UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended~~June 30,~~December 31, 2008


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 the 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~~January 31, ~~2008: 81,475,950~~2009: 79,514,816 shares.

GLOSSARY OF TERMS

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

National Fuel Gas Companies


*~~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, Inc.
ESNE		Energy Systems North East, LLC
Highland		Highland Forest Resources, Inc.
Horizon		Horizon Energy Development, Inc.
Horizon LFG		Horizon LFG, Inc.
Horizon Power		Horizon Power, Inc.
Leidy Hub		Leidy Hub, Inc.
Midstream		National Fuel Gas Midstream Corporation
Model City		Model City Energy, LLC
National Fuel		National Fuel Gas Company
NFR		National Fuel Resources, Inc.
Registrant		National Fuel Gas Company
SECI		Seneca Energy Canada Inc.
Seneca		Seneca Resources Corporation
Seneca Energy		Seneca Energy II, LLC
Supply Corporation		National Fuel Gas Supply Corporation

Regulatory Agencies


*~~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


*~~Other~~*

~~2007~~2008 Form 10-K		The Company’s Annual Report on Form 10-K for the year ended September 30, ~~2007~~2008, as amended
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.
Development costs		Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
Dth		Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.

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GLOSSARY OF TERMS (Cont.)


~~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.
Exploration costs		Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
FIN		FASB Interpretation Number
FIN 48		FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - - an interpretation of SFAS 109
Firm transportation and/or storage		The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP		Accounting principles generally accepted in the United States of America
Goodwill		An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging		A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub		Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
Interruptible transportation and/or storage		The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LIBOR		London Interbank Offered Rate
LIFO		Last-in, first-out
Mbbl		Thousand barrels (of oil)
Mcf		Thousand cubic feet (of natural gas)
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth		Thousand decatherms (of natural gas)
MMBtu		Million British thermal units
MMcf		Million cubic feet (of natural gas)
NYMEX		New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Open Season		A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined (“Open Season”) 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~~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

-3-


~~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 131		Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information
SFAS 132R		Statement of Financial Accounting Standards No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits
SFAS 133		Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
SFAS 141R		Statement of Financial Accounting Standards No. 141R, Business Combinations
SFAS 157		Statement of Financial Accounting Standards No. 157, Fair Value Measurements
SFAS 158		Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an ~~Amendment~~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 5151.
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,~~December 31, 2008 and 2007		6 ~~- 7~~

b. Consolidated Balance Sheets ~~— June 30,~~– December 31, 2008 and September 30, ~~2007~~2008		87 - 98

c. Consolidated ~~Statement~~Statements of Cash Flows ~~— Nine~~– Three Months Ended ~~June 30,~~December 31, 2008 and 2007		109

d. Consolidated ~~Statement~~Statements of Comprehensive Income — Three ~~and Nine~~ Months Ended ~~June 30,~~December 31, 2008 and 2007		1110

e. Notes to Consolidated Financial Statements		1211 - 2223

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		2324 - 4442

Item 3. Quantitative and Qualitative Disclosures About Market Risk		4442

Item 4. Controls and Procedures		~~44 - 45~~42

Part II. Other Information

Item 1. Legal Proceedings		4542

Item 1 A. Risk Factors		4542 - 44

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		4645 - 4746

Signatures		4847
~~EX-4.1~~EX-10.1
EX-10.2
EX-10.3
EX-12
EX-31.1
EX-31.2
EX-32
EX-99

~~The Company has nothing to report under this item.~~

The Company has nothing to report under this item.

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

This Form 10-Q contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2 — MD&A, under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction and other projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions.

-5-

Part I. Financial Information

Item 1.Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)


	Three Months Ended						Three Months Ended
	June 30,						December 31,
(Thousands of Dollars, Except Per Common Share Amounts)	2008			2007			2008			2007

INCOME
Operating Revenues	$	548,382		$	448,779		$	607,163		$	568,268


Operating Expenses
Purchased Gas		272,893			219,075			328,733			278,010
Operation and Maintenance		102,602			90,390			101,334			102,455
Property, Franchise and Other Taxes		19,135			17,622			18,762			17,672
Depreciation, Depletion and Amortization		42,804			37,759			42,342			44,121
Impairment of Oil and Gas Producing Properties								182,811			—

		437,434			364,846			673,982			442,258

Operating Income		110,948			83,933
Operating Income (Loss)								(66,819	)		126,010
Other Income (Expense):
Income from Unconsolidated Subsidiaries		1,561			926
Income (Loss) from Unconsolidated Subsidiaries								(686	)		2,275
Interest Income		3,086			1,377			1,892			3,093
Other Income		1,649			787			5,327			1,253
Interest Expense on Long-Term Debt		(19,468	)		(18,226	)		(18,056	)		(16,289	)
Other Interest Expense		(1,199	)		(1,512	)		375			(724	)

Income from Continuing Operations Before Income Taxes		96,577			67,285
Income Tax Expense		36,722			26,073
Income (Loss) Before Income Taxes								(77,967	)		115,618
Income Tax Expense (Benefit)								(35,289	)		45,014


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
Net Income (Loss) Available for Common Stock								(42,678	)		70,604


EARNINGS REINVESTED IN THE BUSINESS
Balance at April 1		1,008,084			834,902
Balance at October 1								953,799			983,776

		1,067,939			881,700			911,121			1,054,380
Share Repurchases		(17,083	)		—
Dividends on Common Stock (2008 - $0.325 per share; 2007 - $0.31 per share)		(26,479	)		(25,897	)
Cumulative Effect of the Adoption of FIN 48								—			(406	)
Adoption of SFAS 158 Measurement Date Provision								(804	)		—
Dividends on Common Stock (2008 - $0.325; 2007 - $0.31)								(25,841	)		(26,023	)

Balance at June 30	$	1,024,377		$	855,803
Balance at December 31							$	884,476		$	1,027,951


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
Net Income (Loss) Available for Common Stock							$	(0.54	)	$	0.84

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
Net Income (Loss) Available for Common Stock							$	(0.53	)	$	0.82

Weighted Average Common Shares Outstanding:
Used in Basic Calculation		81,342,788			83,483,718			79,289,005			83,611,177

Used in Diluted Calculation		83,712,193			85,668,055			80,167,893			85,819,534

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

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

(Unaudited)

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


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

ASSETS
Property, Plant and Equipment	$	4,982,596	$	4,873,969
Less — Accumulated Depreciation, Depletion and Amortization		1,938,841		1,719,869

		3,043,755		3,154,100

Current Assets
Cash and Temporary Cash Investments		136,685		68,239
Hedging Collateral Deposits		3,743		1
Receivables — Net of Allowance for Uncollectible Accounts of $41,369 and $33,117, Respectively		229,220		185,397
Unbilled Utility Revenue		79,404		24,364
Gas Stored Underground		64,279		87,294
Materials and Supplies — at average cost		25,694		31,317
Unrecovered Purchased Gas Costs		26,716		37,708
Other Current Assets		56,385		65,158
Deferred Income Taxes		6,340		—

		628,466		499,478


Other Assets
Recoverable Future Taxes		83,541		82,506
Unamortized Debt Expense		13,531		13,978
Other Regulatory Assets		190,890		189,587
Deferred Charges		4,233		4,417
Other Investments		69,801		80,640
Investments in Unconsolidated Subsidiaries		13,443		16,279
Goodwill		5,476		5,476
Intangible Assets		25,620		26,174
Prepaid Post-Retirement Benefit Costs		20,775		21,034
Fair Value of Derivative Financial Instruments		111,303		28,786
Other		13,353		7,732

		551,966		476,609


Total Assets	$	4,224,187	$	4,130,187

See Notes to Condensed Consolidated Financial Statements

-7-

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


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

CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued And Outstanding – 79,512,716 Shares And 79,120,544 Shares, Respectively	$	79,513	$	79,121
Paid in Capital		580,377		567,716
Earnings Reinvested in the Business		884,476		953,799

Total Common Shareholder Equity Before Items of Other Comprehensive Income		1,544,366		1,600,636
Accumulated Other Comprehensive Income		50,101		2,963

Total Comprehensive Shareholders’ Equity		1,594,467		1,603,599
Long-Term Debt, Net of Current Portion		999,000		999,000

Total Capitalization		2,593,467		2,602,599


Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		66,000		—
Current Portion of Long-Term Debt		100,000		100,000
Accounts Payable		197,968		142,520
Amounts Payable to Customers		4,715		2,753
Dividends Payable		25,841		25,714
Interest Payable on Long-Term Debt		15,557		22,114
Customer Advances		30,093		33,017
Other Accruals and Current Liabilities		65,415		45,220
Deferred Income Taxes		—		1,871
Fair Value of Derivative Financial Instruments		2,941		1,362

		508,530		374,571


Deferred Credits
Deferred Income Taxes		604,044		634,372
Taxes Refundable to Customers		18,452		18,449
Unamortized Investment Tax Credit		4,516		4,691
Cost of Removal Regulatory Liability		103,877		103,100
Other Regulatory Liabilities		96,378		91,933
Pension and Other Post-Retirement Liabilities		73,076		78,909
Asset Retirement Obligations		92,597		93,247
Other Deferred Credits		129,250		128,316

		1,122,190		1,153,017

Commitments and Contingencies		—		—


Total Capitalization and Liabilities	$	4,224,187	$	4,130,187

See Notes to Condensed Consolidated Financial Statements

-8-

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated ~~Balance Sheets~~Statements of Cash Flows

(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


	Three Months Ended
	December 31,
(Thousands of Dollars)	2008			2007

OPERATING ACTIVITIES
Net Income (Loss) Available for Common Stock	$	(42,678	)	$	70,604
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties		182,811			—
Depreciation, Depletion and Amortization		42,342			44,121
Deferred Income Taxes		(69,626	)		5,296
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions		1,032			431
Impairment of Investment in Partnership		1,804			—
Excess Tax Benefits Associated with Stock-Based Compensation Awards		(5,927	)		(16,275	)
Other		6,628			4,916
Change in:
Hedging Collateral Deposits		(3,742	)		2,070
Receivables and Unbilled Utility Revenue		(98,914	)		(127,894	)
Gas Stored Underground and Materials and Supplies		20,971			(186	)
Unrecovered Purchased Gas Costs		10,992			2,583
Prepayments and Other Current Assets		14,958			10,422
Accounts Payable		3,705			42,398
Amounts Payable to Customers		1,962			(1,228	)
Customer Advances		(2,924	)		635
Other Accruals and Current Liabilities		30,407			25,400
Other Assets		12,560			10,163
Other Liabilities		(6,217	)		1,889

Net Cash Provided by Operating Activities		100,144			75,345


INVESTING ACTIVITIES
Capital Expenditures		(84,268	)		(69,744	)
Cash Held in Escrow		—			58,397
Net Proceeds from Sale of Oil and Gas Producing Properties		—			1,500
Other		(632	)		(761	)

Net Cash Used in Investing Activities		(84,900	)		(10,608	)


FINANCING ACTIVITIES
Change in Notes Payable to Banks and Commercial Paper		66,000			—
Excess Tax Benefits Associated with Stock-Based Compensation Awards		5,927			16,275
Reduction of Long-Term Debt		—			(24	)
Dividends Paid on Common Stock		(25,714	)		(25,873	)
Net Proceeds from Issuance of Common Stock		6,989			9,846

Net Cash Provided by Financing Activities		53,202			224


Net Increase in Cash and Temporary Cash Investments		68,446			64,961

Cash and Temporary Cash Investments at October 1		68,239			124,806


Cash and Temporary Cash Investments at December 31	$	136,685		$	189,767

See Notes to Condensed Consolidated Financial Statements

-9-

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated ~~Statement~~Statements of ~~Cash Flows~~Comprehensive Income

(Unaudited)

Nine Months Ended
June 30,
(Thousands of Dollars) 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


	Three Months Ended
	December 31,
(Thousands of Dollars)	2008			2007

Net Income (Loss) Available for Common Stock	$	(42,678	)	$	70,604

Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment		8			(18	)
Unrealized Loss on Securities Available for Sale Arising During the Period		(10,032	)		(1,201	)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		118,880			(20,859	)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income		(28,792	)		5,421

Other Comprehensive Income (Loss), Before Tax		80,064			(16,657	)

Income Tax Benefit Related to Unrealized Loss on Securities Available for Sale Arising During the Period		(3,791	)		(59	)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		48,128			(8,648	)
Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gains) Losses from Derivative Financial Instruments In Net Income		(11,411	)		2,133

Income Taxes – Net		32,926			(6,574	)

Other Comprehensive Income (Loss)		47,138			(10,083	)

Comprehensive Income	$	4,460		$	60,521

See Notes to Condensed Consolidated Financial Statements

-10-

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

~~Consolidated Statements of Comprehensive Income~~
~~(Unaudited)~~

Three Months Ended
June 30,
(Thousands of Dollars) 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~~

~~-11-~~

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

~~National Fuel Gas Company~~

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 — Summary of Significant Accounting Policies

Principles of Consolidation.The Company consolidates its majority owned entities. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated.

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

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

Earnings for Interim Periods.The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2008, 2007 ~~2006~~ and ~~2005~~2006 that are included in the Company’s ~~2007~~2008 Form 10-K. The consolidated financial statements for the year ended September 30, ~~2008~~2009 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.

The earnings for the ~~nine~~three months ended ~~June 30,~~December 31, 2008 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, ~~2008.~~2009. 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~~investments purchased with a maturity of generally three months or less to be cash equivalents.

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

At September 30, 2008, the Company accrued ~~$19.9~~$16.8 million of capital expenditures related to the construction of the Empire Connector project. This amount ~~has been~~was excluded from the Consolidated Statement of Cash Flows at ~~June~~September 30, 2008 since it ~~represents~~represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2008 and have been included in the Consolidated Statement of Cash Flows at December 31, 2008.

Hedging Collateral Deposits.~~Cash~~This is an account title for cash held in margin accounts ~~serves~~funded by the Company to serve as collateral for open positions on exchange-traded futures contracts ~~exchange-traded options~~ and over-the-counter ~~swaps and collars.~~swap agreements.

At December 31, 2008, the Company had hedging collateral deposits of $3.7 million related to its exchange-traded futures contracts. The Company’s over-the-counter swap agreements were in a significant asset position at December 31, 2008. Under the terms of those agreements, the Company was not required to fund any cash as hedging collateral; rather, the counterparties were required to provide collateral to the Company. The amount of the collateral received was $34.1 million. This amount

-11-

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

Gas Stored Underground — Current.In the Utility segment, gas stored underground – current is ~~carried at~~valued using the LIFO method. This value or cost is lower than the current market value of ~~cost or market, on a LIFO method.~~the gas stored underground. 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~~$36.2 million at ~~June 30,~~December 31, 2008, is reduced to zero by September 30 of each year as the inventory is replenished.

Property, Plant and Equipment.In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.

Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying current market prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The Company’s capitalized costs exceeded the full cost ceiling for the Company’s oil and gas properties at December 31, 2008. As such, the Company recognized a pre-tax impairment of $182.8 million at December 31, 2008. Deferred income taxes of $74.6 million were recorded associated with this impairment.

-12-

Item 1.Financial Statements (Cont.)

Accumulated Other Comprehensive ~~Income (Loss).~~Income.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 )


	At December 31, 2008			At September 30, 2008
Funded Status of the Pension and Other Post-Retirement Benefit Plans	$	(19,741	)	$	(19,741	)
Cumulative Foreign Currency Translation Adjustment		(63	)		(71	)
Net Unrealized Gain on Derivative Financial Instruments		69,320			15,949
Net Unrealized Gain on Securities Available for Sale⁽¹⁾		585			6,826

Accumulated Other Comprehensive Income	$	50,101		$	2,963


⁽¹⁾		Includes a balanced equity mutual fund that is in an unrealized loss position of $3.3 million ($2.1 million after taxes) and $1.1 million ($0.7 million after taxes) at December 31, 2008 and September 30, 2008, respectively. The fair value of this investment was $10.9 million at December 31, 2008 and $12.4 million at September 30, 2008. This investment has been in an unrealized loss position for less than twelve months. Based on this fact and the fact that management has the intent and ability to hold the investment for a sufficient period of time for the asset to recover in value, management does not consider this investment to be other than temporarily impaired.

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~~reflect the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining diluted earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options and stock-settled SARs. The diluted weighted average shares outstanding shown on the Consolidated ~~Statements~~Statement of Income reflects the potential dilution as a result of these stock options and stock-settled SARs as determined using the Treasury Stock Method. Stock options and stock-settled SARs that are antidilutive are excluded from the calculation of diluted earnings per common share. For the quarter ~~and nine months~~ ended ~~June 30,~~December 31, 2008, there were no765,000 stock options ~~excluded as being antidilutive. There were 6,593~~ and ~~2,190~~365,000 stock-settled SARs excluded as being ~~antidilutive for the quarter and nine months ended June 30, 2008, respectively.~~antidilutive. For the quarter ~~and nine months~~ ended ~~June 30,~~December 31, 2007, there were no stock options ~~excluded as being antidilutive. There were 1,817 and 271~~or 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.antidilutive.

Stock-Based Compensation.~~For~~During the quarter ended ~~June 30,~~December 31, 2008, the Company granted ~~30,000~~610,000 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~~$29.88 per share. The weighted average grant date fair value of these stock-settled SARs was ~~$12.23~~$4.09 per ~~share and $9.06 per share for the quarter and nine months ended June 30, 2008, respectively.~~share. 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~~during the quarter ~~and nine months~~ ended ~~June 30,~~December 31, 2008 vest and become ~~exercisable~~exerciseable annually in one-third increments, provided that a performance condition is met. The performance condition for ~~diluted earnings per share~~each fiscal year, generally stated, is ~~met for~~an increase over the prior fiscal ~~year.~~year of at least five percent in certain oil and natural gas production of the Exploration and Production segment. The weighted average grant date fair value of these stock-settled SARs

~~-13-~~

Item 1.Financial Statements (Cont.)

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, on October 1, 2008, the Company adopted 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.~~basis. 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. For further discussion of the impact of the adoption of SFAS 157 for financial assets and financial liabilities, refer to Note 2 — Fair Value Measurements. The Company is currently evaluating the impact that the adoption of SFAS 157 for nonfinancial assets and nonfinancial liabilities will have on its consolidated financial statements. The Company has identified Goodwill as being the major nonfinancial asset that will be impacted by SFAS 157 and Asset Retirement Obligations as being the major nonfinancial liability that will be impacted by SFAS 157.

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 fully adopted by the Company by the end of fiscal 2009. ~~Currently, the~~The Company ~~measures~~has historically measured its plan assets and benefit obligations using a June 30th measurement date. In anticipation of changing to a September 30th measurement date, the Company will be recording fifteen months of pension and other post-retirement benefit costs during fiscal 2009. In accordance with the provisions of SFAS 158, these costs have been calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $5.1 million and have been recorded by the Company during the quarter ended December 31, 2008 as a $3.8 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $1.3 million ($0.8 million after tax) adjustment to earnings reinvested in the business. For further discussion of the impact of adopting the measurement date provisions of SFAS 158, refer to Note 8 – Retirement Plan and Other Post-Retirement Benefits.

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 isbecame effective ~~as of~~for the ~~Company’s first quarter of fiscal 2009.~~Company on October 1, 2008. The Company ~~is currently evaluating~~did not elect the ~~impact, if~~fair value measurements option for any of its financial instruments other than those that ~~the adoption of SFAS 159 will have on its consolidated financial statements.~~are already being measured at fair value.

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.

-14-

~~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~~the notes to the consolidated financial statements.

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

Note 2 ~~— Income Taxes~~– Fair Value Measurements

Beginning in fiscal 2009, the Company adopted the provisions of SFAS 157, “Fair Value Measurements.” SFAS 157 establishes a fair-value hierarchy, which prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The adoption of SFAS 157 has not had a significant impact on the consolidated financial statements.

The ~~components~~following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of ~~federal, state~~December 31, 2008. As required by SFAS 157, financial assets and ~~foreign income taxes included~~liabilities are classified in their entirety based on the ~~Consolidated Statements~~lowest level 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

input that is significant to the fair value measurement.

-15-

Item 1.Financial Statements (Cont.)


Recurring Fair Value Measures	At fair value as of December 31, 2008
(Dollars in thousands)	Level 1		Level 2		Level 3		Total

Assets:
Cash Equivalents	$	114,547	$	—	$	—	$	114,547
Derivative Financial Instruments		—		28,273		83,030		111,303
Other Investments		17,715		—		—		17,715
Hedging Collateral Deposits		3,743		—		—		3,743

Total	$	136,005	$	28,273	$	83,030	$	247,308


Liabilities:
Derivative Financial Instruments	$	2,941	$	—	$	—	$	2,941

Total	$	2,941	$	—	$	—	$	2,941

Derivative Financial Instruments

The derivative financial instruments reported in Level 1 consist of NYMEX futures contracts. The hedging collateral deposits associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 consist of natural gas swap agreements used in the Company’s Exploration and Production segment and natural gas swap agreements used in the Energy Marketing segment. The fair value of these natural gas price swap agreements is based on an internal model that uses observable inputs. The fair market value of the price swap agreements reported in Level 2 as assets has been reduced by $0.7 million based on an assessment of counterparty credit risk. The derivative financial instruments reported in Level 3 consist of all of the Exploration and Production segment’s crude oil swap agreements and some of its natural gas swap agreements. The fair value of the crude oil and natural gas price swap agreements is based on an internal model that uses both observable and unobservable inputs. The fair market value of the price swap agreements reported in Level 3 as assets has been reduced by $2.7 million based on an assessment of counterparty credit risk. This credit reserve, as well as the credit reserve established for the Level 2 price swap agreement assets, was determined by applying default probabilities to the anticipated cash flows that the Company is either expecting from its counterparties or expecting to pay to its counterparties.

Cash Equivalents

The cash equivalents reported in Level 1 consist of SEC registered money market mutual funds.

Other Investments

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

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

-16-

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

Item 1.Financial Statements (Cont.)


	Three Months Ended
	December 31,
	2008			2007

U.S. Income (Loss) Before Income Taxes	$	(78,141	)	$	115,444


Income Tax Expense (Benefit), Computed at Federal Statutory Rate of 35%	$	(27,349	)	$	40,405

Increase (Reduction) in Taxes Resulting From:
State Income Taxes		(5,039	)		7,043
Miscellaneous		(3,075	)		(2,608	)


Total Income Taxes	$	(35,463	)	$	44,840
	-

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


	At June 30, 2008			At September 30, 2007			At December 31, 2008			At September 30, 2008

Deferred Tax Liabilities:
Property, Plant and Equipment	$	669,079		$	612,648		$	614,556		$	673,313
Pension and Other Post-Retirement Benefit Costs – SFAS 158								44,345			43,340
Unrealized Hedging Gains								47,856			14,936
Other		38,451			61,616			36,975			40,455

Total Deferred Tax Liabilities		707,530			674,264			743,732			772,044


Deferred Tax Assets:
Fair Value of Derivative Instruments and Securities		(65,192	)		—
Pension and Other Post-Retirement Benefit Costs – SFAS 158								(44,831	)		(43,340	)
Other		(120,817	)		(107,458	)		(101,197	)		(92,461	)

Total Deferred Tax Assets		(186,009	)		(107,458	)		(146,028	)		(135,801	)

Total Net Deferred Income Taxes	$	521,521		$	566,806		$	597,704		$	636,243


Presented as Follows:
Net Deferred Tax Asset – Current	$	(84,297	)	$	(8,550	)
Net Deferred Tax Liability/(Asset) – Current							$	(6,340	)	$	1,871
Net Deferred Tax Liability – Non-Current		605,818			575,356			604,044			634,372

Total Net Deferred Income Taxes	$	521,521		$	566,806		$	597,704		$	636,243

Item 1.Financial Statements (Cont.)

~~For~~The Company is also subject to various routine state income tax examinations. The Company’s operating subsidiaries mainly operate in four states which have statutes of limitations that generally expire between three to four years from the ~~major states in which~~date of filing of the ~~various subsidiary companies operate, the earliest~~income tax ~~year open for examination is as follows:~~


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

return.

Note 34 — Capitalization

Common Stock.During the ~~nine~~three months ended ~~June 30,~~December 31, 2008, the Company issued ~~884,644~~687,180 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).~~exercises. The Company also issued ~~7,200~~2,100 original issue shares of common stock to the ~~eight~~seven 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~~three months ended ~~June 30,~~December 31, 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~~three months ended ~~June 30,~~December 31, 2008, ~~72,205~~297,108 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,~~Shareholder Rights Plan.In 1996, the Company’s Board of Directors ~~authorized the Company to implement~~adopted a ~~share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to~~shareholder rights plan (Plan). The Plan has been amended six times since it was adopted and is now embodied in 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~~effective December 4, 2008, a copy of which was included as an exhibit to the ~~rights of~~Form 8-K filed by the Company on December 4, 2008.

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

The Rights ~~(the “Rights”). The principal amendments are an extension~~have anti-takeover effects because they will cause substantial dilution of the ~~expiration date of the Rights Agreement from July 31, 2008~~Company’s common stock if a person attempts 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 ofacquire the Company ~~means~~on terms not approved by the ~~number~~Board of ~~securities then issued~~Directors (an Acquiring Person).

The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date Rights that are owned by an Acquiring Person will be null and ~~outstanding together with the number~~void. At any time following a Distribution Date, each holder of ~~such securities not then actually issued and outstanding which such person would be deemed~~a Right may exercise its right to ~~own beneficially~~receive, upon payment of an amount calculated under the Rights Agreement, ~~including, among~~common stock of the Company (or, under certain circumstances, other ~~things, certain derivative~~securities or ~~synthetic arrangements~~assets of the Company) having ~~characteristics~~a value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.

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

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

~~-17-~~-19-

Item 1.Financial Statements (Cont.)

~~Long-Term Debt.~~~~In April 2008,~~ At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company ~~issued $300.0 million of 6.50% senior, unsecured notes~~may redeem the Rights 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~~whole, but not in ~~April 2018. The holders of the notes may require the Company to repurchase their notes in the event of a change in control~~part, at a price ~~equal~~of $0.005 per Right, payable in cash or stock. A decision to ~~101%~~redeem the Rights requires the vote of 75% of the ~~principal amount. In addition,~~Company’s full Board of Directors. Also, at any time following the ~~Company is required to either offer~~Distribution Date, 75% of the Company’s full Board of Directors may vote to exchange the ~~notes for substantially similar notes as are registered under the Securities Act of 1933~~Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain ~~circumstances, register the resale~~adjustments.

Upon exercise of the ~~notes. The~~Rights, the Company ~~used $200.0 million~~may need additional regulatory approvals to satisfy the requirements of the ~~proceeds~~Rights Agreement. The Rights will expire on July 31, 2018, unless earlier than that date, they are exchanged or redeemed or the Plan is amended to ~~refund $200.0 million of 6.303% medium-term notes that subsequently matured on May 27, 2008.~~extend the expiration date.

Note 45 — Commitments and Contingencies

Environmental Matters.The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.

As disclosed in Note H of the Company’s ~~2007~~2008 Form 10-K, the Company ~~received, in 1998 and again in October 1999, notice that~~has agreed with the NYDEC ~~believes the Company is responsible for contamination discovered at~~to remediate a former manufactured gas plant site located in New ~~York for which the~~York. The Company ~~had not been named as~~has submitted 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 commentedRemedial Design/Remedial Action work plan 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 for remediation of ~~$10.4 million associated with~~ this ~~site.~~site of $16.4 million.

At ~~June 30,~~December 31, 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~~$19.3 million to ~~$17.2~~$23.5 million. The minimum estimated liability of ~~$13.5~~$19.3 million, which includes the $16.4 million discussed above, has been recorded on the Consolidated Balance Sheet at ~~June 30, 2008, including the $10.4 million discussed above.~~December 31, 2008. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet.

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

Other.The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings

~~-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~~or 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~~In the Company’s 2008 Form 10-K, the Company ~~has~~reported financial results for five ~~reportable~~business segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing and Timber. The division of the Company’s operations into the ~~reportable~~reported segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors. During the quarter ended December 31, 2008, management made the decision to eliminate the Timber segment as a reportable segment based on the fact that the Timber operations do not meet any of the quantitative thresholds specified by SFAS 131. Furthermore, from a qualitative standpoint, management’s focus has changed regarding the Timber operations. While the Timber segment will continue to harvest hardwood

-20-

Item 1.Financial Statements (Cont.)

timber and process lumber products that are used in high-end furniture, cabinetry and flooring, management no longer considers the Timber operations to be integral to the overall operations of the Company. As a result of this change in focus and the fact that the Timber operations cannot be aggregated into one of the other four reportable business segments, the Timber operations have been included in the All Other category in the disclosures that follow. Prior year segment information shown below has been restated to reflect this change in presentation.

The data presented in the tables below reflect the ~~reportable~~reported segments and reconciliations to consolidated amounts. As stated in the ~~2007~~2008 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting ~~(where~~(when applicable). When these items are not applicable, the Company evaluates performance based on net income. There have been no changes in the basis of segmentation, other than as noted above, nor in the basis of measuring segment profit or loss, from those used in the Company’s ~~2007~~2008 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~~2008 Form 10-K. While the Exploration and Production segment reported a pre-tax impairment charge of $182.8 million at December 31, 2008, this reduction in segment assets was largely offset by increases in the asset position of its derivative financial instruments combined with the receipt of cash collateral on such derivative financial instruments.

Quarter Ended December 31, 2008 (Thousands)


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

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

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

Segment Profit:

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

Quarter Ended December 31, 2007 (Thousands)


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

Revenue from External Customers	$	327,125	$	31,884	$	107,955	$	86,719	$	553,683	$	14,450	$	135		$	568,268

Intersegment Revenues	$	4,299	$	20,347	$	—	$	—	$	24,646	$	2,714	$	(27,360	)	$	—

Segment Profit:

Net Income (Loss)	$	20,217	$	12,778	$	34,022	$	954	$	67,971	$	2,736	$	(103	)	$	70,604

~~-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-~~-21-

Item 1.Financial Statements (Cont.)

As indicated under “New Accounting Pronouncements” in Note 1 – Summary of Significant Accounting Policies, in accordance with the measurement date provisions of SFAS 158 that 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, the Company will be recording fifteen months of pension and other post-retirement benefit costs during fiscal 2009. As allowed by SFAS 158, these costs have been calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $3.8 million and have been recorded by the Company during the quarter ended December 31, 2008 as a $3.4 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $0.4 million ($0.2 million after tax) adjustment to earnings reinvested in the business. In addition, for the Company’s non-qualified pension plan, benefit costs of $1.3 million have been recorded by the Company during the quarter ended December 31, 2008 as a $0.4 million increase to Other Regulatory Assets in the Company’s Utility segment and a $0.9 million ($0.6 million after tax) adjustment to earnings reinvested in the business. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be fully adopted by the Company by the end of fiscal 2009.

Employer Contributions.During the ~~nine~~three months ended ~~June 30,~~December 31, 2008, the Company contributed ~~$3.8~~$7.0 million to its retirement plan and ~~$25.3~~$6.6 million to its VEBA trusts and 401(h) accounts infor its other post-retirement ~~benefit plan.~~benefits. In the remainder of ~~2008,~~2009, the Company expects to contribute ~~$12.2~~in the range of $8.0 million to $13.0 million to its retirement plan. As a result of the recent downturn in the stock markets and general economic conditions, it is likely that the Company will have to fund larger amounts to the retirement plan ~~and $3.8~~subsequent to fiscal 2009 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2009, the Company expects to contribute in the range of $18.0 million to $23.0 million to its VEBA trusts and 401(h) ~~accounts in its other post-retirement benefit plan.~~accounts.

~~-22-~~-23-

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

OVERVIEW

~~The~~In the Company’s 2008 Form 10-K, the Company ~~is a diversified energy company~~reported financial results for five business segments: Utility, Pipeline and ~~reports its operating results in five reportable business segments. For~~Storage, Exploration and Production, Energy Marketing and Timber. During the quarter ended ~~June 30,~~December 31, 2008, management made the decision to eliminate the Timber segment as a reportable segment based on the fact that the Timber operations do not meet any of the quantitative thresholds specified by SFAS 131. Furthermore, from a qualitative standpoint, management’s focus has changed regarding the Timber operations. While the Timber segment will continue to harvest hardwood timber and process lumber products that are used in high-end furniture, cabinetry and flooring, management no longer considers the Timber operations to be integral to the overall operations of the Company. As a result of this change in focus and the fact that the Timber operations cannot be aggregated into one of the other four reportable business segments, the Timber operations have been included in the All Other category in the disclosures that follow. Prior year segment information shown below has been restated to reflect this change in presentation.

The Company experienced a loss of $42.7 million for the quarter ended December 31, 2008 compared to earnings of $70.6 million for the quarter ended ~~June 30, 2007,~~December 31, 2007. The loss for the ~~Company has experienced~~quarter ended December 31, 2008 was driven largely by an ~~increase in earnings~~impairment charge of ~~$13.1~~$182.8 million ~~primarily due to higher earnings~~($108.2 million after tax) recorded in the Exploration and Production segment. ~~The Utility segment and~~In 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~~oil 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 continuedgas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Such costs are subject to a quarterly ceiling test prescribed by SEC Regulation S-X Rule 4-10 that determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. At December 31, 2008, due to significant declines in crude oil and natural gas commodity prices (Cushing, Oklahoma West Texas Intermediate oil reported spot price of $44.60 per Bbl at December 31, 2008 versus a reported price of $100.70 per Bbl at September 30, 2008; Henry Hub natural gas reported spot price of $5.63 per MMBtu at December 31, 2008 versus a reported price of $7.12 per MMBtu at September 30, 2008), the book value of the Company’s oil and gas properties exceeded the ceiling, resulting in the ~~Gulf and West Coast regions. In the Pipeline and Storage segment, the majority~~impairment charge mentioned above. (Note — Because actual pricing of the ~~expenditures~~Company’s various producing properties varies depending on their location, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Cushing oil and Henry Hub prices, which are only indicative.) If natural gas prices used in the ceiling test calculation at December 31, 2008 had been $1 per MMBtu lower, the Company would have recorded an additional impairment charge of approximately $51 million (after tax). If crude oil prices used in the ceiling test calculation at December 31, 2008 had been $5 per Bbl lower, the Company would have recorded an additional impairment charge of approximately $53 million (after tax). If both natural gas and crude oil prices used in the ceiling test calculation at December 31, 2008 were lower by $1 per MMBtu and $5 per Bbl, respectively, the Company would have recorded an additional impairment charge of approximately $104 million (after tax). These calculated impairment charges are based solely on price changes and do not take into account any other changes to the ceiling test calculation.

Despite the loss for ~~construction costs~~the quarter ended December 31, 2008, the Company’s balance sheet remains strong with a capitalization structure of 58% equity and 42% debt at December 31, 2008. The Company also continues to have strong liquidity despite the generally reported problems in the credit markets. The Company has been able to borrow short-term funds under its credit lines and through the commercial paper market to fund working capital needs throughout the quarter. The Company maintains a number of individual uncommitted or discretionary lines of credit with financial institutions for general corporate purposes. These credit lines, which aggregate to $420.0 million, are revocable at the option of the ~~Empire Connector project.~~financial institutions and are reviewed on an annual basis. The ~~project is on schedule~~Company anticipates that these lines of credit will continue to be ~~completed~~renewed, or replaced 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,similar lines. At December 31, 2008, the Company had ~~repurchased 6,667,275 shares for $262.8~~borrowed $66.0 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.

its lines of credit. The ~~Company has begun~~total amount available 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 inbe issued under the Company’s ~~All Other category.~~commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million, which commitment extends through September 30, 2010. At December 31, 2008, 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.did not have any borrowings under its committed credit facility.

CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to “Critical Accounting Estimates” in Item 7 of the Company’s ~~2007~~2008 Form 10-K. There have been no ~~subsequent~~material changes to that ~~disclosure.~~disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K.

~~-23-~~-24-

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

Oil and Gas Exploration and Development Costs.The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties. In accordance with this methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company’s oil and gas reserves based on current market prices (the “ceiling”) is compared with the book value of those reserves at the balance sheet date. If the book value of the reserves in any country exceeds the ceiling, a non-cash charge must be recorded to reduce the book value of the reserves to the calculated ceiling. As disclosed in the Company’s 2008 Form 10-K, at September 30, 2008, the ceiling exceeded the book value of the Company’s oil and gas properties by approximately $500 million. Because of declines in commodity prices since September 30, 2008, the book value of the Company’s oil and gas properties exceeded the ceiling at December 31, 2008. The quoted Cushing, Oklahoma spot price for West Texas Intermediate oil had declined from a reported price of $100.70 per Bbl at September 30, 2008 to a reported price of $44.60 per Bbl at December 31, 2008. The quoted Henry Hub spot price for natural gas had declined from a reported price of $7.12 per MMBtu at September 30, 2008 to a reported price of $5.63 per MMBtu at December 31, 2008. Consequently, the Company recorded an impairment charge of $182.8 million ($108.2 million after-tax) during the quarter ended December 31, 2008. (Note — Because actual pricing of the Company's various producing properties varies depending on their location, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Cushing oil and Henry Hub prices, which are only indicative.) If natural gas prices used in the ceiling test calculation at December 31, 2008 had been $1 per MMBtu lower, the Company would have recorded an additional impairment charge of approximately $51 million (after tax). If crude oil prices used in the ceiling test calculation at December 31, 2008 had been $5 per Bbl lower, the Company would have recorded an additional impairment charge of approximately $53 million (after tax). If both natural gas and crude oil prices used in the ceiling test calculation at December 31, 2008 were lower by $1 per MMBtu and $5 per Bbl, respectively, the Company would have recorded an additional impairment charge of approximately $104 million (after tax). These calculated impairment charges are based solely on price changes and do not take into account any other changes to the ceiling test calculation. For a more complete discussion of the full cost method of accounting, refer to “Oil and Gas Exploration and Development Costs” under “Critical Accounting Estimates” in Item 7 of the Company’s 2008 Form 10-K.

Accounting for Derivative Financial Instruments.The Company, in its Exploration and Production segment, Energy Marketing segment, and Pipeline and Storage segment, uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments are categorized as price swap agreements and futures contracts. Gains or losses associated with the derivative financial instruments are matched with gains or losses resulting from the underlying physical transaction that is being hedged. To the extent that the derivative financial instruments would ever be deemed to be ineffective based on the effectiveness testing, mark-to-market gains or losses from the derivative financial instruments would be recognized in the income statement without regard to an underlying physical transaction.

The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The Company adopted SFAS 157 during the quarter ended December 31, 2008. As such, the fair value of such derivative financial instruments is determined under the provisions of SFAS 157. The fair value of exchange traded derivative financial instruments is determined from Level 1 inputs, which are quoted prices in active markets. The Company determines the fair value of non exchange-traded derivative financial instruments based on an internal model, which uses both observable and unobservable inputs other than quoted prices. These inputs are considered Level 2 or Level 3 inputs. All derivative financial instrument assets and liabilities are evaluated for the probability of default by either the counterparty or the Company. Credit reserves are applied against the fair values of such assets or liabilities. For a more complete discussion of the types of derivative financial instruments used by the Company, refer to the “Market Risk Sensitive Instruments” section in Item 7 of the Company’s 2008 Form 10-K.

-25-

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~~Company experienced a loss of $42.7 million for the quarter ended ~~June 30,~~December 31, 2008 compared to earnings of ~~$46.8~~$70.6 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,December 31, 2007. The ~~increase~~decrease in earnings ~~from continuing operations~~ of ~~$18.7~~$113.3 million is primarily the result of ~~higher earnings~~a loss recognized in the Exploration and Production segment. ~~The Utility~~Lower earnings in the Energy Marketing segment, ~~and~~as well as a loss in the All Other category, also contributed to the ~~increase in earnings. These earnings increases discussed above were slightly offset by lower~~decrease. Higher earnings in the Utility and Pipeline and Storage ~~and Energy Marketing~~ segments ~~as well as in~~and the Corporate category ~~combined with a higher loss in the Timber segment.~~

slightly offset these decreases. The Company’s ~~earnings were $225.5 million~~loss for the ~~nine months~~quarter ended ~~June 30,~~December 31, 2008, ~~compared to earnings of $179.8~~includes a non-cash $182.8 million ~~for the nine months ended June 30, 2007. The Company’s earnings from continuing operations were $225.5~~impairment charge ($108.2 million after tax) 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~~segment’s oil and gas producing properties under the ~~All Other category also contributed to~~full cost method of accounting using crude oil and natural gas commodity pricing at December 31, 2008, which were lower than the ~~increase in earnings. These earnings increases discussed above were slightly offset by lower earnings in~~pricing at September 30, 2008, the ~~Pipeline and Storage, Energy Marketing, and Timber segments as well as in the Corporate category.~~

last ceiling test measurement date. 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~~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

Three Months Ended December 31(Thousands)


							Increase
	2008			2007			(Decrease)
Utility	$	22,088		$	20,217		$	1,871
Pipeline and Storage		17,176			12,778			4,398
Exploration and Production		(83,557	)		34,022			(117,579	)
Energy Marketing		599			954			(355	)

Total Reportable Segments		(43,694	)		67,971			(111,665	)
All Other		(868	)		2,736			(3,604	)
Corporate		1,884			(103	)		1,987

Total Consolidated	$	(42,678	)	$	70,604		$	(113,282	)

Utility

Utility Operating Revenues

Three Months Ended December 31(Thousands)


					Increase
	2008		2007		(Decrease)
Retail Sales Revenues:
Residential	$	272,418	$	246,797	$	25,621
Commercial		41,333		38,033		3,300
Industrial		2,106		1,651		455

		315,857		286,481		29,376

Transportation		32,011		33,424		(1,413	)
Off-System Sales		3,732		8,213		(4,481	)
Other		2,590		3,306		(716	)

	$	354,190	$	331,424	$	22,766

~~-24-~~-26-

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

Three Months Ended December 31(MMcf)


					Increase
	2008		2007		(Decrease)
Retail Sales:
Residential		18,166		17,127		1,039
Commercial		2,911		2,877		34
Industrial		143		123		20

		21,220		20,127		1,093
Transportation		17,473		17,827		(354	)
Off-System Sales		512		1,031		(519	)

		39,205		38,985		220

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 )

Three Months Ended December 31


							Percent
							Colder (Warmer) Than
	Normal		2008		2007		Normal			Prior Year
Buffalo		2,260		2,313		2,094		2.3			10.5
Erie		2,081		2,067		1,871		(0.7	)		10.5

2008 Compared with 2007

Operating revenues for the Utility segment increased ~~$7.3~~$22.8 million for the quarter ended ~~June 30,~~December 31, 2008 as compared with the quarter ended ~~June 30,~~December 31, 2007. ~~The~~This increase ~~for the quarter is primarily attributable to~~largely resulted from a ~~$16.8~~$29.4 million increase in ~~off-system sales revenue (see discussion below) partially offset by~~retail gas revenues coupled with a ~~$10.0~~$4.5 million decrease in ~~retail~~off-system sales ~~revenue.~~revenues and a $1.4 million decrease in transportation revenues.

The ~~$10.0 million decrease~~increase in retail gas sales revenues for the Utility segment was ~~a function~~primarily due to higher retail sales volumes, as shown in the table above. The volume increase, most notably in the residential category, is primarily the result of ~~lower throughput volumes, partially offset by~~weather that was 10.5 percent colder than the ~~recovery of higher gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar~~prior year in ~~revenues) coupled with~~both operating jurisdictions.

In the ~~revenue impact of a rate design change. In December 2007,~~New York jurisdiction, 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, thus spreading the recovery of such costs more evenly throughout the year. As a result of this rate order, retail and transportation revenues for the quarter ended December 31, 2008 were $2.2 million lower than revenues for the quarter ended December 31, 2007.

Total off-system sales revenues for the quarters ended December 31, 2008 and December 31, 2007 amounted to $3.7 million and $8.2 million, respectively. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was no material impact to margins for the quarters ended December 31, 2008 and 2007. On October 16, 2008, the FERC issued Order No. 717 (“Final Rule”). The Final Rule regarding the standards of conduct was effective November 26, 2008. The Final Rule seemingly holds that a local distribution company making off-system sales on unaffiliated pipelines would engage in “marketing” that would require compliance with the FERC’s standards of conduct. Accordingly, pending clarification from the FERC of this issue, as of November 1, 2008, Distribution Corporation ceased off-system sales activities.

The Utility segment’s earnings for the quarter ended December 31, 2008 were $22.1 million, an increase of $1.9 million when compared with earnings of $20.2 million for the quarter ended December 31, 2007. In the Pennsylvania jurisdiction, earnings increased $0.6 million. The major factors contributing to this increase were the positive earnings impact associated with colder weather ($0.8 million), a slight increase in usage per account ($0.2 million), and lower interest expense ($0.2 million), offset by higher operating expenses of $0.6 million (primarily bad debt expense due to higher gas costs and the possible impact current economic conditions may have on customers). In the New York jurisdiction, earnings increased $1.3 million. This increase was primarily the result of $1.9 million in lower operating expenses (primarily due to a decrease in other post-retirement benefit costs) and lower interest expense ($0.6 million). These increases were partly offset by the earnings impact of the December 28, 2007 rate order discussed above ($1.4 million). The

~~-25-~~-27-

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

~~thus spreading~~phrase “usage per account” in this paragraph refers to the ~~recovery of such~~average gas consumption per customer account after factoring out any impact that weather may have had on consumption. The decrease in other post-retirement benefit costs ~~more evenly throughout~~discussed above stems from the ~~year. This~~NYPSC rate ~~design change resulted in lower retail and transportation revenues~~order that became effective December 28, 2007 whereby the rate allowance for post-retirement benefit costs was reduced given projected reductions 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, 2007other post-retirement benefit obligation as a result of ~~the rate design change. It is expected that there will also be~~ an increase in ~~retail~~the discount rate from 5% to 6.25% during 2006. The decreases to interest expense primarily reflect lower borrowings 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 toslightly 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.rates.

The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. For the quarter ended ~~June 30,~~December 31, 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. For the quarter ended December 31, 2007, the WNC preserved $1.1 million of earnings, as weather was warmer than normal for the period. In periods of colder than normal weather, the WNC benefits Distribution Corporation’s New York customers.

Pipeline and Storage

Pipeline and Storage Operating Revenues

Three Months Ended December 31(Thousands)


	2008		2007		Increase
Firm Transportation	$	33,105	$	31,406	$	1,699
Interruptible Transportation		1,103		991		112

		34,208		32,397		1,811

Firm Storage Service		16,686		16,621		65
Other		5,210		3,213		1,997

	$	56,104	$	52,231	$	3,873

Pipeline and Storage Throughput

Three Months Ended December 31(MMcf)


	2008		2007		Increase
Firm Transportation		110,315		92,883		17,432
Interruptible Transportation		1,792		1,083		709

		112,107		93,966		18,141

2008 Compared with 2007

Operating revenues for the Pipeline and Storage segment increased $3.9 million in the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. This increase consisted of a $1.8 million increase in firm and interruptible transportation revenues. The Pipeline and Storage segment was able to obtain multiple new contracts for firm transportation service in the quarter ended December 31, 2008 which resulted in higher reservation, commodity and surcharge, and overrun revenues. In addition, there were increased efficiency gas revenues ($2.0 million) reported as part of other revenues in the table above. Under Supply Corporation’s tariff with shippers, Supply Corporation is allowed to retain a set percentage of shipper-supplied gas to cover compressor fuel costs and other operational purposes. To the extent that Supply Corporation does not need all of the gas to cover such operational needs, it is allowed to keep the excess gas as inventory. That inventory is later sold to customers. The excess gas that is retained as inventory represents efficiency gas revenue to Supply Corporation. During the quarter ended December 31, 2008, Supply Corporation retained a higher volume of gas than was retained during the quarter ended December 31, 2007.

The ~~Utility~~Pipeline and Storage segment’s earnings for the ~~nine months~~quarter ended ~~June 30,~~December 31, 2008 were ~~$62.2 million;~~$17.2 million, an increase of ~~$7.9~~$4.4 million when compared with earnings of ~~$54.3~~$12.8 million for the ~~nine months~~quarter ended ~~June 30,~~December 31, 2007. ~~In the New York jurisdiction, earnings increased $5.2 million. Lower operating costs of $4.5 million (mostly~~The increase is largely attributable to higher transportation revenues ($1.2 million) due to ~~lower post-retirement benefit costs~~the addition of new contracts for firm transportation service and ~~lower bad debt expense), the positive impact of non-recurring regulatory adjustments made in 2007~~higher efficiency gas revenues ($~~0.9~~1.3 million), ~~the positive impact of a lower effective~~as discussed above. In addition, there was an increase in allowance for funds

~~-26-~~-28-

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~~used during construction of $2.1 million. The 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.

~~-27-~~

~~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~~is a result of 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~~construction 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~~which was completed and placed in service on December 10, 2008. Construction of the ~~quarter ended June 30, 2007. In addition, there was a $1.9 million positive earnings impact during~~Empire Connector began in September 2007 so 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 thecalculated allowance for funds used during construction ~~($2.3 million),~~was relatively small during the quarter ended December 31, 2007. With much more significant construction work in progress balances during the quarter ended December 31, 2008, the calculated allowance for funds used during construction was much higher. These earnings increases were partially offset by higher ~~efficiency gas revenues ($2.0 million), and~~interest expense of $0.4 million. The increase in interest expense was due to higher ~~transportation and storage revenues ($2.5 million).~~borrowings.

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 )

Three Months Ended December 31(Thousands)


							Increase
	2008			2007			(Decrease)
Gas (after Hedging)	$	41,093		$	45,557		$	(4,464	)
Oil (after Hedging)		53,071			59,643			(6,572	)
Gas Processing Plant		7,328			11,075			(3,747	)
Other		417			(1,309	)		1,726
Intrasegment Elimination⁽¹⁾		(5,197	)		(7,011	)		1,814

	$	96,712		$	107,955		$	(11,243	)


⁽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.

~~-28-~~

~~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 )

Three Months Ended December 31


					Increase
	2008		2007		(Decrease)
Gas Production(MMcf)
Gulf Coast		1,746		2,826		(1,080	)
West Coast		1,022		1,027		(5	)
Appalachia		1,851		1,917		(66	)

Total Production		4,619		5,770		(1,151	)


Oil Production(Mbbl)
Gulf Coast		128		156		(28	)
West Coast		682		629		53
Appalachia		15		37		(22	)

Total Production		825		822		3

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
Three Months Ended December 31

~~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


					Increase
	2008		2007		(Decrease)
Average Gas Price/Mcf
Gulf Coast	$	7.04	$	7.14	$	(0.10	)
West Coast	$	5.02	$	6.77	$	(1.75	)
Appalachia	$	8.53	$	7.45	$	1.08
Weighted Average	$	7.19	$	7.18	$	0.01
Weighted Average After Hedging	$	8.90	$	7.90	$	1.00

Average Oil Price/Bbl
Gulf Coast	$	56.19	$	89.84	$	(33.65	)
West Coast	$	48.01	$	81.80	$	(33.79	)
Appalachia	$	69.06	$	84.12	$	(15.06	)
Weighted Average	$	49.66	$	83.43	$	(33.77	)
Weighted Average After Hedging	$	64.34	$	72.59	$	(8.25	)

-29-

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

~~$36.01~~2008 Compared with 2007

Operating revenues for the Exploration and Production segment decreased $11.2 million for the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. Oil production revenue after hedging decreased $6.6 million. A decrease in the weighted average price of oil after hedging ($8.25 per ~~barrel~~Bbl) was the primary cause, as a production increase in ~~weighted average prices after hedging for continuing operations.~~the West Coast offset decreases in Gulf Coast and Appalachian production, keeping overall oil production flat. Gas production revenue after hedging ~~from continuing operations increased $21.9 million due to~~decreased $4.5 million. A decrease in gas production (1,151 MMcf) more than offset an increase in the weighted average price of gas after hedging ~~for continuing operations~~ ($~~2.19~~1.00 per Mcf) ~~as well as an increase~~. The decrease in gas production ~~of 1,217 MMcf. The~~occurred primarily in this segment’s Gulf Coast region (1,080 MMcf), which is mainly the result of ~~this segment was primarily responsible~~lingering shut-ins caused by Hurricane Ike in September 2008. While Seneca’s properties sustained only superficial damage from the hurricanes, two significant producing properties remained shut-in for the ~~increase in natural gas production from continuing operations (702 MMcf). Production from new fields in~~quarter ended December 31, 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~~repair work on third party pipelines and onshore processing facilities. All pre-hurricane production is expected to be back on line by the ~~weighted average price~~end of ~~gas after hedging for continuing operations ($1.66 per Mcf)~~the quarter ended March 31, 2009. Appalachian production was slightly lower due to compressor down time 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.pipeline constraints.

The Exploration and Production segment’s ~~earnings from continuing operations~~loss for the quarter ended ~~June 30,~~December 31, 2008 ~~were $39.8~~was $83.6 million ~~an increase of $21.0 million when~~ compared with earnings ~~from continuing operations~~ of ~~$18.8~~$34.0 million for the quarter ended ~~June 30, 2007. Higher~~December 31, 2007, a decrease of $117.6 million. The decrease in earnings is primarily the result of an impairment charge of $108.2 million, as discussed above. Also, lower natural gas production and lower crude oil prices ~~higher~~decreased earnings by $5.9 million, and $4.4 million, respectively. Higher natural gas prices ~~and higher natural gas production increased earnings~~slightly offset these decreases by ~~$17.4 million, $8.3 million and $6.0 million, respectively, while lower crude oil production decreased earnings by $1.8~~$3.0 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)~~of $1.7 million and higher lease operating expenses of $1.3 million also ~~negatively impacted~~contributed to the decrease in earnings. Lower ~~interest~~depletion expense of ~~$2.1~~$0.6 million ~~slightly offset these decreases.~~

made a small contribution to earnings. 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), higherin general and administrative and other operating expenses ~~($3.8 million),~~is mainly due to a bad debt charge related to a customer’s bankruptcy filing combined with higher personnel costs in the Appalachian region. The increase in lease operating expenses is primarily due to higher production taxes related to increased production from the High Island 24L and ~~mark-to-market adjustments on derivative financial instruments ($1.3 million) also negatively impacted earnings. Lower interest expense~~23L fields in the Gulf Coast region, higher property taxes and increased well repair costs associated with higher than normal activity in the West Coast region, and an increase in the number of ~~$4.5 million and higher interest income of $1.6 million slightly offset these decreases.~~producing properties in the Appalachian region.

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

Three Months Ended December 31(Thousands)


	2008		2007			Increase
Natural Gas (after Hedging)	$	114,984	$	86,735		$	28,249
Other		23		(16	)		39

	$	115,007	$	86,719		$	28,288

Energy Marketing Volumes

Three Months Ended December 31


	2008		2007		Increase
Natural Gas – (MMcf)		13,136		10,841		2,295

2008 Compared with 2007

Operating revenues for the Energy Marketing segment increased $28.3 million for the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. The increase primarily reflects an increase in volumes, largely attributable to sales transactions undertaken to offset certain basis risks that the Energy Marketing segment was exposed to under certain commodity purchase contracts. These offsetting transactions had the effect of increasing revenue and volumes sold with minimal impact to earnings.

-30-

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

The 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 )

~~-31-~~

~~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~~segment’s earnings 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,~~December 31, 2008 were ~~$2.2~~$0.6 million, a decrease of ~~$0.9~~$0.4 million when compared with earnings of ~~$3.1~~$1.0 million for the ~~nine months~~quarter ended ~~June 30,~~December 31, 2007. ~~The decrease was~~Despite colder weather, earnings decreased 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.

~~-32-~~

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

Corporate and All Other

2008 Compared with 2007

Corporate and All Other operations recorded earnings of ~~$1.3~~$1.0 million for the quarter ended ~~June 30,~~December 31, 2008, a decrease of $1.6 million when compared ~~with~~to the earnings of ~~$2.3~~$2.6 million recorded for the quarter ended ~~June 30,~~December 31, 2007. The ~~positive~~decrease in earnings ~~impacts of higher~~was due to lower margins from log and lumber sales ($1.3 million), lower interest income ($1.2 million), lower equity method income from Horizon Power’s investments in unconsolidated subsidiaries ($~~0.4~~0.8 million), and ~~lower income tax expense ($0.4 million) were more than offset by~~ higher interest expense ($~~1.2~~0.5 million). In addition, during the quarter ended December 31, 2008, ESNE, an unconsolidated subsidiary of Horizon Power, recorded an impairment charge of $3.6 million. Horizon Power’s 50% share of the impairment was $1.8 million ($1.1 million on an after tax basis). ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. The impairment was driven by a significant decrease in “run time” for the plant given the economic downturn and the resulting decrease in demand for electric power. The decreases were partially offset by lower operating expenses ($1.1 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 ($0.7 million), a gain resulting from a death benefit on corporate-owned life insurance policies held by the ~~sale of a turbine by Horizon Power~~Company ($~~0.6~~2.3 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~~$1.2 million ~~higher~~lower in the quarter ended ~~June 30,~~December 31, 2008 as compared to the quarter ended ~~June 30,~~December 31, 2007. ~~For the nine months ended June 30, 2008, interest~~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~~was $1.6 million ~~and $4.0 million, respectively, for~~lower during the quarter ~~and nine months~~ ended ~~June 30,~~December 31, 2008 as compared to the quarter ~~and nine months~~ ended ~~June 30,~~December 31, 2007 as a result of lower interest rates and lower average temporary cash investment balances.

Other Income

Other Income increased $4.1 million for the ~~investment~~quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. This increase is attributable to an increase in the allowance for funds used during construction of ~~cash~~$2.1 million in the Pipeline and Storage segment associated with the Empire Connector project, as well as a death benefit gain on life insurance proceeds ~~received from~~of $2.3 million recognized in the ~~sale of SECI in August 2007.~~Corporate category.

Interest Expense on Long-Term Debt

Interest on long-term debt increased ~~$1.2~~$1.8 million for the quarter ended ~~June 30,~~December 31, 2008 as compared with the quarter ended ~~June 30,~~December 31, 2007. ~~For the nine months ended June 30, 2008, interest on~~This increase can be attributed to a higher average amount of 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~~outstanding. In April 2008, ~~of a~~the Company issued $300 million of 6.5% ~~Note~~senior, unsecured notes due in April 2018. This increase was partially 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~~source of cash during the ~~nine-month period~~three-month periods ended ~~June 30,~~December 31, 2008 and December 31, 2007 consisted of cash provided by operating ~~activities and proceeds from the issuance of long-term debt. These sources~~activities. This source of cash ~~were~~was supplemented by ~~issues~~issuances of new shares of common stock as a result of stock option ~~exercises.~~exercises and by short-term borrowings (for the quarter ended December 31, 2008). During the ~~nine~~three months ended ~~June 30,~~December 31, 2008 and December 31, 2007, 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.~~

~~-33-~~-31-

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, impairment of oil and gas producing properties, impairment of investment in partnerships, 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~~$100.1 million for the ~~nine~~three months ended ~~June 30,~~December 31, 2008, an increase of ~~$10.5~~$24.8 million when compared with ~~$404.6~~the $75.3 million provided by operating activities for the ~~nine~~three months ended ~~June 30,~~December 31, 2007. The increase is ~~partially~~primarily due to ~~lower working capital requirements~~higher cash provided by operating activities 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. Despite lower crude oil prices and lower natural gas production, this 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~~experienced an increase in cash provided by ~~operations that resulted~~operating activities due to the receipt of hedging collateral deposits from some of the ~~sale of SECI in August 2007. Offsetting these increases were higher working capital requirements in the Energy Marketing segment.~~counterparties to its derivative financial instruments.

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled ~~$284.6~~$119.2 million ~~during~~for the ~~nine~~three months ended ~~June 30, 2008.~~December 31, 2008 and $69.7 million for the three months ended December 31, 2007. The table below presents these expenditures:

~~-34-~~-32-

~~Supply Corporation continues to view its potential Tuscarora Extension project as an important link to Millennium and potential storage development~~Appalachia — specifically 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,Marcellus Shale producing area — Supply Corporation is ~~also exploring a new project (the~~actively pursuing development of its Appalachian Lateral pipeline project. The Appalachian Lateral is expected to be routed through areas in Pennsylvania where producers are actively drilling and are seeking market access for their newly discovered reserves. The Appalachian Lateral will complement Supply Corporation’s original West to East ~~project) that would provide for new capacity~~(“W2E”) project, which was designed to transport Rockies gas supply from Clarington, Ohio to the ~~Rockies Express Project,~~Ellisburg/Leidy/Corning area and includes the Tuscarora-to-Corning facilities previously referred to as the Tuscarora Extension. The Appalachian ~~production, storage and other~~Lateral will transport gas supply from Pennsylvania’s producing area to the Overbeck area of Supply Corporation’s existing system, where the facilities associated with the W2E project will move the gas to eastern market points, toincluding Leidy, and to interconnections with Millennium and Empire at Corning. ~~The West~~Engineering analyses to ~~East project could include the Tuscarora Extension project, or could be a second phase following~~evaluate routing options and the development of an updated project cost estimate are under way.

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~~with service commencing as early as 2011. Supply Corporation expects that the availability of this incremental storage capacity will complement the ~~West to East and~~ Appalachian ~~Lateral~~Lateral/W2E pipeline transportation projects and help ~~meet~~balance the ~~demand for storage created by the prospective increased~~increasing flow of ~~Rockies~~Appalachian and ~~Appalachian~~Rockies gas supply into the western Pennsylvania area, ~~although traditional~~and the growing demand for 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.~~on the east coast.

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~~Appalachian Lateral/W2E transportation projects is estimated to ~~East~~be in the range of $750 million to $1 billion, and ~~Appalachian Lateral projects would amount~~is expected to ~~at least $700 million, which would~~ be financed by a combination of debt and equity. As of ~~June 30,~~December 31, 2008, ~~there have been no costs incurred by Supply Corporation related to the Tuscarora Extension project, $0.1~~$0.2 million has been spent to study the ~~West to East and~~ Appalachian ~~Lateral~~Lateral/W2E transportation projects, and approximately ~~$0.2~~$0.8 million has been spent to study the storage expansion project. Costs associated with these projects have been included in preliminary survey and investigation charges and have been fully reserved for at December 31, 2008. Supply Corporation has not yet filed an application with the FERC for the authority to build either pipeline project or the storage ~~expansion(s).~~expansion.

Exploration and Production

The Exploration and Production segment capital expenditures for the ~~nine~~three months ended ~~June 30,~~December 31, 2008 were primarily well drilling and completion expenditures and included approximately ~~$46.9~~$11.9 million for the Gulf Coast region, substantially all of which was for the off-shore program in the shallow waters of the Gulf of Mexico, ~~$51.1~~$10.4 million for the West Coast region and ~~$42.6~~$64.1 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~~$10.2 million spent to develop proved undeveloped reserves.

~~Timber~~ For all of 2009, the Company expects to spend $244 million on Exploration and Production segment capital expenditures. Previously reported 2009 capital expenditures for the Exploration and Production segment were $285 million. The decrease in estimated capital expenditures is primarily due to low commodity prices. Estimated capital expenditures in the Gulf Coast region will decrease from $35.0 million to $19.0 million. Estimated capital expenditures in the West Coast region will decrease from $54.0 million to $35.0 million. In the Appalachian region, estimated capital expenditures will decrease from $196.0 million to $190.0 million.

The ~~majority of the Timber~~Exploration and Production segment capital expenditures for the ~~nine~~three months ended ~~June 30, 2008 were~~December 31, 2007 included approximately $6.8 million for ~~construction~~the Gulf Coast region, substantially all of ~~a lumber sorter~~which was 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~~the off-shore program in the ~~development~~Gulf of ~~a co-generation plant. Horizon Power received proceeds of $5.3~~Mexico, $12.8 million for the West Coast region and ~~recorded a pre-tax gain of $0.9~~$11.1 million ~~associated with~~for the ~~sale.~~Appalachian region. These amounts included $4.5 million spent to develop proved undeveloped reserves.

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

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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~~Consolidated short-term ~~notes payable to banks or commercial paper at June 30,~~debt increased $66.0 million during the three months ended December 31, 2008. ~~However, the~~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. At December 31, 2008, the Company had outstanding short-term notes payable to banks of $66.0 million. There was no outstanding commercial paper at December 31, 2008. 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~~$420.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed, or replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility ~~which totals~~totaling $300.0 million, ~~and~~which commitment extends through September 30, 2010.

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

Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September 30, 2010. At ~~June 30,~~December 31, 2008, the Company’s debt to capitalization ratio (as calculated under the facility) was ~~.41.~~.42. The constraints specified in the committed credit facility would permit an additional ~~$1.84~~$1.79 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 committed credit facility, 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,~~December 31, 2008, the Company would have been permitted to issue up to a maximum of ~~$1.2~~$0.9 billion in additional long-term unsecured indebtedness at ~~then-current~~then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands. However, if the Company was to experience another impairment of oil and gas properties this year, it is possible that these indenture covenants would restrict the Company’s ability to issue additional long-term unsecured indebtedness. This would not preclude the Company from issuing new indebtedness to replace maturing debt.

The Company’s 1974 indenture, pursuant to which $199.0 million (or 18%) of the Company’s long-term debt (as of ~~June 30,~~December 31, 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 (i) to ~~(i)~~ pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fail to make a payment when due of any principal or interest on any other indebtedness aggregating $20.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $20.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of ~~June 30,~~December 31, 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 iswas 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. In November 2008, the Company filed a registration statement with the SEC in connection with the Company’s plan to offer to exchange the notes for substantially similar registered 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,~~ In January 2009, the ~~Company’s Board of Directors authorized~~SEC declared the registration statement, as amended, effective, and the Company commenced the exchange offer. The Company expects the exchange offer 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 dependingexpire on ~~market conditions.~~February 18, 2009.

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.

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

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~~$30.5 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~~$2.8 million. The Company has guaranteed 50% or ~~$2.0~~$1.4 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~~2008 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.

~~-38-~~

~~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.~~rate.

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

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

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.

In a proposed budget delivered on December 16, 2008, the Governor of the State of New York included revenue from a planned amendment to the Public Service Law increasing the utility assessment from the current rate of 1/3 of one percent to one percent of a utility’s in-state gross operating revenue, together with a temporary surcharge equal to an additional one percent of the utility’s gross operating revenue. If adopted into law, the Governor’s proposal would increase the assessment charged to Distribution’s New York Division, based on the most current calculation, from $2.3 million to approximately $14 million, all other things being equal. The Company is unable to ascertain the outcome of the Governor’s proposed increase to the assessment at this time. Should it become law, the Company would seek to recover the increased expense by petitioning the Public Service Commission for an increase in rates or such other means of recovery as is available under the law.

The increase in the utility assessment would also impact marketing companies. If adopted into law, the Governor’s proposal would establish a new assessment charged to NFR for the first time. While the proposed legislation mandates that such assessment be added as a separate item to bills rendered by marketing companies to their customers, NFR management is evaluating the proposed legislation to determine the extent to which, and the details of how it will pass along this cost increase to its customers. NFR management is also evaluating potential legal challenges to certain aspects of the assessment.

Based on management’s most recent estimates, the annual assessment imposed on NFR could range from approximately $4.4 million to approximately $8.3 million. It is the opinion of NFR management that the proposed legislation fails to adequately define key language necessary to compute the assessment, leading to a certain degree of uncertainty concerning the impact and size of the assessment.

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~~included 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.

~~-39-~~

~~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. AThe 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.

-37-

~~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~~required construction of this project. ~~Construction began in September 2007 and is~~The new facilities were placed into service on ~~schedule~~December 10, 2008. As of that date, Empire became an interstate pipeline subject to ~~be completed by~~FERC regulation. The order described above requires Empire to make a filing at the ~~planned~~FERC, within three years after the in-service date, ~~of November 2008, although the actual in-service date will depend upon the completion of the Millennium Pipeline.~~justifying Empire’s existing recourse rates or proposing alternative rates.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.

The Company ~~received, in 1998 and again in October 1999, notice that~~has agreed with the NYDEC ~~believes the Company is responsible for contamination discovered at~~to remediate a former manufactured gas plant site located in New ~~York for which the~~York. The Company ~~had not been named as~~has submitted 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 commentedRemedial Design/Remedial Action work plan 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 for remediation of ~~$10.4 million associated with~~ this ~~site.~~site of $16.4 million.

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, on October 1, 2008, the Company adopted 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.~~basis. 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. For further discussion of the impact of the adoption of SFAS 157 for financial assets and financial liabilities, refer to Part I, Item 1 at Note 2 — Fair Value Measurements. The Company is currently evaluating the impact that the adoption of SFAS 157 for nonfinancial assets and nonfinancial liabilities will have on its consolidated financial statements. The Company has identified Goodwill as being the major nonfinancial asset that will be impacted by SFAS 157 and Asset Retirement Obligations as being the major nonfinancial liability that will be impacted by SFAS 157.

~~-41-~~-38-

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~~an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS ~~132R).~~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 fully adopted by the Company by the end of fiscal 2009. ~~Currently, the~~The Company ~~measures~~has historically measured its plan assets and benefit obligations using a June 30th measurement date. In anticipation of changing to a September 30th measurement date, the Company will be recording fifteen months of pension and other post-retirement benefit costs during fiscal 2009. In accordance with the provisions of SFAS 158, these costs have been calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $5.1 million and have been recorded by the Company during the quarter ended December 31, 2008 as a $3.8 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $1.3 million ($0.8 million after tax) adjustment to earnings reinvested in the business. For further discussion of the impact of adopting the measurement date provisions of SFAS 158, refer to Part I, Item 1 at Note 8 — Retirement Plan and Other Post-Retirement Benefits.

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 isbecame effective ~~as of~~for the ~~Company’s first quarter of fiscal 2009.~~Company on October 1, 2008. The Company ~~is currently evaluating~~did not elect the ~~impact, if~~fair value measurement option for any of its financial instruments other than those that ~~the adoption of SFAS 159 will have on its consolidated financial statements.~~are already being measured at fair value.

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~~the notes to the consolidated financial statements.

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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, objectives, goals, projections, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are ~~“forward-looking” statements~~“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.	Financial and economic conditions, including the availability of credit, and their effect on the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments;

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

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

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

	5.	Economic disruptions ~~caused by~~or uninsured losses resulting from terrorist activities, acts of war, or major accidents, ~~and downturns in economic activity including national~~fires, hurricanes, other severe weather, pest infestation or ~~regional recessions;~~other natural disasters;

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

	7.	Changes in demographic patterns and weather ~~conditions, including the occurrence of severe weather such as hurricanes;~~conditions;

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


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

	10.		Uncertainty of oil and gas reserve estimates;

5.	11.		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.	12.		Significant changes from expectations in the Company’s actual production levels for natural gas or oil;

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

8.	14.		Changes in the price differentials between various types of oil;

9.	15.		Inability to obtain new customers or retain existing ones;

~~10.~~	16.		Significant changes in competitive factors affecting the Company;

~~11.~~	17.		Changes in laws and regulations to which the Company is subject, including ~~changes in~~ tax, environmental, safety and employment laws and regulations;

~~12.~~	18.		Governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements;

~~13.~~	19.		Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;

~~14.~~	20.		Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs or plans;

~~-43-~~

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

~~15.~~
	21.		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.~~22.		Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties;

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

~~21.~~	24.		Significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur;

~~22.~~	25.		Changes in accounting principles or the application of such principles to the Company;

~~23.~~	26.		The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at 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.~~27.		Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or

~~26.~~	28.		Increasing costs of insurance, changes in coverage and the ability to obtain insurance.

-41-

~~Item 4.~~~~Controls and Procedures (Concl.)~~

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

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended ~~June 30,~~December 31, 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 45 — Commitments and Contingencies, and Part I, Item 2 — MD&A of this report under the heading “Other Matters — Environmental Matters.”

In addition to ~~the~~these 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 are they expected to have a material adverse effect on the financial condition of the Company.

Item 1A.Risk Factors

The risk factors in Item 1A of the Company’s ~~2007~~2008 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~~factors presented below ~~supersedes~~supersede the risk ~~factor~~factors having the same ~~caption~~captions in the ~~2007~~2008 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.~~10-K.

-42-

Item 1A.Risk Factors (Cont.)

National Fuel may be adversely affected by economic ~~conditions.~~conditions and their impact on our suppliers and customers.

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. All of National Fuel’s segments are exposed to risks associated with the creditworthiness or performance of key suppliers and customers, many of which may be adversely affected by volatile conditions in the financial markets. These conditions could result in financial instability or other adverse effects at any of our suppliers or customers. For example, counterparties to National Fuel’s commodity hedging arrangements or commodity sales contracts might not be able to perform their obligations under these arrangements or contracts. 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. Any of these events could have a material adverse effect on National Fuel’s results of operations, financial condition and cash flows.

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

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

A December 2008 New York State budget proposal to increase the assessment on utility companies’ gross operating revenues from intrastate utility operations, and to extend, for the first time, that assessment to energy marketing companies, such as NFR, could have a material adverse effect on the Company’s results of operations, financial condition or cash flows. The risk of an adverse effect is greatest if Distribution Corporation is unable to recover any increase in its assessment in the regulated rates it charges to its New York utility customers, or if NFR, which does not have regulated rates, is unable to collect any assessment against it from its customers.

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

In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have sought to establish competitive markets in which customers may purchase supplies of gas from marketers, rather than from utility companies. In June 1999, the Governor of Pennsylvania signed into law the Natural Gas Choice and Competition Act. The Act revised the Public Utility Code relating to the restructuring of the natural gas industry, to permit consumer choice of natural gas suppliers. The early programs instituted to comply with the Act did not result in significant change, and many residential customers currently continue to purchase natural gas from the utility companies. In October 2005, the PaPUC concluded that “effective competition” does not exist in the retail natural gas supply market statewide. On September 11, 2008, the PaPUC adopted a Final Order and Action Plan designed to “increase effective competition in the retail market for natural gas services.” The plan sets forth a schedule of action items for utilities and the PaPUC in order to remove “barriers in the market structure” that, in the opinion of the PaPUC, prevented the full participation of unregulated natural gas suppliers in

-43-

Item 1A.Risk Factors (Concl.)

Pennsylvania retail markets. In New York, in August 2004, the NYPSC issued its Statement of Policy on Further Steps Toward Competition in Retail Energy Markets. This policy statement has a similar goal of encouraging customer choice of alternative natural gas providers. In 2005, the NYPSC stepped up its efforts to encourage customer choice at the retail residential level, and customer choice activities increased in Distribution Corporation’s New York service territory. In April 2007, the NYPSC, noting that the retail energy marketplace in New York is established and continuing to expand, commenced a review to determine if existing programs initially designed to promote competition had outlived their usefulness and whether the cost of programs currently funded by utility rate payers should be shifted to market competitors. Increased retail choice activities, to the extent they occur, may increase Distribution Corporation’s cost of doing business, put an additional portion of its business at regulatory risk, and create uncertainty for the future, all of which may make it more difficult to manage Distribution Corporation’s business profitably.

Both the NYPSC and the PaPUC have instituted proceedings for the purpose of promoting conservation of energy commodities, including natural gas. In New York, Distribution Corporation implemented a Conservation Incentive Program that promotes conservation and efficient use of natural gas by offering customer rebates for high-efficiency appliances, among other things. The intent of conservation and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers results in decreased revenues to the Utility. To prevent revenue erosion caused by conservation, the NYPSC approved a “revenue decoupling mechanism” that renders Distribution Corporation’s New York division financially indifferent to the effects of conservation. In Pennsylvania, although a proceeding is pending, the PaPUC has not yet directed Distribution Corporation to implement conservation measures. If the NYPSC were to revoke the revenue decoupling mechanism in a future proceeding or the PaPUC were to adopt a conservation program without a revenue decoupling mechanism or other changes in rate design, reduced customer usage could decrease revenues, forcing Distribution Corporation to file for rate relief.

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

Financial accounting requirements regarding exploration and production activities may affect National Fuel’s profitability.

National Fuel accounts for its exploration and production activities under the full cost method of accounting. Each quarter, National Fuel must compare the level of its unamortized investment in oil and natural gas properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses quarter-end spot prices for oil and natural gas (as adjusted for hedging). If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be “impaired,” and the full cost accounting rules require that the investment must be written down to the calculated net present value. Such an instance would require National Fuel to recognize an immediate expense in that quarter, and its earnings would be reduced. National Fuel’s Exploration and Production segment recorded an impairment charge under the full cost method of accounting in the quarter ended December 31, 2008. If spot market prices at a subsequent quarter end are lower than prices at December 31, 2008, absent any changes in other factors affecting the present value of the future net revenue projected to be recovered from the Company’s oil and natural gas properties, the Company would be required to record an additional impairment charge. Depending on the magnitude of the decrease in prices, that charge could be material.

-44-

~~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


					Total Number of		Maximum Number
					Shares Purchased		of Shares that May
					as Part of Publicly		Yet Be Purchased
	Total Number of				Announced Share		Under Share
	Shares		Average Price		Repurchase Plans		Repurchase Plans
Period	Purchased^(a)		Paid per Share		or Programs		or Programs^(b)
Oct. 1-31, 2008		10,929		$35.07		—		6,971,019
Nov. 1-30, 2008		11,005		$32.31		—		6,971,019
Dec. 1-31, 2008		309,344		$29.79		—		6,971,019

Total		331,278		$30.05		—		6,971,019


^(a)		Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices or applicable withholding ~~taxes, and (iii)~~taxes. During the quarter ended December 31, 2008, the Company did not purchase any shares of its common stock ~~of the Company purchased on the open market~~ pursuant to ~~the Company’s~~its publicly announced share repurchase program. ~~Shares~~Of the 331,278 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~~34,170 were purchased for the Company’s 401(k) plans and ~~29,604~~297,108 were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock.

^(b)		OnIn 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~~The Company completed the repurchase of the eight million shares during 2008. In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares of the Company’s common stock. The Company had, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. However, such repurchases may be made ~~from time to time~~in the future if conditions improve. Such repurchases would be made 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,~~December 4, 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,~~December 4, 2008).

1010.1		~~Material contracts:~~

•		~~Director Services Agreement, dated as~~Description of ~~June 1, 2008, between~~long-term performance incentives under the National Fuel Gas Company ~~and Philip C. Ackerman (incorporated herein by reference to Exhibit 99, Form 8-K dated June 16, 2008).~~Performance Incentive Program.

1210.2		~~Statements regarding Computation~~Form of ~~Ratios:~~

		~~Ratio of Earnings to Fixed Charges for~~Stock Appreciation Right Award Notice under the ~~Twelve Months Ended June 30, 2008~~National Fuel Gas Company 1997 Award and ~~the Fiscal Years Ended September 30, 2004 through 2007.~~Option Plan.

~~-46-~~-45-


	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


	Retirement Plan						Other Post-Retirement Benefits						Retirement Plan						Other Post-Retirement Benefits
Nine months ended June 30,	2008			2007			2008			2007
													2008			2007			2008			2007
Service Cost	$	9,448		$	9,674		$	3,828		$	4,210		$	2,728		$	3,150		$	950		$	1,276
Interest Cost		33,712			33,263			20,311			20,399			11,709			11,237			6,875			6,771
Expected Return on Plan Assets		(41,250	)		(38,427	)		(25,286	)		(20,220	)		(14,489	)		(13,750	)		(7,904	)		(8,429	)
Amortization of Prior Service Cost		606			661			3			3			183			202			(268	)		1
Amortization of Transition Amount		—			—			5,346			5,345			—			—			566			1,782
Amortization of Losses		8,298			10,146			2,195			6,160			1,419			2,766			2,318			732
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾		7,597			3,885			20,028			16,453
Net Amortization and Deferral For Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾														3,240			1,100			4,339			7,212


Net Periodic Benefit Cost	$	18,411		$	19,202		$	26,425		$	32,350		$	4,790		$	4,705		$	6,876		$	9,345


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


	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


	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	)


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

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


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

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


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


	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


			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


								At September 30,
	At June 30, 2008							2007									At September 30,
	Gross					Net		Net		At December 31, 2008							2008
	Carrying		Accumulated			Carrying		Carrying		Gross					Net		Net
	Amount		Amortization			Amount		Amount		Carrying		Accumulated			Carrying		Carrying
										Amount		Amortization			Amount		Amount
Intangible Assets Subject to Amortization:
Long-Term Transportation Contracts	$	8,580	$	(5,791	)	$	2,789	$	3,591	$	8,580	$	(6,213	)	$	2,367	$	2,522
Long-Term Gas Purchase Contracts		31,864		(7,814	)		24,050		25,245		31,864		(8,611	)		23,253		23,652

	$	40,444	$	(13,605	)	$	26,839	$	28,836	$	40,444	$	(14,824	)	$	25,620	$	26,174


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
Three Months Ended December 31, 2008										$	554
Three Months Ended December 31, 2007										$	666


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


							Percent Colder
							(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	)


	Total								Increase
	Expenditures for			2008			2007		(Decrease)
	Long-Lived Assets
Utility	$	38.8		$	13.6		$	12.7	$	0.9
Pipeline and Storage⁽¹⁾		106.2			19.5			25.3		(5.8	)
Exploration and Production(2)		140.6			86.4			30.7		55.7
Timber		1.2
Corporate and All Other		0.2
Eliminations⁽²⁾		(2.4	)
All Other					—			1.0		(1.0	)
Eliminations⁽³⁾					(0.3	)		—		(0.3	)

	$	284.6		$	119.2		$	69.7	$	49.5


⁽¹⁾		Amount ~~includes $19.9~~for the three months ended December 31, 2008 excludes $16.8 million of ~~accrued~~ capital expenditures related to the Empire Connector ~~project.~~project accrued at September 30, 2008 and paid during the three months ended December 31, 2008. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at that date. The amount has been included in the Consolidated Statement of Cash Flows at December 31, 2008.

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

⁽²⁾⁽³⁾		Represents ~~$2.4~~$0.3 million of capital expenditures ~~included~~ in the Pipeline and Storage segment for the purchase of pipeline facilities from 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~~December 31, 2008.


	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