National Fuel Gas (NFG) 10-Q 2008 Q3 Quarterly report

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, 2008

OR

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 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 filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

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 31, 2008: 81,475,950 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 State Pipeline
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.
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
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
NTSB	National Transportation Safety Board
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
2007 Form 10-K	The Company’s Annual Report on Form 10-K for the year ended September 30, 2007
ARB 51	Accounting Research Bulletin No. 51, Consolidated Financial Statements
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.
Cashout revenues	A cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper.
Degree day	A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative	A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.
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.

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GLOSSARY OF TERMS (Cont.)
Exchange Act	Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets	Includes capital expenditures, stock acquisitions and/or investments in partnerships.
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 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.
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)
MMcf	Million cubic feet (of 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.
PRP	Potentially responsible party
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 utility 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.
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

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GLOSSARY OF TERMS (Concl.)
SFAS 115	Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities
SFAS 123R	Statement of Financial Accounting Standards No. 123R, Share-Based Payment
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 159	Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of SFAS 115
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
Stock acquisitions	Investments in corporations.
Unbundled service	A service that has been separated from other services, with rates charged that reflect only the cost of the separated service.
VEBA	Voluntary Employees’ Beneficiary Association
WNC	Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.

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INDEX

	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, 2008 and 2007	6 - 7
b. Consolidated Balance Sheets — June 30, 2008 and September 30, 2007	8 - 9
c. Consolidated Statement of Cash Flows — Nine Months Ended June 30, 2008 and 2007	10
d. Consolidated Statement of Comprehensive Income — Three and Nine Months Ended June 30, 2008 and 2007	11
e. Notes to Consolidated Financial Statements	12 - 22
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23 - 44
Item 3. Quantitative and Qualitative Disclosures About Market Risk	44
Item 4. Controls and Procedures	44 - 45
Part II. Other Information
Item 1. Legal Proceedings	45
Item 1 A. Risk Factors	45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	45 - 46
Item 3. Defaults Upon Senior Securities	§
Item 4. Submission of Matters to a Vote of Security Holders	§
Item 5. Other Information	§
Item 6. Exhibits	46 - 47
Signatures	48
EX-4.1
EX-12
EX-31.1
EX-31.2
EX-32
EX-99

§ The Company has nothing to report under this item.

     Reference to the “Company” in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.

     This Form 10-Q contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2 — MD&A, under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, statements regarding future prospects, plans, performance and 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.

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Part I. Financial Information

Item 1.Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)

	Three Months Ended
	June 30,
(Thousands of Dollars, Except Per Common Share Amounts)	2008			2007
INCOME
Operating Revenues	$	548,382		$	448,779
Operating Expenses
Purchased Gas		272,893			219,075
Operation and Maintenance		102,602			90,390
Property, Franchise and Other Taxes		19,135			17,622
Depreciation, Depletion and Amortization		42,804			37,759
		437,434			364,846
Operating Income		110,948			83,933
Other Income (Expense):
Income from Unconsolidated Subsidiaries		1,561			926
Interest Income		3,086			1,377
Other Income		1,649			787
Interest Expense on Long-Term Debt		(19,468	)		(18,226	)
Other Interest Expense		(1,199	)		(1,512	)
Income from Continuing Operations Before Income Taxes		96,577			67,285
Income Tax Expense		36,722			26,073
Income from Continuing Operations		59,855			41,212
Income from Discontinued Operations, Net of Tax		—			5,586
Net Income Available for Common Stock		59,855			46,798
EARNINGS REINVESTED IN THE BUSINESS
Balance at April 1		1,008,084			834,902
		1,067,939			881,700
Share Repurchases		(17,083	)		—
Dividends on Common Stock (2008 - $0.325 per share; 2007 - $0.31 per share)		(26,479	)		(25,897	)
Balance at June 30	$	1,024,377		$	855,803
Earnings Per Common Share:
Basic:
Income from Continuing Operations	$	0.74		$	0.49
Income from Discontinued Operations		—			0.07
Net Income Available for Common Stock	$	0.74		$	0.56
Diluted:
Income from Continuing Operations	$	0.72		$	0.48
Income from Discontinued Operations		—			0.07
Net Income Available for Common Stock	$	0.72		$	0.55
Weighted Average Common Shares Outstanding:
Used in Basic Calculation		81,342,788			83,483,718
Used in Diluted Calculation		83,712,193			85,668,055

See Notes to Condensed Consolidated Financial Statements

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Item 1.Financial Statements (Cont.)

National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)

	Nine Months Ended
	June 30,
(Thousands of Dollars, Except Per Common Share Amounts)	2008			2007
INCOME
Operating Revenues	$	2,002,503		$	1,737,537
Operating Expenses
Purchased Gas		1,082,340			938,918
Operation and Maintenance		325,642			305,502
Property, Franchise and Other Taxes		58,206			54,562
Depreciation, Depletion and Amortization		129,337			115,561
		1,595,525			1,414,543
Operating Income		406,978			322,994
Other Income (Expense):
Income from Unconsolidated Subsidiaries		4,866			3,099
Interest Income		8,356			3,098
Other Income		4,982			4,028
Interest Expense on Long-Term Debt		(52,045	)		(52,158	)
Other Interest Expense		(4,209	)		(4,877	)
Income from Continuing Operations Before Income Taxes		368,928			276,184
Income Tax Expense		143,465			108,804
Income from Continuing Operations		225,463			167,380
Income from Discontinued Operations, Net of Tax		—			12,385
Net Income Available for Common Stock		225,463			179,765
EARNINGS REINVESTED IN THE BUSINESS
Balance at October 1		983,776			786,013
		1,209,239			965,778
Share Repurchases		(106,647	)		(34,351	)
Cumulative Effect of the Adoption of FIN 48		(406	)		—
Dividends on Common Stock (2008 - $0.945 per share; 2007 - $0.91 per share)		(77,809	)		(75,624	)
Balance at June 30	$	1,024,377		$	855,803
Earnings Per Common Share:
Basic:
Income from Continuing Operations	$	2.72		$	2.02
Income from Discontinued Operations		—			0.15
Net Income Available for Common Stock	$	2.72		$	2.17
Diluted:
Income from Continuing Operations	$	2.65		$	1.96
Income from Discontinued Operations		—			0.15
Net Income Available for Common Stock	$	2.65		$	2.11
Weighted Average Common Shares Outstanding:
Used in Basic Calculation		82,789,748			83,018,583
Used in Diluted Calculation		85,000,381			85,192,777

See Notes to Condensed Consolidated Financial Statements

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Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Balance Sheets
(Unaudited)

	June 30,		September 30,
(Thousands of Dollars)	2008		2007
ASSETS
Property, Plant and Equipment	$	4,730,708	$	4,461,586
Less — Accumulated Depreciation, Depletion and Amortization		1,686,616		1,583,181
		3,044,092		2,878,405
Current Assets
Cash and Temporary Cash Investments		259,198		124,806
Cash Held in Escrow		—		61,964
Hedging Collateral Deposits		30,778		4,066
Receivables — Net of Allowance for Uncollectible Accounts of $35,588 and $28,654, Respectively		302,522		172,380
Unbilled Utility Revenue		19,580		20,682
Gas Stored Underground		53,735		66,195
Materials and Supplies — at average cost		33,310		35,669
Unrecovered Purchased Gas Costs		5,680		14,769
Other Current Assets		31,767		45,057
Deferred Income Taxes		84,297		8,550
		820,867		554,138
Other Assets
Recoverable Future Taxes		83,453		83,954
Unamortized Debt Expense		14,501		12,070
Other Regulatory Assets		129,640		137,577
Deferred Charges		5,235		5,545
Other Investments		82,474		85,902
Investments in Unconsolidated Subsidiaries		16,916		18,256
Goodwill		5,476		5,476
Intangible Assets		26,839		28,836
Prepaid Pension and Post-Retirement Benefit Costs		56,926		61,006
Fair Value of Derivative Financial Instruments		—		9,188
Other		7,442		8,059
		428,902		455,869
Total Assets	$	4,293,861	$	3,888,412

See Notes to Condensed Consolidated Financial Statements

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Item 1.Financial Statements (Cont.)

National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)

	June 30,			September 30,
(Thousands of Dollars)	2008			2007
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding – 81,473,550 Shares and 83,461,308 Shares, Respectively	$	81,474		$	83,461
Paid in Capital		583,693			569,085
Earnings Reinvested in the Business		1,024,377			983,776
Total Common Shareholder Equity Before Items of Other Comprehensive Loss		1,689,544			1,636,322
Accumulated Other Comprehensive Loss		(105,872	)		(6,203	)
Total Comprehensive Shareholders’ Equity		1,583,672			1,630,119
Long-Term Debt, Net of Current Portion		999,000			799,000
Total Capitalization		2,582,672			2,429,119
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		—			—
Current Portion of Long-Term Debt		100,000			200,024
Accounts Payable		162,838			109,757
Amounts Payable to Customers		12,864			10,409
Dividends Payable		26,479			25,873
Interest Payable on Long-Term Debt		15,774			18,158
Customer Advances		—			22,863
Other Accruals and Current Liabilities		136,458			36,062
Fair Value of Derivative Financial Instruments		180,255			16,200
		634,668			439,346
Deferred Credits
Deferred Income Taxes		605,818			575,356
Taxes Refundable to Customers		14,037			14,026
Unamortized Investment Tax Credit		4,866			5,392
Cost of Removal Regulatory Liability		101,251			91,226
Other Regulatory Liabilities		95,846			76,659
Post-Retirement Liabilities		60,152			70,555
Asset Retirement Obligations		74,653			75,939
Other Deferred Credits		119,898			110,794
		1,076,521			1,019,947
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	4,293,861		$	3,888,412

See Notes to Condensed Consolidated Financial Statements

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Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Statement of Cash Flows
(Unaudited)

	Nine Months Ended
	June 30,
(Thousands of Dollars)	2008			2007
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	225,463		$	179,765
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		129,337			125,986
Deferred Income Taxes		27,603			27,107
Income from Unconsolidated Subsidiaries, Net of Cash Distributions		1,340			(1,486	)
Excess Tax Benefits Associated with Stock-Based Compensation Awards		(16,275	)		(13,689	)
Other		(1,120	)		4,722
Change in:
Hedging Collateral Deposits		(26,712	)		16,276
Receivables and Unbilled Utility Revenue		(129,102	)		(43,733	)
Gas Stored Underground and Materials and Supplies		14,819			34,725
Unrecovered Purchased Gas Costs		9,089			12,970
Prepayments and Other Current Assets		17,370			30,685
Accounts Payable		53,081			(12,560	)
Amounts Payable to Customers		2,455			(4,738	)
Customer Advances		(22,863	)		(29,417	)
Other Accruals and Current Liabilities		94,031			77,842
Other Assets		19,178			918
Other Liabilities		17,373			(821	)
Net Cash Provided by Operating Activities		415,067			404,552
INVESTING ACTIVITIES
Capital Expenditures		(264,728	)		(206,509	)
Investment in Partnership		—			(3,300	)
Cash Held in Escrow		58,397			—
Net Proceeds from Sale of Oil and Gas Producing Properties		5,675			5,137
Other		(3,414	)		(1,072	)
Net Cash Used in Investing Activities		(204,070	)		(205,744	)
FINANCING ACTIVITIES
Excess Tax Benefits Associated with Stock-Based Compensation Awards		16,275			13,689
Shares Repurchased under Repurchase Plan		(129,592	)		(43,344	)
Net Proceeds from Issuance of Long-Term Debt		296,655			—
Reduction of Long-Term Debt		(200,024	)		(119,550	)
Dividends Paid on Common Stock		(77,204	)		(74,748	)
Net Proceeds from Issuance of Common Stock		17,285			16,819
Net Cash Used in Financing Activities		(76,605	)		(207,134	)
Effect of Exchange Rates on Cash		—			1,245
Net Increase (Decrease) in Cash and Temporary Cash Investments		134,392			(7,081	)
Cash and Temporary Cash Investments at October 1		124,806			69,611
Cash and Temporary Cash Investments at June 30	$	259,198		$	62,530

See Notes to Condensed Consolidated Financial Statements

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Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Statements of Comprehensive Income
(Unaudited)

	Three Months Ended
	June 30,
(Thousands of Dollars)	2008			2007
Net Income Available for Common Stock	$	59,855		$	46,798
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment		2			10,029
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period		(1,603	)		1,570
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		(139,684	)		13,343
Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income		33,082			5,581
Other Comprehensive Income (Loss), Before Tax		(108,203	)		30,523
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) On Securities Available for Sale Arising During the Period		(608	)		562
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) On Derivative Financial Instruments Arising During the Period		(57,136	)		5,433
Reclassification Adjustment for Income Tax Benefit on Realized Losses on Derivative Financial Instruments In Net Income		13,546			2,277
Income Taxes – Net		(44,198	)		8,272
Other Comprehensive Income (Loss)		(64,005	)		22,251
Comprehensive Income (Loss)	$	(4,150	)	$	69,049

	Nine Months Ended
	June 30,
(Thousands of Dollars)	2008			2007
Net Income Available for Common Stock	$	225,463		$	179,765
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment		(72	)		6,384
Minimum Pension Liability Adjustment		—			(320	)
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period		(4,817	)		2,844
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		(208,256	)		2,388
Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income		45,242			7,799
Other Comprehensive Income (Loss), Before Tax		(167,903	)		19,095
Income Tax Expense (Benefit) Related to Minimum Pension Liability Adjustment		—			(121	)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) On Securities Available for Sale Arising During the Period		(1,429	)		1,046
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) On Derivative Financial Instruments Arising During the Period		(85,300	)		669
Reclassification Adjustment for Income Tax Benefit on Realized Losses on Derivative Financial Instruments In Net Income		18,495			3,933
Income Taxes – Net		(68,234	)		5,527
Other Comprehensive Income (Loss)		(99,669	)		13,568
Comprehensive Income	$	125,794		$	193,333

See Notes to Condensed Consolidated Financial Statements

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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, 2007, 2006 and 2005 that are included in the Company’s 2007 Form 10-K. The consolidated financial statements for the year ended September 30, 2008 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.

     The earnings for the nine months ended June 30, 2008 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2008. 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 6 – Business Segment Information.

Consolidated Statement of Cash Flows.For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents. At June 30, 2008, the Company accrued $19.9 million of capital expenditures related to the construction of 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.

Hedging Collateral Deposits.Cash held in margin accounts serves as collateral for open positions on exchange-traded futures contracts, exchange-traded options and over-the-counter swaps and collars.

Cash Held in Escrow.On August 31, 2007, the Company received approximately $232.1 million of proceeds 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 impact of the foreign currency hedge.

-12-

Item 1.Financial Statements (Cont.)

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 $77.9 million at June 30, 2008, is reduced to zero by September 30 of each year as the inventory is replenished.

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

	At June 30, 2008			At September 30, 2007
Funded Position of the Pension and Other Post-Retirement Benefit Plans Adjustment	$	(12,482	)	$	(12,482	)
Cumulative Foreign Currency Translation Adjustment		(155	)		(83	)
Net Unrealized Loss on Derivative Financial Instruments		(100,095	)		(3,886	)
Net Unrealized Gain on Securities Available for Sale		6,860			10,248
Accumulated Other Comprehensive Loss	$	(105,872	)	$	(6,203	)

Earnings Per Common Share.Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the 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 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 the quarter and nine months ended June 30, 2008, there were no stock options excluded as being antidilutive. There were 6,593 and 2,190 stock-settled SARs excluded as being antidilutive for the quarter and nine months ended June 30, 2008, respectively. For the quarter and nine months ended June 30, 2007, there were no stock options excluded as being antidilutive. There were 1,817 and 271 stock-settled SARs excluded as being antidilutive for the quarter and nine months ended June 30, 2007, respectively.

Share Repurchases.The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is settled as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note 3 – Capitalization for further discussion of the share repurchase program.

Stock-Based Compensation.For the quarter ended June 30, 2008, the Company granted 30,000 performance-based stock-settled SARs having a weighted average exercise price of $58.99 per share. For the nine months ended June 30, 2008, the Company granted 321,000 performance-based stock-settled SARs having a weighted average exercise price of $48.46 per share. The weighted average grant date fair value of these stock-settled SARs was $12.23 per share and $9.06 per share for the quarter and nine months ended June 30, 2008, respectively. The accounting treatment for such stock-settled SARs is the same under SFAS 123R as the accounting for stock options under SFAS 123R. The stock-settled SARs granted for the quarter and nine months ended June 30, 2008 vest and become exercisable annually in one-third increments, provided that a performance condition for diluted earnings per share is met for the prior fiscal year. The weighted average grant date fair value of these stock-settled SARs

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Item 1.Financial Statements (Cont.)

granted during the quarter and nine months ended June 30, 2008 was estimated on the date of grant using the same accounting treatment that is applied for stock options under SFAS 123R, and assumes that the performance conditions specified will be achieved. If such conditions are not met, no compensation expense is recognized and any recognized compensation expense is reversed.

     There were no stock options granted during the quarter and nine months ended June 30, 2008. The Company granted 25,000 restricted share awards (non-vested stock as defined in SFAS 123R) during the nine months ended June 30, 2008. The weighted average fair value of such restricted shares was $48.41 per share. There were no restricted share awards granted during the quarter ended June 30, 2008.

New Accounting Pronouncements.In September 2006, the FASB issued SFAS 157, “Fair Value Measurements”. SFAS 157 provides guidance for using fair value to measure assets and liabilities. The pronouncement 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 is to be applied whenever another standard requires or allows assets or liabilities to be measured at fair value. In accordance with FASB Staff Position FAS No. 157-2, SFAS 157 is effective for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009. The same FASB Staff Position delays the effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value on a recurring basis, until the Company’s first quarter of fiscal 2010. The Company is currently evaluating the impact that the adoption of SFAS 157 will have on its consolidated financial statements.

     In September 2006, the FASB also issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” (an amendment 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 status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 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 adopted by the Company by the end of fiscal 2009. Currently, the Company measures its plan assets and benefit obligations using a June 30th measurement date.

     In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of SFAS 115.” SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not otherwise required to be measured at fair value under GAAP. A company that elects the fair value option for an eligible item will be required to recognize in current earnings any changes in that item’s fair value in reporting periods subsequent to the date of adoption. SFAS 159 is effective as of the Company’s first quarter of fiscal 2009. The Company is currently evaluating the impact, if any, that the adoption of SFAS 159 will have on its consolidated financial statements.

     In December 2007, the FASB issued SFAS 141R, “Business Combinations.” SFAS 141R will significantly change 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, 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 effective as of the Company’s first quarter of fiscal 2010.

     In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB 51.” SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests (NCI) and classified as a

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Item 1.Financial Statements (Cont.)

component of equity. This new consolidation method will significantly change the accounting for transactions with minority interest holders. SFAS 160 is effective as of the Company’s first quarter of fiscal 2010. The Company currently does not have any NCI.

     In March 2008, 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. SFAS 161 is effective as of the Company’s second quarter of fiscal 2009. The Company is currently evaluating the impact that the adoption of SFAS 161 will have on its disclosures in its notes to its consolidated financial statements.

Note 2 — Income Taxes

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

	Nine Months Ended
	June 30,
	2008			2007
Operating Expenses:
Current Income Taxes
Federal	$	92,384		$	65,629
State		23,388			19,259
Foreign		90			22
Deferred Income Taxes
Federal		18,906			18,221
State		8,697			5,270
Foreign		—			3,616
		143,465			112,017
Deferred Investment Tax Credit		(523	)		(523	)
Total Income Taxes	$	142,942		$	111,494
Presented as Follows:
Other Income	$	(523	)	$	(523	)
Income Tax Expense – Continuing Operations		143,465			108,804
Income from Discontinued Operations		—			3,213
Total Income Taxes	$	142,942		$	111,494

     The U.S. and foreign components of income before income taxes are as follows (in thousands):

	Nine Months Ended
	June 30,
	2008		2007
U.S.	$	368,191	$	275,196
Foreign		214		16,063
	$	368,405	$	291,259

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Item 1.Financial Statements (Cont.)

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

	Nine Months Ended
	June 30,
	2008			2007
Income Tax Expense, Computed at Statutory Rate of 35%	$	128,942		$	101,941
Increase (Reduction) in Taxes Resulting From:
State Income Taxes		20,855			15,944
Miscellaneous		(6,855	)		(6,391	)
Total Income Taxes	$	142,942		$	111,494

     Significant components of the Company’s deferred tax liabilities and assets are as follows (in thousands):

	At June 30, 2008			At September 30, 2007
Deferred Tax Liabilities:
Property, Plant and Equipment	$	669,079		$	612,648
Other		38,451			61,616
Total Deferred Tax Liabilities		707,530			674,264
Deferred Tax Assets:
Fair Value of Derivative Instruments and Securities		(65,192	)		—
Other		(120,817	)		(107,458	)
Total Deferred Tax Assets		(186,009	)		(107,458	)
Total Net Deferred Income Taxes	$	521,521		$	566,806
Presented as Follows:
Net Deferred Tax Asset – Current	$	(84,297	)	$	(8,550	)
Net Deferred Tax Liability – Non-Current		605,818			575,356
Total Net Deferred Income Taxes	$	521,521		$	566,806

     Regulatory liabilities representing the reduction of previously recorded deferred income taxes with rate-regulated activities that are expected to be refundable to customers amounted to $14.0 million at both June 30, 2008 and September 30, 2007. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $83.5 million and $84.0 million at June 30, 2008 and September 30, 2007, respectively.

     The Company adopted FIN 48 on October 1, 2007. As of the date of adoption, a cumulative effect adjustment was recorded that resulted in a decrease to retained earnings of $0.4 million. Upon adoption, the unrecognized tax benefits were $1.7 million, all of which would impact the effective tax rate (net of federal benefit) if recognized. There has been no change in the balance of unrecognized tax benefits through June 30, 2008 and the Company does not anticipate any significant change in this liability over the next twelve months.

     The Company recognizes estimated interest payable relating to income taxes in Other Interest Expense and estimated penalties relating to income taxes in Other Income. The Company has accrued interest of $0.5 million through June 30, 2008 and has not accrued any penalties.

-16-

Item 1.Financial Statements (Cont.)

     The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 2008 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. The IRS has issued a Full Acceptance Letter for the fiscal 2007 CAP audit, and is in the process of completing the post-filing review of this return. While the federal statute of limitations remains open for fiscal 2005 and later years, IRS examinations for years prior to fiscal 2007 have been completed and the Company believes such years are effectively settled.

     For the major states in which the various subsidiary companies operate, the earliest tax year open for examination is as follows:

New York	Fiscal 2002
Pennsylvania	Fiscal 2003
California	Fiscal 2003
Texas	Fiscal 2003

Note 3 — Capitalization

Common Stock.During the nine months ended June 30, 2008, the Company issued 884,644 original issue shares of common stock as a result of stock option exercises and 25,000 original issue shares for restricted stock awards (non-vested stock as defined in SFAS 123R). The Company also issued 7,200 original issue shares of common stock to the eight non-employee directors of the Company who receive compensation under the Company’s Retainer Policy for Non-Employee Directors, as partial consideration for the directors’ services during the nine months ended June 30, 2008. Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the nine months ended June 30, 2008, 72,205 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.

     On December 8, 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. During the nine months ended June 30, 2008, the Company repurchased 2,832,397 shares for $129.6 million under this program, funded with cash provided by operating activities. Since the repurchase program was implemented, the Company has repurchased 6,667,275 shares for $262.8 million.

Shareholder Rights Plan.On February 21, 2008, the Board of Directors of the Company approved amendments to the Company’s Amended and Restated Rights Agreement (the “Rights Agreement”). The amendments modify the rights of holders of the Company’s Common Stock Purchase Rights (the “Rights”). The principal amendments are an extension of the expiration date of the Rights Agreement from July 31, 2008 to July 31, 2018 and an increase in the exercise price of the Rights from $65 to $150 per full share. The Board also approved amendments to the Rights Agreement (i) to provide that the phrase “then outstanding,” when used with reference to a person’s beneficial ownership of securities of the Company, means the number of securities then issued and outstanding together with the number of such securities not then actually issued and outstanding which such person would be deemed to own beneficially under the Rights Agreement, including, among other things, certain derivative or synthetic arrangements having characteristics of a long position in the Company’s common stock, (ii) to eliminate certain restrictive covenants that would have applied to the Company after the distribution date of the Rights, and (iii) to clarify and update the Rights Agreement in various respects. The Company, on July 11, 2008, entered into an amended and restated Rights Agreement, reflecting the changes described in this paragraph, with the Bank of New York, as Rights Agent, and on July 15, 2008, filed with the SEC copies of that agreement as exhibits to Forms 8-A and Form 8-K.

-17-

Item 1.Financial Statements (Cont.)

Long-Term Debt.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. 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 in the event of a change in control at a price equal to 101% of the principal amount. In addition, the Company is required to either offer to exchange the notes for substantially similar notes as are registered under the Securities Act of 1933 or, in certain circumstances, register the resale of the notes. The Company used $200.0 million of the proceeds to refund $200.0 million of 6.303% medium-term notes that subsequently matured on May 27, 2008.

Note 4 — 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 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 2007 Form 10-K, the Company received, in 1998 and again in October 1999, notice that the NYDEC believes the Company is responsible for contamination discovered at a former manufactured gas plant site located in New York for which the Company had not been named as a PRP. In February 2007, the NYDEC identified the Company as a PRP for the site and issued a proposed remedial action plan. The NYDEC estimated clean-up costs under its proposed remedy to be $8.9 million if implemented. Although the Company commented to the NYDEC that the proposed remedial action plan contained a number of material errors, omissions and procedural defects, the NYDEC, in a March 2007 Record of Decision, selected the remedy it had previously proposed. In July 2007, the Company appealed the NYDEC’s Record of Decision to the New York State Supreme Court, Albany County. The Court dismissed the appeal in January 2008. The Company filed a notice of appeal in February 2008. In July 2008, the Company withdrew its appeal and agreed to the terms of an Order on Consent issued by the NYDEC. Pursuant to the order, the Company will remediate the site consistent with the remedy selected in the NYDEC’s Record of Decision. The Company will also reimburse the NYDEC in the amount of approximately $1.5 million for costs incurred in connection with the site from 1998 through May 30, 2007. The Company acknowledged that additional charges related to the site will be billed to the Company at a later date, including costs incurred by the NYDEC after May 30, 2007 and any costs incurred by the New York Department of Health. The Company has not received any estimates of such additional costs. The Company has recorded an estimated minimum liability of $10.4 million associated with this site.

     At June 30, 2008, 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 $13.5 million to $17.2 million. The minimum estimated liability of $13.5 million has been recorded on the Consolidated Balance Sheet at June 30, 2008, including the $10.4 million discussed above. 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 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

-18-

Item 1.Financial Statements (Cont.)

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

Note 5 — Discontinued Operations

     On August 31, 2007, the Company, in its Exploration and Production segment, completed the sale of SECI, Seneca’s wholly owned subsidiary that operated in Canada. The Company received approximately $232.1 million of proceeds from the sale, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. The sale resulted in the recognition of a gain of approximately $120.3 million, net of tax, during the fourth quarter of 2007. SECI is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in the provinces of Alberta, Saskatchewan and British Columbia in Canada. The decision to sell was based on lower than expected returns from the Canadian oil and gas properties combined with difficulty in finding significant new reserves. Seneca will continue its exploration and development activities in Appalachia, the Gulf of Mexico, and California. As a result of the decision to sell SECI, the Company began presenting all SECI operations as discontinued operations during the fourth quarter of 2007.

     The following is selected financial information of the discontinued operations for SECI:

	Three Months			Nine Months
	Ended			Ended
	June 30,			June 30,
(Thousands)	2007			2007
Operating Revenues	$	14,366		$	42,004
Operating Expenses		9,915			27,205
Operating Income		4,451			14,799
Interest Income		272			799
Income before Income Taxes		4,723			15,598
Income Tax Expense (Benefit)		(863	)		3,213
Income from Discontinued Operations	$	5,586		$	12,385

Note 6 — Business Segment Information

     The Company has five reportable segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing, and Timber. The division of the Company’s operations into the reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.

     The data presented in the tables below reflect the reportable segments and reconciliations to consolidated amounts. As stated in the 2007 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (where applicable). When these items are not applicable, the Company evaluates performance based on net income. There have been no changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2007 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the 2007 Form 10-K.

-19-

Item 1.Financial Statements (Cont.)

			Pipeline		Exploration							Total				Corporate and
			and		and		Energy					Reportable				Intersegment			Total
Quarter Ended June 30, 2008 (Thousands)	Utility		Storage		Production		Marketing		Timber			Segments		All Other		Eliminations			Consolidated
Revenue from External Customers	$	217,339	$	32,054	$	126,154	$	162,129	$	10,114		$	547,790	$	395	$	197		$	548,382
Intersegment Revenues	$	3,154	$	20,131	$	—	$	—	$	—		$	23,285	$	4,439	$	(27,724	)	$	—
Segment Profit (Loss):
Net Income (Loss)	$	7,848	$	12,534	$	39,791	$	478	$	(2,066	)	$	58,585	$	1,106	$	164		$	59,855

			Pipeline		Exploration						Total				Corporate and
			and		and		Energy				Reportable				Intersegment			Total
Nine Months Ended June 30, 2008 (Thousands)	Utility		Storage		Production		Marketing		Timber		Segments		All Other		Eliminations			Consolidated
Revenue from External Customers	$	1,067,194	$	101,871	$	348,829	$	440,111	$	40,438	$	1,998,443	$	3,564	$	496		$	2,002,503
Intersegment Revenues	$	13,567	$	61,340	$	—	$	—	$	—	$	74,907	$	10,251	$	(85,158	)	$	—
Segment Profit (Loss):
Net Income (Loss)	$	62,228	$	40,931	$	108,385	$	7,079	$	2,214	$	220,837	$	5,137	$	(511	)	$	225,463

			Pipeline		Exploration							Total				Corporate and
			and		and		Energy					Reportable				Intersegment			Total
Quarter Ended June 30, 2007 (Thousands)	Utility		Storage		Production		Marketing		Timber			Segments		All Other		Eliminations			Consolidated
Revenue from External Customers	$	210,604	$	30,128	$	80,028	$	113,380	$	13,131		$	447,271	$	1,308	$	200		$	448,779
Intersegment Revenues	$	2,586	$	20,332	$	—	$	—	$	—		$	22,918	$	2,253	$	(25,171	)	$	—
Segment Profit (Loss):
Income (Loss) from Continuing Operations	$	3,705	$	15,451	$	18,849	$	1,233	$	(364	)	$	38,874	$	458	$	1,880		$	41,212

			Pipeline		Exploration						Total				Corporate and
			and		and		Energy				Reportable				Intersegment			Total
Nine Months Ended June 30, 2007 (Thousands)	Utility		Storage		Production		Marketing		Timber		Segments		All Other		Eliminations			Consolidated
Revenue from External Customers	$	1,000,860	$	94,889	$	233,708	$	360,036	$	43,079	$	1,732,572	$	4,387	$	578		$	1,737,537
Intersegment Revenues	$	12,556	$	61,585	$	—	$	—	$	—	$	74,141	$	6,540	$	(80,681	)	$	—
Segment Profit:
Income from Continuing Operations	$	54,322	$	43,075	$	52,573	$	8,431	$	3,053	$	161,454	$	1,911	$	4,015		$	167,380

-20-

Item 1.Financial Statements (Cont.)

Note 7 — Intangible Assets

     The components of the Company’s intangible assets were as follows (in thousands):

								At September 30,
	At June 30, 2008							2007
	Gross					Net		Net
	Carrying		Accumulated			Carrying		Carrying
	Amount		Amortization			Amount		Amount
Intangible Assets Subject to Amortization:
Long-Term Transportation Contracts	$	8,580	$	(5,791	)	$	2,789	$	3,591
Long-Term Gas Purchase Contracts		31,864		(7,814	)		24,050		25,245
	$	40,444	$	(13,605	)	$	26,839	$	28,836
Aggregate Amortization Expense:
(Thousands)
Three Months Ended June 30, 2008	$	666
Three Months Ended June 30, 2007	$	666
Nine Months Ended June 30, 2008	$	1,997
Nine Months Ended June 30, 2007	$	1,997

     The gross carrying amount of intangible assets subject to amortization at June 30, 2008 remained unchanged from September 30, 2007. The only activity with regard to intangible assets subject to amortization was amortization expense as shown in the table above. Amortization expense for the long-term transportation contracts is estimated to be $0.3 million for the remainder of 2008 and $0.5 million for fiscal 2009. Amortization expense for transportation contracts is estimated to be $0.4 million annually for 2010, 2011 and 2012. Amortization expense for the long-term gas purchase contracts is estimated to be $0.4 million for the remainder of 2008 and $1.6 million annually for 2009, 2010, 2011 and 2012.

Note 8 — Retirement Plan and Other Post-Retirement Benefits

     Components of Net Periodic Benefit Cost (in thousands):

	Retirement Plan						Other Post-Retirement Benefits
Three months ended June 30,	2008			2007			2008			2007
Service Cost	$	3,149		$	3,225		$	1,276		$	1,403
Interest Cost		11,237			11,087			6,770			6,800
Expected Return on Plan Assets		(13,750	)		(12,809	)		(8,428	)		(6,740	)
Amortization of Prior Service Cost		202			220			1			1
Amortization of Transition Amount		—			—			1,782			1,782
Amortization of Losses		2,766			3,382			732			2,053
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)(1)		783			(344	)		4,354			3,382
Net Periodic Benefit Cost	$	4,387		$	4,761		$	6,487		$	8,681

-21-

Item 1.Financial Statements (Cont.)

	Retirement Plan						Other Post-Retirement Benefits
Nine months ended June 30,	2008			2007			2008			2007
Service Cost	$	9,448		$	9,674		$	3,828		$	4,210
Interest Cost		33,712			33,263			20,311			20,399
Expected Return on Plan Assets		(41,250	)		(38,427	)		(25,286	)		(20,220	)
Amortization of Prior Service Cost		606			661			3			3
Amortization of Transition Amount		—			—			5,346			5,345
Amortization of Losses		8,298			10,146			2,195			6,160
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)(1)		7,597			3,885			20,028			16,453
Net Periodic Benefit Cost	$	18,411		$	19,202		$	26,425		$	32,350

⁽¹⁾ The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.

Employer Contributions.During the nine months ended June 30, 2008, the Company contributed $3.8 million to its retirement plan and $25.3 million to its VEBA trusts and 401(h) accounts in its other post-retirement benefit plan. In the remainder of 2008, the Company expects to contribute $12.2 million to its retirement plan and $3.8 million to its VEBA trusts and 401(h) accounts in its other post-retirement benefit plan.

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

OVERVIEW

     The Company is a diversified energy company and reports its operating results in five reportable business segments. For the quarter ended June 30, 2008 compared to the quarter ended June 30, 2007, the Company has experienced an increase in earnings of $13.1 million, primarily due to higher earnings in the Exploration and Production segment. The Utility segment and the All Other category also contributed to the increase in earnings. These earnings increases discussed above were slightly offset by lower earnings in the Pipeline and Storage and Energy Marketing segments as well as in the Corporate category, combined with a higher loss in the Timber segment. For the nine months ended June 30, 2008 compared to the nine months ended June 30, 2007, the Company experienced an increase in earnings of $45.7 million, due primarily to higher earnings in the Exploration and Production segment. The Utility segment and the All Other category also contributed to the increase in earnings. These earnings increases discussed above were slightly offset by lower earnings in the Pipeline and Storage, Energy Marketing, and Timber segments as well as in the Corporate category. The Company’s earnings are discussed further in the Results of Operations section that follows.

     From a capital resources and liquidity perspective, the Company spent $284.6 million on capital expenditures during the nine months ended June 30, 2008, with approximately 49% being spent in the Exploration and Production segment, 37% in the Pipeline and Storage segment and 14% in the Utility segment. The amounts spent in the various segments reflect the Company’s belief that the Exploration and Production segment and the Pipeline and Storage segment currently provide the best earnings growth opportunities for shareholders. In the Exploration and Production segment, the Company’s principal focus continues to be the development of its nearly one million acres in the Appalachian region along with continued exploration and development in the Gulf and West Coast regions. In the Pipeline and Storage segment, the majority of the expenditures were for construction costs of the Empire Connector project. The project is on schedule to be completed by the planned in-service date of November 2008, although the actual in-service date will depend upon the completion of the Millennium Pipeline. This project and other capital expenditures are discussed further in the Capital Resources and Liquidity section that follows.

     The Company regularly considers the repurchase of outstanding shares of common stock under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to repurchase up to an aggregate amount of 8 million shares. Through June 30, 2008, the Company had repurchased 6,667,275 shares for $262.8 million under this program, including 2,832,397 shares for $129.6 million during the nine months ended June 30, 2008. These matters are discussed further in the Capital Resources and Liquidity section that follows.

     The Company has begun to explore the sale of Horizon LFG, a New York corporation that owns and operates short-distance landfill gas pipeline companies that are engaged in the purchase, sale and transportation of landfill gas in Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Horizon LFG is included in the Company’s All Other category. The Company is also exploring the sale of Horizon Power’s unconsolidated subsidiaries. This includes ESNE, which generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania, as well as Seneca Energy and Model City, which generate and sell electricity using methane gas obtained from landfills owned by outside parties.

CRITICAL ACCOUNTING ESTIMATES

     For a complete discussion of critical accounting estimates, refer to “Critical Accounting Estimates” in Item 7 of the Company’s 2007 Form 10-K. There have been no subsequent changes to that disclosure.

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

RESULTS OF OPERATIONS

Earnings

     The Company’s earnings were $59.9 million for the quarter ended June 30, 2008 compared to earnings of $46.8 million for the quarter ended June 30, 2007. As previously discussed, the Company has presented its Canadian operations in the Exploration and Production segment (in conjunction with the sale of SECI) as discontinued operations. The Company’s earnings from continuing operations were $59.9 million for the quarter ended June 30, 2008 compared to earnings from continuing operations of $41.2 million for the quarter ended June 30, 2007. The increase in earnings from continuing operations of $18.7 million is primarily the result of higher earnings in the Exploration and Production segment. The Utility segment and the All Other category also contributed to the increase in earnings. These earnings increases discussed above were slightly offset by lower earnings in the Pipeline and Storage and Energy Marketing segments, as well as in the Corporate category, combined with a higher loss in the Timber segment.

     The Company’s earnings were $225.5 million for the nine months ended June 30, 2008 compared to earnings of $179.8 million for the nine months ended June 30, 2007. The Company’s earnings from continuing operations were $225.5 million for the nine months ended June 30, 2008 compared to earnings from continuing operations of $167.4 million for the nine months ended June 30, 2007. The increase in earnings from continuing operations of $58.1 million is primarily the result of higher earnings in the Exploration and Production segment. The Utility segment and the All Other category also contributed to the increase in earnings. These earnings increases discussed above were slightly offset by lower earnings in the Pipeline and Storage, Energy Marketing, and Timber segments as well as in the Corporate category.

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

Earnings (Loss) by Segment

	Three Months Ended									Nine Months Ended
	June 30,									June 30,
							Increase/								Increase/
(Thousands)	2008			2007			(Decrease)			2008			2007		(Decrease)
Utility	$	7,848		$	3,705		$	4,143		$	62,228		$	54,322	$	7,906
Pipeline and Storage		12,534			15,451			(2,917	)		40,931			43,075		(2,144	)
Exploration and Production		39,791			18,849			20,942			108,385			52,573		55,812
Energy Marketing		478			1,233			(755	)		7,079			8,431		(1,352	)
Timber		(2,066	)		(364	)		(1,702	)		2,214			3,053		(839	)
Total Reportable Segments		58,585			38,874			19,711			220,837			161,454		59,383
All Other		1,106			458			648			5,137			1,911		3,226
Corporate		164			1,880			(1,716	)		(511	)		4,015		(4,526	)
Total Earnings from Continuing Operations		59,855			41,212			18,643			225,463			167,380		58,083
Earnings from Discontinued Operations		—			5,586			(5,586	)		—			12,385		(12,385	)
Total Consolidated	$	59,855		$	46,798		$	13,057		$	225,463		$	179,765	$	45,698

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

Utility

Utility Operating Revenues

	Three Months Ended							Nine Months Ended
	June 30,							June 30,
					Increase/							Increase/
(Thousands)	2008		2007		(Decrease)			2008		2007		(Decrease)
Retail Sales Revenues:
Residential	$	153,058	$	158,922	$	(5,864	)	$	793,124	$	778,572	$	14,552
Commercial		20,459		24,380		(3,921	)		124,582		127,485		(2,903	)
Industrial		1,178		1,432		(254	)		6,754		7,081		(327	)
		174,695		184,734		(10,039	)		924,460		913,138		11,322
Transportation		21,584		21,017		567			97,345		86,358		10,987
Off-System Sales		20,540		3,727		16,813			48,606		3,727		44,879
Other		3,674		3,712		(38	)		10,350		10,193		157
	$	220,493	$	213,190	$	7,303		$	1,080,761	$	1,013,416	$	67,345

Utility Throughput

	Three Months Ended							Nine Months Ended
	June 30,							June 30,
					Increase/							Increase/
(MMcf)	2008		2007		(Decrease)			2008		2007		(Decrease)
Retail Sales:
Residential		8,618		10,679		(2,061	)		53,881		56,729		(2,848	)
Commercial		1,334		1,836		(502	)		9,197		10,132		(935	)
Industrial		77		113		(36	)		524		628		(104	)
		10,029		12,628		(2,599	)		63,602		67,489		(3,887	)
Transportation		12,086		12,981		(895	)		55,966		53,556		2,410
Off-System Sales		1,711		467		1,244			4,790		467		4,323
		23,826		26,076		(2,250	)		124,358		121,512		2,846

Degree Days

							Percent Colder
							(Warmer) Than
	Normal		2008		2007		Normal			Prior Year
Three Months Ended June 30
Buffalo		927		817		921		(11.9	)		(11.3	)
Erie		885		762		900		(13.9	)		(15.3	)
Nine Months Ended June 30
Buffalo		6,551		6,175		6,195		(5.7	)		(0.3	)
Erie		6,142		5,737		5,930		(6.6	)		(3.3	)

2008 Compared with 2007

     Operating revenues for the Utility segment increased $7.3 million for the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. The increase for the quarter is primarily attributable to a $16.8 million increase in off-system sales revenue (see discussion below) partially offset by a $10.0 million decrease in retail sales revenue. The $10.0 million decrease in retail gas sales revenues was a function of lower throughput volumes, partially offset by the recovery of higher gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues) coupled with the revenue impact of a rate design change. In December 2007, the NYPSC issued an order providing for an annual rate increase of $1.8 million beginning December 28, 2007. As part of this rate order, a rate design change was adopted that shifts a greater amount of cost recovery into the minimum bill amount,

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

thus spreading the recovery of such costs more evenly throughout the year. This rate design change resulted in lower retail and transportation revenues in the quarter ended March 31, 2008 compared to the quarter ended March 31, 2007. The rate order caused higher retail and transportation revenues in the quarter ended June 30, 2008 compared to the quarter ended June 30, 2007. However, on a year-to-date basis, retail and transportation revenues for the nine months ended June 30, 2008 (exclusive of the impact of higher gas costs) are still lower than the nine months ended June 30, 2007 as a result of the rate design change. It is expected that there will also be an increase in retail and transportation revenue in the fourth quarter of this year compared to the prior year as a result of the rate design change.

     Operating revenues for the Utility segment increased $67.3 million for the nine months ended June 30, 2008 as compared with the nine months ended June 30, 2007. This increase largely resulted from a $44.9 million increase in off-system sales revenue (see discussion below) and an $11.3 million increase in retail sales revenue coupled with an $11.0 million increase in transportation revenues. The increase in retail gas sales revenues for the Utility segment was largely a function of higher gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues) partially offset by the revenue impact of the rate design change discussed above. The increase in transportation revenues was primarily due to a 2.4 Bcf increase in transportation throughput, largely due to the migration of customers from retail sales to transportation service.

     As reported in 2006, on November 17, 2006, the U.S. Court of Appeals vacated and remanded the FERC’s Order No. 2004 regarding affiliate standards of conduct with respect to natural gas pipelines. The Court’s decision became effective on January 5, 2007, and on January 9, 2007, the FERC issued Order No. 690, its Interim Rule, designed to respond to the Court’s decision. In Order No. 690, as clarified by the FERC on March 21, 2007, the FERC readopted, on an interim basis, certain provisions that existed prior to the issuance of Order No. 2004 that had made it possible for the Utility segment to engage in certain off-system sales without triggering the adverse consequences that would otherwise arise under the Order No. 2004 standards of conduct. As a result, the Utility segment resumed engaging in off-system sales on non-affiliated pipelines as of May 2007. Total off-system sales revenues for the quarters ended June 30, 2008 and June 30, 2007 amounted to $20.5 million and $3.7 million, respectively. Total off-system sales revenues for the nine months ended June 30, 2008 and June 30, 2007 amounted to $48.6 million and $3.7 million, respectively. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was not a material impact to margins for the quarters and nine months ended June 30, 2008 and 2007.

     The Utility segment’s earnings for the quarter ended June 30, 2008 were $7.8 million, an increase of $4.1 million compared to earnings of $3.7 million for the quarter ended June 30, 2007. In the New York jurisdiction, earnings increased by $4.4 million. As a result of the rate design change in the New York jurisdiction, earnings for the third quarter of fiscal 2008 increased by $1.7 million from the third quarter of fiscal 2007. A $1.7 million decrease in operating costs (mostly due to lower post-retirement benefit costs), a non-recurring regulatory adjustment made in 2007 ($0.9 million), and the positive impact of a lower effective tax rate ($0.8 million) also contributed to the overall increase in earnings for the New York jurisdiction. These increases were partly offset by lower usage per account ($1.0 million). In the Pennsylvania jurisdiction, earnings decreased by $0.3 million due primarily to lower usage per account offset in part by lower operating costs and lower interest expense.

     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 jurisdiction. For the quarter ended June 30, 2008, the WNC preserved earnings of approximately $0.4 million, as weather was warmer than normal for the period. For the quarter ended June 30, 2007, the WNC did not have a significant impact on earnings as the weather was close to normal.

     The Utility segment’s earnings for the nine months ended June 30, 2008 were $62.2 million; an increase of $7.9 million when compared with earnings of $54.3 million for the nine months ended June 30, 2007. In the New York jurisdiction, earnings increased $5.2 million. Lower operating costs of $4.5 million (mostly due to lower post-retirement benefit costs and lower bad debt expense), the positive impact of non-recurring regulatory adjustments made in 2007 ($0.9 million), the positive impact of a lower effective

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

tax rate ($0.9 million), a routine regulatory adjustment ($0.7 million), lower property taxes ($0.7 million), and higher customer usage per account ($0.3 million) also contributed to the overall increase in earnings for the New York jurisdiction. These increases were partly offset by a $3.1 million decrease in earnings associated with the rate design change discussed above. In the Pennsylvania jurisdiction, earnings increased $2.7 million due primarily to a base rate increase that became effective in January 2007 ($2.6 million), higher usage per account ($0.9 million), and a decrease in operating costs of $1.1 million (mostly due to lower bad debt expense). These increases were partially offset by the negative earnings impact associated with warmer weather ($1.5 million).

     For the nine months ended June 30, 2008, the WNC preserved earnings of approximately $2.5 million, as the weather was warmer than normal. For the nine months ended June 30, 2007, the WNC preserved earnings of approximately $2.3 million, as the weather was also warmer than normal.

Pipeline and Storage

Pipeline and Storage Operating Revenues

	Three Months Ended							Nine Months Ended
	June 30,							June 30,
					Increase/
(Thousands)	2008		2007		(Decrease)			2008		2007		Increase
Firm Transportation	$	29,020	$	28,556	$	464		$	93,427	$	89,819	$	3,608
Interruptible Transportation		1,151		1,170		(19	)		3,237		3,071		166
		30,171		29,726		445			96,664		92,890		3,774
Firm Storage Service		16,754		17,002		(248	)		50,325		50,194		131
Other		5,260		3,732		1,528			16,222		13,390		2,832
								��
	$	52,185	$	50,460	$	1,725		$	163,211	$	156,474	$	6,737

Pipeline and Storage Throughput

	Three Months Ended							Nine Months Ended
	June 30,							June 30,
(MMcf)	2008		2007		Decrease			2008		2007		Increase
Firm Transportation		68,263		78,455		(10,192	)		283,104		273,513		9,591
Interruptible Transportation		1,540		1,670		(130	)		3,844		3,597		247
		69,803		80,125		(10,322	)		286,948		277,110		9,838

2008 Compared with 2007

     Operating revenues for the Pipeline and Storage segment increased $1.7 million for the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. The increase was primarily due to increased efficiency gas revenues ($1.9 million) reported as part of other revenues in the table above. The majority of this increase was due to higher gas prices in the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. Overall, throughput decreased during the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. While Supply Corporation’s and Empire’s transportation volumes decreased during the quarter, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight fixed-variable rate design and Empire’s modified fixed-variable rate design.

     Operating revenues for the nine months ended June 30, 2008 increased $6.7 million as compared with the nine months ended June 30, 2007. The increase was primarily due to a $3.8 million increase in transportation revenue primarily due to the fact that the Pipeline and Storage segment was able to renew existing contracts at higher rates due to favorable market conditions related to the demand for transportation service associated with storage. In addition, there was a $3.1 million increase in efficiency gas revenues reported as part of other revenues in the table above. This increase was due primarily to higher gas prices in the nine months ended June 30, 2008 as compared with the nine months ended June 30, 2007.

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

     The Pipeline and Storage segment’s earnings for the quarter ended June 30, 2008 were $12.5 million, a decrease of $2.9 million when compared to earnings of $15.4 million for the quarter ended June 30, 2007. The decrease in earnings primarily reflects the earnings impact associated with higher operation and maintenance expenses resulting from the non-recurrence in 2008 of a reversal of a reserve for preliminary survey costs ($4.8 million) related to the Empire Connector project recognized in the quarter ended June 30, 2007. In addition, there was an earnings decrease associated with higher interest expense ($0.8 million). These earnings decreases were partially offset by an increase in the allowance for funds used during construction ($1.0 million), higher efficiency gas revenues ($1.2 million) and the earnings benefit associated with lower income taxes ($0.5 million).

     The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2008 were $40.9 million, a decrease of $2.1 million when compared to earnings of $43.0 million for the nine months ended June 30, 2007. The main factors contributing to this decrease were higher operation and maintenance expenses ($5.7 million), resulting from the non-recurrence in 2008 of a reversal of a reserve for preliminary survey costs ($4.8 million) related to the Empire Connector project recognized during the quarter ended June 30, 2007. In addition, there was a $1.9 million positive earnings impact during the nine months ended June 30, 2007 associated with the discontinuance of hedge accounting for Empire’s interest rate collar that did not recur during the nine months ended June 30, 2008. There was also an earnings decrease associated with higher interest expense ($1.1 million). These earnings decreases were partially offset by an increase in the allowance for funds used during construction ($2.3 million), higher efficiency gas revenues ($2.0 million), and higher transportation and storage revenues ($2.5 million).

Exploration and Production

Exploration and Production Operating Revenues

	Three Months Ended									Nine Months Ended
	June 30,									June 30,
							Increase/									Increase/
(Thousands)	2008			2007			(Decrease)			2008			2007			(Decrease)
Gas (after Hedging) from Continuing Operations	$	56,591		$	34,712		$	21,879		$	155,793		$	107,976		$	47,817
Oil (after Hedging) from Continuing Operations		66,695			42,577			24,118			185,650			117,084			68,566
Gas Processing Plant from Continuing Operations		13,566			10,466			3,100			35,674			28,212			7,462
Other from Continuing Operations		(291	)		(291	)		—			(3,174	)		165			(3,339	)
Intrasegment Elimination from Continuing Operations (1)		(10,407	)		(7,436	)		(2,971	)		(25,114	)		(19,729	)		(5,385	)
Operating Revenues from Continuing Operations	$	126,154		$	80,028		$	46,126		$	348,829		$	233,708		$	115,121
Operating Revenues from Canada – Discontinued Operations	$	—		$	14,366		$	(14,366	)	$	—		$	42,004		$	(42,004	)

⁽¹⁾ Represents the elimination of certain West Coast gas production revenue included in “Gas (after Hedging) from Continuing Operations” 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.

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

Production Volumes

	Three Months Ended							Nine Months Ended
	June 30,							June 30,
					Increase/							Increase/
	2008		2007		(Decrease)			2008		2007		(Decrease)
Gas Production(MMcf)
Gulf Coast		3,019		2,317		702			8,868		7,934		934
West Coast		1,007		1,019		(12	)		3,010		2,883		127
Appalachia		1,793		1,266		527			5,538		3,998		1,540
Total Production from Continuing Operations		5,819		4,602		1,217			17,416		14,815		2,601
Canada — Discontinued Operations		—		1,639		(1,639	)		—		5,216		(5,216	)
Total Production		5,819		6,241		(422	)		17,416		20,031		(2,615	)
Oil Production(Mbbl)
Gulf Coast		124		165		(41	)		409		540		(131	)
West Coast		598		599		(1	)		1,825		1,789		36
Appalachia		23		32		(9	)		88		91		(3	)
Total Production from Continuing Operations		745		796		(51	)		2,322		2,420		(98	)
Canada — Discontinued Operations		—		58		(58	)		—		175		(175	)
Total Production		745		854		(109	)		2,322		2,595		(273	)

Average Prices

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2008		2007		Increase		2008		2007		Increase
Average Gas Price/Mcf
Gulf Coast	$	12.17	$	7.37	$	4.80	$	9.66	$	6.74	$	2.92
West Coast	$	10.61	$	7.20	$	3.41	$	8.43	$	6.76	$	1.67
Appalachia	$	11.53	$	8.59	$	2.94	$	9.25	$	7.71	$	1.54
Weighted Average for Continuing Operations	$	11.71	$	7.67	$	4.04	$	9.32	$	7.01	$	2.31
Weighted Average After Hedging for Continuing Operations	$	9.73	$	7.54	$	2.19	$	8.95	$	7.29	$	1.66
Canada - Discontinued Operations		N/M	$	6.82		N/M		N/M	$	6.34		N/M
Average Oil Price/bbl
Gulf Coast	$	124.43	$	65.17	$	59.26	$	103.46	$	59.37	$	44.09
West Coast	$	114.35	$	57.77	$	56.58	$	94.64	$	52.96	$	41.68
Appalachia	$	114.99	$	60.43	$	54.56	$	94.18	$	59.35	$	34.83
Weighted Average for Continuing Operations	$	116.05	$	59.41	$	56.64	$	96.17	$	54.63	$	41.54
Weighted Average After Hedging for Continuing Operations	$	89.55	$	53.54	$	36.01	$	79.97	$	48.39	$	31.58
Canada - Discontinued Operations		N/M	$	51.58		N/M		N/M	$	48.16		N/M

2008 Compared with 2007

     Operating revenues from continuing operations for the Exploration and Production segment increased $46.1 million for the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. Oil production revenue after hedging from continuing operations increased $24.1 million due to a

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

$36.01 per barrel increase in weighted average prices after hedging for continuing operations. Gas production revenue after hedging from continuing operations increased $21.9 million due to an increase in the weighted average price of gas after hedging for continuing operations ($2.19 per Mcf) as well as an increase in gas production of 1,217 MMcf. The Gulf Coast region of this segment was primarily responsible for the increase in natural gas production from continuing operations (702 MMcf). Production from new fields in 2008 (primarily in the High Island area) outpaced declines in production from some existing fields, quarter to quarter. The Appalachian region of this segment also contributed to the increase in natural gas production from continuing operations (527 MMcf), consistent with increased drilling activity in the region.

     Operating revenues from continuing operations for the Exploration and Production segment increased $115.1 million for the nine months ended June 30, 2008 as compared with the nine months ended June 30, 2007. Oil production revenue after hedging from continuing operations increased $68.6 million due primarily to a $31.58 per barrel increase in weighted average prices after hedging for continuing operations. Gas production revenue after hedging from continuing operations increased $47.8 million due to an increase in the weighted average price of gas after hedging for continuing operations ($1.66 per Mcf) and an increase in gas production of 2,601 MMcf. The increase in gas production from continuing operations occurred primarily in the Appalachian region (1,540 MMcf), consistent with increased drilling activity in the region. The Gulf Coast region also contributed to the increase in natural gas production from continuing operations (934 MMcf). Production from new fields in 2008 (primarily in the High Island area) outpaced declines in production from some existing fields, period to period, as discussed above.

     The Exploration and Production segment’s earnings from continuing operations for the quarter ended June 30, 2008 were $39.8 million, an increase of $21.0 million when compared with earnings from continuing operations of $18.8 million for the quarter ended June 30, 2007. Higher crude oil prices, higher natural gas prices and higher natural gas production increased earnings by $17.4 million, $8.3 million and $6.0 million, respectively, while lower crude oil production decreased earnings by $1.8 million. Higher lease operating costs ($4.2 million), higher depletion expense ($3.1 million), higher state income tax expense ($2.5 million) and higher general and administrative and other operating expenses ($1.5 million) also negatively impacted earnings. Lower interest expense of $2.1 million slightly offset these decreases.

     The Exploration and Production segment’s earnings from continuing operations for the nine months ended June 30, 2008 were $108.4 million, an increase of $55.8 million when compared with earnings from continuing operations of $52.6 million for the nine months ended June 30, 2007. Higher crude oil prices, higher natural gas prices and higher natural gas production increased earnings by $47.7 million, $18.8 million and $12.3 million, respectively, while lower crude oil production decreased earnings by $3.1 million. Higher lease operating costs ($9.0 million), higher depletion expense ($8.9 million), higher state income tax expense ($3.4 million), higher general and administrative and other operating expenses ($3.8 million), and mark-to-market adjustments on derivative financial instruments ($1.3 million) also negatively impacted earnings. Lower interest expense of $4.5 million and higher interest income of $1.6 million slightly offset these decreases.

Energy Marketing

Energy Marketing Operating Revenues

	Three Months Ended							Nine Months Ended
	June 30,							June 30,
					Increase/								Increase/
(Thousands)	2008		2007		(Decrease)			2008			2007		(Decrease)
Natural Gas (after Hedging)	$	162,127	$	113,351	$	48,776		$	440,123		$	359,895	$	80,228
Other		2		29		(27	)		(12	)		141		(153	)
	$	162,129	$	113,380	$	48,749		$	440,111		$	360,036	$	80,075

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

Energy Marketing Volumes

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2008		2007		Increase		2008		2007		Increase
Natural Gas — (MMcf)		14,641		13,014		1,627		47,189		44,063		3,126

2008 Compared with 2007

     Operating revenues for the Energy Marketing segment increased $48.7 million and $80.1 million, respectively, for the quarter and nine months ended June 30, 2008 as compared with the quarter and nine months ended June 30, 2007. The increase for both the quarter and nine months ended June 30, 2008 is primarily due to higher gas sales revenue due to an increase in the price of natural gas that was recovered through revenues as well as an increase in volumes. The increase in volumes is attributable to an increase in volumes sold to low-margin wholesale customers, as well as an increase in the number of commercial and industrial customers served by the Energy Marketing segment.

     Earnings in the Energy Marketing segment decreased $0.8 million and $1.4 million, respectively, for the quarter and nine months ended June 30, 2008 as compared with the quarter and nine months ended June 30, 2007. For the quarter ended June 30, 2008, higher operating costs of $0.8 million, primarily due to an increase in bad debt expense, are responsible for the decrease in earnings. Despite higher operating revenues and volumes, margins did not change significantly because the volume increase is primarily attributable to low-margin customers. For the nine months ended June 30, 2008, higher operating costs of $1.0 million (primarily due to an increase in bad debt expense) coupled with lower margins of $0.5 million are responsible for the decrease in earnings. A major factor in the margin decrease is the non-recurrence of a purchased gas expense adjustment recorded during the quarter ended March 31, 2007. During that quarter, the Energy Marketing segment reversed an accrual for $2.3 million of purchased gas expense due to the resolution of a contingency. The increase in volumes noted above, the profitable sale of certain gas held as inventory, and the marketing flexibility that the Energy Marketing segment derives from its contracts for significant storage capacity partially offset this decrease.

Timber

Timber Operating Revenues

	Three Months Ended							Nine Months Ended
	June 30,							June 30,
												Increase/
(Thousands)	2008		2007		Decrease			2008		2007		(Decrease)
Log Sales	$	2,726	$	3,504	$	(778	)	$	16,649	$	16,950	$	(301	)
Green Lumber Sales		958		1,318		(360	)		3,872		3,582		290
Kiln-Dried Lumber Sales		5,846		7,247		(1,401	)		18,612		20,742		(2,130	)
Other		584		1,062		(478	)		1,305		1,805		(500	)
Operating Revenues	$	10,114	$	13,131	$	(3,017	)	$	40,438	$	43,079	$	(2,641	)

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

Timber Board Feet

	Three Months Ended							Nine Months Ended
	June 30,							June 30,
												Increase/
(Thousands)	2008		2007		Decrease			2008		2007		(Decrease)
Log Sales		1,527		1,724		(197	)		7,140		6,458		682
Green Lumber Sales		2,273		2,709		(436	)		7,496		6,619		877
Kiln-Dried Lumber Sales		3,436		4,001		(565	)		10,536		10,953		(417	)
		7,236		8,434		(1,198	)		25,172		24,030		1,142

2008 Compared with 2007

     Operating revenues for the Timber segment decreased $3.0 million for the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. The decrease can be primarily attributed to a decrease in both log sales and kiln-dried lumber sales of $0.8 million and $1.4 million, respectively. Overall, the Timber segment is currently selling a greater amount of lower priced, low margin species than higher margin species due to poor market conditions and wet weather that hampered harvesting, resulting in a decline in revenues. The decrease in log sales is due to a decline in cherry veneer log sales volumes of 106,000 board feet that can be attributed to the mix of logs being harvested in the current quarter as compared to the quarter ended June 30, 2007. Cherry veneer logs are more valuable and sell at higher prices than other species and have the largest impact on overall log sales revenue. The decrease in kiln-dried lumber sales is due to both a decline in sales volumes of 565,000 board feet as well as a decline in the market price of kiln-dried lumber.

     Operating revenues for the Timber segment decreased $2.6 million for the nine months ended June 30, 2008 as compared with the nine months ended June 30, 2007. This decrease is largely due to a decline in kiln-dried lumber sales of $2.1 million. The decrease in kiln-dried lumber sales is due to both a decline in the market price of kiln-dried lumber as well as a decline in kiln-dried lumber sales volumes of 417,000 board feet. Log sales also decreased $0.3 million primarily due to a decline in cherry veneer log sales volumes of 130,000 board feet, partially offset by increases in log sales volumes from lower priced logs. Cherry veneer logs are more valuable and sell at higher prices than other species and have the largest impact on overall log sales revenue.

     The Timber segment recorded a loss of $2.1 million for the quarter ended June 30, 2008, a decrease of $1.7 million when compared with a loss of $0.4 million for the quarter ended June 30, 2007. This decrease was the result of lower margins of $1.7 million, largely from lumber and log sales due to the decrease in revenues noted above.

     The Timber segment’s earnings for the nine months ended June 30, 2008 were $2.2 million, a decrease of $0.9 million when compared with earnings of $3.1 million for the nine months ended June 30, 2007. The decrease was primarily due to an increase in depletion and depreciation expense of $0.6 million due to harvesting more timber from Company owned land than the prior year combined with the addition of a lumber sorter for Highland’s sawmill operations that was placed into service in October 2007. Lower margins of $0.1 million also contributed to the decrease in earnings. During the six months ended March 31, 2008, margins were up over the prior year, largely due to favorable weather conditions, resulting in an increase in the harvesting of higher margin species. The change in market and weather conditions in the quarter ended June 30, 2008, as discussed above, eliminated the margin improvements seen during the six months ended March 31, 2008.

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

Corporate and All Other

2008 Compared with 2007

     Corporate and All Other recorded earnings of $1.3 million for the quarter ended June 30, 2008 compared with earnings of $2.3 million for the quarter ended June 30, 2007. The positive earnings impacts of higher income from unconsolidated subsidiaries ($0.4 million) and lower income tax expense ($0.4 million) were more than offset by higher interest expense ($1.2 million) and higher operating costs ($0.8 million). The increase in operating costs can be attributed to the proxy contest with New Mountain Vantage GP, L.L.C.

     For the nine months ended June 30, 2008, Corporate and All Other had earnings of $4.6 million compared with earnings of $5.9 million for the nine months ended June 30, 2007. The positive earnings impacts of higher income from unconsolidated subsidiaries ($1.1 million), lower income tax expense ($0.8 million), lower interest expense ($0.7 million), a gain on the sale of a turbine by Horizon Power ($0.6 million), and slightly higher margins by Horizon LFG ($0.3 million) were more than offset by higher operating costs ($4.5 million) and lower interest income ($0.6 million). The increase in operating costs can be attributed to the proxy contest with New Mountain Vantage GP, L.L.C.

Interest Income

     Interest income was $1.7 million higher in the quarter ended June 30, 2008 as compared to the quarter ended June 30, 2007. For the nine months ended June 30, 2008, interest income increased $5.3 million as compared with the nine months ended June 30, 2007. These increases are mainly due to higher interest income (excluding intercompany interest income) in the Exploration and Production segment of $1.1 million and $4.0 million, respectively, for the quarter and nine months ended June 30, 2008 as compared to the quarter and nine months ended June 30, 2007 as a result of the investment of cash proceeds received from the sale of SECI in August 2007.

Interest Expense on Long-Term Debt

     Interest on long-term debt increased $1.2 million for the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. For the nine months ended June 30, 2008, interest on long-term debt decreased $0.1 million as compared with the nine months ended June 30, 2007. The increase in the quarter ended June 30, 2008 is due to the issuance in April 2008 of a $300 million, 6.5% Note due in April 2018. This increase was offset slightly by the repayment of $200 million of 6.303% medium-term notes that matured on May 27, 2008. The decrease in the nine months ended June 30, 2008 as compared to the nine months ended June 30, 2007 is due to an overall decline in interest on long-term debt as a result of a lower average amount of long-term debt outstanding. The Company repaid $22.8 million of Empire’s secured debt in December 2006. It also redeemed $96.3 million of 6.5% unsecured notes in April 2007.

CAPITAL RESOURCES AND LIQUIDITY

     The Company’s primary sources of cash during the nine-month period ended June 30, 2008 consisted of cash provided by operating activities and proceeds from the issuance of long-term debt. These sources of cash were supplemented by issues of new shares of common stock as a result of stock option exercises. During the nine months ended June 30, 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 fiscal 2006, the Company began repurchasing outstanding shares of its common stock under a share repurchase program, which is discussed below under Financing Cash Flow.

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

Operating Cash Flow

     Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, deferred income taxes, and income or loss from unconsolidated subsidiaries net of cash distributions.

     Cash provided by operating activities in the Utility and the Pipeline and Storage segments may vary from period to period because of the impact of rate cases. In the Utility segment, 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 Supply Corporation’s straight fixed-variable rate design.

     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 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 and futures contracts in an attempt to manage this energy commodity price risk.

     Net cash provided by operating activities totaled $415.1 million for the nine months ended June 30, 2008, an increase of $10.5 million compared with $404.6 million provided by operating activities for the nine months ended June 30, 2007. The increase is partially due to lower working capital requirements in the Utility segment for the nine months ended June 30, 2008 as compared to the nine months ended June 30, 2007. In the Exploration and Production segment, for the nine months ended June 30, 2008 as compared to the nine months ended June 30, 2007, cash provided by operations increased due to higher commodity prices, partially offset by the decrease in cash provided by operations that resulted from the sale of SECI in August 2007. Offsetting these increases were higher working capital requirements in the Energy Marketing segment.

Investing Cash Flow

Expenditures for Long-Lived Assets

     The Company’s expenditures for long-lived assets totaled $284.6 million during the nine months ended June 30, 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.)

Nine Months Ended June 30, 2008 (in millions of dollars)

	Total
	Expenditures for
	Long-Lived Assets
Utility	$	38.8
Pipeline and Storage(1)		106.2
Exploration and Production		140.6
Timber		1.2
Corporate and All Other		0.2
Eliminations(2)		(2.4	)
	$	284.6

(1)	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.
(2)	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 months ended June 30, 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 months ended June 30, 2008 were related to the Empire Connector project costs, which is discussed below, as well as for additions, improvements, and replacements to this segment’s transmission and gas storage systems.

     The Company continues to explore various opportunities to expand its capabilities to transport gas to the East Coast, either through the Supply Corporation or Empire systems or in partnership with others. Construction of the Empire Connector, a pipeline designed to transport up to approximately 250 MDth of natural gas per day that will connect the Empire Pipeline with the Millennium Pipeline, began in September 2007. The Empire Connector is on schedule to be completed by the planned in-service date of November 2008, although the actual in-service date will depend upon the completion of the Millennium Pipeline. Refer to the Rate and Regulatory Matters section that follows for further discussion of this matter. The total cost to the Company of the Empire Connector project is estimated at $180 million, after giving effect to sales tax exemptions worth approximately $3.7 million. As of June 30, 2008, the Company had incurred approximately $107.7 million in costs related to this project. Of this amount, $42.7 million and $88.0 million were incurred during the quarter and nine months ended June 30, 2008, respectively, and $2.1 million and $3.5 million were incurred during the quarter and nine months ended June 30, 2007, respectively. All project costs incurred as of June 30, 2008 have been capitalized as Construction Work in Progress. The Company anticipates financing the remaining cost of this project with cash on hand.

     Supply Corporation continues to view its potential Tuscarora Extension project as an important link to Millennium and potential storage development in the Corning, New York area. This new pipeline, which would expand the Supply Corporation system from its Tuscarora storage field to the intersection of the proposed Millennium and Empire Connector pipelines, could be designed initially to transport up to approximately 130 MDth of natural gas per day. It may also provide Supply Corporation with the opportunity to increase the deliverability of the existing Tuscarora storage field. Using the results of a preliminary Open Season, Supply Corporation is also exploring a new project (the West to East project) that would provide for new capacity from the Rockies Express Project, Appalachian production, storage and other points to Leidy and to interconnections with Millennium and Empire at Corning. The West to East project could include the Tuscarora Extension project, or could be a second phase following the development of the Tuscarora Extension project.

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

     In light of the rapidly growing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, Supply Corporation recently initiated a new Open Season for its “Appalachian Lateral,” a project designed to complement the West to East project. The Appalachian Lateral is expected to be located through an area where producers are actively drilling and seeking to find access to the market for their newly discovered reserves.

     In conjunction with the West to East and Appalachian Lateral projects, Supply Corporation has plans to develop new storage capacity by pursuing expansion of certain of its existing storage facilities. The expansion of these fields, which Supply Corporation hopes to market through one offering at market-based rates, could provide approximately 8.5 Bcf of incremental storage capacity with incremental withdrawal deliverability of up to 121 MDth of natural gas per day, available in 2011. Supply Corporation expects that the availability of this incremental storage capacity will complement the West to East and Appalachian Lateral pipeline projects and help meet the demand for storage created by the prospective increased flow of Rockies and Appalachian gas supply into the western Pennsylvania area, although traditional gas supplies will also be able to take advantage of this incremental storage capacity. An Open Season for this storage capacity is planned to be held later in 2008.

     The timeline associated with Supply Corporation’s pipeline and storage projects depends on market development. Should the market materialize, the Company anticipates financing the Tuscarora Extension project and/or the storage expansion(s) with cash on hand and/or through the use of the Company’s lines of credit. The capital cost of the West to East and Appalachian Lateral projects would amount to at least $700 million, which would be financed by a combination of debt and equity. As of June 30, 2008, there have been no costs incurred by Supply Corporation related to the Tuscarora Extension project, $0.1 million has been spent to study the West to East and Appalachian Lateral projects, and approximately $0.2 million has been spent to study the storage expansion project. Supply Corporation has not yet filed an application with the FERC for the authority to build either pipeline project or the storage expansion(s).

Exploration and Production

     The Exploration and Production segment capital expenditures for the nine months ended June 30, 2008 included approximately $46.9 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, $51.1 million for the West Coast region and $42.6 million for the Appalachian region. The Appalachian region capital expenditures include $2.4 million for the purchase of storage facilities, buildings, and base gas from Supply Corporation, as shown in the table on the previous page. These amounts included approximately $20.7 million spent to develop proved undeveloped reserves.

Timber

     The majority of the Timber segment capital expenditures for the nine months ended June 30, 2008 were for construction of a lumber sorter for Highland’s sawmill operations that was placed into service in October 2007 as well as for purchases of equipment for Highland’s sawmill and kiln operations.

All Other

     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 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.

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

Financing Cash Flow

     The Company did not have any outstanding short-term notes payable to banks or commercial paper at June 30, 2008. 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 $430.0 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 which totals $300.0 million and 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, 2008, the Company’s debt to capitalization ratio (as calculated under the facility) was .41. The constraints specified in the committed credit facility would permit an additional $1.84 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 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 uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.

     Under the Company’s existing indenture covenants, at June 30, 2008, the Company would have been permitted to issue up to a maximum of $1.2 billion in additional long-term unsecured indebtedness at 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.

     The Company’s 1974 indenture pursuant to which $199.0 million (or 18%) of the Company’s long-term debt (as of June 30, 2008) 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 to (i) pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) 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 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, 2008, 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. 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 in the event of a change in control at a price equal to 101% of the principal amount. In addition, the

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

Company is required to either offer to exchange the notes for substantially similar notes as are registered under the Securities Act of 1933 or, in certain circumstances, register the resale of the notes. The Company used $200.0 million of the proceeds to refund $200.0 million of 6.303% medium-term notes that subsequently matured on May 27, 2008.

     On December 8, 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. As of June 30, 2008, the Company has repurchased 6,667,275 shares for $262.8 million under this program, including 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. These share repurchases were funded with cash provided by operating activities and/or through the use of the Company’s lines of credit. In the future, it is expected that this share repurchase program will continue to be funded with cash provided by operating activities and/or through the use of the Company’s lines of credit. It is anticipated that open market repurchases will continue from time to time depending on market conditions.

     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 $30.7 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters, computer equipment 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 $3.9 million. The Company has guaranteed 50% or $2.0 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.

Market Risk Sensitive Instruments

     For a complete discussion of market risk sensitive instruments, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2007 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.

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

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

     On January 29, 2007, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by $52.0 million. Following standard procedure, the NYPSC suspended the proposed tariff amendments to enable its staff and intervenors to conduct a routine investigation and hold hearings. Distribution Corporation explained in the filing that its request for rate relief was necessitated by decreased revenues resulting from customer conservation efforts and increased customer uncollectibles, among other things. The rate filing also included a proposal for an efficiency and conservation initiative with a revenue decoupling mechanism designed to render the Company indifferent to throughput reductions resulting from conservation. On September 20, 2007, the NYPSC issued an order approving, with modifications, Distribution Corporation’s conservation program for implementation on an accelerated basis. Associated ratemaking issues, however, were reserved for consideration in the rate case.

     On December 21, 2007, the NYPSC issued a rate order providing for an annual rate increase of $1.8 million, together with a monthly bill surcharge that would collect up to $10.8 million to recover expenses for implementation of the conservation program. The rate increase and bill surcharge became effective December 28, 2007. The rate order further provided for a return on equity of 9.1%. 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 usage per customer. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. The Company surcharges or credits any difference from the average weather normalized usage per customer account. The surcharge or credit is calculated to recover total margin for the most recent twelve-month period ending December 31, and applied to customer bills annually, beginning March 1st.

     On April 18, 2008, Distribution Corporation filed an appeal with Supreme Court, Albany County, seeking review of the rate order. The appeal contends that portions of the rate order should be invalidated because they fail to meet the applicable legal standard for agency decisions. Among the issues challenged by the Company are the reasonableness of the NYPSC’s disallowance of expense items, including health care costs, and the methodology used for calculating rate of return, which the appeal contends understated the Company’s cost of equity. The Company cannot predict the outcome of the appeal at this time.

Pennsylvania Jurisdiction

     On June 1, 2006, Distribution Corporation filed proposed tariff amendments with PaPUC to increase annual revenues by $25.9 million to cover increases in the cost of service to be effective July 30, 2006. The rate request was filed to address increased costs associated with Distribution Corporation’s ongoing construction program as well as increases in operating costs, particularly uncollectible accounts. Following standard regulatory procedure, the PaPUC issued an order on July 20, 2006 instituting a rate proceeding and suspending the proposed tariff amendments until March 2, 2007. On October 2, 2006, the parties, including Distribution Corporation, Staff of the PaPUC and intervenors, executed an agreement (Settlement) proposing to settle all issues in the rate proceeding. The Settlement includes an increase in annual revenues of $14.3 million to non-gas revenues, an agreement not to file a rate case until January 28, 2008 at the earliest and an early implementation date. The Settlement was approved by the PaPUC at its meeting on November 30, 2006, and the new rates became effective January 1, 2007.

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

     On June 8, 2006, the NTSB issued safety recommendations to Distribution Corporation, the PaPUC and certain other parties as a result of an investigation of a natural gas explosion that occurred on Distribution Corporation’s system in Dubois, Pennsylvania in August 2004. The explosion destroyed a residence, resulting in the death of two people who lived there, and damaged a number of other houses in the immediate vicinity. Without admitting liability, Distribution Corporation settled all significant third-party claims against it related to the explosion.

     The NTSB’s safety recommendations to Distribution Corporation involved revisions to its butt-fusion procedures for joining plastic pipe, and revisions to its procedures for qualifying personnel who perform plastic fusions. Although not required by law to do so, Distribution Corporation implemented those recommendations. In December 2006, the NTSB classified its recommendations as “closed” after determining that Distribution Corporation took acceptable action with respect to the recommendations.

     The NTSB’s recommendation to the PaPUC was to require an analysis of the integrity of butt-fusion joints in Distribution Corporation’s system and replacement of those joints that are determined to have unacceptable characteristics. Distribution Corporation has worked cooperatively with the Staff of the PaPUC to permit the PaPUC to undertake the analysis recommended by the NTSB.

     In late November 2007, Distribution Corporation reached a tentative settlement with the Law Bureau Prosecutory Staff of the PaPUC (the “Law Bureau”) regarding the explosion and the PaPUC’s subsequent investigation. The Law Bureau and Distribution Corporation jointly submitted the terms of the settlement to the PaPUC for approval. The PaPUC issued the Settlement Agreement for public comment with a comment period ending April 3, 2008. While no comments were filed, the Chairman of the PaPUC recommended that, pursuant to revised provisions of the Settlement Agreement, Distribution Corporation should, without admitting liability, make a $100,000 payment to an assistance fund for payment-troubled customers and make an additional $50,000 payment to fund safety-related activities. The PaPUC adopted the Chairman’s recommendation unanimously at its public meeting held on May 1, 2008, and a tentative final order was issued on May 21, 2008. Distribution Corporation accepted the proposed Settlement Agreement. No other comments were filed, and by its terms the tentative order approving the Settlement Agreement became final on June 5, 2008 without further action by the PaPUC. On June 19, 2008, Distribution Corporation fulfilled the last condition for closing the proceeding by providing notice to the Secretary of the PaPUC that the $100,000 payment to the assistance fund had been made. Distribution Corporation is working with the Staff of the PaPUC to determine how the additional $50,000 in safety-related funding will be spent.

Pipeline and Storage

     Supply Corporation currently does not have a rate case on file with the FERC. A 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 currently does not have a rate case on file with the NYPSC. Among the issues resolved in connection with Empire’s FERC application to build the Empire Connector are the rates and terms of service that will become applicable to all of Empire’s business, effective upon Empire constructing and placing its new facilities into service (currently expected for November 2008). At that time, Empire will become an interstate pipeline subject to FERC regulation. The order described in the following paragraph requires Empire to make a filing at the FERC within three years after the in-service date justifying Empire’s existing recourse rates or proposing alternative rates.

     On December 21, 2006, the FERC issued an order granting a Certificate of Public Convenience and Necessity authorizing the construction and operation of the Empire Connector and various other related pipeline projects by other unaffiliated companies. The Empire Certificate contains various environmental and other conditions. Empire accepted that Certificate and received additional environmental permits from the U.S. Army Corps of Engineers and state environmental agencies. Empire also received, from all six upstate New York counties in which it will build the Empire Connector

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

project, final approval of sales tax exemptions and temporary partial property tax abatements. In June 2007, Empire signed a firm transportation service agreement with KeySpan Gas East Corporation, under which Empire is obligated to provide transportation service that will require construction of this project. Construction began in September 2007 and is on schedule to be completed by the planned in-service date of November 2008, although the actual in-service date will depend upon the completion of the Millennium Pipeline.

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 received, in 1998 and again in October 1999, notice that the NYDEC believes the Company is responsible for contamination discovered at a former manufactured gas plant site located in New York for which the Company had not been named as a PRP. In February 2007, the NYDEC identified the Company as a PRP for the site and issued a proposed remedial action plan. The NYDEC estimated clean-up costs under its proposed remedy to be $8.9 million if implemented. Although the Company commented to the NYDEC that the proposed remedial action plan contained a number of material errors, omissions and procedural defects, the NYDEC, in a March 2007 Record of Decision, selected the remedy it had previously proposed. In July 2007, the Company appealed the NYDEC’s Record of Decision to the New York State Supreme Court, Albany County. The Court dismissed the appeal in January 2008. The Company filed a notice of appeal in February 2008. In July 2008, the Company withdrew its appeal and agreed to the terms of an Order on Consent issued by the NYDEC. Pursuant to the order, the Company will remediate the site consistent with the remedy selected in the NYDEC’s Record of Decision. The Company will also reimburse the NYDEC in the amount of approximately $1.5 million for costs incurred in connection with the site from 1998 through May 30, 2007. The Company acknowledged that additional charges related to the site will be billed to the Company at a later date, including costs incurred by the NYDEC after May 30, 2007 and any costs incurred by the New York Department of Health. The Company has not received any estimates of such additional costs. The Company has recorded an estimated minimum liability of $10.4 million associated with this site.

     At June 30, 2008, 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 $13.5 million to $17.2 million. The minimum estimated liability of $13.5 million has been recorded on the Consolidated Balance Sheet at June 30, 2008, including the $10.4 million discussed above. 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 or other factors could adversely impact the Company.

New Accounting Pronouncements

     In September 2006, the FASB issued SFAS 157. SFAS 157 provides guidance for using fair value to measure assets and liabilities. The pronouncement 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 is to be applied whenever another standard requires or allows assets or liabilities to be measured at fair value. In accordance with FASB Staff Position FAS No. 157-2, SFAS 157 is effective for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009. The same FASB Staff Position delays the effective date for nonfinancial assets and nonfinancial liabilities, except for

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

items that are recognized or disclosed at fair value on a recurring basis, until the Company’s first quarter of fiscal 2010. The Company is currently evaluating the impact that the adoption of SFAS 157 will have on its consolidated financial statements.

     In September 2006, the FASB also issued SFAS 158, (an amendment 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 status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 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 adopted by the Company by the end of fiscal 2009. Currently, the Company measures its plan assets and benefit obligations using a June 30th measurement date.

     In February 2007, the FASB issued SFAS 159. SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not otherwise required to be measured at fair value under GAAP. A company that elects the fair value option for an eligible item will be required to recognize in current earnings any changes in that item’s fair value in reporting periods subsequent to the date of adoption. SFAS 159 is effective as of the Company’s first quarter of fiscal 2009. The Company is currently evaluating the impact, if any, that the adoption of SFAS 159 will have on its consolidated financial statements.

     In December 2007, the FASB issued SFAS 141R. SFAS 141R will significantly change 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, 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 effective as of the Company’s first quarter of fiscal 2010.

     In December 2007, the FASB issued SFAS 160. SFAS 160 will change 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 the accounting for transactions with minority interest holders. SFAS 160 is effective as of the Company’s first quarter of fiscal 2010. The Company currently does not have any NCI.

     In March 2008, the FASB issued SFAS 161. 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. SFAS 161 is effective as of the Company’s second quarter of fiscal 2009. The Company is currently evaluating the impact that the adoption of SFAS 161 will have on its disclosures in its notes to its consolidated financial 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

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

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, performance and 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 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.	Changes in economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents, and downturns in economic activity including national or regional recessions;
2.	Changes in demographic patterns and weather conditions, including the occurrence of severe weather such as hurricanes;
3.	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;
4.	Uncertainty of oil and gas reserve estimates;
5.	Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including shortages, delays or unavailability of equipment and services required in drilling operations;
6.	Significant changes from expectations in the Company’s actual production levels for natural gas or oil;
7.	Changes in the availability and/or price of derivative financial instruments;
8.	Changes in the price differentials between various types of oil;
9.	Inability to obtain new customers or retain existing ones;
10.	Significant changes in competitive factors affecting the Company;
11.	Changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations;
12.	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 gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements;
13.	Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;
14.	Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs or plans;

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

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.	Occurrences affecting the Company’s ability to obtain funds from operations, from borrowings under our credit lines or other credit facilities or from issuances of other short-term notes or debt or equity securities to finance needed capital expenditures and other investments, including any downgrades in the Company’s credit ratings;
17.	Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties;
18.	Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
19.	Changes in the market price of timber and the impact such changes might have on the types and quantity of timber harvested by the Company;
20.	Significant changes in tax rates or policies or in rates of inflation or interest;
21.	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;
22.	Changes in accounting principles or the application of such principles to the Company;
23.	The cost and effects of legal and administrative claims against the Company;
24.	Changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefit plans;
25.	Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide post-retirement benefits; or
26.	Increasing costs of insurance, changes in coverage and the ability to obtain insurance.

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

Item 3.Quantitative and Qualitative Disclosures About Market Risk

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

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, 2008.

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Item 4.Controls and Procedures (Concl.)

Changes in Internal Controls Over Financial Reporting

     There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended June 30, 2008 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

     On June 8, 2006, the NTSB issued safety recommendations to Distribution Corporation, the PaPUC and certain others as a result of its investigation of a natural gas explosion that occurred on Distribution Corporation’s system in Dubois, Pennsylvania in August 2004. For a discussion of this matter, refer to Part II, Item 7 — MD&A of this report under the heading “Other Matters — Rate and Regulatory Matters.”

     For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 4 — Commitments and Contingencies, and Part I, Item 2 — MD&A of this report under the heading “Other Matters — Environmental Matters.”

     In addition to the matters referenced above, 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 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 2007 Form 10-K, as amended by Item 1A of the Company’s Form 10-Q for the quarter ended March 31, 2008, have not materially changed other than as set forth below. The risk factor presented below supersedes the risk factor having the same caption in the 2007 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2007 Form 10-K and the March 31, 2008 Form 10-Q.

National Fuel may be adversely affected by economic conditions.

     Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect National Fuel’s revenues and cash flows or restrict its future growth. Economic conditions in National Fuel’s utility service territories and energy marketing territories also impact its collections of accounts receivable. Customers of National Fuel’s Utility and Energy Marketing segments may have particular trouble paying their bills during periods of declining economic activity and high commodity prices, potentially resulting in increased bad debt expense and reduced earnings.

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

     On April 1, 2008, the Company issued a total of 2,400 unregistered shares of Company common stock to the eight non-employee directors of the Company who receive compensation under the Company’s Retainer Policy for Non-Employee Directors, 300 shares to each such director. All of these unregistered shares were issued as partial consideration for the directors’ services during the quarter ended June 30, 2008. These transactions were exempt from registration by Section 4(2) of the Securities Act of 1933 as transactions not involving a public offering.

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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)
Apr. 1 - 30, 2008		446,666	$	46.99		439,722		1,332,725
May 1 - 31, 2008		32,337	$	57.99		—		1,332,725
June 1 - 30, 2008		9,686	$	58.43		—		1,332,725
Total		488,689	$	47.94		439,722		1,332,725

(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, and (iii) shares of common stock of the Company purchased on the open market pursuant to the Company’s publicly announced share repurchase program. Shares purchased other than through a publicly announced share repurchase program totaled 6,944 in April 2008, 32,337 in May 2008 and 9,686 in June 2008 (a three month total of 48,967). Of those shares, 19,363 were purchased for the Company’s 401(k) plans and 29,604 were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock.

(b)

On December 8, 2005, the Company’s Board of Directors authorized the repurchase of up to eight million shares of the Company’s common stock. Repurchases may be made from time to time in the open market or through private transactions.

Item 6.Exhibits

     (a) Exhibits

Exhibit
Number	Description of Exhibit
3(ii)	By-Laws:
•	National Fuel Gas Company By-Laws as amended June 11, 2008 (incorporated herein by reference to Exhibit 3.1, Form 8-K dated June 16, 2008).
4	Instruments defining the rights of security holders:
4.1	Officer’s Certificate establishing 6.50% Notes due 2018, dated April 11, 2008
•	Amended and Restated Rights Agreement, dated as of July 11, 2008, between National Fuel Gas Company and The Bank of New York, as rights agent (incorporated herein by reference to Exhibit 4.1, Form 8-K dated July 15, 2008).
10	Material contracts:
•	Director Services Agreement, dated as of June 1, 2008, between National Fuel Gas Company and Philip C. Ackerman (incorporated herein by reference to Exhibit 99, Form 8-K dated June 16, 2008).
12	Statements regarding Computation of Ratios:
	Ratio of Earnings to Fixed Charges for the Twelve Months Ended June 30, 2008 and the Fiscal Years Ended September 30, 2004 through 2007.

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Item 6.Exhibits (Concl.)

Exhibit
Number	Description of Exhibit
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.
31.2	Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
32	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99	National Fuel Gas Company Consolidated Statement of Income for the Twelve Months Ended June 30, 2008 and 2007.

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SIGNATURES

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

NATIONAL FUEL GAS COMPANY
                   (Registrant)
 

/s/ R. J. Tanski  

R. J. Tanski 

Treasurer and Principal Financial Officer 

/s/ K. M. Camiolo  

K. M. Camiolo 

Controller and Principal Accounting Officer 

Date: August 8, 2008

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