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 December 31, 2007

OR

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

For the transition period from                      to                     

Commission File Number 1-3880

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

New Jersey	13-1086010
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
6363 Main Street
Williamsville, New York	14221
(Address of principal executive offices)	(Zip Code)

(716) 857-7000
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. YES þ  NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b‑2 of the Exchange Act. (Check one):

Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(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). YES o  NO þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Common stock, $1 par value, outstanding at January 31, 2008: 83,526,251 shares.

GLOSSARY OF TERMS

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

National Fuel Gas Companies
Company	The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Data-Track	Data-Track Account Services, Inc.
Distribution Corporation	National Fuel Gas Distribution Corporation
Empire	Empire State Pipeline
ESNE	Energy Systems North East, LLC
Highland	Highland Forest Resources, Inc.
Horizon	Horizon Energy Development, Inc.
Horizon LFG	Horizon LFG, Inc.
Horizon Power	Horizon Power, Inc.
Leidy Hub	Leidy Hub, Inc.
Model City	Model City Energy, LLC
National Fuel	National Fuel Gas Company
NFR	National Fuel Resources, Inc.
Registrant	National Fuel Gas Company
SECI	Seneca Energy Canada Inc.
Seneca	Seneca Resources Corporation
Seneca Energy	Seneca Energy II, LLC
Supply Corporation	National Fuel Gas Supply Corporation
Regulatory Agencies
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
NTSB	National Transportation Safety Board
NYDEC	New York State Department of Environmental Conservation
NYPSC	State of New York Public Service Commission
PaPUC	Pennsylvania Public Utility Commission
SEC	Securities and Exchange Commission
Other
2007 Form 10-K	The Company’s Annual Report on Form 10-K for the year ended September 30, 2007
ARB 51	Accounting Research Bulletin No. 51, Consolidated Financial Statements
Bbl	Barrel (of oil)
Bcf	Billion cubic feet (of natural gas)
Board foot	A measure of lumber and/or timber equal to 12 inches in length by 12 inches in width by one inch in thickness.
Btu	British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.
Capital expenditure	Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Cashout revenues	A cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper.
Degree day	A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative	A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.

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GLOSSARY OF TERMS (Cont.)

Dth	Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Exchange Act	Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets	Includes capital expenditures, stock acquisitions and/or investments in partnerships.
FIN	FASB Interpretation Number
FIN 48 Firm transportation and/or storage	FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of SFAS 109 The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP	Accounting principles generally accepted in the United States of America
Goodwill	An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging	A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub	Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
Interruptible transportation and/or storage	The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LIFO	Last-in, first-out
Mbbl	Thousand barrels (of oil)
Mcf	Thousand cubic feet (of natural gas)
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth	Thousand decatherms (of natural gas)
MMcf	Million cubic feet (of natural gas)
Open Season	A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined (“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 statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundling”) of gas commodity service from transportation service for wholesale and large- volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.
SAR	Stock-settled stock appreciation right
SFAS	Statement of Financial Accounting Standards
SFAS 87	Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions
SFAS 88	Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits
SFAS 106	Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions

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GLOSSARY OF TERMS (Concl.)

SFAS 109	Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes
SFAS 115	Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities
SFAS 123R	Statement of Financial Accounting Standards No. 123R, Share-Based Payment
SFAS 132R	Statement of Financial Accounting Standards No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits
SFAS 141R	Statement of Financial Accounting Standards No. 141R, Business Combinations
SFAS 157	Statement of Financial Accounting Standards No. 157, Fair Value Measurements
SFAS 158	Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of SFAS 87, 88, 106, and 132R
SFAS 159	Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of SFAS 115
SFAS 160	Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB 51.
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.
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 Months Ended December 31, 2007 and 2006		6
	b.	Consolidated Balance Sheets — December 31, 2007 and September 30, 2007		7 — 8
	c.	Consolidated Statements of Cash Flows — Three Months Ended December 31, 2007 and 2006		9
	d.	Consolidated Statements of Comprehensive Income — Three Months Ended December 31, 2007 and 2006		10
	e.	Notes to Consolidated Financial Statements		11 — 19
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			20 — 36
Item 3.	Quantitative and Qualitative Disclosures About Market Risk			36
Item 4.	Controls and Procedures			36 — 37
	Part II. Other Information
Item 1.	Legal Proceedings			37 — 38
Item 1 A.	Risk Factors			38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds			38
Item 3.	Defaults Upon Senior Securities			•
Item 4.	Submission of Matters to a Vote of Security Holders			39
Item 5.	Other Information			•
Item 6.	Exhibits			39
Signatures				40
EX-10.1
EX-12
EX-31.1
EX-31.2
EX-32
EX-99

• The Company has nothing to report under this item.

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

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

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Part I. Financial Information

Item 1. Financial Statements

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

	Three Months Ended
	December 31,
(Thousands of Dollars, Except Per Common Share Amounts)	2007			2006
INCOME
Operating Revenues	$	568,268		$	490,659
Operating Expenses
Purchased Gas		278,010			242,939
Operation and Maintenance		102,455			94,704
Property, Franchise and Other Taxes		17,672			16,952
Depreciation, Depletion and Amortization		44,121			39,407
		442,258			394,002
Operating Income		126,010			96,657
Other Income (Expense):
Income from Unconsolidated Subsidiaries		2,275			1,231
Interest Income		3,093			1,085
Other Income		1,253			715
Interest Expense on Long-Term Debt		(16,289	)		(16,043	)
Other Interest Expense		(724	)		(1,849	)
Income from Continuing Operations Before Income Taxes		115,618			81,796
Income Tax Expense		45,014			31,108
Income from Continuing Operations		70,604			50,688
Income from Discontinued Operations, Net of Tax		—			3,832
Net Income Available for Common Stock		70,604			54,520
EARNINGS REINVESTED IN THE BUSINESS
Balance at October 1		983,776			786,013
		1,054,380			840,533
Share Repurchases		—			(34,018	)
Cumulative Effect of the Adoption of FIN 48		(406	)		—
Dividends on Common Stock (2007 — $0.31; 2006 — $0.30)		(26,023	)		(24,787	)
Balance at December 31	$	1,027,951		$	781,728
Earnings Per Common Share:
Basic:
Income from Continuing Operations	$	0.84		$	0.61
Income from Discontinued Operations		—			0.05
Net Income Available for Common Stock	$	0.84		$	0.66
Diluted:
Income from Continuing Operations	$	0.82		$	0.60
Income from Discontinued Operations		—			0.04
Net Income Available for Common Stock	$	0.82		$	0.64
Weighted Average Common Shares Outstanding:
Used in Basic Calculation		83,611,177			82,679,343
Used in Diluted Calculation		85,819,534			84,730,910

See Notes to Condensed Consolidated Financial Statements

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Item 1. Financial Statements (Cont.)

National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)

	December 31,		September 30,
	2007		2007
(Thousands of Dollars)
ASSETS
Property, Plant and Equipment	$	4,525,608	$	4,461,586
Less — Accumulated Depreciation, Depletion and Amortization		1,616,488		1,583,181
		2,909,120		2,878,405
Current Assets
Cash and Temporary Cash Investments		189,767		124,806
Cash Held in Escrow		—		61,964
Hedging Collateral Deposits		1,996		4,066
Receivables — Net of Allowance for Uncollectible Accounts of $34,106 and $28,654, Respectively		242,440		172,380
Unbilled Utility Revenue		78,480		20,682
Gas Stored Underground		60,481		66,195
Materials and Supplies — at average cost		41,569		35,669
Unrecovered Purchased Gas Costs		12,186		14,769
Other Current Assets		32,453		45,057
Deferred Income Taxes		17,468		8,550
		676,840		554,138
Other Assets
Recoverable Future Taxes		83,787		83,954
Unamortized Debt Expense		11,586		12,070
Other Regulatory Assets		131,154		137,577
Deferred Charges		5,582		5,545
Other Investments		85,325		85,902
Investments in Unconsolidated Subsidiaries		17,825		18,256
Goodwill		5,476		5,476
Intangible Assets		28,170		28,836
Prepaid Pension and Post-Retirement Benefit Costs		63,188		61,006
Fair Value of Derivative Financial Instruments		6,026		9,188
Other		7,344		8,059
		445,463		455,869
Total Assets	$	4,031,423	$	3,888,412

See Notes to Condensed Consolidated Financial Statements

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Item 1. Financial Statements (Cont.)

National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)

	December 31,			September 30,
(Thousands of Dollars)	2007			2007
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued And Outstanding — 83,946,575 Shares And 83,461,308 Shares, Respectively	$	83,947		$	83,461
Paid in Capital		595,375			569,085
Earnings Reinvested in the Business		1,027,951			983,776
Total Common Shareholder Equity Before Items of Other Comprehensive Loss		1,707,273			1,636,322
Accumulated Other Comprehensive Loss		(16,286	)		(6,203	)
Total Comprehensive Shareholders’ Equity		1,690,987			1,630,119
Long-Term Debt, Net of Current Portion		799,000			799,000
Total Capitalization		2,489,987			2,429,119
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		—			—
Current Portion of Long-Term Debt		200,000			200,024
Accounts Payable		152,155			109,757
Amounts Payable to Customers		9,181			10,409
Dividends Payable		26,023			25,873
Interest Payable on Long-Term Debt		13,541			18,158
Customer Advances		23,498			22,863
Other Accruals and Current Liabilities		50,207			36,062
Fair Value of Derivative Financial Instruments		29,089			16,200
		503,694			439,346
Deferred Credits
Deferred Income Taxes		581,692			575,356
Taxes Refundable to Customers		14,031			14,026
Unamortized Investment Tax Credit		5,217			5,392
Cost of Removal Regulatory Liability		98,613			91,226
Other Regulatory Liabilities		78,374			76,659
Post-Retirement Liabilities		66,706			70,555
Asset Retirement Obligations		77,253			75,939
Other Deferred Credits		115,856			110,794
		1,037,742			1,019,947
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	4,031,423		$	3,888,412

See Notes to Condensed Consolidated Financial Statements

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Item 1. Financial Statements (Cont.)

National Fuel Gas Company
Consolidated Statements of Cash Flows
(Unaudited)

	Three Months Ended
	December 31,
(Thousands of Dollars)	2007			2006
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	70,604		$	54,520
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		44,121			42,825
Deferred Income Taxes		5,296			11,198
Income from Unconsolidated Subsidiaries, Net of Cash Distributions		431			(18	)
Excess Tax Benefits Associated with Stock-Based Compensation Awards		(16,275	)		(13,717	)
Other		4,916			5,728
Change in:
Hedging Collateral Deposits		2,070			9,916
Receivables and Unbilled Utility Revenue		(127,894	)		(91,875	)
Gas Stored Underground and Materials and Supplies		(186	)		5,324
Unrecovered Purchased Gas Costs		2,583			(11,021	)
Prepayments and Other Current Assets		10,422			20,398
Accounts Payable		42,398			11,736
Amounts Payable to Customers		(1,228	)		3,166
Customer Advances		635			534
Other Accruals and Current Liabilities		25,400			(756	)
Other Assets		10,163			1,883
Other Liabilities		1,889			(6,810	)
Net Cash Provided by Operating Activities		75,345			43,031
INVESTING ACTIVITIES
Capital Expenditures		(69,744	)		(65,302	)
Investment in Partnership		—			(1,650	)
Cash Held in Escrow		58,397			—
Net Proceeds from Sale of Oil and Gas Producing Properties		1,500			2,141
Other		(761	)		(316	)
Net Cash Used in Investing Activities		(10,608	)		(65,127	)
FINANCING ACTIVITIES
Change in Notes Payable to Banks and Commercial Paper		—			71,600
Excess Tax Benefits Associated with Stock-Based Compensation Awards		16,275			13,717
Shares Repurchased under Repurchase Plan		—			(42,921	)
Reduction of Long-Term Debt		(24	)		(23,005	)
Dividends Paid on Common Stock		(25,873	)		(25,026	)
Net Proceeds from Issuance of Common Stock		9,846			6,743
Net Cash Provided by Financing Activities		224			1,108
Effect of Exchange Rates on Cash		—			(1,025	)
Net Increase (Decrease) in Cash and Temporary Cash Investments		64,961			(22,013	)
Cash and Temporary Cash Investments at October 1		124,806			69,611
Cash and Temporary Cash Investments at December 31	$	189,767		$	47,598

See Notes to Condensed Consolidated Financial Statements

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Item 1. Financial Statements (Cont.)

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

	Three Months Ended
	December 31,
(Thousands of Dollars)	2007			2006
Net Income Available for Common Stock	$	70,604		$	54,520
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment		(18	)		(4,868	)
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period		(1,201	)		790
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		(20,859	)		9,501
Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income		5,421			3,177
Other Comprehensive Income (Loss), Before Tax		(16,657	)		8,600
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period		(59	)		275
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		(8,648	)		3,730
Reclassification Adjustment for Income Tax Benefit on Realized Losses from Derivative Financial Instruments In Net Income		2,133			2,020
Income Taxes — Net		(6,574	)		6,025
Other Comprehensive Income (Loss)		(10,083	)		2,575
Comprehensive Income	$	60,521		$	57,095

See Notes to Condensed Consolidated Financial Statements

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Item 1. Financial Statements (Cont.)

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

Note 1 — Summary of Significant Accounting Policies

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

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

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

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

     The earnings for the three months ended December 31, 2007 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2008. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year.

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

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

Cash Held in Escrow. On August 31, 2007, the Company received approximately $232.1 million of proceeds from the sale of SECI, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. The escrow account is a Canadian dollar denominated account. On a U.S. dollar basis, the value of this account was $62.0 million at September 30, 2007. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. To hedge against foreign currency exchange risk related to the cash being held in escrow, the Company holds a forward contract to sell Canadian dollars. For presentation purposes on the Consolidated Statement of Cash Flows, for the three months ended December 31, 2007, the Cash Held in Escrow line item within Investing Activities reflects the net proceeds to the Company after adjusting for the impact of the foreign currency hedge.

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Item 1. Financial Statements (Cont.)

Gas Stored Underground — Current. In the Utility segment, gas stored underground — current is carried at lower of cost or market, on a LIFO method. Gas stored underground — current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $13.8 million at December 31, 2007, is reduced to zero by September 30 of each year as the inventory is replenished.

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

	At December 31, 2007			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		(101	)		(83	)
Net Unrealized Loss on Derivative Financial Instruments		(12,809	)		(3,886	)
Net Unrealized Gain on Securities Available for Sale		9,106			10,248
Accumulated Other Comprehensive Loss	$	(16,286	)	$	(6,203	)

Earnings Per Common Share. Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share 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 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 ended December 31, 2007, there were no stock options or stock-settled SARs excluded as being antidilutive. For the quarter ended December 31, 2006, there were 122,253 stock options excluded as being antidilutive. There were no stock-settled SARs excluded as being antidilutive for the quarter ended December 31, 2006.

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

Stock-Based Compensation. The Company granted 25,000 restricted share awards (non-vested stock as defined in SFAS 123R) during the quarter ended December 31, 2007. The weighted average fair value of such restricted shares was $48.41 per share. There were no stock options or stock-settled SARs granted during the quarter ended December 31, 2007.

-12-

Item 1. Financial Statements (Cont.)

New Accounting Pronouncements. On October 1, 2007, the Company adopted FIN 48, “Accounting for Uncertainty in Income Taxes.” FIN 48 clarifies the accounting for income taxes by prescribing a minimum probability threshold that a tax position must meet before a financial statement benefit is recognized. The minimum threshold is defined in FIN 48 as a tax position that is more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If a tax benefit meets this threshold, it is measured and recognized based on an analysis of the cumulative probability of the tax benefit being ultimately sustained. The adoption of FIN 48 did not have a material impact on the Company’s consolidated financial statements. For further discussion of the impact of adopting FIN 48, refer to Note 2 — Income Taxes.

     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. The pronouncement is effective for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009. The pronouncement is effective for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value on a recurring basis, as of the Company’s first quarter of fiscal 2010. The Company is currently evaluating the impact that the adoption of SFAS 157 will have on its consolidated financial statements.

     In September 2006, the FASB also issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” (an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R). SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be adopted by the Company by the end of fiscal 2009. Currently, the Company measures its plan assets and benefit obligations using a June 30th measurement date.

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

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

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

-13-

Item 1. Financial Statements (Cont.)

Note 2 — Income Taxes

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

	Three Months Ended
	December 31,
	2007			2006
Current Income Taxes
Federal	$	34,259		$	16,653
State		5,459			5,036
Foreign		—			—
Deferred Income Taxes
Federal		(80	)		8,210
State		5,376			1,209
Foreign		—			1,779
		45,014			32,887
Deferred Investment Tax Credit		(174	)		(174	)
Total Income Taxes	$	44,840		$	32,713
Presented as Follows:
Other Income	$	(174	)	$	(174	)
Income Tax Expense — Continuing Operations		45,014			31,108
Income from Discontinued Operations		—			1,779
Total Income Taxes	$	44,840		$	32,713

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

	Three Months Ended
	December 31,
	2007		2006
U.S.	$	115,389	$	81,575
Foreign		55		5,658
	$	115,444	$	87,233

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

	Three Months Ended
	December 31,
	2007			2006
Income Tax Expense, Computed at Statutory Rate of 35%	$	40,405		$	30,532
Increase (Reduction) in Taxes Resulting From:
State Income Taxes		7,043			4,059
Miscellaneous		(2,608	)		(1,878	)
Total Income Taxes	$	44,840		$	32,713

-14-

Item 1. Financial Statements (Cont.)

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

	At December 31, 2007			At September 30, 2007
Deferred Tax Liabilities:
Property, Plant and Equipment	$	626,814		$	612,648
Other		49,684			61,616
Total Deferred Tax Liabilities		676,498			674,264
Deferred Tax Assets:
Other		(112,274	)		(107,458	)
Total Deferred Tax Assets		(112,274	)		(107,458	)
Total Net Deferred Income Taxes	$	564,224		$	566,806
Presented as Follows:
Net Deferred Tax Asset — Current	$	(17,468	)	$	(8,550	)
Net Deferred Tax Liability — Non-Current		581,692			575,356
Total Net Deferred Income Taxes	$	564,224		$	566,806

     Regulatory liabilities representing the reduction of previously recorded deferred income taxes with rate-regulated activities that are expected to be refundable to customers amounted to $14.0 million at both December 31, 2007 and September 30, 2007. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $83.8 million and $84.0 million at December 31, 2007 and September 30, 2007, respectively.

     As indicated under “New Accounting Pronouncements” in Note 1 — Summary of Significant Accounting Policies, the Company adopted FIN 48 on October 1, 2007. As of the date of adoption, a cumulative effect adjustment was recorded that resulted in a decrease to retained earnings of $0.4 million. Upon adoption, the unrecognized tax benefits were $1.7 million, all of which would impact the effective tax rate (net of federal benefit) if recognized. There was no change in the balance of unrecognized tax benefits during the quarter ended December 31, 2007 and the Company does not expect a material change within the next twelve months.

     Consistent with existing policies, the Company recognizes estimated interest payable relating to income taxes in Other Interest Expense and estimated penalties relating to income taxes in Other Income. As of October 1, 2007, the Company has accrued interest of $0.5 million and has not accrued any penalties.

     The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 2007 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. While the federal statute of limitations remains open for fiscal 2004 and later years, IRS examinations for years prior to fiscal 2007 have been completed and the Company believes such years are effectively settled.

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

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

-15-

Item 1. Financial Statements (Cont.)

Note 3 — Capitalization

Common Stock. During the three months ended December 31, 2007, the Company issued 496,714 original issue shares of common stock as a result of stock option exercises and 25,000 original issue shares for restricted stock awards (non-vested stock as defined in SFAS 123R). The Company also issued 2,400 original issue shares of common stock to the non-employee directors of the Company as partial consideration for the directors’ services during the three months ended December 31, 2007. Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the three months ended December 31, 2007, 38,847 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

     On December 8, 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. During the quarter ended December 31, 2007, the Company did not repurchase any shares under this program. Since the share repurchase program was implemented, the Company has repurchased 3,834,878 shares for $133.2 million.

Note 4 — Commitments and Contingencies

Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and 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 Form 10-K, the Company received, in 1998 and again in October 1999, notice that the NYDEC believes the Company is responsible for contamination discovered at a former manufactured gas plant site located in New York for which the Company had not been named as a PRP. In February 2007, the NYDEC identified the Company as a PRP for the site and issued a proposed remedial action plan. The NYDEC estimated clean-up costs under its proposed remedy to be $8.9 million if implemented. Although the Company commented to the NYDEC that the proposed remedial action plan contained a number of material errors, omissions and procedural defects, the NYDEC, in a March 2007 Record of Decision, selected the remedy it had previously proposed. In July 2007, the Company appealed the NYDEC’s Record of Decision to the New York State Supreme Court, Albany County. The Court dismissed the appeal in January 2008. The Company is reviewing its options in this matter and believes that a negotiated resolution with the NYDEC regarding the site remains possible.

     At December 31, 2007, 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 $12.1 million to $15.8 million. The minimum estimated liability of $12.1 million has been recorded on the Consolidated Balance Sheet at December 31, 2007. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and insurance proceeds.

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

Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased

-16-

Item 1. Financial Statements (Cont.)

gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor to have a material adverse effect on the financial condition of the Company.

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 the Gulf of Mexico, in California and in Appalachia. 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 Ended
	December 31,
(Thousands)	2006
Operating Revenues	$	13,581
Operating Expenses		8,248
Operating Income		5,333
Interest Income		278
Income before Income Taxes		5,611
Income Tax Expense		1,779
Income from Discontinued Operations	$	3,832

Note 6 — Business Segment Information

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

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

-17-

Item 1. Financial Statements (Cont.)

Quarter Ended December 31, 2007 (Thousands)

			Pipeline		Exploration						Total				Corporate and
			and		and		Energy				Reportable				Intersegment			Total
	Utility		Storage		Production		Marketing		Timber		Segments		All Other		Eliminations			Consolidated
Revenue from External Customers	$	327,125	$	31,884	$	107,955	$	86,719	$	12,900	$	566,583	$	1,550	$	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	$	397	$	68,368	$	2,339	$	(103	)	$	70,604

Quarter Ended December 31, 2006 (Thousands)

			Pipeline		Exploration						Total				Corporate and
			and		and		Energy				Reportable				Intersegment			Total
	Utility		Storage		Production		Marketing		Timber		Segments		All Other		Eliminations			Consolidated
Revenue from External Customers	$	288,782	$	29,809	$	75,128	$	83,318	$	11,763	$	488,800	$	1,676	$	183		$	490,659
Intersegment Revenues	$	4,029	$	20,368	$	—	$	—	$	—	$	24,397	$	2,198	$	(26,595	)	$	—
Segment Profit:
Income from Continuing Operations	$	17,174	$	13,688	$	16,891	$	492	$	217	$	48,462	$	985	$	1,241		$	50,688

Note 7 — Intangible Assets

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

								At September 30,
	At December 31, 2007							2007
	Gross					Net		Net
	Carrying		Accumulated			Carrying		Carrying
	Amount		Amortization			Amount		Amount
Intangible Assets Subject to Amortization:
Long-Term Transportation Contracts	$	8,580	$	(5,256	)	$	3,324	$	3,591
Long-Term Gas Purchase Contracts		31,864		(7,018	)		24,846		25,245
	$	40,444	$	(12,274	)	$	28,170	$	28,836
Aggregate Amortization Expense:
(Thousands)
Three Months Ended December 31, 2007	$	666
Three Months Ended December 31, 2006	$	665

-18-

Item 1. Financial Statements (Cont.)

     The gross carrying amount of intangible assets subject to amortization at December 31, 2007 remained unchanged from September 30, 2007. The only activity with regard to intangible assets subject to amortization was amortization expense as shown in the table above. Amortization expense for the transportation contracts is estimated to be $0.8 million for the remainder of 2008 and $0.5 million for 2009. Amortization expense for transportation contracts is estimated to be $0.4 million for 2010, 2011 and 2012. Amortization expense for the long-term gas purchase contracts is estimated to be $1.2 million for the remainder of 2008 and $1.6 million annually for 2009, 2010, 2011 and 2012.

Note 8 — Retirement Plan and Other Post-Retirement Benefits

     Components of Net Periodic Benefit Cost (in thousands):

Three months ended December 31,

	Retirement Plan						Other Post-Retirement Benefits
	2007			2006			2007			2006
Service Cost	$	3,150		$	3,225		$	1,276		$	1,403
Interest Cost		11,237			11,088			6,771			6,800
Expected Return on Plan Assets		(13,750	)		(12,809	)		(8,429	)		(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)		1,100			155			7,212			2,339
Net Periodic Benefit Cost	$	4,705		$	5,261		$	9,345		$	7,638

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

Employer Contributions. During the three months ended December 31, 2007, the Company contributed $2.5 million to its retirement plan and $9.5 million to its other post-retirement benefit plan. In the remainder of 2008, the Company expects to contribute in the range of $12.0 million to $17.0 million to its retirement plan and to contribute in the range of $15.0 million to $25.0 million to its other post-retirement benefit plan.

-19-

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

OVERVIEW

     The Company is a diversified energy company consisting of five reportable business segments. For the quarter ended December 31, 2007 compared to the quarter ended December 31, 2006, the Company has experienced an overall increase in earnings of $16.1 million primarily due to higher earnings in the Exploration and Production segment. Earnings were also higher in the Utility, Energy Marketing, and Timber segments, as well as the All Other category. Lower earnings in the Pipeline and Storage segment and the Corporate category slightly offset these increases. 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 $69.7 million on capital expenditures during the quarter ended December 31, 2007, with approximately 44% being spent in the Exploration and Production segment, 36% in the Pipeline and Storage segment and 18% in the Utility segment. In the Pipeline and Storage segment, the majority of the expenditures were for construction of 18 miles of the Empire Connector project. The Company expects to complete the project by November 1, 2008. This project and other capital expenditures are discussed further in the Capital Resources and Liquidity section that follows.

     On January 29, 2007, the Company commenced a rate case in the New York jurisdiction of the Utility segment by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by $52.0 million annually. The Company explained in the filing that its request for rate relief is 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 aggressive efficiency and conservation initiative with a revenue decoupling mechanism designed to render the Company indifferent to throughput reductions resulting from conservation. In September 2007, the NYPSC issued an order approving the Company’s conservation program, and the administrative law judge assigned to the proceeding issued a recommended decision. In December 2007, the NYPSC issued an Order that provides for an annual rate increase, effective December 28, 2007, of $1.8 million as well as a monthly bill surcharge that would collect up to $10.8 million to recover expenses arising from the conservation program. The Order also approved the Company’s proposed revenue decoupling mechanism. This matter is discussed more fully in the Rate and Regulatory Matters section that follows.

CRITICAL ACCOUNTING ESTIMATES

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

RESULTS OF OPERATIONS

Earnings

     The Company’s earnings were $70.6 million for the quarter ended December 31, 2007 compared to earnings of $54.5 million for the quarter ended December 31, 2006. 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 $70.6 million for the quarter ended December 31, 2007 compared to earnings from continuing operations of $50.7 million for the quarter ended December 31, 2006. The increase in earnings from continuing operations of $19.9 million is the result of higher earnings in the Exploration and Production, Utility, Energy Marketing, and Timber segments, and the All Other category, slightly offset by lower earnings in the Pipeline and Storage segment and the Corporate category. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.

-20-

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

Earnings (Loss) by Segment

						Increase
Three Months Ended December 31 (Thousands)	2007			2006		(Decrease)
Utility	$	20,217		$	17,174	$	3,043
Pipeline and Storage		12,778			13,688		(910	)
Exploration and Production		34,022			16,891		17,131
Energy Marketing		954			492		462
Timber		397			217		180
Total Reportable Segments		68,368			48,462		19,906
All Other		2,339			985		1,354
Corporate		(103	)		1,241		(1,344	)
Total Earnings from Continuing Operations		70,604			50,688		19,916
Earnings from Discontinued Operations		—			3,832		(3,832	)
Total Consolidated	$	70,604		$	54,520	$	16,084

Utility

Utility Operating Revenues

					Increase
Three Months Ended December 31 (Thousands)	2007		2006		(Decrease)
Retail Sales Revenues:
Residential	$	246,797	$	225,432	$	21,365
Commercial		38,033		35,635		2,398
Industrial		1,651		1,901		(250	)
		286,481		262,968		23,513
Transportation		33,424		26,876		6,548
Off-System Sales		8,213		—		8,213
Other		3,306		2,967		339
	$	331,424	$	292,811	$	38,613

Utility Throughput

					Increase
Three Months Ended December 31 (MMcf)	2007		2006		(Decrease)
Retail Sales:
Residential		17,127		16,678		449
Commercial		2,877		2,868		9
Industrial		123		192		(69	)
		20,127		19,738		389
Transportation		17,827		15,853		1,974
Off-System Sales		1,031		—		1,031
		38,985		35,591		3,394

Degree Days

							Percent
Three Months Ended							Colder (Warmer) Than
December 31	Normal		2007		2006		Normal			Prior Year
Buffalo		2,260		2,094		1,947		(7.3	)		7.6
Erie		2,081		1,871		1,878		(10.1	)		(0.4	)

2007 Compared with 2006

     Operating revenues for the Utility segment increased $38.6 million for the quarter ended December 31, 2007 as compared with the quarter ended December 31, 2006. This increase largely resulted from a $23.5 million increase in retail gas revenues coupled with an $8.2 million increase in off-system sales revenues and a $6.5 million increase in transportation revenues. The increase in retail gas

-21-

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

sales revenues for the Utility segment was largely a function of higher gas costs (gas costs are recovered dollar for dollar in revenues), coupled with the revenue impact of higher sales volumes, as shown in the table above. The increase in transportation revenues was primarily due to a 2.0 Bcf increase in transportation throughput, largely due to the migration of retail sales customers to transportation service.

     As reported in 2006, on November 17, 2006, the U.S. Court of Appeals vacated and remanded FERC’s Order No. 2004, its latest 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, FERC issued Order No. 690, its Interim Rule, designed to respond to the Court’s decision. In Order No. 690, as clarified by 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 to engage in certain off-system sales without triggering the adverse consequences that would otherwise arise under the standards of conduct. As such, the Utility resumed engaging in off-system sales on non-affiliated pipelines as of May 2007. Total off-system sales revenues for the quarter ended December 31, 2007 amounted to $8.2 million. 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 quarter ended December 31, 2007.

     The Utility segment’s earnings for the quarter ended December 31, 2007 were $20.2 million, an increase of $3.0 million when compared with earnings of $17.2 million for the quarter ended December 31, 2006. In the Pennsylvania jurisdiction, earnings increased $2.1 million. The major factors contributing to this increase were the base rate increase effective January 1, 2007 ($2.0 million) and higher usage per account ($1.0 million). These increases were partly offset by the negative earnings impact associated with warmer weather ($0.7 million). In the New York jurisdiction, earnings increased $0.9 million. This increase was primarily the result of higher usage per account.

     The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s 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 quarters ended December 31, 2007 and December 31, 2006, the WNC preserved $1.1 million and $1.5 million of earnings, respectively, since it was warmer than normal. In periods of colder than normal weather, the WNC benefits Distribution Corporation’s New York customers.

Pipeline and Storage

Pipeline and Storage Operating Revenues

					Increase
Three Months Ended December 31 (Thousands)	2007		2006		(Decrease)
Firm Transportation	$	31,406	$	29,489	$	1,917
Interruptible Transportation		991		945		46
		32,397		30,434		1,963
Firm Storage Service		16,621		16,402		219
Other		3,213		3,341		(128	)
	$	52,231	$	50,177	$	2,054

Pipeline and Storage Throughput

Three Months Ended December 31 (MMcf)	2007		2006		Increase
Firm Transportation		92,883		74,427		18,456
Interruptible Transportation		1,083		995		88
		93,966		75,422		18,544

-22-

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

2007 Compared with 2006

     Operating revenues for the Pipeline and Storage segment increased $2.1 million in the quarter ended December 31, 2007 as compared with the quarter ended December 31, 2006. This increase consisted primarily of a $2.0 million increase in firm and interruptible transportation revenues. The Pipeline and Storage segment was able to renew existing contracts at higher rates due to favorable market conditions related to the demand for storage and the related transportation service associated with storage. While transportation volumes increased by 18.5 Bcf, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight-fixed variable rate design.

     The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2007 were $12.8 million, a decrease of $0.9 million when compared with earnings of $13.7 million for the quarter ended December 31, 2006. The decrease is largely attributable to the non-recurrence of a $1.9 million positive earnings impact associated with the discontinuance of hedge accounting for Empire’s interest rate collar. On December 8, 2006, Empire repaid $22.8 million of secured debt. The interest rate on that secured debt was hedged by an interest rate collar. Upon the repayment of that debt, the corresponding interest rate collar no longer qualified for hedge accounting, and the unrealized gain in accumulated other comprehensive income was reclassified to the income statement in December 2006. Increased operating costs (primarily post-retirement benefit costs) of $0.7 million, higher interest expense of $0.5 million and lower efficiency gas revenues of $0.2 million also contributed to the decrease in earnings. These earnings decreases were partially offset by higher firm and interruptible transportation and storage service revenues ($1.4 million), lower depreciation expense ($0.8 million), and an increase in allowance for funds used during construction ($0.4 million).

Exploration and Production

Exploration and Production Operating Revenues

							Increase
Three Months Ended December 31 (Thousands)	2007			2006			(Decrease)
Gas (after Hedging) from Continuing Operations	$	45,557		$	36,010		$	9,547
Oil (after Hedging) from Continuing Operations		59,643			35,955			23,688
Gas Processing Plant from Continuing Operations		11,075			8,629			2,446
Other from Continuing Operations		(1,309	)		384			(1,693	)
Intrasegment Elimination from Continuing Operations (1)		(7,011	)		(5,850	)		(1,161	)
Operating Revenues from Continuing Operations	$	107,955		$	75,128		$	32,827
Operating Revenues from Canada — Discontinued Operations	$	—		$	13,581		$	(13,581	)

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

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

Production Volumes

					Increase
Three Months Ended December 31	2007		2006		(Decrease)
Gas Production (MMcf)
Gulf Coast		2,826		2,723		103
West Coast		1,027		944		83
Appalachia		1,917		1,394		523
Total Production from Continuing Operations		5,770		5,061		709
Canada — Discontinued Operations		—		1,721		(1,721	)
Total Production		5,770		6,782		(1,012	)
Oil Production (Mbbl)
Gulf Coast		156		202		(46	)
West Coast		629		591		38
Appalachia		37		27		10
Total Production from Continuing Operations		822		820		2
Canada — Discontinued Operations		—		56		(56	)
Total Production		822		876		(54	)

Average Prices

					Increase
Three Months Ended December 31	2007		2006		(Decrease)
Average Gas Price/Mcf
Gulf Coast	$	7.14	$	6.55	$	0.59
West Coast	$	6.77	$	6.09	$	0.68
Appalachia	$	7.45	$	7.22	$	0.23
Weighted Average for Continuing Operations	$	7.18	$	6.65	$	0.53
Weighted Average After Hedging for Continuing Operations	$	7.90	$	7.12	$	0.78
Canada — Discontinued Operations		—	$	6.39	$	(6.39	)
Average Oil Price/Bbl
Gulf Coast	$	89.84	$	56.51	$	33.33
West Coast	$	81.80	$	51.11	$	30.69
Appalachia	$	84.12	$	59.78	$	24.34
Weighted Average for Continuing Operations	$	83.43	$	52.73	$	30.70
Weighted Average After Hedging for Continuing Operations	$	72.59	$	43.82	$	28.77
Canada — Discontinued Operations		—	$	42.58	$	(42.58	)

2007 Compared with 2006

     Operating revenues from continuing operations for the Exploration and Production segment increased $32.8 million for the quarter ended December 31, 2007 as compared with the quarter ended December 31, 2006. Oil production revenue after hedging increased $23.7 million. An increase in the weighted average price of oil after hedging ($28.77 per bbl) was the primary cause, as production increases in the West Coast and Appalachian regions offset a decrease in Gulf Coast production, keeping overall oil production flat. Gas production revenue after hedging increased $9.5 million. An increase in gas production (709 MMcf) and an increase in the weighted average price of gas after hedging ($0.78 per Mcf) contributed similarly to the increase. The increase in gas production occurred primarily in this segment’s Appalachian region (523 MMcf), consistent with increased drilling activity in this region during fiscal 2007. Drilling activity will continue to be significant in the Appalachian region in 2008.

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

     The Exploration and Production segment’s earnings from continuing operations for the quarter ended December 31, 2007 were $34.0 million compared with earnings from continuing operations of $16.9 million for the quarter ended December 31, 2006, an increase of $17.1 million. Higher crude oil prices, higher natural gas prices and higher natural gas production increased earnings by $15.4 million, $2.9 million and $3.3 million, respectively. Higher interest income and lower interest expense also increased earnings by $1.1 million and $1.2 million, respectively. These increases were partially offset by increased depletion expense ($3.5 million), higher lease operating expenses ($1.5 million) and higher state income tax expense ($1.1 million).

Energy Marketing

Energy Marketing Operating Revenues

						Increase
Three Months Ended December 31 (Thousands)	2007			2006		(Decrease)
Natural Gas (after Hedging)	$	86,735		$	83,270	$	3,465
Other		(16	)		48		(64	)
	$	86,719		$	83,318	$	3,401

Energy Marketing Volumes

Three Months Ended December 31	2007		2006		Decrease
Natural Gas — (MMcf)		10,841		11,116		(275	)

2007 Compared with 2006

     Operating revenues for the Energy Marketing segment increased $3.4 million for the quarter ended December 31, 2007 as compared with the quarter ended December 31, 2006. This increase primarily reflects higher gas sales revenue due to an increase in the price of natural gas, slightly offset by a decrease in throughput. The decrease in throughput was due to a decline in volumes sold to certain low-margin wholesale and industrial customers.

     The Energy Marketing segment’s earnings for the quarter ended December 31, 2007 were $1.0 million, an increase of $0.5 million when compared with earnings of $0.5 million for the quarter ended December 31, 2006. Despite warmer weather, gross margin increased by $0.5 million due to higher average margins per Mcf.

Timber

Timber Operating Revenues

						Increase
Three Months Ended December 31 (Thousands)	2007			2006		(Decrease)
Log Sales	$	5,174		$	4,065	$	1,109
Green Lumber Sales		1,401			918		483
Kiln-dried Lumber Sales		6,548			6,270		278
Other		(223	)		510		(733	)
Operating Revenues	$	12,900		$	11,763	$	1,137

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

Timber Board Feet

Three Months Ended December 31 (Thousands)	2007		2006		Increase
Log Sales		2,024		1,709		315
Green Lumber Sales		2,431		1,530		901
Kiln-dried Lumber Sales		3,747		3,157		590
		8,202		6,396		1,806

2007 Compared with 2006

     Operating revenues for the Timber segment increased $1.1 million for the quarter ended December 31, 2007 as compared with the quarter ended December 31, 2006. The increase in revenues can be attributed mainly to slightly more favorable weather conditions in the quarter ended December 31, 2007 as compared to unfavorable weather conditions that greatly diminished the harvesting of logs during the quarter ended December 31, 2006. Since weather conditions were somewhat more favorable during the current quarter, log sales increased by $1.1 million or 315,000 board feet. There was also an increase in both green lumber and kiln-dried lumber sales of $0.5 million and $0.3 million, respectively, since a larger amount of logs were available for processing in the current quarter as compared to the quarter ended December 31, 2006. The increase in kiln-dried lumber sales volumes was partially offset by a decline in market price of kiln-dried lumber.

     The Timber segment’s earnings for the quarter ended December 31, 2007 were $0.4 million, an increase of $0.2 million when compared with earnings of $0.2 million for the quarter ended December 31, 2006. The increase was primarily due to higher margins from log and lumber sales of $0.2 million as a result of the increase in revenues noted above.

Corporate and All Other

2007 Compared with 2006

     Corporate and All Other operations recorded earnings of $2.2 million for each of the quarters ended December 31, 2007 and 2006. Increases in earnings due to higher income from unconsolidated subsidiaries of $0.7 million, lower interest expense of $0.8 million, higher interest income of $0.5 million, and lower income tax expense ($0.4 million) were completely offset by higher operating costs of $2.4 million.

Interest Income

     Interest income was $2.0 million higher in the quarter ended December 31, 2007 as compared to the quarter ended December 31, 2006. Interest income in the Exploration and Production segment increased $1.6 million as a result of the investment of cash proceeds received from the sale of SECI in August 2007.

Interest Charges

     Interest on long-term debt increased $0.2 million for the quarter ended December 31, 2007 as compared with the quarter ended December 31, 2006. This increase can be attributed to the non-recurrence of a $1.9 million benefit to interest expense recognized in the quarter ended December 31, 2006 as a result of the discontinuance of hedge accounting for Empire’s interest rate collar, as discussed above under Pipeline and Storage. The underlying long-term debt associated with this interest rate collar was repaid during the quarter ended December 31, 2006 and the unrealized gain recorded in accumulated other comprehensive income associated with the interest rate collar was reclassified to interest expense. Largely offsetting this increase was an overall decline in interest on long-term debt as

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

a result of a lower average amount of long-term debt outstanding. As previously mentioned, 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.

     Other interest charges were $1.1 million lower for the quarter ended December 31, 2007 as compared with the quarter ended December 31, 2006. The decrease resulted from a lower average amount of short-term debt outstanding during the quarter ended December 31, 2007, lower other interest charges in the Utility segment, and an increase in the allowance for borrowed funds used during construction, primarily in the Pipeline and Storage segment.

CAPITAL RESOURCES AND LIQUIDITY

     The Company’s primary source of cash during the three-month period ended December 31, 2007 consisted of cash provided by operating activities. This source of cash was supplemented by issuances of new shares of common stock as a result of stock option exercises. During the three months ended 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.

Operating Cash Flow

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

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

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

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

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

     Net cash provided by operating activities totaled $75.3 million for the three months ended December 31, 2007, an increase of $32.3 million when compared with the $43.0 million provided by operating activities for the three months ended December 31, 2006. The timing of gas cost recovery in the Utility segment for the quarter ended December 31, 2007 as compared to the quarter ended December 31, 2006 is primarily responsible for the increase. Higher cash receipts in the Exploration and Production segment also contributed to the increase.

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

Investing Cash Flow

Expenditures for Long-Lived Assets

     The Company’s expenditures for long-lived assets totaled $69.7 million during the three months ended December 31, 2007. The table below presents these expenditures:

Three Months Ended December 31, 2007
(in millions of dollars)

	Total
	Expenditures for
	Long-Lived Assets
Utility	$	12.7
Pipeline and Storage		25.3
Exploration and Production		30.7
Timber		1.0
	$	69.7

Utility

     The majority of the Utility capital expenditures for the three months ended December 31, 2007 were made for replacement of mains and main extensions, as well as for the replacement of service lines.

Pipeline and Storage

     The majority of the Pipeline and Storage capital expenditures for the three months ended December 31, 2007 were related to the Empire Connector project costs, which is discussed below.

     The Company continues to explore various opportunities to expand its capabilities to transport gas to the East Coast, either through the Supply Corporation or Empire systems or in partnership with others. Construction of the Empire Connector, a pipeline which will connect the Empire Pipeline with the Millennium Pipeline and which is designed to transport up to approximately 250 MDth of natural gas per day, began in September 2007. The planned in-service date is November 2008. Refer to the Rate and Regulatory Matters section that follows for further discussion of this matter. The total cost to the Company of the Empire Connector project is estimated at $177 million, after giving effect to sales tax exemptions worth approximately $3.7 million. The Company anticipates financing this project with cash on hand and/or through the use of the Company’s lines of credit. As of December 31, 2007, the Company had incurred approximately $44.8 million in costs related to this project. Of this amount, $25.1 million and $0.4 million were incurred during the quarters ended December 31, 2007 and December 31, 2006, respectively. All project costs incurred as of December 31, 2007, have been capitalized as either Construction Work in Progress ($37.7 million) or Materials and Supplies Inventory ($7.1 million), as per the accounting guidance in the FERC’s Uniform System of Accounts and SFAS 71.

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

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

     Supply Corporation has plans to develop new storage capacity by pursuing expansion of its East Branch and Galbraith storage facilities. The expansion of these two fields, which Supply Corporation hopes to market through one offering at market-based rates, could provide approximately 7 Bcf of incremental storage capacity with incremental withdrawal deliverability of up to 80 MDth of natural gas per day, available in 2011. Supply Corporation expects that the availability of this incremental storage capacity will complement the West to East pipeline project and help meet the demand for storage created by the prospective increased flow of Rockies gas supply into the western Pennsylvania area, although traditional gas supplies will also be able to take advantage of this incremental storage capacity. An Open Season for this capacity is expected in 2008.

     The timeline associated with Supply Corporation’s pipeline and storage projects depends on market development. Should the market materialize, the Company anticipates financing the Tuscarora Extension project and/or the East Branch/Galbraith expansion(s) with cash on hand and/or through the use of the Company’s lines of credit. The capital cost of the West to East project could amount to $700 million, which would be financed by a combination of debt and equity. There have been no costs incurred by the Company related to either pipeline project as of December 31, 2007. Approximately $0.2 million has been spent to study the East Branch/Galbraith project as of December 31, 2007. The Company has not yet filed an application with the FERC for the authority to build either pipeline project or the storage expansion(s).

Exploration and Production

     The Exploration and Production segment capital expenditures for the three months ended December 31, 2007 included approximately $6.8 million for the Gulf Coast region, substantially all of which was for the off-shore program in the Gulf of Mexico, $12.8 million for the West Coast region and $11.1 million for the Appalachian region. These amounts included approximately $4.5 million spent to develop proved undeveloped reserves.

Timber

     The majority of the Timber segment capital expenditures for the three months ended December 31, 2007 were for construction of a lumber sorter for Highland’s sawmill operations that was placed into service in October 2007 as well as for purchases of equipment for Highland’s sawmill and kiln operations.

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

Financing Cash Flow

     The Company did not have any outstanding short-term notes payable to banks or commercial paper at December 31, 2007. However, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, repurchases of stock, and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As for bank loans, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines, which aggregate to $455.0 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

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

available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million that extends through September 30, 2010.

     Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September 30, 2010. At December 31, 2007, the Company’s debt to capitalization ratio (as calculated under the facility) was .37. The constraints specified in the committed credit facility would permit an additional $2.14 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio would exceed .65. If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.

     Under the Company’s existing indenture covenants, at December 31, 2007, the Company would have been permitted to issue up to a maximum of $1.5 billion in additional long-term unsecured indebtedness at then-current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands.

     The Company’s 1974 indenture, pursuant to which $399.0 million (or 40%) of the Company’s long-term debt (as of December 31, 2007) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

     The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries 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 December 31, 2007, the Company had no debt outstanding under the committed credit facility.

     The Company has an effective registration statement on file with the SEC under which it has available capacity to issue an additional $550.0 million of debt and equity securities under the Securities Act of 1933. The Company may sell all or a portion of the remaining registered securities if warranted by market conditions and the Company’s capital requirements. Any offer and sale of the above mentioned $550.0 million of debt and equity securities will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

     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.

     On December 8, 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. As of December 31, 2007, the Company has repurchased 3,834,878 shares for $133.2 million under this program. There were no share repurchases under this program during the quarter

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

ended December 31, 2007. 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 expected that open market repurchases will continue from time to time depending on market conditions.

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 $33.8 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters and other items and are accounted for as operating leases. The Company’s unconsolidated subsidiaries, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $4.5 million. The Company has guaranteed 50% or $2.3 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 to have a material adverse effect on the financial condition of the Company.

Market Risk Sensitive Instruments

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

Rate and Regulatory Matters

Utility Operation

     Base rate adjustments in both the New York and Pennsylvania 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 aggressive 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,

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

the Company’s conservation program for implementation on an accelerated basis. Associated ratemaking issues, however, were reserved for consideration in the rate case. On September 28, 2007, an administrative law judge assigned to the proceeding issued a recommended decision (RD) based on a review and analysis of the evidence presented in the case. On December 21, 2007, the NYPSC issued an Order adopting some provisions of the RD and modifying others. The Order provides 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 arising from the conservation program. The rate increase and bill surcharge became effective December 28, 2007. The Order further provides for a return on equity of 9.1%. As recommended in the RD, the Order also approved the Company’s proposed revenue decoupling mechanism.

Pennsylvania Jurisdiction

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

     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 Settlement Agreement 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 Settlement Agreement to the PaPUC for approval. Distribution Corporation anticipates that the PaPUC will review the Settlement Agreement in the first quarter of calendar 2008. In the Settlement Agreement, Distribution Corporation agrees, without admitting liability, to pay a $50,000 fine and to fund an additional $30,000 of safety-related activities. Distribution Corporation also agrees to make various improvements to its butt-fusion procedures and to implement a program to review existing butt-fusions.

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

Pipeline and Storage

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

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

     On December 21, 2006, the FERC issued an order granting a Certificate of Public Convenience and Necessity authorizing the construction and operation of the Empire Connector and various other related pipeline projects by other unaffiliated companies. The Empire Certificate contains various environmental and other conditions. Empire has accepted that Certificate. Additional environmental permits from the U.S. Army Corps of Engineers and state environmental agencies have been received. Empire has also received, from all six upstate New York counties in which it would build the Empire Connector project, final approval of sales tax exemptions and temporary partial property tax abatements necessary to enable the Empire Connector to generate a fair return. In June 2007, Empire signed a firm transportation service agreement with KeySpan Gas East Corporation, under which Empire is obligated to provide transportation service that will require construction of this project. Construction began in September 2007 and is planned to be complete by November 1, 2008.

Environmental Matters

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

     The Company received, in 1998 and again in October 1999, notice that the NYDEC believes the Company is responsible for contamination discovered at a former manufactured gas plant site located in New York for which the Company had not been named as a PRP. In February 2007, the NYDEC identified the Company as a PRP for the site and issued a proposed remedial action plan. The NYDEC estimated clean-up costs under its proposed remedy to be $8.9 million if implemented. Although the Company commented to the NYDEC that the proposed remedial action plan contained a number of material errors, omissions and procedural defects, the NYDEC, in a March 2007 Record of Decision, selected the remedy it had previously proposed. In July 2007, the Company appealed the NYDEC’s Record of Decision to the New York State Supreme Court, Albany County. The Court dismissed the appeal in January 2008. The Company is reviewing its options in this matter and believes that a negotiated resolution with the NYDEC regarding the site remains possible.

     At December 31, 2007, 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 $12.1 million to $15.8 million. The minimum estimated liability of $12.1 million has been recorded on the Consolidated Balance Sheet at December 31, 2007. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and insurance proceeds.

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

     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

     On October 1, 2007, the Company adopted FIN 48. FIN 48 clarifies the accounting for income taxes by prescribing a minimum probability threshold that a tax position must meet before a financial statement benefit is recognized. The minimum threshold is defined in FIN 48 as a tax position that is more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If a tax benefit meets this threshold, it is measured and recognized based on an analysis of the cumulative probability of the tax benefit being ultimately sustained. The adoption of FIN 48 did not have a material impact on the Company’s consolidated financial statements. For further discussion of the impact of adopting FIN 48, refer to Part I, Item 1 at Note 2 — Income Taxes.

     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. The pronouncement is effective for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009. The pronouncement is effective for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value on a recurring basis, as of the Company’s first quarter of fiscal 2010. The Company is currently evaluating the impact that the adoption of SFAS 157 will have on its consolidated financial statements.

     In September 2006, the FASB also issued SFAS 158, an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R. SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be adopted by the Company by the end of fiscal 2009. Currently, the Company measures its plan assets and benefit obligations using a June 30th measurement date.

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

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

     In December 2007, the FASB issued SFAS 160. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests (NCI) and classified as a component of equity. This new consolidation method will significantly change the accounting for transactions with minority interest holders. SFAS 160 is effective as of the Company’s first quarter of fiscal 2010. The Company currently does not have any NCI.

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

Safe Harbor for Forward-Looking Statements

     The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, performance and capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking” statements as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

1.	Changes in economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents;
2.	Changes in demographic patterns and weather conditions, including the occurrence of severe weather such as hurricanes;
3.	Changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments or the valuation of the Company’s natural gas and oil reserves;
4.	Uncertainty of oil and gas reserve estimates;
5.	Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves;
6.	Significant changes from expectations in the Company’s actual production levels for natural gas or oil;
7.	Changes in the availability and/or price of derivative financial instruments;
8.	Changes in the price differentials between various types of oil;
9.	Inability to obtain new customers or retain existing ones;
10.	Significant changes in competitive factors affecting the Company;
11.	Changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations;

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

12.	Governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements;
13.	Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;
14.	Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs or plans;
15.	The nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits;
16.	Occurrences affecting the Company’s ability to obtain funds from operations, from borrowings under our credit lines or other credit facilities or from issuances of other short-term notes or debt or equity securities to finance needed capital expenditures and other investments, including any downgrades in the Company’s credit ratings;
17.	Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties;
18.	Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
19.	Significant changes in tax rates or policies or in rates of inflation or interest;
20.	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;
21.	Changes in accounting principles or the application of such principles to the Company;
22.	The cost and effects of legal and administrative claims against the Company;
23.	Changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefit plans;
24.	Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide post-retirement benefits; or
25.	Increasing costs of insurance, changes in coverage and the ability to obtain insurance.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

     The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without

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Item 4. Controls and Procedures (Concl.)

limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2007.

Changes in Internal Control Over Financial Reporting

     There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 2007 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

     In an action instituted in the New York State Supreme Court, Kings County on February 18, 2003 against Distribution Corporation and Paul J. Hissin, an unaffiliated third party, plaintiff Donna Fordham-Coleman, as administratrix of the estate of Velma Arlene Fordham, alleges that Distribution Corporation’s failure to initiate natural gas service, despite an attempt to do so, at an apartment leased to the plaintiff’s decedent, Velma Arlene Fordham, caused the decedent’s death in February 2001. The plaintiff sought damages for wrongful death and pain and suffering, plus punitive damages. Distribution Corporation denied plaintiff’s material allegations, asserted seven affirmative defenses and asserted a cross-claim against the co-defendant. Distribution Corporation believes, and has vigorously asserted, that plaintiff’s allegations lack merit. The court changed venue of the action to New York State Supreme Court, Erie County. Trial was scheduled to begin October 15, 2007. However, the parties resolved the action.

     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.”

     On November 8, 2007, Distribution Corporation filed a complaint with the PaPUC requesting that the PaPUC commence an investigation to determine whether New Mountain Vantage GP, L.L.C. (New Mountain), and others acting in concert with it, had violated Pennsylvania law by acquiring control of Distribution Corporation without the prior approval of the PaPUC. Distribution Corporation also petitioned the PaPUC for an order requiring New Mountain to show cause why it should not be required to apply for and receive a certificate of public convenience prior to acquiring control of Distribution Corporation. On December 19, 2007, Distribution Corporation filed a petition with the NYPSC seeking relief in a form and manner substantially similar to the order sought in Pennsylvania. Pursuant to an agreement dated January 24, 2008 among the Company, New Mountain and certain affiliates of New Mountain, Distribution Corporation filed motions to withdraw the complaint and petitions filed with the PaPUC and NYPSC. The NYPSC granted the motion on January 30, 2008; however, the motion before the PaPUC remains pending.

     The resolution of the Fordham-Coleman action described above did not have a material effect on the consolidated financial condition, results of operations, or cash flow of the Company. Although no assurances can be given, the Company believes, based on the information presently known, that the ultimate resolution of the matters before the PaPUC and NYPSC described above will not be material to the consolidated financial condition, results of operations, or cash flow of the Company.

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Item 1. Legal Proceedings (Concl.)

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

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

Item 1A. Risk Factors

     For a discussion of risk factors, refer to “Risk Factors” in Item 1A of the Company’s 2007 Form 10-K. There have been no subsequent material changes to that disclosure.

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

     On October 1, 2007, the Company issued a total of 2,400 unregistered shares of Company common stock to the eight non-employee directors of the Company serving on the Board of Directors, 300 shares to each such director. All of these unregistered shares were issued as partial consideration for such directors’ services during the quarter ended December 31, 2007, pursuant to the Company’s Retainer Policy for Non-Employee Directors. These transactions were exempt from registration by Section 4(2) of the Securities Act of 1933, as transactions not involving a public offering.

Issuer Purchases of Equity Securities

					Total Number of		Maximum Number
					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, 2007		8,768	$	47.15		—		4,165,122
Nov. 1-30, 2007		28,356	$	47.76		—		4,165,122
Dec. 1-31, 2007		23,559	$	47.78		—		4,165,122
Total		60,683	$	47.68		—		4,165,122

(a)

Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes. During the quarter ended December 31, 2007, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 60,683 shares purchased other than through a publicly announced share repurchase program, 21,836 were purchased for the Company’s 401(k) plans and 38,847 were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock.

(b)

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

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Item 4. Submission of Matters to a Vote of Security Holders

     On January 24, 2008, the Company and New Mountain Vantage GP, L.L.C. and its affiliates entered into an agreement to settle a proxy contest pertaining to the election of directors to the Company’s Board of Directors at the Company’s Annual Meeting of Stockholders to be held on February 21, 2008. A description of the terms of the settlement is included in the Company’s Schedule 14A filed with the SEC on January 30, 2008, and such description is incorporated herein by reference. The description of the settlement agreement is qualified in its entirety by reference to the full text of the settlement agreement, which is attached as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 24, 2008 and incorporated herein by reference.

Item 6. Exhibits

(a) Exhibits

Exhibit
Number			Description of Exhibit
			Material Contracts:
			Form of Employment Continuation and Noncompetition Agreement among the Company, a subsidiary of the Company and Karen M. Camiolo (incorporated by reference to Exhibit 10.1, Form 10-K for fiscal year ended September 30, 2007 in File No. 1-3380).
	10.1		Description of performance goals for certain executive officers under the National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Plan.
		12	Statements regarding Computation of Ratios:
			Ratio of Earnings to Fixed Charges for the Twelve Months Ended December 31, 2007 and the Fiscal Years Ended September 30, 2003 through 2007.
		31.1	Written statements of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
		31.2	Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
		32	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
		99	National Fuel Gas Company Consolidated Statement of Income for the Twelve Months Ended December 31, 2007 and 2006.

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SIGNATURE

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

	NATIONAL FUEL GAS COMPANY                (Registrant)
	/s/ R. J. Tanski
	R. J. Tanski
	Treasurer and Principal Financial Officer
	/s/ K. M. Camiolo
	K. M. Camiolo
	Controller and Principal Accounting Officer
Date: February 8, 2008

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