is anticipated to be placed in service by the fall of 2010. The schedule for the final phase is being developed. When all three phases are complete, the system will consist of approximately 30 miles of gathering system pipeline at a cost of approximately $25 million to $30 million. Phase I is estimated to cost approximately $15 million. As of June 30,months ended December 31, 2009, the Company ~~has spent approximately $2.8 million~~continues to see strong interest for pipeline and storage capacity in ~~costs on Phase I~~the Marcellus Shale region. If such projects in the Pipeline and ~~Phase II related~~Storage segment are to ~~this project. The Company has funded these costs with cash on hand~~go forward, the most significant expenditures are expected to occur in 2011 and ~~anticipates that future costs will be funded with cash on hand as well.~~2012. For further discussion of the Company’s capital expenditures, refer to the Capital Resources and Liquidity section below.

CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to “Critical Accounting Estimates” in Item 7 of the Company’s ~~2008 Form 10-K and Item 2 of the Company’s December 31, 2008 and March 31,~~ 2009 Form ~~10-Qs.~~10-K. There have been no material changes to ~~those disclosures~~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 ~~those documents.~~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 current market prices (the “ceiling”) is compared with the book value of ~~those reserves~~the Company’s oil and gas properties at the balance sheet date. If the book value of the ~~reserves~~oil and gas properties in any country exceeds the ceiling, a non-cash charge must be recorded to reduce the book value of the ~~reserves~~oil and gas properties to the calculated ceiling. ~~As disclosed in the Company’s 2008 Form 10-K, at September 30, 2008,~~At December 31, 2009, the ceiling exceeded the book value of the ~~Company’s~~ oil and gas properties by approximately ~~$500~~$417 million. ~~Because of declines in commodity prices since September 30, 2008, the book value of the Company’s oil and gas properties exceeded the ceiling at December 31, 2008.~~ The quoted Cushing, Oklahoma spot price for West Texas Intermediate oil ~~had declined from a reported price of $100.70 per Bbl at September 30, 2008 to a reported price of $44.60 per Bbl~~ at December 31, ~~2008.~~2009 was $79.39. The quoted Henry Hub spot price for natural gas ~~had declined from a reported price of $7.12 per MMBtu at September 30, 2008 to a reported price of $5.63 per MMBtu~~ at December 31, ~~2008. Consequently, the Company recorded an impairment charge of $182.8 million ($108.2 million after-tax) during the quarter ended December 31, 2008.~~2009 was $5.79. (Note —– Because actual pricing of the Company’s various producing properties varies depending on their location, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Cushing oil and Henry Hub prices, which are only indicative of current prices.) At June 30, 2009, the quoted Cushing, Oklahoma spot price for West Texas Intermediate oil was $69.82 per Bbl ($49.64 per Bbl at March 31, 2009) and the quoted spot price for natural gas was $3.88 per MMBtu ($3.63 per MMBtu at March 31, 2009). At June 30, 2009, the ceiling exceeded the book value of the Company’s oil and gas properties by approximately $247 million (and approximately $37 million at March 31, 2009). If natural gas prices used in the ceiling test calculation at ~~June 30,~~December 31, 2009 had been $1 per MMBtu lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately ~~$197~~$360 million. If crude oil prices used in the ceiling test calculation at ~~June 30,~~

-28-

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

RESULTS OF OPERATIONS

Earnings

The ~~Company’s~~Company earnings were ~~$42.9~~$64.5 million for the quarter ended ~~June 30,~~December 31, 2009 compared to ~~earnings~~a loss of ~~$59.9~~$42.7 million for the quarter ended ~~June 30,~~December 31, 2008. The ~~decrease~~increase in earnings of ~~$17.0~~$107.2 million is primarily the result of ~~lower~~higher earnings in the Exploration and Production segment. ~~The~~Higher earnings in the Utility and ~~Pipeline and Storage~~Energy Marketing segments as well as the All Other category also contributed to the ~~decrease in earnings. Higher~~increase. Lower earnings in the ~~Energy Marketing~~Pipeline and Storage segment and a loss in the Corporate category slightly offset these ~~decreases.~~

increases. The Company’s ~~earnings were $73.7 million~~loss for the ~~nine months~~quarter ended June 30, 2009 compared to earnings of $225.5 million for the nine months ended June 30, 2008. The decrease in earnings of $151.8 million is primarily the result of lower earnings in the Exploration and Production segment. The Utility segment and the All Other category also contributed to the decrease in earnings. Higher earnings in the Pipeline and Storage and Energy Marketing segments, as well as the Corporate category, slightly offset these decreases. The Company’s earnings for the nine months ended June 30, 2009 includeDecember 31, 2008 includes a non-cash $182.8 million impairment charge ($108.2 million after tax) ~~recorded during the quarter ended December 31, 2008~~ for the Exploration and Production segment’s oil and gas producing properties.

Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.

Earnings (Loss) by Segment


	Three Months Ended									Nine Months Ended															Increase
	June 30,									June 30,
							Increase/									Increase/
(Thousands)	2009			2008			(Decrease)			2009			2008			(Decrease)
Three Months Ended December 31(Thousands)																			2009			2008			(Decrease)
Utility	$	5,396		$	7,848		$	(2,452	)	$	60,303		$	62,228		$	(1,925	)	$	23,013		$	22,088		$	925
Pipeline and Storage		9,221			12,534			(3,313	)		41,582			40,931			651			10,354			17,176			(6,822	)
Exploration and Production		27,083			39,791			(12,708	)		(38,366	)		108,385			(146,751	)		29,779			(83,557	)		113,336
Energy Marketing		1,331			478			853			7,509			7,079			430			1,092			599			493

Total Reportable Segments		43,031			60,651			(17,620	)		71,028			218,623			(147,595	)		64,238			(43,694	)		107,932
All Other		(1,086	)		(960	)		(126	)		(46	)		7,351			(7,397	)		1,166			(868	)		2,034
Corporate		959			164			795			2,728			(511	)		3,239			(905	)		1,884			(2,789	)

Total Consolidated	$	42,904		$	59,855		$	(16,951	)	$	73,710		$	225,463		$	(151,753	)	$	64,499		$	(42,678	)	$	107,177

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

revenues for the nine months ended June 30, 2009 were $2.2 million lower than revenues for the nine months ended June 30, 2008. There was no impact to revenues when comparing the quarters ended June 30, 2009 and June 30, 2008.warmer weather.

The Utility segment’s earnings for the quarter ended ~~June 30,~~December 31, 2009 were ~~$5.4~~$23.0 million, ~~a decrease~~an increase of ~~$2.4~~$0.9 million when compared towith earnings of ~~$7.8~~$22.1 million for the quarter ended ~~June 30,~~December 31, 2008. In the New York jurisdiction, earnings ~~decreased by $1.1~~increased $0.5 million. The positive earnings impact associated with lower operating expenses of $0.7 million (primarily a decrease ~~was largely~~in bad debt expense due to ~~higher interest expense ($1.5 million) partially~~lower gas costs) and routine regulatory adjustments of $0.9 million were the main factors in the earnings increase. These factors were offset by ~~lower operating costs ($0.4 million). The~~an increase in interest expense ~~stems~~($0.9 million) stemming from the borrowing of a portion of the Company’s April 2009 debt issuance. ~~This~~The April 2009 debt was issued at a significantly higher interest rate than the interest rates on ~~existing~~ debt ~~at the time of issuance.~~that had matured in March 2009. In the Pennsylvania jurisdiction, earnings ~~decreased by $1.3��~~increased $0.4 million. The positive earnings impact associated with lower operating costs of $1.5 million (primarily a decrease ~~was largely~~in bad debt expense due to ~~higher interest~~lower gas costs) and lower income tax expense ~~($0.4 million) and~~of $1.3 million (due to a lower effective tax rate) were the main factors in the earnings increase. These factors were largely offset by lower usage per account ($~~0.4~~0.9 million)~~. The phrase “usage per account” refers to~~, higher interest expense ($0.9 million), the ~~average gas consumption per customer account after factoring out any~~negative earnings impact ~~that~~of warmer weather ~~may have had on consumption.~~($0.2 million), and routine regulatory adjustments ($0.1 million). As with the New York jurisdiction, the increase in interest expense in the Pennsylvania jurisdiction is attributable to the Company’s April 2009 debt ~~issuance.~~issuance and the fact that it was issued at a significantly higher interest rate than the interest rates on debt that had matured in March 2009.

-30-

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

The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. For ~~both~~ the quarter ended ~~June 30,~~December 31, 2009, ~~and June 30,~~the WNC preserved $0.2 million of earnings, as it was warmer than normal. For the quarter ended December 31, 2008, the WNC ~~preserved~~did not have a significant impact on earnings ~~of approximately $0.4 million, as weather was warmer than normal for those periods.~~

The Utility segment’s earnings for the nine months ended June 30, 2009 were $60.3 million, a decrease of $1.9 million when compared with earnings of $62.2 million for the nine months ended June 30, 2008. In the New York jurisdiction, earnings decreased $0.5 million. The earnings impact of the December 28, 2007 rate order discussed above ($1.4 million), higher interest expense ($1.1 million) and regulatory true-up adjustments ($0.5 million) were the main factors in the earnings decrease. These factors were offset by a $3.0 million decrease in operating costs (primarily due to a decrease in other post-retirement benefit costs as well as a decrease in health insurance and prescription drug costs). The reason for the increase in interest costs is attributable to the April 2009 debt issuance, as discussed above. In the Pennsylvania jurisdiction, earnings decreased $1.4 million. The negative earnings impact associated with lower usage per account ($1.9 million), higher income tax expense ($1.4 million) and higher operating costs of $1.3 million (primarily bad debt expense due to the possible impact current economic conditions may have on customers) was largely offset by the positive earnings impact of colder weather ($2.0 million) and lower interest expense ($0.5 million).

~~For the nine months ended June 30, 2009, the WNC reduced earnings by approximately $0.2 million,~~ as the weather was close to normal. In periods of colder than ~~normal. For the nine months ended June 30, 2008,~~normal weather, the WNC ~~preserved earnings of approximately $2.5 million, as the weather was warmer than normal.~~benefits Distribution Corporation’s New York customers.

Pipeline and Storage

Pipeline and Storage Operating Revenues

Three Months Ended Nine Months Ended
June 30, June 30,
Increase/ Increase/
(Thousands) 2009 2008 (Decrease) 2009 2008 (Decrease)
Firm Transportation $ 32,894 $ 29,020 $ 3,874 $ 105,931 $ 93,427 $ 12,504
Interruptible Transportation 635 1,151 (516 ) 2,862 3,237 (375 )

33,529 30,171 3,358 108,793 96,664 12,129

Firm Storage Service 16,648 16,754 (106 ) 50,101 50,311 (210 )
Interruptible Storage Service 4 — 4 18 14 4
Other 643 5,260 (4,617 ) 9,018 16,222 (7,204 )

$ 50,824 $ 52,185 $ (1,361 ) $ 167,930 $ 163,211 $ 4,719

~~-36-~~

Operating revenues for the Pipeline and Storage segment decreased ~~$1.4~~$1.3 million ~~for~~in the quarter ended ~~June 30,~~December 31, 2009 as compared with the quarter ended ~~June 30,~~December 31, 2008. The decrease was primarily due to ~~decreased~~a decline in efficiency gas revenues ($~~3.9~~3.5 million) reported as part of other revenues in the table above. This ~~decrease~~decease was primarily due to lower gas prices and lower transportation volumes retained during the quarter ended ~~June 30,~~December 31, 2009 as compared with the quarter ended ~~June 30,~~December 31, 2008. It also reflects a lower gain, quarter over quarter, on the sale of such retained efficiency gas volumes held in inventory. Under Supply Corporation’s tariff with ~~suppliers,~~shippers, Supply Corporation is allowed to retain a set percentage of shipper-supplied gas to cover compressor fuel costs and other operational purposes. To the extent that Supply Corporation does not need all of the gas to cover such operational needs, it is allowed to keep the excess gas as inventory. That inventory is later sold to customers. The excess gas that is retained as inventory ~~represents~~as well as any gains resulting from the sale of such inventory represent efficiency gas revenue to Supply Corporation. ~~The~~Interruptible transportation revenues also decreased $0.8 million due primarily to a decrease in ~~efficiency gas revenues~~the gathering rate Supply Corporation is allowed to charge. Partially offsetting the decreases was ~~partially offset by~~ an increase in firm transportation revenues ~~($3.4 million) due to~~of $3.3 million. This increase was primarily the result of higher revenues from the Empire Connector, which was placed in service in December ~~2008, combined with higher reservation, commodity, and surcharge revenues associated with new contracts for transportation service.~~2008. While transportation ~~volumes~~volume decreased ~~during the quarter,~~by 22.5 Bcf largely due to warmer weather and lower industrial demand, volume fluctuations generally do not have a significant impact on revenues as a result of ~~the~~Supply Corporation and Empire’s straight fixed-variable rate ~~design used by both Supply Corporation and Empire.~~

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

of the ~~earnings impact associated with~~construction of the Empire Connector, which was completed and placed in service on December 10, 2008. The increase in both depreciation expense and property taxes is primarily a result of the Empire Connector being placed in service in December 2008. The increase in operating expenses can primarily be attributed to higher ~~transportation revenues ($2.2 million).~~pension expense. The increase in interest expense can be attributed to higher debt balances and a higher average interest rate on ~~borrowings.~~borrowings combined with a decrease in the allowance for borrowed funds used during construction resulting from the completion of the Empire Connector. The increase in the average interest rate stems from the Company’s April 2009 debt issuance. The ~~decrease in the allowance for funds used during construction can be attributed to the completion of the Empire Connector in December 2008.~~

~~The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2009~~decreases were ~~$41.6 million, an increase of $0.7 million when compared to earnings of $40.9 million for the nine months ended June 30, 2008. The increase was primarily due to~~partially offset by the earnings impact associated with ~~an increase in~~higher transportation revenues ~~($7.9 million),~~of $1.6 million, as discussed above. In addition, increased earnings resulted from an increase in the allowance for funds used during construction ($0.7 million) and higher interest income ($0.1 million). The increase in the allowance for funds used during construction reflects the fact that construction work in progress balances for the Empire Connector were significantly higher during the quarter ended December 31, 2008 than they were during the nine months ended June 30, 2008. While construction of the Empire Connector began in September 2007, winter weather limited significant construction until the spring and summer of 2008. These factors, which increased earnings, were largely

~~-37-~~

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

offset by a decrease in efficiency gas revenues ($4.4 million), higher interest expense ($3.1 million), and higher depreciation expense ($1.2 million). The increase in interest expense can be attributed to higher debt balances and a higher average interest rate on borrowings. The increase in the average interest rate stems from the Company’s April 2009 debt issuance. The increase in depreciation expense can be attributed primarily to a revision of accumulated depreciation combined with the increased depreciation associated with placing the Empire Connector in service in December 2008.

Exploration and Production

Exploration and Production Operating Revenues


	Three Months Ended									Nine Months Ended															Increase
	June 30,									June 30,
							Increase/									Increase/
(Thousands)	2009			2008			(Decrease)			2009			2008			(Decrease)
Three Months Ended December 31(Thousands)																			2009			2008			(Decrease)
Gas (after Hedging)	$	38,450		$	56,591		$	(18,141	)	$	118,345		$	155,793		$	(37,448	)	$	40,868		$	41,093		$	(225	)
Oil (after Hedging)		56,690			66,695			(10,005	)		156,340			185,650			(29,310	)		62,695			53,071			9,624
Gas Processing Plant		5,380			13,566			(8,186	)		18,785			35,674			(16,889	)		7,208			7,328			(120	)
Other		270			(291	)		561			717			(3,174	)		3,891			47			417			(370	)
Intrasegment Elimination⁽¹⁾		(3,171	)		(10,407	)		7,236			(12,777	)		(25,114	)		12,337			(4,467	)		(5,197	)		730

	$	97,619		$	126,154		$	(28,535	)	$	281,410		$	348,829		$	(67,419	)	$	106,351		$	96,712		$	9,639

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

~~Average Prices~~

Three Months Ended Nine Months Ended
June 30, June 30,
2009 2008 Decrease 2009 2008 Decrease
Average Gas Price/Mcf

Gulf Coast $ 3.95 $ 12.17 $ (8.22 ) $ 4.90 $ 9.66 $ (4.76 )
West Coast $ 3.04 $ 10.61 $ (7.57 ) $ 4.10 $ 8.43 $ (4.33 )
Appalachia $ 4.11 $ 11.53 $ (7.42 ) $ 6.06 $ 9.25 $ (3.19 )
Weighted Average $ 3.86 $ 11.71 $ (7.85 ) $ 5.18 $ 9.32 $ (4.14 )
Weighted Average After Hedging $ 5.94 $ 9.73 $ (3.79 ) $ 7.28 $ 8.95 $ (1.67 )

Average Oil Price/Bbl

Gulf Coast $ 56.29 $ 124.43 $ (68.14 ) $ 50.64 $ 103.46 $ (52.82 )
West Coast $ 55.77 $ 114.35 $ (58.58 ) $ 46.84 $ 94.64 $ (47.80 )
Appalachia $ 48.93 $ 114.99 $ (66.06 ) $ 54.90 $ 94.18 $ (39.28 )
Weighted Average $ 55.77 $ 116.05 $ (60.28 ) $ 47.69 $ 96.17 $ (48.48 )
Weighted Average After Hedging $ 67.19 $ 89.55 $ (22.36 ) $ 62.67 $ 79.97 $ (17.30 )

2009 Compared with 2008

Operating revenues for the Exploration and Production segment ~~decreased $28.5~~increased $9.6 million for the quarter ended ~~June 30,~~December 31, 2009 as compared with the quarter ended ~~June 30,~~December 31, 2008. ~~Gas~~Oil production revenue after hedging ~~decreased $18.1~~increased $9.6 million. ~~This decrease is due to a decrease~~An increase in the weighted average price of ~~gas~~oil after hedging ($~~3.79~~10.19 per ~~Mcf), partially offset by an increase in gas~~Bbl) was the primary cause, as production of 657 MMcf. The increase in gas production occurred partially in this segment’s Appalachian region (362 MMcf) as a result of additional wells drilled throughout fiscal 2008 that came on line in 2009. The Gulf Coast region also experienced an increase in gas production (288 MMcf). Production from a new field (Cyclops) that started producing at the end of March 2009 was responsible for the increase, partly offset by declines in production from some existing fields, quarter to quarter. Oil production revenue after hedging decreased $10.0 million due to a $22.36 per Bbl decline in weighted average prices of oil after hedging. This decrease was partially offset by an increase in productionlevels in the Gulf Coast and West Coast regions ~~of this segment. The increase in crude oil production~~were marginally higher in the Gulf Coast region of 52 Mbbl is due to production from a new field in the High Island area. In the West Coast region, increased production at the Midway Sunset field is responsible for the increase in crude oil production of 56 Mbbl in this region.

~~Operating revenues for the Exploration and Production segment decreased $67.4 million for the nine months ended June 30, 2009 as compared with the nine months ended June 30, 2008.~~current period. Gas production revenue ~~after hedging decreased $37.4 million due~~was relatively flat when comparing the quarter ended December 31, 2009 to ~~a decline~~the quarter ended December 31, 2008. Increases in ~~the weighted average price of gas after hedging ($1.67 per Mcf) as well as a decrease in gas production of 1,170 MMcf. The decrease in gas production occurred in the~~ Gulf Coast region (1,750 MMcf) as a result of lingering shut-ins caused by Hurricane Ike in September 2008. While Seneca’s properties sustained only superficial damage from the hurricanes, two significant producing propertiesand Appalachian production were shut-in for a significant portion of the current fiscal year due to repair work on third party pipelines and onshore processing facilities. One of the properties was back on line by March 31, 2009 and the other property was back on line by the end of April 2009. Partly offsetting the decrease in gas production in the Gulf Coast region was an increase in gas production in the Appalachian region of 527 MMcf as a result of additional wells drilled throughout fiscal 2008 that came on line in 2009. Oil production revenue after hedging decreased $29.3 million due primarily to a $17.30 per Bbl decrease in weighted average prices of oil after hedging, partiallylargely offset by ~~an increase~~price decreases in ~~production in the West Coast and Gulf Coast~~those regions.

The Exploration and Production segment’s earnings for the quarter ended ~~June 30,~~December 31, 2009 were ~~$27.1~~$29.8 million ~~a decrease of $12.7 million when~~ compared with ~~earnings~~a loss of ~~$39.8~~$83.6 million for the quarter ended ~~June 30, 2008. Lower natural gas prices and~~December 31, 2008, an increase of $113.4 million. The increase in earnings is primarily the result of the non-recurrence of an impairment charge of $108.2 million that was recorded in the quarter ended December 31, 2008, as discussed above. Higher crude oil prices ~~decreased earnings by $15.9 million~~ and ~~$12.3 million, respectively, while~~marginally higher crude oil production ~~and natural gas production~~ increased earnings by ~~$5.8~~$5.6 million and ~~$4.2~~$0.7 million, respectively. Lower lease operating expenses ($0.6 million) and lower interest ~~income of $1.3 million~~expense ($0.6 million) also contributed to the increase in earnings. The decrease in lease operating expenses is primarily due to lower production taxes related to the lower production revenue from High Island 24 and 23 fields in the Gulf Coast region and lower well operating costs related to High Island 356, which is in the process of being plugged. The decrease in interest expense is primarily due to a lower average amount of debt outstanding. The increase in earnings is partially offset by higher depletion expense ($0.5 million), lower interest income ($0.8 million), higher general and administrative and other operating expenses ($0.6 million), and the earnings impact associated with higher income tax expense ($0.5 million). The increase in depletion expense is primarily due to an increase in production partially offset by a lower full cost pool balance after the impairment charge taken during the quarter ended December 31, 2008. The decrease in interest income is primarily due to lower temporary cash investment balances and lower interest rates. The increase in general and administrative and other operating expenses is mainly due to higher personnel costs.

Energy Marketing

Energy Marketing Operating Revenues


Three Months Ended December 31(Thousands)	2009		2008		Decrease
Natural Gas (after Hedging)	$	71,713	$	114,984	$	(43,271	)
Other		23		23		—

	$	71,736	$	115,007	$	(43,271	)

Energy Marketing Volume


Three Months Ended December 31	2009		2008		Increase
Natural Gas — (MMcf)		14,101		13,136		965

2009 Compared with 2008

Operating revenues for the Energy Marketing segment decreased $43.3 million for the quarter ended December 31, 2009 as compared with the quarter ended December 31, 2008. The decrease is largely attributable to lower gas sales revenue, due to a lower average price of natural gas that was recovered through revenues. While volume sold increased, the majority of the increase was attributable to sales transactions undertaken at the Niagara pipeline delivery point to offset certain basis risks that the Energy Marketing segment was exposed to under certain fixed basis commodity purchase contracts for Appalachian production. These offsetting transactions had the effect of increasing revenue and volume sold with minimal impact to earnings.

~~-39-~~-33-

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

~~interest rates also contributed to the decline in earnings. Lower lease operating expenses of $2.8 million, lower interest expense of $1.7 million, and the~~ The Energy Marketing segment’s earnings impact associated with a lower effective tax rate ($2.4 million) somewhat offset the decline in earnings. The decrease in lease operating expenses is primarily due to a reduction in steam fuel costs in the West Coast region and a decline in marine fuel costs and production taxes as well as lower expenses due to the sale of five properties during fiscal 2009, all in the Gulf Coast region. The decrease in interest expense is primarily due to a lower average amount of debt outstanding.

~~The Exploration and Production segment’s loss~~ for the nine months ended June 30, 2009 was $38.4 million, compared with earnings of $108.4 million for the nine months ended June 30, 2008, a decrease of $146.8 million. The decrease in earnings is primarily the result of an impairment charge of $108.2 million, as discussed above. In addition, lower crude oil prices, lower natural gas prices and lower natural gas production contributed to the decrease in earnings by $28.0 million, $17.5 million and $6.8 million, respectively, while higher crude oil production increased earnings by $9.0 million. Higher operating costs of $3.0 million and lower interest income of $4.6 million also contributed to the decrease in earnings. The increase in operating costs is primarily due to an increase in bad debt expense as a result of a customer’s bankruptcy filing, and higher personnel costs in the Appalachian and Gulf Coast regions. The decline in interest income is due to lower interest rates and lower temporary cash investment balances. Slightly offsetting these earnings decreases were lower interest expense ($4.7 million), lower lease operating expenses ($3.1 million), lower depletion expense ($1.9 million) and lower state income tax expense ($3.2 million). The decline in interest expense is primarily due to a lower average amount of debt outstanding. The decrease in lease operating expenses is primarily due to a reduction in steam fuel costs in the West Coast region and a decline in well servicing workover expenses and production taxes in the Gulf Coast region. The decrease in depletion is primarily due to a lower full cost pool balance after the impairment charge taken during the quarter ended December 31, ~~2008.~~

~~Energy Marketing~~

~~Energy Marketing Operating Revenues~~

Three Months Ended Nine Months Ended
June 30, June 30,
Increase/ Increase/
(Thousands) 2009 2008 (Decrease) 2009 2008 (Decrease)

Natural Gas (after Hedging) $ 71,870 $ 162,127 $ (90,257 ) $ 350,331 $ 440,123 $ (89,792 )
Other 24 2 22 114 (12 ) 126

$ 71,894 $ 162,129 $ (90,235 ) $ 350,445 $ 440,111 $ (89,666 )

~~Energy Marketing Volumes~~

Three Months Ended Nine Months Ended
June 30, June 30,
2009 2008 Decrease 2009 2008 Increase

Natural Gas — (MMcf) 14,634 14,641 (7 ) 50,459 47,189 3,270

2009 ~~Compared~~were $1.1 million, an increase of $0.5 million when compared with ~~2008~~

~~Operating revenues for the Energy Marketing segment decreased $90.2~~earnings of $0.6 million ~~and $89.7 million, respectively,~~ for the quarter ~~and nine months~~ ended ~~June 30, 2009 as compared with~~December 31, 2008. Higher margin of $0.4 million was the ~~quarter and nine months ended June 30, 2008. The decrease~~primary reason for ~~both~~ the quarter and nine months ended June 30, 2009 is primarily due to lower gas sales revenue due to a lower average price of natural gas that was recovered through revenues. For the nine months ended June 30, 2009 as compared to the nine months ended June 30, 2008, this decline was somewhat offset by an increase in volumes sold.increase. The increase in ~~volumes is largely attributable to colder weather as well as sales transactions undertaken to offset certain~~

~~-40-~~

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

basis risk that the Energy Marketing segment was exposed to under certain commodity purchase contracts. These offsetting transactions had the effect of increasing revenue and volumes sold with minimal impact to earnings.

Earnings in the Energy Marketing segment increased $0.9 million and $0.4 million, respectively, for the quarter and nine months ended June 30, 2009 as compared with the quarter and nine months ended June 30, 2008. For the quarter ended June 30, 2009, lower operating costs of $0.6 million, primarily due to a decrease in bad debt expense, as well as higher margins of $0.4 million, are responsible for the increase in earnings. The increase in marginsmargin was primarily driven by improved average margins per Mcf and lower pipeline ~~transportation~~ fuel costs due to lower natural gas commodity prices. For the nine months ended June 30, 2009, higher margins of $0.6 million combined with lower operating costs of $0.4 million (primarily due to a decline in bad debt expense) are responsible for the increase in earnings. These increases were partially offset by higher income tax expense of $0.4 million for the nine months ended June 30, 2009 as compared to the nine months ended June 30, 2008.

Corporate and All Other

2009 Compared with 2008

Corporate and All Other operations recorded ~~losses~~earnings of ~~$0.1 million and $0.8~~$0.3 million for the ~~quarters~~quarter ended ~~June 30,~~December 31, 2009, ~~and June 30, 2008, respectively.~~a decrease of $0.7 million when compared to the earnings of $1.0 million recorded for the quarter ended December 31, 2008. The decrease in ~~the loss period over period~~earnings was largely due to ~~lower operating costs~~the non-recurrence of a gain resulting from a death benefit on corporate-owned life insurance policies held by the Company ($~~1.1~~2.3 million)~~. In 2008,~~ that occurred during the ~~proxy contest with New Mountain Vantage GP, L.L.C. led to an increase in operating costs, which did not recur in 2009.~~quarter ended December 31, 2008. In addition, lower income tax expense ($0.8 million), higher margins from log and lumber sales ($0.3 million), and higher interest income ($0.3 million) contributed to the increase in earnings. These were partially offset by higher interest expense ~~($0.8 million) due to~~of $1.4 million (primarily the result of higher borrowings at a higher interest rate ~~(mostly~~ due to the $250 million of 8.75% notes that were issued in April 2009)~~. In addition, lower equity method~~ and higher income ~~from Horizon Power’s investments in unconsolidated subsidiaries ($0.6 million) and lower margins from Horizon LFG ($0.5 million) also decreased~~tax expense of $1.2 million further reduced earnings.

~~For the nine months ended June 30, 2009, Corporate and All Other had earnings of $2.7 million compared with earnings of $6.8 million for the nine months ended June 30, 2008.~~ The decrease in earnings was ~~largely attributable to lower~~partially offset by higher margins from log and lumber sales ($~~5.5~~1.9 million)~~, lower margins from Horizon LFG ($1.4 million), lower~~ and higher interest income ($~~1.9~~1.0 million)~~, lower income from Horizon Power’s investments in unconsolidated subsidiaries ($1.5 million), and~~ due to higher ~~interest expense ($1.3 million). The increase in interest expense reflects higher borrowings at a higher interest rate, as mentioned above.~~average temporary cash investment balances. In addition, during the quarter ended December 31, 2008, ESNE, an unconsolidated subsidiary of Horizon Power, recorded an impairment charge of $3.6 ~~million.~~million which did not recur. Horizon Power’s 50% share of the impairment was $1.8 million ($1.1 million on an after tax basis). Also, Horizon Power recognized a gain on the sale of a turbine ($0.6 million) during 2008 that did not recur in 2009. These earnings decreases were partially offset by lower operating costs ($3.7 million). In 2008, the proxy contest with New Mountain Vantage GP, L.L.C. led to an increase in operating costs, which did not recur in 2009. In addition, lower income tax expense ($3.5 million) and a gain on life insurance policies held by the Company ($2.3 million) further offset the earnings decrease.

Interest Income

Interest income was ~~$1.6~~$0.7 million lower in the quarter ended ~~June 30,~~December 31, 2009 as compared to the quarter ended ~~June 30,~~December 31, 2008. ~~For~~Lower cash investment balances in the ~~nine months ended June 30, 2009, interest income decreased $4.0 million as compared with the nine months ended June 30, 2008. These decreases are mainly due to~~Exploration and Production segment and lower interest rates ~~and lower average temporary cash investment balances.~~on such investments were the primary factors contributing to the decrease.

Other Income

Other ~~income~~Income decreased ~~$1.0~~$4.5 million for the quarter ended ~~June 30,~~December 31, 2009 as compared with the quarter ended ~~June 30,~~December 31, 2008. This decrease is ~~attributable~~attributed to a $2.7 million decrease in the allowance for funds used during construction ~~of $0.9 million~~ in the Pipeline and Storage segment ~~primarily associated with the~~

~~-41-~~

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

Empire Connector project. For the nine months ended June 30, 2009, other income increased $1.5 million as compared with the nine months ended June 30, 2008. This increase is attributable to an increase in the allowance for funds used during construction of $0.7 million in the Pipeline and Storage segment primarilymainly associated with the Empire Connector ~~project, as well as~~project. In addition, a gain resulting from a death benefit ~~gain~~ on corporate-owned life insurance ~~proceeds~~policies of $2.3 million recognized ~~in the Corporate category. Offsetting these increases, as noted above, Horizon Power recognized a pre-tax gain on the sale of a turbine of $0.9 million~~ during the quarter ended ~~March~~December 31, 2008 ~~that~~ did not ~~recur in 2009.~~recur.

Interest Expense on Long-Term Debt

Interest ~~expense~~ on long-term debt increased ~~$2.3~~$4.0 million for the quarter ended ~~June 30,~~December 31, 2009 as compared with the quarter ended ~~June 30,~~December 31, 2008. ~~For the nine months ended June 30, 2009, interest expense on long-term debt increased $5.3 million as compared with the nine months ended June 30, 2008. The~~This increase is ~~due to~~primarily the result of a higher average amount of long-term debt outstanding combined with ~~an overall increase in the weighted~~higher average interest ~~rate.~~rates. In ~~April 2008, the Company issued $300 million of 6.5% senior, unsecured notes due in April 2018, and in~~ April 2009, the Company issued $250 million of 8.75% senior, unsecured notes due in May 2019. This increase was ~~partly~~partially offset by ~~the repayment of $200 million of 6.303% medium-term notes that matured in May 2008 and~~ the repayment of $100 million of 6.0% medium-term notes that matured in March 2009.

~~Other Interest Expense~~

Other Interest expense increased $1.3 million for the quarter ended June 30, 2009 as compared to the quarter ended June 30, 2008. For the nine months ended June 30, 2009, other interest expense increased $0.8 million as compared with the nine months ended June 30, 2008. These increases are mainly due to higher interest expense on regulatory deferrals (primarily deferred gas costs) in the Utility segment.

~~Effective Tax Rate~~

The effective tax rate of 32.2% for the nine months ended June 30, 2009 is lower than the effective tax rate of 38.8% for the nine months ended June 30, 2008 due to the reduction in pre-tax income for the nine months ended June 30, 2009. The reduction in pre-tax income is a result of the impairment charge recorded during the quarter ended December 31, 2008 in the Exploration and Production segment.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary source of cash during the ~~nine-month~~three-month periods ended ~~June 30,~~December 31, 2009 and ~~June 30,~~December 31, 2008 consisted of cash provided by operating ~~activities and proceeds from the issuance of long-term debt. These sources~~activities. This source of cash ~~were~~was supplemented by issues of new shares of common stock as a result of stock option exercises. During the ~~nine~~quarter ended December 31, 2008, short-term borrowings also supplemented the Company’s cash position. During the three months ended ~~June 30,~~December 31, 2009 and ~~June 30,~~December 31, 2008, the common stock used to fulfill the requirements of the Company’s 401(k) plans and Direct Stock Purchase and Dividend Reinvestment Plan was obtained via open market purchases. ~~During the quarter~~

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

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

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

The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve is reduced as the inventory is replenished.

Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil. The Company uses various derivative financial instruments, including price swap agreements ~~no cost collars, options~~ and futures contracts in an attempt to manage this energy commodity price risk.

Net cash provided by operating activities totaled ~~$511.8~~$68.3 million for the ~~nine~~three months ended ~~June 30,~~December 31, 2009, ~~an increase~~a decrease of ~~$96.7~~$31.8 million when compared with ~~$415.1~~the $100.1 million provided by operating activities for the ~~nine~~three months ended ~~June 30,~~December 31, 2008. ~~The increase is primarily~~In the Exploration and Production segment, cash provided by operations decreased due to lower cash receipts from the ~~timing~~sale of oil and gas ~~cost recovery in~~production. In the ~~Utility~~Pipeline and Storage segment, ~~for~~cash provided by operations decreased due to lower cash receipts from the ~~nine months ended June 30, 2009 as compared~~sale of efficiency gas inventory. From a consolidated perspective, higher interest payments on long-term debt and higher contributions to the ~~nine months ended June 30, 2008.~~Company’s tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) also contributed to the decrease in cash provided by operating activities.

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled ~~$230.5 million during the nine months ended June 30, 2009 and $284.6~~$67.8 million for the ~~nine~~three months ended ~~June 30,~~December 31, 2009 and $119.2 million for the three months ended December 31, 2008. The table below presents these expenditures:

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

Total Expenditures for Long-Lived Assets

Nine Months Ended June 30, Increase
(Millions) 2009 2008 (Decrease)

Utility $ 40.4 $ 38.8 $ 1.6
Pipeline and Storage 34.8 ⁽¹⁾ 106.2 ⁽⁵⁾ (71.4 )
Exploration and Production 151.7 ⁽²⁾ 140.6 11.1
All Other 3.9 ⁽³⁾ 1.4 2.5
Eliminations (0.3 )⁽⁴⁾ (2.4 )⁽⁶⁾ 2.1

$ 230.5 $ 284.6 $ (54.1 )


Three Months Ended December 31,							Increase
(Millions)	2009			2008			(Decrease)
Utility:
Capital Expenditures	$	12.0		$	13.6		$	(1.6	)
Pipeline and Storage:
Capital Expenditures		7.0			19.5	⁽³⁾		(12.5	)
Exploration and Production:
Capital Expenditures		47.7	^{(1) (2)}		86.4	⁽⁴⁾		(38.7	)
All Other:
Capital Expenditures		1.0	⁽²⁾		—			1.0
Investment in Partnership		0.1			—			0.1
Eliminations		—			(0.3	)⁽⁵⁾		0.3

	$	67.8		$	119.2		$	(51.4	)


⁽¹⁾		Amount includes $15.4 million of accrued capital expenditures at December 31, 2009, the majority of which was in the Appalachian region. This amount has been excluded from the Consolidated Statement of Cash Flows at December 31, 2009 since it represents a non-cash investing activity at that date.

⁽²⁾		Capital expenditures for the ~~nine~~Exploration and Production segment for the three months ended ~~June~~December 31, 2009 exclude $9.1 million of capital expenditures, the majority of which was in the Appalachian region. Capital expenditures for All Other for the three months ended December 31, 2009 exclude $0.7 million of capital expenditures related to the construction of the Midstream Covington Gathering System. Both of these amounts were accrued at September 30, 2009 and paid during the three months ended December 31, 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 amounts have been included in the Consolidated Statement of Cash Flows at December 31, 2009.

⁽³⁾		Amount for the three months ended December 31, 2008 excludes $16.8 million of ~~accrued~~ capital expenditures related to the Empire Connector project accrued at September 30, 2008 and paid during the ~~nine~~three months ended ~~June 30, 2009.~~December 31, 2008. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at that date. The amount has been included in the Consolidated Statement of Cash Flows at ~~June 30, 2009.~~December 31, 2008.

~~-43-~~

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


⁽²⁾⁽⁴⁾		Amount ~~for the nine months ended June 30, 2009~~ includes ~~$9.4~~$51.7 million of accrued capital expenditures at December 31, 2008, the majority of which was for lease acquisitions in the Appalachian region. This amount has been excluded from the Consolidated Statement of Cash Flows at ~~June 30, 2009~~December 31, 2008 since it represents a non-cash investing activity at that date.

⁽³⁾		~~Amount includes a $0.8 million capital contribution made by NFG Midstream Processing, LLC in the Whitetail Processing plant.~~

⁽⁴⁾⁽⁵⁾		Represents $0.3 million of capital expenditures in the Pipeline and Storage segment for the purchase of pipeline facilities from the Appalachian region of the Exploration and Production segment during the quarter ended December 31, 2008.

⁽⁵⁾		Amount includes $19.9 million of accrued capital expenditures related to the Empire Connector project. This amount has been excluded from the Consolidated Statement of Cash Flows at June 30, 2008 since it represents a non-cash investing activity at that date.

⁽⁶⁾		Represents $2.4 million of capital expenditures included in the Appalachian region of the Exploration and Production segment for the purchase of storage facilities, buildings, and base gas from Supply Corporation during the quarter ended March 31, 2008.

Utility

The majority of the Utility capital expenditures for the ~~nine~~three months ended ~~June 30,~~December 31, 2009 and ~~June 30,~~December 31, 2008 were made for replacement of mains and main extensions, as well as for the replacement of service lines.

Pipeline and Storage

The majority of the Pipeline and Storage capital expenditures for the ~~nine~~three months ended ~~June 30,~~December 31, 2009 were related to additions, improvements, and ~~June 30,~~replacements to this segment’s transmission and gas storage systems. The majority of the Pipeline and Storage capital expenditures for the three months ended December 31, 2008 were related to the Empire Connector project, which was placed into service on December 10, ~~2008, as well as for additions, improvements,~~2008.

-36-

Item 2.Management’s Discussion and ~~replacements to this segment’s transmission~~Analysis of Financial Condition and ~~gas storage systems.~~Results of Operations (Cont.)

In light of the growing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus Shale producing area — Supply Corporation isand Empire are actively pursuing ~~development of~~ several expansion projects. The largest, Supply Corporation’s Appalachian Lateral pipeline project is expected to be routed through areas in Pennsylvania where producers are actively drilling and are seeking market access for their newly discovered reserves. The Appalachian Lateral will complement Supply Corporation’s original West to East (“W2E”) project, which was designed to transport Rockies gas supply from Clarington, Ohio to the Ellisburg/Leidy/Corning area and includes the Tuscarora-to-Corning facilities previously referred to as the Tuscarora Extension. The Appalachian Lateral will transport gas supply from Pennsylvania’s producing area to the Overbeck area of Supply Corporation’s existing system, where the facilities associated with the W2E project will move the gas to eastern market points, including Leidy, Pennsylvania, and to interconnections with Millennium and Empire at Corning, New York. Preliminary engineering routing analysis, project cost estimate and rate design have been completed, and prospective shippers have been offered precedent agreements for their consideration.

~~In addition,~~ Supply Corporation is ~~working~~moving forward with ~~the Appalachian producers to develop~~ two strategic compressor horsepower expansions, both supported by signed precedent agreements with Appalachian producers, designed to move ~~attached~~anticipated Marcellus production gas to ~~off-system markets.~~markets beyond Supply Corporation’s pipeline system.

The first strategic horsepower expansion project involves new compression ~~and approximately 3.5 miles of new pipeline to establish a delivery point from~~along Supply Corporation’s Line N, ~~to Texas Eastern at~~increasing that line’s capacity into Texas Eastern’s Holbrook Station ~~near Bristoria~~ in southwestern ~~Pennsylvania.~~Pennsylvania (“Line N Expansion Project”). This project is designed and contracted for 150,000 Dth/day of firm transportation, and will allow ~~local (Marcellus)~~anticipated Marcellus production located in the vicinity of Line N to flow south and access markets off Texas Eastern’s system, with a ~~first phase~~projected in-service date of ~~service commencing~~November 2011. On October 20, 2009, Supply Corporation entered the FERC National Environmental Policy Act (NEPA) Pre-filing review, and is in ~~mid-to-late 2010~~the process of preparing an NGA Section 7(c) application to the FERC for approval of the Line N Expansion Project. The preliminary cost estimate for the Line N Expansion Project is $23 million. As of December 31, 2009, approximately $0.6 million has been spent to study the Line N Expansion Project, which has been included in preliminary survey and ~~the second phase in late 2011.~~investigation charges and has been fully reserved for at December 31, 2009.

The second strategic horsepower expansion project involves the addition of compression at Supply Corporation’s existing interconnect with Tennessee Gas Pipeline at Lamont, Pennsylvania, with a projected in-service date ~~early-to-mid-2010.~~of June 2010 (“Lamont Project”). The Lamont Project is designed and contracted for 40,000 Dth/day of firm transportation and will afford shippers a transportation path from their anticipated Marcellus production located in Elk and Cameron Counties, Pennsylvania to markets attached to Tennessee Gas Pipeline’s 300 Line. The Lamont Project will be constructed under Supply Corporation’s existing blanket construction certificate authority from the FERC. The preliminary cost estimate for the Lamont Project is $6 million. As of December 31, 2009, less than $0.1 million has been spent to study the Lamont Project, which has been included in preliminary survey and investigation charges and has been fully reserved for at December 31, 2009.

In ~~conjunction with the Appalachian Lateral and W2E transportation projects,~~addition, Supply Corporation continues to actively pursue its largest planned expansion, the West-to-East (“W2E”) pipeline project, which is designed to transport Rockies and/or locally produced natural gas supplies to the Ellisburg/Leidy/Corning area. Supply Corporation anticipates that the development of the W2E project will occur in phases, and based on requests from the Marcellus producing community for transportation service commencing as early as 2011, Supply Corporation began a binding Open Season on August 26, 2009. This Open Season offered transportation capacity on two initial phases (“Phase I” and “Phase II”) of the W2E pipeline project. As currently envisioned, constructed in 2 phases, Phase I would be designed to transport approximately 100,000 Dth/day from the Marcellus producing area through a new 39-mile pipeline to be constructed through Elk, Cameron, and Clinton Counties to the Leidy Hub, with an anticipated in-service date of late 2011. Phase II, with a late 2012 projected in-service date, consists of an additional 43 miles of new pipeline extending through Clearfield and Jefferson Counties to Supply Corporation’s Line K system and would provide additional transportation capacity of at least 325,000 Dth/day. The project also includes 25,000 horsepower of compression at two stations located along the new pipeline.

This binding Open Season concluded on October 8, 2009 with significant participation by Marcellus producers. Supply Corporation received binding requests for 175,000 Dth/day of firm transportation capacity, has ~~plans~~fully executed precedent agreements for 100,000 Dth/day, and expects to ~~develop new storage capacity~~execute the remaining agreements submitted by ~~expanding certain of its existing storage facilities. The expansion of these fields, which~~those shippers. Supply Corporation is pursuing ~~concurrently with~~post-Open Season capacity requests for the ~~Appalachian Lateral/~~remaining Phase I and Phase II capacity. Preliminary engineering, alternate routing analysis, preliminary cost estimate and rate design have been completed. This project will require an NGA Section 7(c) application, which Supply Corporation has not filed. The capital cost of these two phases is estimated to be $260 million. As of December 31, 2009, approximately $1.0 million has been spent to study the W2E Phase I and II transportation ~~projects, could provide approximately 8.5 MMDth of incremental storage capacity with incremental withdrawal deliverability of up to 121 MDth of natural gas per day, with service~~project, which has been included in preliminary survey and investigation charges and has been fully reserved for at December 31, 2009.

~~-44-~~-37-

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

~~commencing as~~ In conjunction with Phases I and II of the W2E transportation project, Supply Corporation plans to develop new storage capacity by expanding two of its existing storage facilities. The expansion of the East Branch and Galbraith fields, which could be completed in early ~~as 2012.~~2013, provides 7.9 MMDth of incremental storage capacity and approximately 88 MDth per day of additional withdrawal deliverability. Supply Corporation expects that the availability of this incremental storage capacity will complement Phases I and II of the ~~Appalachian Lateral/~~W2E pipeline project by providing incremental transportation ~~projects~~throughput to and ~~help~~from key market interconnect points. It will also serve to balance the increasing flow of Appalachian ~~and Rockies~~ gas supply ~~into~~through the western Pennsylvania area ~~and~~with the growing demand for gas on the ~~east coast.~~

~~The timeline associated with all of Supply Corporation’s pipeline and~~East Coast. This storage ~~projects~~expansion project will ~~depend on market development.~~require an NGA Section 7 (c) application, which Supply Corporation has not yet ~~filed an application with the FERC~~filed. The preliminary cost estimate for ~~the authority to build any of these projects.~~

The capital cost of the Appalachian Lateral/W2E transportation projects is estimated to be in the range of $750 million to $1 billion, and is expected to be financed by a combination of debt and equity. Preliminary cost estimates for thethis storage expansion ~~Bristoria and Lamont projects are $78 million, $35 million and $6 million, respectively.~~project is $64 million. As of ~~June 30,~~December 31, 2009, approximately $1.0 million has been spent to study ~~the~~this storage expansion project, ~~$0.4 million~~which has been spent to study the Appalachian Lateral/W2E transportation projects, and lesser amounts have been spent on preliminary engineering for the Bristoria and Lamont projects. Costs associated with these projects have been included in preliminary survey and investigation charges and ~~have~~has been fully reserved for at ~~June 30,~~December 31, 2009. The specific timeline associated with the storage expansion will depend on market development.

Supply Corporation expects that its previously announced Appalachian Lateral project will complement W2E Phases I and II due to its strategic upstream location. The Appalachian Lateral pipeline, which is routed through several counties in central Pennsylvania where producers are actively drilling and seeking market access for their newly discovered reserves, will be able to collect and transport locally produced Marcellus shale gas to Supply Corporation’s Line K corridor — and subsequently through the W2E Phase I and II facilities.

Supply Corporation has closed the Appalachian Lateral Open Season and the original Rockies supply-driven W2E Open Season, while it focuses on development of the W2E Phase I and II project. Supply Corporation expects to continue marketing efforts for all remaining sections of the W2E/Appalachian Lateral project. The timeline associated with sections other than W2E Phases I and II will depend on market development.

On October 1, 2009, Empire commenced the Open Season process for an expansion project that will provide at least 300,000 Dth/day of incremental firm transportation capacity from anticipated Marcellus production at new and existing interconnection(s) along its recently completed Empire Connector line and along a proposed 16-mile 24” pipeline extension into Tioga County, Pennsylvania. Empire’s preliminary cost estimate for the Tioga County Extension Project is approximately $45 million. This project would enable shippers to deliver their gas at existing Empire interconnections with Millennium Pipeline at Corning, New York, with TransCanada Pipeline at Chippawa, and with utility and power generation markets along its path, as well as to a planned new interconnection with Tennessee Gas Pipeline’s 200 Line (Zone 5) in Ontario County, New York. Empire completed the non-binding Open Season process on November 25, 2009 for capacity in the Tioga County Extension Project, and has executed a binding precedent agreement with its anchor shipper for 200,000 Dth/day. Empire is in the process of finalizing binding precedent agreements with other shippers who participated in the Open Season, representing requests for at least an additional 100,000 Dth/day. On January 28, 2010, Empire entered the FERC NEPA Pre-filing review, and is in the process of preparing a NGA Section 7 (c) application it anticipates filing with the FERC for approval of the Tioga County Extension project. Empire anticipates that these facilities will be placed in-service on or after September 1, 2011. As of December 31, 2009, approximately $0.2 million has been spent to study the Tioga County Extension Project, which has been included in preliminary survey and investigation charges and has been fully reserved for at December 31, 2009.

The ~~Company’s Empire Connector project has been in service since December 10, 2008, when construction~~Company anticipates financing the Line N Expansion Project, the Lamont Project, Phase I and Phase II of the ~~actual pipeline~~W2E/Appalachian Lateral project, the storage expansion project, and ~~compression facilities was completed, with some right-of-way restoration work remaining to be completed thereafter. During~~ the quarter and nine months ended June 30, 2009, the Company incurred costs of $0.1 million and $21.9 million, respectively, on this project. After June 30, 2009, about $5.3 million, amounting to about 2.8% of the $192 million total project cost, remain to be incurred, almostTioga County Extension Project, all of which ~~is expected to be incurred by the end~~are discussed above, with a combination of ~~September 2009.~~cash from operations, short-term debt, and long-term debt.

Exploration and Production

The Exploration and Production segment capital expenditures for the ~~nine~~three months ended ~~June 30,~~December 31, 2009 were primarily well drilling and completion expenditures and included approximately ~~$16.9~~$1.3 million for the Gulf Coast region, $7.4 million for the West Coast region and $39.0 million for the Appalachian region. These amounts included approximately $12.8 million spent to develop proved undeveloped reserves.

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

The Exploration and Production segment capital expenditures for the three months ended December 31, 2008 were primarily well drilling and completion expenditures and included approximately $11.9 million for the Gulf Coast region, substantially all of which was for the off-shore program in the shallow waters of the Gulf of Mexico, ~~$28.8~~$10.4 million for the West Coast region and ~~$106.0~~$64.1 million for the Appalachian region. These amounts included approximately ~~$22.0~~$10.2 million spent to develop proved undeveloped reserves.

~~In July 2009,~~For all of 2010, the Company expects to spend $345 million on Exploration and Production segment capital expenditures. Previously reported 2010 estimated capital expenditures for the Exploration and Production segment ~~purchased Ivanhoe Energy’s United States oil and gas operations for approximately $39.2~~were $255 million. ~~This purchase complements the segment’s existing oil producing assets~~Estimated capital expenditures in the ~~Midway Sunset Field~~Gulf Coast region will increase from $14.0 million to $18.0 million. Estimated capital expenditures in ~~California. This~~the West Coast region will increase from $17.0 million to $27.0 million. In the Appalachian region, estimated capital expenditures will increase from $224.0 million to $300.0 million. The increase in estimated capital expenditures in the Appalachian region is primarily due to the Company’s planned acquisition of two tracts of land in the Appalachian region. The Company’s wholly-owned subsidiary, Seneca, was ~~funded~~the high bidder on these two tracts of land at approximately $71.8 million. The transaction is expected to close on March 12, 2010. The Company anticipates funding this transaction with cash ~~on hand.~~from operations and/or short-term borrowings. The Company’s estimate of drilling 55 to 75 gross wells in the Marcellus Shale during 2010 remains unchanged.

~~The~~For fiscal 2011, the Company expects to spend $488 million on Exploration and Production segment capital expenditures. Previously reported fiscal 2011 estimated capital expenditures for the ~~nine months ended June 30, 2008 included approximately $46.9 million for~~Exploration and Production segment were $417 million. Estimated capital expenditures in the Gulf Coast region ~~substantially all of which was for the off-shore program~~will increase from $5.0 million to $10.0 million. Estimated capital expenditures in ~~the shallow waters of the Gulf of Mexico, $51.1 million for~~ the West Coast region will increase from $27.0 million to $28.0 million. In the Appalachian region, estimated capital expenditures will increase from $385.0 million to $450.0 million. The Company’s estimate of drilling 100 to 130 gross wells in the Marcellus Shale during 2011 remains unchanged.

For fiscal 2012, the Company expects to spend $625 million on Exploration and ~~$42.6 million~~Production segment capital expenditures. Previously reported fiscal 2012 estimated capital expenditures for the ~~Appalachian region. The~~Exploration and Production segment were $497 million. Estimated capital expenditures in the Gulf Coast region will increase from $12.0 million to $19.0 million. In the Appalachian region, estimated capital expenditures ~~included $2.4~~will increase from $444.0 million ~~for the purchase of storage facilities, buildings, and base gas from Supply Corporation, as shown~~to $565.0 million. Estimated capital expenditures in the ~~table on~~West Coast region will remain at the ~~previous page. These amounts included approximately $20.7 million spent~~previously reported $41.0 million. The Company had previously reported that it anticipates drilling 120 to ~~develop proved undeveloped reserves.~~150 gross wells in the Marcellus Shale during 2012. The Company now anticipates drilling 130 to 160 gross wells in the Marcellus Shale during 2012.

All Other

The majority of the All Other category’s capital expenditures for long-lived assets for the ~~nine~~three months ended ~~June 30,~~December 31, 2009 were for the construction of Midstream Corporation’s Covington Gathering System, as discussed below. ~~The majority of the All Other category’s capital expenditures~~Expenditures for long-lived assets for the ~~nine~~three months ended December 31, 2009 also included a $0.1 million capital contribution made by NFG Midstream Processing, LLC to Whitetail Processing Plant, LLC, as discussed below.

NFG Midstream Covington, LLC, a wholly owned subsidiary of Midstream Corporation, is constructing a gathering system in Tioga County, Pennsylvania. The project, called the Covington Gathering System, is being constructed in two phases. The first phase was completed and placed in service in November 2009. The second phase is anticipated to be placed in service in June ~~30, 2008 were for construction~~2010. When completed, the system will consist of approximately 15 miles of gathering system at a ~~lumber sorter for Highland’s sawmill operations as well as for purchases~~cost of ~~equipment for Highland’s sawmill and kiln operations.~~$15 million to $18 million. As of December 31, 2009, Midstream Corporation has spent approximately $8.9 million in costs related to this project.

~~-45-~~-39-

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

NFG Midstream Covington, LLC, a wholly owned subsidiary of Midstream Corporation, is constructing a gathering system in Tioga County and Lycoming County in Pennsylvania. The project, called the Covington Gathering System, is to be constructed in three phases, with the first phase under construction and anticipated to be placed in service by the fall of 2009. The second phase is anticipated to be placed in service by the fall of 2010. The schedule for the final phase is being developed. When all three phases are complete, the system will consist of approximately 30 miles of gathering system at a cost of $25 million to $30 million. As of June 30, 2009, the Company has spent approximately $2.8 million in costs on Phase I and Phase II related to this project.

~~NFG Midstream~~ Processing, LLC, another wholly owned subsidiary of Midstream Corporation, has a 35% ownership in ~~the~~ Whitetail Processing ~~Plant.~~Plant, LLC. The plant ~~is currently under construction with completion expected~~was placed into service in ~~October~~November 2009. The ~~total project cost is estimated at $4 million. Once completed, the~~ plant ~~will extract~~extracts natural gas liquids from local production. As of ~~June 30,~~December 31, 2009, the Company invested ~~$0.8~~$1.4 million related to the construction of the plant.

The Company anticipates funding the Midstream Corporation projects with cash from operations and/or short-term borrowings. ~~These expenditures were not included in the estimated capital expenditures reported in the Company’s 2008 Form 10-K.~~

In March 2008, Horizon Power sold a gas-powered turbine that it had planned to use in the development of a co-generation plant. Horizon Power received proceeds of $5.3 million and recorded a pre-tax gain of $0.9 million associated with the sale.

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

Financing Cash Flow

The Company did not have any outstanding short-term notes payable to banks or commercial paper at ~~June 30,~~December 31, 2009. However, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, repurchases of stock, and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As for bank loans, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines, which aggregate to $420.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed, or replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million ~~which commitment~~that extends through September 30, 2010.

Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September 30, 2010. At ~~June 30,~~December 31, 2009, the Company’s debt to capitalization ratio (as calculated under the facility) was .43. The constraints specified in the committed credit facility would permit an additional $1.78 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio would exceed .65. If a downgrade in any of the

~~-46-~~

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

Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its committed credit facility, uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations. At December 31, 2009, the Company’s long-term debt ratings were: BBB (S&P), Baa1 (Moody’s Investor Service), and A- (Fitch Ratings Service). At December 31, 2009, the Company’s commercial paper ratings were: A-2 (S&P), P-2 (Moody’s Investor Service), and F2 (Fitch Ratings Service).

Under the Company’s existing indenture covenants, at ~~June 30,~~December 31, 2009, the Company would have been permitted to issue up to a maximum of ~~$495.0 million~~$1.18 billion in additional long-term unsecured indebtedness at ~~then-current~~then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands. However, if the Company were to experience another impairment of oil and gas properties ~~this year,~~in the future, it is possible that these indenture covenants would restrict the Company’s ability to issue additional long-term unsecured indebtedness. This would not preclude the Company from issuing new indebtedness to replace maturing debt.

-40-

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

The Company’s 1974 indenture, pursuant to which $99.0 million (or 7.9%) of the Company’s long-term debt (as of ~~June 30,~~December 31, 2009) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries ~~fails~~fail to make a payment when due of any principal or interest on any other indebtedness aggregating $20.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $20.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of ~~June 30,~~December 31, 2009, the Company had no debt outstanding under the committed credit facility.

In April 2008, the Company issued $300.0 million of 6.50% senior, unsecured notes in a private placement exempt from registration under the Securities Act of 1933. In February 2009, the Company exchanged the notes for economically identical notes registered under the Securities Act of 1933. The notes have a term of 10 years, with a maturity date in April 2018. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. The Company used $200.0 million of the proceeds of the issuance to refund $200.0 million of 6.303% medium-term notes that matured on May 27, 2008.

In April 2009, the Company issued $250.0 million of 8.75% notes due in March 2019. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $247.8 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including to replenish cash that was used to pay the $100 million due at the maturity of the Company’s 6.0% medium-term notes on March 1, 2009. After this debt issuance, the Company’s embedded cost of long-term debt ~~increased from~~was 6.95% at December 31, 2009 and 6.5% ~~to 6.95%.~~at December 31, 2008. If the Company were to issue long-term debt today, its borrowing costs might be expected to be in the range of ~~7.0%~~5.5% to ~~8.0%~~6.5% depending on the ~~length of maturity.~~

~~-47-~~

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

On December 8, 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company could repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. The Company repurchased 439,722 and 2,832,397 shares for $20.7 million and $129.6 million, respectively, during the quarter and nine months ended June 30, 2008 under this program. The Company completed the repurchase of the 8 million shares during the last quarter of fiscal 2008. In September 2008, the Company’s Board of Directors authorized the repurchase of an additional 8 million shares of the Company’s common stock. The Company, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. Such repurchases may resume in the future. The share repurchases mentioned above were funded with cash provided by operating activities.maturity date.

The Company may issue debt or equity securities in a public offering or a private placement from time to time. The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.

OFF-BALANCE SHEET ARRANGEMENTS

The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating ~~and capital~~ leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Utility and the Pipeline and Storage segments, having a remaining lease commitment of approximately ~~$27.7~~$25.6 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters and other items and are accounted for as operating leases. The Company’s unconsolidated subsidiaries, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $2.3 million. The Company has guaranteed 50% or $1.1 million of these capital lease commitments.

OTHER MATTERS

In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

During the ~~nine~~three months ended ~~June 30,~~December 31, 2009, the Company contributed ~~$16.0~~$20.2 million to its ~~retirement plan~~Retirement Plan and ~~$21.5~~$6.2 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of ~~2009,~~2010, the Company does not expect to contribute to ~~its retirement plan. As a result of~~ the ~~recent downturn in the stock markets and general economic conditions, it~~Retirement Plan. It is ~~expected~~likely that the Company will have to fund ~~in the range of $20 million to $40 million~~larger amounts to the ~~retirement plan~~Retirement Plan subsequent to fiscal ~~2009.~~2010 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of ~~2009,~~2010, the Company expects to contribute ~~approximately $5.0~~in the range of $19.0 million to $20.0 million to its VEBA trusts and 401(h) accounts.

-41-

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

differential (between the sales locations and NYMEX) to a forward NYMEX curve because there is not a forward curve specific to ~~these~~this sales ~~locations.~~location. Given the high level of historical correlation between NYMEX prices and prices at ~~these~~this sales ~~locations,~~location, the Company does not believe that the fair ~~values~~value recorded by the Company would be significantly different from what it expects to receive upon settlement. The fair value of the Level 3 derivative assets was reduced by $0.7 million based upon the Company’s assessment of counterparty credit risk. The Company applied default probabilities to the anticipated cash flows that it was expecting from its counterparties to calculate the credit reserve. The Company incorporated hedging collateral deposits received from the counterparties in calculating the credit reserve.

The Level 3 assets amount to $34.5 million at June 30, 2009 and represent 52% of the Derivative Financial Instruments Assets or 7% of the Total Assets shown in Part I, Item 1 at Note 2 — Fair Value Measurements at June 30, 2009.

At June 30, 2009, the Company transferred $9.8 million of derivative assets from Level 3 assets to Level 2 assets. These assets related to the natural gas swaps on southern California natural gas production. This transfer occurred because the Company was able to obtain and utilize forward-looking, observable basis differential information for the underlying hedges at this location. In the prior quarters, the Company utilized historical basis differentials at this location. Also, at June 30, 2009, the Company transferred $1.3 million of derivative assets from Level 2 assets to Level 3 assets. These assets related to certain natural gas swaps on Gulf of Mexico natural gas production. Since the basis differential related to these natural gas swaps could no longer be considered immaterial and the Company could only utilize historical basis differential information to estimate the basis differential, these positions were considered Level 3.

The Company uses the ~~natural gas and~~ crude oil swaps classified as Level 3 to hedge against the risk of declining commodity prices and not as speculative investments. Gains or losses related to these Level 3 derivative assets (including any reduction for credit risk) are deferred until the hedged commodity transaction occurs in accordance with the provisions of ~~SFAS 133.~~the existing guidance for derivative instruments and hedging activities. The value of the swaps represented a $0.1 million reduction to Derivative Financial Instruments Assets or 0.03% of Total Assets as shown in Part I, Item 1 at Note 2 — Fair Value Measurements at December 31, 2009.

The ~~significant increase~~decrease in the net fair value of the Level 3 ~~assets~~positions from October 1, ~~2008~~2009 to ~~June 30,~~December 31, 2009, as shown in Part I, Item 1 at Note 2, was attributable to ~~a significant decrease~~an increase in the commodity price of ~~natural gas and~~ crude oil during that period. The Company believes that these fair values reasonably represent the amounts that the Company would realize upon settlement based on commodity prices that were present at ~~June 30,~~December 31, 2009.

The fair value of all the Company’s Derivative Financial Instruments Assets was reduced by $0.2 million based on the Company’s assessment of credit risk. The Company applied default probabilities to the anticipated cash flows that it was expecting from its counterparties to calculate the credit reserve.

For a complete discussion of market risk sensitive instruments, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s ~~2008~~2009 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive ~~instruments~~.instruments.

Rate and Regulatory Matters

Utility Operation

Base rate adjustments in both the New York and Pennsylvania ~~rate~~ jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities.

New York Jurisdiction

Customer delivery rates charged by Distribution Corporation’s New York division were established in a rate order issued on December 21, 2007 by the NYPSC. The rate order approved a revenue increase of $1.8 million annually, together with a surcharge that would collect up to $10.8 million to recover expenses for implementation of an efficiency and conservation incentive program. The rate order further provided for a return on equity of 9.1%. In connection with the efficiency and conservation program, the rate order ~~also~~ adopted Distribution Corporation’s proposed revenue decoupling mechanism. The revenue decoupling mechanism, like others, “decouples” revenues from throughput by enabling the Company to collect from small volume customers its allowed margin on average weather normalized

~~-49-~~

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

On April 18, 2008, Distribution Corporation filed an appeal with Supreme Court, Albany County, seeking review of the rate order. The appeal ~~contends~~contended that portions of the rate order ~~should be invalidated~~were invalid because they ~~fail~~failed to meet the applicable legal standard for agency decisions. Among the issues challenged by the Company ~~are~~were the reasonableness of the NYPSC’s disallowance of expense items and the methodology used for calculating rate of return, which the appeal ~~contends~~contended understated the Company’s cost of equity. ~~Briefs~~Because of the issues appealed, the case was later transferred to the Appellate Division, New York State’s second-highest court. On December 31, 2009, the Appellate Division issued its Opinion and Judgment. The court upheld the NYPSC’s determination relating to the authorized rate of return but also supported the Company’s argument that the NYPSC improperly disallowed recovery of certain environmental clean-up costs. The court remanded that issue to the NYPSC for further proceedings consistent with its decision. The remand proceedings have not yet been initiated by the NYPSC. On February 1, 2010, the NYPSC filed ~~and oral argument~~a motion for permission to Appeal to the Court of Appeals, New York State’s highest court, seeking appeal of the Appellate Division’s annulment of that part of the rate order relating to disallowance of certain environmental clean up costs. If the NYPSC’s motion is ~~scheduled~~granted, the matter will be heard by the Court of Appeals. Distribution Corporation intends to ~~be held in October 2009.~~oppose the NYPSC’s motion. The Company cannot ~~predict~~ascertain the outcome of the appeal proceedings at this time.

On April 7, 2009, the Governor of the State of New York signed into law an amendment to the Public Service Law increasing the utility assessment from the current rate of 1/3 of one percent to one percent of a utility’s in-state gross operating revenue, together with a temporary surcharge equal, as applied, to an additional one percent of the utility’s gross operating revenue. The amendment is expected to increase the assessment charged to Distribution Corporation’s New York Division, based on the most current calculation, from $2.3 million to approximately $26 million, all other things being equal. The NYPSC, in a generic proceeding initiated for the purpose of implementing the amended law, has provided for recovery, through rates, of the full cost of the increased assessment.

Pennsylvania Jurisdiction

Distribution Corporation currently does not have a rate case on file with the PaPUC. Distribution Corporation’s current tariff in its Pennsylvania jurisdiction was last approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007.

Pipeline and Storage

Supply Corporation currently does not have a rate case on file with the FERC. The rate settlement approved by the FERC on February 9, 2007 requires Supply Corporation to make a general rate filing to be effective December 1, 2011, and bars Supply Corporation from making a general rate filing before then, with some exceptions specified in the settlement.

Empire’s new facilities (the Empire Connector project) were placed into service on December 10, 2008. As of that date, Empire became an interstate pipeline subject to FERC regulation, performing services under a FERC-approved tariff and at FERC-approved rates. The December 21, 2006 FERC order issuing Empire its Certificate of Public Convenience and Necessity requires Empire to ~~make~~file a ~~filing~~cost and revenue study at the FERC, within three years after the in-service date, in conjunction with which Empire will either ~~justifying~~justify Empire’s existing recourse rates or ~~proposing~~propose alternative rates.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory 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 ~~$16.0~~$15.2 million.

~~-50-~~

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

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussions. If enacted or adopted, legislation or regulation that restricts carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Proposed measures could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities. But legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

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.

New Authoritative Accounting ~~Pronouncements~~and Financial Reporting Guidance

In September 2006, the FASB issued ~~SFAS 157. SFAS 157 provides~~authoritative guidance for using fair value to measure assets and liabilities. ~~The pronouncement~~This guidance serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. ~~SFAS 157~~This guidance is to be applied whenever ~~another standard requires or allows~~ assets or liabilities are to be measured at fair value. ~~In accordance with FASB Staff Position FAS No. 157-2, on~~On October 1, 2008, the Company adopted ~~SFAS 157~~this guidance for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis. The ~~same FASB Staff Position delays the effective date~~FASB’s authoritative guidance for using fair value to measure nonfinancial assets and nonfinancial liabilities ~~except for items that are recognized or disclosed at fair value~~ on a ~~recurring~~nonrecurring basis ~~until~~became effective during the ~~Company’s first~~ quarter ~~of fiscal 2010. For further discussion of the impact of the adoption of SFAS 157 for financial assets and financial liabilities, refer to Part I, Item 1 at Note 2 — Fair Value Measurements.~~ended December 31, 2009. The ~~Company is currently evaluating the impact that the adoption of SFAS 157 for~~Company’s nonfinancial assets and nonfinancial liabilities ~~will have on its consolidated financial statements.~~were not impacted by this guidance during the quarter ended December 31, 2009. The Company has identified Goodwill as being the major nonfinancial asset that may be impacted by the adoption of ~~SFAS 157.~~this guidance. The impact of this guidance will be known when the Company performs its annual test for goodwill impairment at the end of the fiscal year; however, at this time, it is not expected to be material. The Company ~~does not believe there are any~~has identified Asset Retirement Obligations as a nonfinancial ~~liabilities~~liability that ~~will~~may be impacted by the adoption of ~~SFAS 157.~~

~~In September 2006,~~ the ~~FASB issued SFAS 158, an amendment~~guidance. The impact of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R. SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded statusthis guidance will be ~~measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158,~~known when the Company ~~has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158~~recognizes new asset retirement obligations. However, at ~~September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be fully adopted by~~this time, the Company by the end of fiscal 2009. The Company has historically measured its plan assets and benefit obligations using a June 30th measurement date. In anticipation of changing to a September 30th measurement date, the Company will be recording fifteen months of pension and other post-retirement benefit costs during fiscal 2009. In accordance with the provisions of SFAS 158, these costs have been calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $5.1 million and have been recorded by the Company during the quarter ended December 31, 2008 as a $3.8 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $1.3 million ($0.8 million after tax) adjustment to earnings reinvested in the business. For further discussion ofbelieves the impact of ~~adopting~~ the ~~measurement date provisions of SFAS 158, refer to Part I, Item 1 at Note 9 — Retirement Plan and Other Post-Retirement Benefits.~~

~~-51-~~

~~Item 2.~~~~Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)~~guidance will be immaterial.

In December 2007, the FASB ~~issued SFAS 141R. SFAS 141R will~~revised authoritative guidance that significantly ~~change~~changes the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies, acquisition costs, in process research and development and restructuring costs. In addition, under ~~SFAS 141R,~~this guidance, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income tax expense. ~~SFAS 141R is~~This authoritative guidance became effective for the Company as of ~~the Company’s first quarter of fiscal 2010.~~October 1, 2009. The Company will apply this guidance to future business combinations.

In December 2007, the FASB issued ~~SFAS 160. SFAS 160 will change~~authoritative guidance that changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests (NCI) and classified as a component of equity. This new consolidation method ~~will~~ significantly ~~change~~changed the accounting for transactions with minority interest holders. ~~SFAS 160 is~~This authoritative guidance became effective for the Company as of October 1, 2009. This guidance currently does not have an impact on the Company’s consolidated financial statements.

~~In March 2008,~~presented its earnings per share pursuant to the ~~FASB issued SFAS 161. SFAS 161 requires entities to provide enhanced disclosures related to an entity’s derivative instruments~~“two class” method.

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Item 2.Management’s Discussion and ~~hedging activities in order to enable investors to better understand how derivative instruments~~Analysis of Financial Condition and hedging activities impact an entity’s financial reporting. The additional disclosures include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The Company adopted the disclosure provisionsResults of ~~SFAS 161 during the quarter ended March 31, 2009. These disclosures may be found at Part I, Item 1 at Note 3 — Financial Instruments.~~Operations (Cont.)

~~Effective April 1,~~In March 2009, the ~~Company adopted~~ FASB ~~Staff Position FAS 107-1~~issued authoritative guidance that expands the disclosures required in an employer’s financial statements about pension and ~~APB 28-1, “Interim Disclosures about Fair Value~~other post-retirement benefit plan assets. The additional disclosures include more details on how investment allocation decisions are made, the plan’s investment policies and strategies, the major categories of ~~Financial Instruments.” This FASB Staff Position amends SFAS 107, “Disclosures about Fair Value of Financial Instruments,”~~plan assets, the inputs and valuation techniques used to ~~require disclosures about~~measure the fair value of ~~financial instruments~~plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for interim reporting periods of publicly traded companies as well as in annual financial statements. Refer to Part I, Item 1 at Note 3 — Financial Instruments under “Long-Term Debt” for additional disclosures included in accordance with this FASB Staff Position.

~~Effective with this June 30, 2009 Form 10-Q,~~ the ~~Company adopted SFAS 165. SFAS 165 establishes general standards of accounting for~~period, and disclosure regarding significant concentrations of ~~events~~risk within plan assets. The additional disclosure requirements are required for the Company’s Form 10-K for the period ended September 30, 2010. The Company is currently evaluating the impact that occur after the balance sheet date but before financial statements are issued or are available to be issued. Refer to Part I, Item 1 at Note 10 — Subsequent Events for disclosures made as a result of the adoption of ~~SFAS 165.~~this authoritative guidance will have on its consolidated financial statement disclosures.

In June 2009, the FASB issued ~~SFAS 168. SFAS 168 establishes~~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 ~~FASB Accounting Standards Codification~~^TM ~~(the Codification)~~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 is effective as the source of authoritative GAAP recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. Rules and interpretive releases of the ~~SEC under authority~~Company’s first quarter of federal securities law are also sources of authoritative GAAP for SEC registrants. All other nongrandfathered, non-SEC accounting literature not included in the Codification will become nonauthoritative. SFAS 168 is effective for interim and annual periods ending after September 15, 2009.fiscal 2011. The Company is currently evaluating the impact that adoption of this authoritative guidance will ~~update~~have on its ~~disclosures to conform to the Codification in its annual report on Form 10-K for the year ending September 30, 2009. There will be no impact on the Company’s~~ consolidated financial ~~statements as the Codification does not change or alter existing GAAP.~~

~~-52-~~

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

Safe Harbor for Forward-Looking Statements

The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties, but there can

-45-

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

be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

	1.		Financial and economic conditions, including the availability of credit, and their effect on the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments;

	2.		Occurrences affecting the Company’s ability to obtain financing under credit lines or other credit facilities or through the issuance of commercial paper, other short-term notes or debt or equity securities, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;

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

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

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

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

7.6.		Changes in demographic patterns and weather conditions;

8.	7.		Changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments or the valuation of the Company’s natural gas and oil reserves;

~~-53-~~

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

9.
	8.	Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;

~~10.~~	9.	Uncertainty of oil and gas reserve estimates;

~~11.~~	10.	Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, and the need to obtain governmental approvals and permits and comply with environmental laws and regulations;

~~12.~~	11.	Significant differences between the Company’s projected and actual production levels for natural gas or oil;

~~13.~~	12.	Changes in the availability and/or price of derivative financial instruments;

~~14.~~	13.	Changes in the price differentials between oil having different quality and/or different geographic locations, or changes in the price differentials between natural gas having different heating values and/or different geographic locations;

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

	15.	The nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits;

	16.	Significant differences between the Company’s projected and actual capital expenditures and operating expenses, and unanticipated project delays or changes in project costs or plans;

-46-

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

	17.		Inability to obtain new customers or retain existing ones;

~~16.~~	18.		Significant changes in competitive factors affecting the Company;

~~17.~~		~~Changes in laws and regulations to which the Company is subject, including tax, environmental, safety and employment laws and regulations;~~

~~18.~~19.		Governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements;

~~19.~~	20.		Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;

~~20.~~		~~Significant differences between the Company’s projected and actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs or plans;~~

21.		~~The nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits;~~

~~22.~~		Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties;

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

	23.		Significant changes in tax rates or policies or in rates of inflation or interest;

	24.		Significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur;

	25.		Changes in accounting principles or the application of such principles to the Company;

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

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

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

~~-54-~~

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

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

Item 3.Quantitative and Qualitative Disclosures About Market Risk

Refer to the “Market Risk Sensitive Instruments” section in Item 2 — MD&A.

Item 4.Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of ~~June 30,~~December 31, 2009.

-47-

Item 4.Controls and Procedures (Concl.)

Changes in Internal ~~Controls~~Control Over Financial Reporting

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended ~~June 30,~~December 31, 2009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

Item 1.Legal Proceedings

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

In addition to these matters, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service, and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

Item 1A.Risk Factors

The risk factors in Item 1A of the Company’s ~~2008~~2009 Form 10-K ~~as amended by Item 1A of the Company’s Forms 10-Q for the quarters ended December 31, 2008 and March 31, 2009,~~ have not materially changed other than as set forth below. The first two risk factors presented below supersede the risk factors having the same captions in the ~~2008~~2009 Form ~~10-K and~~10-K; the ~~December 31, 2008 and March 31,~~third risk factor supplements the risk factors in the 2009 ~~Forms 10-Q and~~Form 10-K. Each risk factor should otherwise be read in conjunction with all of the risk factors disclosed in the 2009 Form 10-K.

The amount and timing of actual future oil and natural gas production and the cost of drilling are difficult to predict and may vary significantly from reserves and production estimates, which may reduce the Company’s earnings.

There are many risks in developing oil and natural gas, including numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures. The future success of the Company’s Exploration and Production segment depends on its ability to develop additional oil and natural gas reserves that are economically recoverable, and its failure to do so may reduce the Company’s earnings. The total and timing of actual future production may vary significantly from reserves and production estimates. The Company’s drilling of development wells can involve significant risks, including those ~~reports.~~related to timing, success rates, and cost overruns, and these risks can be affected by lease and rig availability, geology, and other factors. Drilling for oil and natural gas can be unprofitable, not only from non-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements, including completion of environmental impact analyses and compliance with other environmental laws and regulations, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their cancellation. The cost of drilling, completing, and operating wells is often uncertain, and new wells may not be productive or the Company may not recover all or any portion of its investment. Production can also be delayed or made uneconomic if there is insufficient gathering, processing and transportation capacity available at an economic price to get that production to a location where it can be profitably sold. Without continued successful exploitation or acquisition activities, the Company’s reserves and revenues will decline as a result of its current reserves being depleted by production. The Company cannot assure you that it will be able to find or acquire additional reserves at acceptable costs.

~~-55-~~-48-

Item 1A.Risk Factors (Concl.)

National Fuel’s need to comply with comprehensive, complex, and sometimes unpredictable government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.

While National Fuel generally refers to its Utility segment and its Pipeline and Storage segment as its “regulated segments,” there are many governmental regulations that have an impact on almost every aspect of National Fuel’s businesses. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may affect its business in ways that the Company cannot predict.

In its Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC and the PaPUC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or to the extent Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costs that may be incurred in connection with governmental investigations or proceedings or mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.

In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have sought to establish competitive markets in which customers may purchase supplies of gas from marketers, rather than from utility companies. In June 1999, the Governor of Pennsylvania signed into law the Natural Gas Choice and Competition Act. The Act revised the Public Utility Code relating to the restructuring of the natural gas industry, to permit consumer choice of natural gas suppliers. The early programs instituted to comply with the Act did not result in significant change, and many residential customers currently continue to purchase natural gas from the utility companies. In October 2005, the PaPUC concluded that “effective competition” does not exist in the retail natural gas supply market statewide. On September 11, 2008, the PaPUC adopted a Final Order and Action Plan designed to “increase effective competition in the retail market for natural gas services.” The plan sets forth a schedule of action items for utilities and the PaPUC in order to remove “barriers in the market structure” that, in the opinion of the PaPUC, prevented the full participation of unregulated natural gas suppliers in Pennsylvania retail markets. In New York, in August 2004, the NYPSC issued its Statement of Policy on Further Steps Toward Competition in Retail Energy Markets. This policy statement has a similar goal of encouraging customer choice of alternative natural gas providers. In 2005, the NYPSC stepped up its efforts to encourage customer choice at the retail residential level, and customer choice activities increased in Distribution Corporation’s New York service territory. In April 2007, the NYPSC, noting that the retail energy marketplace in New York is established and continuing to expand, commenced a review to determine if existing programs initially designed to promote competition had outlived their usefulness and whether the cost of programs currently funded by utility rate payers should be shifted to market competitors. Increased retail choice activities, to the extent they occur, may increase Distribution Corporation’s cost of doing business, put an additional portion of its business at regulatory risk, and create uncertainty for the future, all of which may make it more difficult to manage Distribution Corporation’s business profitably.

Both the NYPSC and the PaPUC have instituted proceedings for the purpose of promoting conservation of energy commodities, including natural gas. In New York, Distribution Corporation implemented a Conservation Incentive Program that promotes conservation and efficient use of natural gas by offering customer rebates for high-efficiency appliances, among other things. The intent of conservation and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers results in decreased revenues to the Utility. To prevent revenue erosion caused by conservation, the NYPSC approved a “revenue decoupling mechanism” that renders Distribution Corporation’s New York division financially indifferent to the effects of conservation. In Pennsylvania, although a proceeding is pending, the PaPUC has not yet directed Distribution Corporation to implement conservation measures. If the NYPSC were to revoke the revenue decoupling mechanism in

~~-56-~~

~~Item 1A.~~~~Risk Factors (Concl.)~~

a future proceeding or the PaPUC were to adopt a conservation program without a revenue decoupling mechanism or other changes in rate design, reduced customer usage could decrease revenues, forcing Distribution Corporation to file for rate relief.

In its Pipeline and Storage segment, National Fuel is subject to the jurisdiction of the FERC with respect to Supply Corporation and Empire. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their natural gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. State commissions can also petition the FERC to investigate whether Supply Corporation’s and Empire’s rates are still just and reasonable, and if not, to reduce those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to reduce the rates it charges its natural gas transportation and/or storage customers, or if Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation’s or Empire’s earnings may decrease.

Environmental regulation significantly affects ~~National Fuel’s~~the Company’s business.

~~National Fuel’s~~The Company’s business operations are subject to federal, state, and local laws and regulations relating to environmental protection. These laws and regulations concern the generation, storage, transportation, disposal or discharge of contaminants and greenhouse gases into the environment, the reporting of such matters, and the general protection of public health, natural resources, wildlife and the environment. Costs of compliance and liabilities could negatively affect ~~National Fuel’s~~the Company’s results of operations, financial condition and cash flows. In addition, compliance with environmental laws and regulations could require unexpected capital expenditures at ~~National Fuel’s~~the Company’s facilities or delay or cause the cancellation of expansion projects or oil and natural gas drilling activities. Because the costs of complying with environmental regulations are significant, additional regulation could negatively affect ~~National Fuel’s~~the Company’s business. Although ~~National Fuel~~the Company cannot predict the impact of the interpretation or enforcement of EPA standards or other federal, state and local regulations, ~~National Fuel’s~~the Company’s costs could increase if environmental laws and regulations become more strict.

Increased regulation of exploration and production activities, including hydraulic fracturing, could adversely impact the Company.

Due to the burgeoning Marcellus Shale play in the northeast United States, together with the fiscal difficulties faced by state governments in New York and Pennsylvania, various state legislative and regulatory initiatives regarding the exploration and production business are possible. These initiatives could include new severance taxes for oil and gas production and new statutes and regulations governing hydraulic fracturing of wells, surface owners’ rights and damage compensation, the spacing of wells, and environmental and safety issues regarding natural gas pipelines. Additionally, legislative initiatives in the U.S. Congress could negatively impact the hydraulic fracturing process. If adopted, any such new state or federal legislation or regulation could lead to operational delays, increased operating costs, additional regulatory burdens and increased risks of litigation for the Company’s Exploration and Production segment.

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

On ~~April~~October 1, 2009, the Company issued a total of ~~2,800~~3,200 unregistered shares of Company common stock to the ~~seven~~eight non-employee directors of the Company then serving on the Board of Directors of the Company and receiving compensation under the Company’s Retainer Policy for Non-Employee Directors, 400 shares to each such director. All of these unregistered shares were issued as partial consideration for ~~the~~such directors’ services during the quarter ended ~~June 30,~~December 31, 2009. These transactions were exempt from registration byunder Section 4(2) of the Securities Act of 1933, as transactions not involving a public offering.

~~Issuer Purchases of Equity Securities~~

Total Number of Maximum Number of
Shares Purchased as Shares that May Yet
Part of Publicly Be Purchased Under
Total Number of Announced Share Share Repurchase
Shares Average Price Repurchase Plans or Plans or
Period Purchased^(a) Paid per Share Programs Programs^(b)
Apr. 1 - 30, 2009 11,818 $ 31.05 — 6,971,019
May 1 - 31, 2009 12,103 $ 31.02 — 6,971,019
June 1 - 30, 2009 14,508 $ 35.24 — 6,971,019

Total 38,429 $ 32.62 — 6,971,019

~~-57-~~-49-

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds (Concl.)

Issuer Purchases of Equity Securities


					Total Number of		Maximum Number
					Shares Purchased		of Shares that May
					as Part of Publicly		Yet Be Purchased
	Total Number of				Announced Share		Under Share
	Shares		Average Price		Repurchase Plans		Repurchase Plans
Period	Purchased^(a)		Paid per Share		or Programs		or Programs^(b)
Oct. 1-31, 2009		7,949		$48.77		—		6,971,019
Nov. 1-30, 2009		8,423		$47.12		—		6,971,019
Dec. 1-31, 2009		257,886		$51.28		—		6,971,019

Total		274,258		$51.08		—		6,971,019


^(a)		Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes. During the quarter ended ~~June 30,~~December 31, 2009, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the ~~38,429~~274,258 shares purchased other than through a publicly announced share repurchase program, ~~34,661~~24,553 were purchased for the Company’s 401(k) plans and ~~3,768~~249,705 were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock.

^(b)		In December 2005, the Company’s Board of Directors authorized the repurchase of up to eight million shares of the Company’s common stock. The Company completed the repurchase of the eight million shares during 2008. In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares of the Company’s common stock. The Company, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. However, such repurchases may be made in the future, ~~if conditions improve. Such repurchases would be made~~either in the open market or through private transactions.

Item 6.Exhibits

~~(a)~~

(a) Exhibits


	Exhibit
	Number			Description of Exhibit

410.1			~~Instruments defining~~Description of long-term performance incentives under the ~~rights of security holders:~~National Fuel Gas Company Performance Incentive Program.

•		10.2		~~Officer’s Certificate establishing 8.75% Notes due 2019, dated April 6, 2009 (incorporated by reference to Exhibit 4.4, Form 8-K dated April 6, 2009).~~Description of performance goals under the Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program and the National Fuel Gas Company Executive Annual Cash Incentive Program.

10		10.3		~~Material contracts:~~National Fuel Gas Company Executive Annual Cash Incentive Program.

~~10.1~~			~~Agreement to Extend Duration of Director Services Agreement, dated June 1, 2009, between National Fuel Gas Company and Philip C. Ackerman~~

12			Statements regarding Computation of Ratios:

				Ratio of Earnings to Fixed Charges for the Twelve Months Ended ~~June 30,~~December 31, 2009 and the Fiscal Years Ended September 30, ~~2005~~2006 through ~~2008.~~2009.

		31.1		Written statements of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.

-50-


		Page
Part I. Financial Information

Item 1. Financial Statements (Unaudited)

a. Consolidated Statements of Income and Earnings Reinvested in the Business — Three ~~and Nine~~ Months Ended ~~June 30,~~December 31, 2009 and 2008		6
	~~6 - 7~~
b. Consolidated Balance Sheets — ~~June 30,~~December 31, 2009 and September 30, ~~2008~~2009		7 - 8
	~~8 - 9~~
c. Consolidated ~~Statement~~Statements of Cash Flows — ~~Nine~~Three Months Ended ~~June 30,~~December 31, 2009 and 2008		9
	10
d. Consolidated Statements of Comprehensive Income — Three ~~and Nine~~ Months Ended ~~June 30,~~December 31, 2009 and 2008		10
	11
e. Notes to Consolidated Financial Statements		11 - 27
	~~12 - 31~~
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		28 - 47
	~~32 - 55~~
Item 3. Quantitative and Qualitative Disclosures About Market Risk		47
	55
Item 4. Controls and Procedures			55	47 - 48

Part II. Other Information

Item 1. Legal Proceedings		48
	55
Item 1 A. Risk Factors		48 - 49
	~~55 - 57~~
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		49 - 50
	~~57 - 58~~
Item 3. Defaults Upon Senior Securities		•
			•
Item 4. Submission of Matters to a Vote of Security Holders		•
			•
Item 5. Other Information		•
	•
Item 6. Exhibits		50 - 51
	58
Signatures		52
59EX-10.1
EX-10.2
EX-10.3
EX-12
EX-31.1
EX-31.2
EX-32
EX-99


	June 30,		September 30,
(Thousands of Dollars)	2009		2008


ASSETS
Property, Plant and Equipment	$	5,078,088	$	4,873,969
Less — Accumulated Depreciation, Depletion and Amortization		2,010,584		1,719,869

		3,067,504		3,154,100

Current Assets
Cash and Temporary Cash Investments		433,230		68,239
Cash Held in Escrow		2,000		—
Hedging Collateral Deposits		6,359		1
Receivables — Net of Allowance for Uncollectible Accounts of $45,209 and $33,117, Respectively		200,594		185,397
Unbilled Utility Revenue		14,568		24,364
Gas Stored Underground		27,721		87,294
Materials and Supplies — at average cost		24,768		31,317
Unrecovered Purchased Gas Costs		1,900		37,708
Other Current Assets		32,477		65,158
Deferred Income Taxes		33,009		—

		776,626		499,478


Other Assets
Recoverable Future Taxes		83,543		82,506
Unamortized Debt Expense		15,345		13,978
Other Regulatory Assets		196,278		189,587
Deferred Charges		1,790		4,417
Other Investments		73,174		80,640
Investments in Unconsolidated Subsidiaries		15,094		16,279
Goodwill		5,476		5,476
Intangible Assets		24,627		26,174
Prepaid Post-Retirement Benefit Costs		21,738		21,034
Fair Value of Derivative Financial Instruments		66,193		28,786
Other		7,914		7,732

		511,172		476,609


Total Assets	$	4,355,302	$	4,130,187


Consolidated
Statement of Income	Gain/(Loss) on Derivative			Gain/(Loss) on Commitment		Gain/(Loss) on Derivative			Gain/(Loss) on Commitment
Operating Revenues	$	(1,395,680	)	$	1,395,680	$	609,000		$	(609,000	)
Purchased Gas	$	(5,985,069	)	$	5,985,069	$	(629,000	)	$	629,000


	Nine Months Ended						Three Months Ended
	June 30,						December 31,
	2009			2008			2009			2008
Current Income Taxes
Federal	$	95,526		$	92,384		$	15,070		$	26,518
State		25,528			23,388			3,916			7,819
Foreign		—			90

Deferred Income Taxes
Federal		(67,051	)		18,906			17,335			(54,055	)
State		(18,443	)		8,697			3,757			(15,571	)

		35,560			143,465			40,078			(35,289	)
Deferred Investment Tax Credit		(523	)		(523	)		(174	)		(174	)


Total Income Taxes	$	35,037		$	142,942		$	39,904		$	(35,463	)


Presented as Follows:
Other Income	$	(523	)	$	(523	)	$	(174	)	$	(174	)
Income Tax Expense		35,560			143,465
Income Tax Expense (Benefit)								40,078			(35,289	)


Total Income Taxes	$	35,037		$	142,942		$	39,904		$	(35,463	)


	Nine Months Ended						Three Months Ended
	June 30,						December 31,
	2009			2008			2009			2008
U.S. Income Before Income Taxes	$	108,747		$	368,405
Income (Loss) Before Income Taxes							$	104,403		$	(78,141	)


Income Tax Expense, Computed at Federal Statutory Rate of 35%	$	38,061		$	128,942
Income Tax Expense (Benefit), Computed at Federal Statutory Rate of 35%							$	36,541		$	(27,349	)

Increase (Reduction) in Taxes Resulting From:
State Income Taxes		4,605			20,855			4,987			(5,039	)
Domestic Production Activities Deduction		(1,790	)		(1,878	)
Miscellaneous		(5,839	)		(4,977	)		(1,624	)		(3,075	)


Total Income Taxes	$	35,037		$	142,942		$	39,904		$	(35,463	)


GLOSSARY OF TERMS (Concl.)

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.


	At June 30, 2009			At September 30, 2008
							At December 31, 2009			At September 30, 2009
Funded Status of the Pension and Other Post-Retirement Benefit Plans	$	(19,741	)	$	(19,741	)	$	(63,802	)	$	(63,802	)
Cumulative Foreign Currency Translation Adjustment		(72	)		(71	)		(87	)		(104	)
Net Unrealized Gain on Derivative Financial Instruments		35,948			15,949			8,610			18,491
Net Unrealized Gain on Securities Available for Sale		1,099			6,826			2,577			3,019

Accumulated Other Comprehensive Income	$	17,234		$	2,963
Accumulated Other Comprehensive Loss							$	(52,702	)	$	(42,396	)


Recurring Fair Value Measures	At fair value as of June 30, 2009								At fair value as of December 31, 2009
(Dollars in thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3			Total


Assets:
Cash Equivalents	$	412,255	$	—	$	—	$	412,255	$	385,813	$	—	$	—		$	385,813
Derivative Financial Instruments		—		31,647		34,546		66,193		2,625		17,315		(149	)		19,791
Other Investments		19,691		—		—		19,691		23,809		—		—			23,809
Hedging Collateral Deposits		6,359		—		—		6,359		1,092		—		—			1,092

Total	$	438,305	$	31,647	$	34,546	$	504,498	$	413,339	$	17,315	$	(149	)	$	430,505


Liabilities:
Derivative Financial Instruments	$	1,815	$	—	$	—	$	1,815

Total	$	1,815	$	—	$	—	$	1,815


Recurring Fair Value Measures	At fair value as of September 30, 2009
(Dollars in thousands)	Level 1		Level 2		Level 3		Total

Assets:
Cash Equivalents	$	390,462	$	—	$	—	$	390,462
Derivative Financial Instruments		5,312		12,536		26,969		44,817
Other Investments		24,276		—		—		24,276
Hedging Collateral Deposits		848		—		—		848

Total	$	420,898	$	12,536	$	26,969	$	460,403


Liabilities:
Derivative Financial Instruments	$	—	$	2,148	$	—	$	2,148

Total	$	—	$	2,148	$	—	$	2,148


				Total Gains/Losses
				Realized and Unrealized												Total Gains/Losses – Realized and Unrealized
							Included in Other												Included in Other			Transfer
	October 1,			Included in			Comprehensive		Transfer In/(Out)					October 1,		Included in			Comprehensive			In/Out of		December 31,
(Dollars in thousands)	2008			Earnings			Income		of Level 3			June 30, 2009		2009		Earnings			Income			Level 3		2009
Assets:
Derivative Financial Instruments	$	7,110		$	(37,339	)⁽¹⁾	$	73,267	$	(8,492	)	$	34,546	$	26,969	$	(3,135	)⁽¹⁾	$	(23,983	)	$	—	$	(149	)

Total	$	7,110		$	(37,339	)	$	73,267	$	(8,492	)	$	34,546	$	26,969	$	(3,135	)	$	(23,983	)	$	—	$	(149	)
Liabilities:
Derivative Financial Instruments	$	(777	)	$	(12,104	)⁽¹⁾	$	12,881	$	—		$	—
Total	$	(777	)	$	(12,104	)	$	12,881	$	—		$	—


	June 30, 2009				September 30, 2008
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Long-Term Debt	$	1,249,000	$	1,285,890	$	1,099,000	$	1,027,098


⁽¹⁾		~~Agrees to the sum of Level 2 and Level 3 Derivative Financial Instrument Assets shown in Note 2, Fair Value Measurements.~~

⁽²⁾		~~Agrees to the Level 1 Derivative Financial Instrument Liabilities shown in Note 2, Fair Value Measurements.~~


⁽¹⁾		Represents hedging of fixed price sales commitments of natural gas.

⁽²⁾		Represents hedging of fixed price purchase commitments of natural gas.

⁽³⁾		Represents hedging of storage withdrawal commitments of natural gas.


			Pipeline		Exploration									Corporate and
			and		and		Energy		Total Reportable					Intersegment			Total
	Utility		Storage		Production		Marketing		Segments		All Other			Eliminations			Consolidated


Revenue from External Customers	$	158,310	$	30,791	$	97,619	$	71,894	$	358,614	$	8,269		$	228		$	367,111

Intersegment Revenues	$	2,940	$	20,033	$	—	$	—	$	22,973	$	374		$	(23,347	)	$	—

Segment Profit:
Net Income (Loss)	$	5,396	$	9,221	$	27,083	$	1,331	$	43,031	$	(1,086	)	$	959		$	42,904


	At June 30, 2009							At September 30, 2008									At September 30,
	Gross					Net		Net		At December 31, 2009							2009
	Carrying		Accumulated			Carrying		Carrying		Gross					Net		Net
	Amount		Amortization			Amount		Amount		Carrying		Accumulated			Carrying		Carrying
										Amount		Amortization			Amount		Amount
Intangible Assets Subject to Amortization:
Long-Term Transportation Contracts	$	4,701	$	(2,531	)	$	2,170	$	2,522	$	4,701	$	(2,729	)	$	1,972	$	2,071
Long-Term Gas Purchase Contracts		31,864		(9,407	)		22,457		23,652		31,864		(12,749	)		19,115		19,465

	$	36,565	$	(11,938	)	$	24,627	$	26,174	$	36,565	$	(15,478	)	$	21,087	$	21,536


Aggregate Amortization Expense:
(Thousands)
Three Months Ended June 30, 2009	$	497
Three Months Ended June 30, 2008	$	666
Nine Months Ended June 30, 2009	$	1,547
Nine Months Ended June 30, 2008	$	1,997
Three Months Ended December 31, 2009										$	449
Three Months Ended December 31, 2008										$	554


	Retirement Plan						Other Post-Retirement Benefits
	2009			2008			2009			2008

Service Cost	$	2,728		$	3,149		$	950		$	1,276
Interest Cost		11,709			11,237			6,875			6,770
Expected Return on Plan Assets		(14,489	)		(13,750	)		(7,904	)		(8,428	)
Amortization of Prior Service Cost		183			202			(268	)		1
Amortization of Transition Amount		—			—			566			1,782
Amortization of Losses		1,419			2,766			2,318			732
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾		2,255			783			3,878			4,354


Net Periodic Benefit Cost	$	3,805		$	4,387		$	6,415		$	6,487


⁽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.


							Percent Colder											Percent
							(Warmer) Than
	Normal		2009		2008		Normal			Prior Year
Three Months Ended June 30
Three Months Ended																		Colder (Warmer) Than
December 31												Normal		2009		2008		Normal			Prior Year
Buffalo		927		854		817		(7.9	)		4.5		2,260		2,246		2,313		(0.6	)		(2.9	)
Erie		885		821		762		(7.2	)		7.7		2,081		2,048		2,067		(1.6	)		(0.9	)
Nine Months Ended June 30
Buffalo		6,514		6,558		6,175		0.7			6.2
Erie		6,108		6,064		5,737		(0.7	)		5.7


⁽¹⁾		Represents the elimination of certain West Coast gas production revenue included in “Gas (after Hedging)” in the table above that was sold to the gas processing plant shown in the table above. An elimination for the same dollar amount was made to reduce the gas processing plant’s Purchased Gas expense.


Nine Months Ended June 30,							Increase
(Millions)	2009			2008			(Decrease)

Utility	$	40.4		$	38.8		$	1.6
Pipeline and Storage		34.8	⁽¹⁾		106.2	⁽⁵⁾		(71.4	)
Exploration and Production		151.7	⁽²⁾		140.6			11.1
All Other		3.9	⁽³⁾		1.4			2.5
Eliminations		(0.3	)⁽⁴⁾		(2.4	)⁽⁶⁾		2.1

	$	230.5		$	284.6		$	(54.1	)


					Total Number of		Maximum Number of
					Shares Purchased as		Shares that May Yet
					Part of Publicly		Be Purchased Under
	Total Number of				Announced Share		Share Repurchase
	Shares		Average Price		Repurchase Plans or		Plans or
Period	Purchased^(a)		Paid per Share		Programs		Programs^(b)
Apr. 1 - 30, 2009		11,818	$	31.05		—		6,971,019
May 1 - 31, 2009		12,103	$	31.02		—		6,971,019
June 1 - 30, 2009		14,508	$	35.24		—		6,971,019

Total		38,429	$	32.62		—		6,971,019


	NATIONAL FUEL GAS COMPANY (Registrant)
	/s/ R. J. Tanski
	R. J. Tanski
	Treasurer and Principal Financial Officer


	/s/ K. M. Camiolo
	K. M. Camiolo
	Controller and Principal Accounting Officer

Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.

Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

National Fuel Gas Company Consolidated ~~Statements~~Statement of Income for the Twelve Months Ended ~~June 30,~~December 31, 2009 and 2008.