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, 2008

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

For the transition period from                      to                     

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)

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, 2009: 79,514,816 shares.

 

 

GLOSSARY OF TERMS

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

National Fuel Gas Companies

Company		The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Data-Track		Data-Track Account Services, Inc.
Distribution Corporation		National Fuel Gas Distribution Corporation
Empire		Empire Pipeline, Inc.
ESNE		Energy Systems North East, LLC
Highland		Highland Forest Resources, Inc.
Horizon		Horizon Energy Development, Inc.
Horizon LFG		Horizon LFG, Inc.
Horizon Power		Horizon Power, Inc.
Leidy Hub		Leidy Hub, Inc.
Midstream		National Fuel Gas Midstream Corporation
Model City		Model City Energy, LLC
National Fuel		National Fuel Gas Company
NFR		National Fuel Resources, Inc.
Registrant		National Fuel Gas Company
SECI		Seneca Energy Canada Inc.
Seneca		Seneca Resources Corporation
Seneca Energy		Seneca Energy II, LLC
Supply Corporation		National Fuel Gas Supply Corporation

Regulatory Agencies

FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
NYDEC		New York State Department of Environmental Conservation
NYPSC		State of New York Public Service Commission
PaPUC		Pennsylvania Public Utility Commission
SEC		Securities and Exchange Commission

Other

2008 Form 10-K		The Company’s Annual Report on Form 10-K for the year ended September 30, 2008, as amended
ARB 51		Accounting Research Bulletin No. 51, Consolidated Financial Statements
Bbl		Barrel (of oil)
Bcf		Billion cubic feet (of natural gas)
Board foot		A measure of lumber and/or timber equal to 12 inches in length by 12 inches in width by one inch in thickness.
Btu		British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.
Capital expenditure		Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Degree day		A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative		A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.
Development costs		Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
Dth		Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.

GLOSSARY OF TERMS (Cont.)

Exchange Act		Securities Exchange Act of 1934, as amended
Expenditures for    long-lived assets		Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costs		Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
FIN		FASB Interpretation Number
FIN 48		FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of SFAS 109
Firm transportation    and/or storage		The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP		Accounting principles generally accepted in the United States of America
Goodwill		An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging		A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub		Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
Interruptible transportation    and/or storage		The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LIBOR		London Interbank Offered Rate
LIFO		Last-in, first-out
Mbbl		Thousand barrels (of oil)
Mcf		Thousand cubic feet (of natural gas)
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth		Thousand decatherms (of natural gas)
MMBtu		Million British thermal units
MMcf		Million cubic feet (of natural gas)
NYMEX		New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Open Season		A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined (“Open Season”) time period are evaluated as if they had been submitted simultaneously.
Proved developed reserves		Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves		Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive.
PRP		Potentially responsible party
Reserves		The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Restructuring		Generally referring to partial “deregulation” of the utility industry by 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

GLOSSARY OF TERMS (Concl.)

SFAS 88		Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits
SFAS 106		Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions
SFAS 109		Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes
SFAS 115		Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities
SFAS 123R		Statement of Financial Accounting Standards No. 123R, Share-Based Payment
SFAS 131		Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information
SFAS 132R		Statement of Financial Accounting Standards No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits
SFAS 133		Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
SFAS 141R		Statement of Financial Accounting Standards No. 141R, Business Combinations
SFAS 157		Statement of Financial Accounting Standards No. 157, Fair Value Measurements
SFAS 158		Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of SFAS 87, 88, 106, and 132R
SFAS 159		Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of SFAS 115
SFAS 160		Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB 51.
SFAS 161		Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS 133
Stock acquisitions		Investments in corporations.
Unbundled service		A service that has been separated from other services, with rates charged that reflect only the cost of the separated service.
VEBA		Voluntary Employees’ Beneficiary Association
WNC		Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.

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, 2008 and 2007		6
b. Consolidated Balance Sheets – December 31, 2008 and September 30, 2008		7 - 8
c. Consolidated Statements of Cash Flows – Three Months Ended December 31, 2008 and 2007		9
d. Consolidated Statements of Comprehensive Income — Three Months Ended December 31, 2008 and 2007		10
e. Notes to Consolidated Financial Statements		11 - 23
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		24 - 42
Item 3. Quantitative and Qualitative Disclosures About Market Risk		42
Item 4. Controls and Procedures		42
Part II. Other Information
Item 1. Legal Proceedings		42
Item 1 A. Risk Factors		42 - 44
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		45
Item 3. Defaults Upon Senior Securities		•
Item 4. Submission of Matters to a Vote of Security Holders		•
Item 5. Other Information		•
Item 6. Exhibits		45 - 46
Signatures		47
EX-10.1
EX-10.2
EX-10.3
EX-12
EX-31.1
EX-31.2
EX-32
EX-99

•

The Company has nothing to report under this item.

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

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

Part I. Financial Information

Item 1. Financial Statements

National Fuel Gas Company

		Three Months Ended
		December 31,
(Thousands of Dollars, Except Per Common Share Amounts)		2008				2007
INCOME
Operating Revenues		$	607,163			$	568,268
Operating Expenses
Purchased Gas			328,733				278,010
Operation and Maintenance			101,334				102,455
Property, Franchise and Other Taxes			18,762				17,672
Depreciation, Depletion and Amortization			42,342				44,121
Impairment of Oil and Gas Producing Properties			182,811				—
			673,982				442,258
Operating Income (Loss)			(66,819	)			126,010
Other Income (Expense):
Income (Loss) from Unconsolidated Subsidiaries			(686	)			2,275
Interest Income			1,892				3,093
Other Income			5,327				1,253
Interest Expense on Long-Term Debt			(18,056	)			(16,289	)
Other Interest Expense			375				(724	)
Income (Loss) Before Income Taxes			(77,967	)			115,618
Income Tax Expense (Benefit)			(35,289	)			45,014
Net Income (Loss) Available for Common Stock			(42,678	)			70,604
EARNINGS REINVESTED IN THE BUSINESS
Balance at October 1			953,799				983,776
			911,121				1,054,380
Cumulative Effect of the Adoption of FIN 48			—				(406	)
Adoption of SFAS 158 Measurement Date Provision			(804	)			—
Dividends on Common Stock (2008 - $0.325; 2007 - $0.31)			(25,841	)			(26,023	)
Balance at December 31		$	884,476			$	1,027,951
Earnings Per Common Share:
Basic:
Net Income (Loss) Available for Common Stock		$	(0.54	)		$	0.84
Diluted:
Net Income (Loss) Available for Common Stock		$	(0.53	)		$	0.82
Weighted Average Common Shares Outstanding:
Used in Basic Calculation			79,289,005				83,611,177
Used in Diluted Calculation			80,167,893				85,819,534

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

		December 31,				September 30,
(Thousands of Dollars)		2008				2008
ASSETS
Property, Plant and Equipment		$	4,982,596			$	4,873,969
Less — Accumulated Depreciation, Depletion and Amortization			1,938,841				1,719,869
			3,043,755				3,154,100
Current Assets
Cash and Temporary Cash Investments			136,685				68,239
Hedging Collateral Deposits			3,743				1
Receivables — Net of Allowance for Uncollectible Accounts of $41,369 and $33,117, Respectively			229,220				185,397
Unbilled Utility Revenue			79,404				24,364
Gas Stored Underground			64,279				87,294
Materials and Supplies — at average cost			25,694				31,317
Unrecovered Purchased Gas Costs			26,716				37,708
Other Current Assets			56,385				65,158
Deferred Income Taxes			6,340				—
			628,466				499,478
Other Assets
Recoverable Future Taxes			83,541				82,506
Unamortized Debt Expense			13,531				13,978
Other Regulatory Assets			190,890				189,587
Deferred Charges			4,233				4,417
Other Investments			69,801				80,640
Investments in Unconsolidated Subsidiaries			13,443				16,279
Goodwill			5,476				5,476
Intangible Assets			25,620				26,174
Prepaid Post-Retirement Benefit Costs			20,775				21,034
Fair Value of Derivative Financial Instruments			111,303				28,786
Other			13,353				7,732
			551,966				476,609
Total Assets		$	4,224,187			$	4,130,187

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)

		December 31,				September 30,
(Thousands of Dollars)		2008				2008
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued And Outstanding – 79,512,716 Shares And 79,120,544 Shares, Respectively		$	79,513			$	79,121
Paid in Capital			580,377				567,716
Earnings Reinvested in the Business			884,476				953,799
Total Common Shareholder Equity Before Items of Other Comprehensive Income			1,544,366				1,600,636
Accumulated Other Comprehensive Income			50,101				2,963
Total Comprehensive Shareholders’ Equity			1,594,467				1,603,599
Long-Term Debt, Net of Current Portion			999,000				999,000
Total Capitalization			2,593,467				2,602,599
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper			66,000				—
Current Portion of Long-Term Debt			100,000				100,000
Accounts Payable			197,968				142,520
Amounts Payable to Customers			4,715				2,753
Dividends Payable			25,841				25,714
Interest Payable on Long-Term Debt			15,557				22,114
Customer Advances			30,093				33,017
Other Accruals and Current Liabilities			65,415				45,220
Deferred Income Taxes			—				1,871
Fair Value of Derivative Financial Instruments			2,941				1,362
			508,530				374,571
Deferred Credits
Deferred Income Taxes			604,044				634,372
Taxes Refundable to Customers			18,452				18,449
Unamortized Investment Tax Credit			4,516				4,691
Cost of Removal Regulatory Liability			103,877				103,100
Other Regulatory Liabilities			96,378				91,933
Pension and Other Post-Retirement Liabilities			73,076				78,909
Asset Retirement Obligations			92,597				93,247
Other Deferred Credits			129,250				128,316
			1,122,190				1,153,017
Commitments and Contingencies			—				—
Total Capitalization and Liabilities		$	4,224,187			$	4,130,187

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

		Three Months Ended
		December 31,
(Thousands of Dollars)		2008				2007
OPERATING ACTIVITIES
Net Income (Loss) Available for Common Stock		$	(42,678	)		$	70,604
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties			182,811				—
Depreciation, Depletion and Amortization			42,342				44,121
Deferred Income Taxes			(69,626	)			5,296
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions			1,032				431
Impairment of Investment in Partnership			1,804				—
Excess Tax Benefits Associated with Stock-Based Compensation Awards			(5,927	)			(16,275	)
Other			6,628				4,916
Change in:
Hedging Collateral Deposits			(3,742	)			2,070
Receivables and Unbilled Utility Revenue			(98,914	)			(127,894	)
Gas Stored Underground and Materials and Supplies			20,971				(186	)
Unrecovered Purchased Gas Costs			10,992				2,583
Prepayments and Other Current Assets			14,958				10,422
Accounts Payable			3,705				42,398
Amounts Payable to Customers			1,962				(1,228	)
Customer Advances			(2,924	)			635
Other Accruals and Current Liabilities			30,407				25,400
Other Assets			12,560				10,163
Other Liabilities			(6,217	)			1,889
Net Cash Provided by Operating Activities			100,144				75,345
INVESTING ACTIVITIES
Capital Expenditures			(84,268	)			(69,744	)
Cash Held in Escrow			—				58,397
Net Proceeds from Sale of Oil and Gas Producing Properties			—				1,500
Other			(632	)			(761	)
Net Cash Used in Investing Activities			(84,900	)			(10,608	)
FINANCING ACTIVITIES
Change in Notes Payable to Banks and Commercial Paper			66,000				—
Excess Tax Benefits Associated with Stock-Based Compensation Awards			5,927				16,275
Reduction of Long-Term Debt			—				(24	)
Dividends Paid on Common Stock			(25,714	)			(25,873	)
Net Proceeds from Issuance of Common Stock			6,989				9,846
Net Cash Provided by Financing Activities			53,202				224
Net Increase in Cash and Temporary Cash Investments			68,446				64,961
Cash and Temporary Cash Investments at October 1			68,239				124,806
Cash and Temporary Cash Investments at December 31		$	136,685			$	189,767

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

		Three Months Ended
		December 31,
(Thousands of Dollars)		2008				2007
Net Income (Loss) Available for Common Stock		$	(42,678	)		$	70,604
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment			8				(18	)
Unrealized Loss on Securities Available for Sale Arising During the Period			(10,032	)			(1,201	)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period			118,880				(20,859	)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income			(28,792	)			5,421
Other Comprehensive Income (Loss), Before Tax			80,064				(16,657	)
Income Tax Benefit Related to Unrealized Loss on Securities Available for Sale Arising During the Period			(3,791	)			(59	)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period			48,128				(8,648	)
Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gains) Losses from Derivative Financial Instruments In Net Income			(11,411	)			2,133
Income Taxes – Net			32,926				(6,574	)
Other Comprehensive Income (Loss)			47,138				(10,083	)
Comprehensive Income		$	4,460			$	60,521

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

Note 1 — Summary of Significant Accounting Policies

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

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

Earnings for Interim Periods. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2008, 2007 and 2006 that are included in the Company’s 2008 Form 10-K. The consolidated financial statements for the year ended September 30, 2009 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, 2008 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2009. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year.

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

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

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

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

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

Item 1. Financial Statements (Cont.)

is included in Accounts Payable on the Consolidated Balance Sheet at December 31, 2008. It is the Company’s policy to not offset hedging collateral deposits paid or received against the derivative financial instruments liability or asset balances.

Cash Held in Escrow. On August 31, 2007, the Company received approximately $232.1 million of proceeds from the sale of SECI, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. The escrow account was a Canadian dollar denominated account. On a U.S. dollar basis, the value of this account was $62.0 million at September 30, 2007. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. To hedge against foreign currency exchange risk related to the cash being held in escrow, the Company held a forward contract to sell Canadian dollars. For presentation purposes on the Consolidated Statement of Cash Flows, for the three months ended December 31, 2007, the Cash Held in Escrow line item within Investing Activities reflects the net proceeds to the Company (received on January 8, 2008) after adjusting for the impact of the foreign currency hedge.

Gas Stored Underground — Current. In the Utility segment, gas stored underground – current is valued using the LIFO method. This value or cost is lower than the current market value of the gas stored underground. Gas stored underground – current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $36.2 million at December 31, 2008, is reduced to zero by September 30 of each year as the inventory is replenished.

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

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

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

Item 1. Financial Statements (Cont.)

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

		At December 31, 2008				At September 30, 2008
Funded Status of the Pension and Other Post-Retirement Benefit Plans		$	(19,741	)		$	(19,741	)
Cumulative Foreign Currency Translation Adjustment			(63	)			(71	)
Net Unrealized Gain on Derivative Financial Instruments			69,320				15,949
Net Unrealized Gain on Securities Available for Sale (1)			585				6,826
Accumulated Other Comprehensive Income		$	50,101			$	2,963

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, 2008, there were 765,000 stock options and 365,000 stock-settled SARs excluded as being antidilutive. For the quarter ended December 31, 2007, there were no stock options or stock-settled SARs excluded as being antidilutive.

Stock-Based Compensation. During the quarter ended December 31, 2008, the Company granted 610,000 performance-based stock-settled SARs having a weighted average exercise price of $29.88 per share. The weighted average grant date fair value of these stock-settled SARs was $4.09 per share. The accounting treatment for such stock-settled SARs is the same under SFAS 123R as the accounting for stock options under SFAS 123R. The stock-settled SARs granted during the quarter ended December 31, 2008 vest and become exerciseable annually in one-third increments, provided that a performance condition is met. The performance condition for each fiscal year, generally stated, is an increase over the prior fiscal year of at least five percent in certain oil and natural gas production of the Exploration and Production segment. The weighted average grant date fair value of these stock-settled SARs granted during the current quarter was estimated on the date of grant using the same accounting treatment that is applied for stock options under SFAS 123R, and assumes that the performance conditions specified will be achieved. If such conditions are not met or it is not considered probable that such conditions will be met, no compensation expense is recognized and any previously recognized compensation expense is reversed.

     There were no stock options or restricted share awards (non-vested stock as defined in SFAS 123R) granted during the quarter ended December 31, 2008.

Item 1. Financial Statements (Cont.)

New Accounting Pronouncements. In September 2006, the FASB issued SFAS 157, “Fair Value Measurements”. SFAS 157 provides guidance for using fair value to measure assets and liabilities. The pronouncement serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. SFAS 157 is to be applied whenever another standard requires or allows assets or liabilities to be measured at fair value. In accordance with FASB Staff Position FAS No. 157-2, on October 1, 2008, the Company adopted SFAS 157 for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis. The same FASB Staff Position delays the effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value on a recurring basis, until the Company’s first quarter of fiscal 2010. For further discussion of the impact of the adoption of SFAS 157 for financial assets and financial liabilities, refer to Note 2 — Fair Value Measurements. The Company is currently evaluating the impact that the adoption of SFAS 157 for nonfinancial assets and nonfinancial liabilities will have on its consolidated financial statements. The Company has identified Goodwill as being the major nonfinancial asset that will be impacted by SFAS 157 and Asset Retirement Obligations as being the major nonfinancial liability that will be impacted by SFAS 157.

     In September 2006, the FASB issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” (an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R). SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be fully adopted by the Company by the end of fiscal 2009. The Company has historically measured its plan assets and benefit obligations using a June 30th measurement date. In anticipation of changing to a September 30th measurement date, the Company will be recording fifteen months of pension and other post-retirement benefit costs during fiscal 2009. In accordance with the provisions of SFAS 158, these costs have been calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $5.1 million and have been recorded by the Company during the quarter ended December 31, 2008 as a $3.8 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $1.3 million ($0.8 million after tax) adjustment to earnings reinvested in the business. For further discussion of the impact of adopting the measurement date provisions of SFAS 158, refer to Note 8 – Retirement Plan and Other Post-Retirement Benefits.

     In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of SFAS 115.” SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not otherwise required to be measured at fair value under GAAP. A company that elects the fair value option for an eligible item will be required to recognize in current earnings any changes in that item’s fair value in reporting periods subsequent to the date of adoption. SFAS 159 became effective for the Company on October 1, 2008. The Company did not elect the fair value measurements option for any of its financial instruments other than those that are already being measured at fair value.

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

Item 1. Financial Statements (Cont.)

     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.

     In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS 133.” SFAS 161 requires entities to provide enhanced disclosures related to an entity’s derivative instruments and hedging activities in order to enable investors to better understand how derivative instruments and hedging activities impact an entity’s financial reporting. The additional disclosures include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective as of the Company’s second quarter of fiscal 2009. The Company is currently evaluating the impact that the adoption of SFAS 161 will have on its disclosures in the notes to the consolidated financial statements.

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

Note 2 – Fair Value Measurements

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

     The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Item 1. Financial Statements (Cont.)

Recurring Fair Value Measures		At fair value as of December 31, 2008
(Dollars in thousands)		Level 1				Level 2				Level 3				Total
Assets:
Cash Equivalents		$	114,547			$	—			$	—			$	114,547
Derivative Financial Instruments			—				28,273				83,030				111,303
Other Investments			17,715				—				—				17,715
Hedging Collateral Deposits			3,743				—				—				3,743
Total		$	136,005			$	28,273			$	83,030			$	247,308
Liabilities:
Derivative Financial Instruments		$	2,941			$	—			$	—			$	2,941
Total		$	2,941			$	—			$	—			$	2,941

Derivative Financial Instruments

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

Cash Equivalents

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

Other Investments

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

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

Item 1. Financial Statements (Cont.)

Fair Value Measurements Using Unobservable Inputs (Level 3)

						Total Gains/Losses –
						Realized and Unrealized
										Included in Other				Transfer
		October 1,				Included in				Comprehensive				In/Out of				December 31,
(Dollars in thousands)		2008				Earnings				Income				Level 3				2008
Assets:
Derivative Financial Instruments		$	7,110			$	(3,716	)(1)		$	79,636			$	—			$	83,030
Total		$	7,110			$	(3,716	)		$	79,636			$	—			$	83,030
Liabilities:
Derivative Financial Instruments		$	(777	)		$	(12,104	)(1)		$	12,881			$	—			$	—
Total		$	(777	)		$	(12,104	)		$	12,881			$	—			$	—

Note 3 — Income Taxes

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

		Three Months Ended
		December 31,
		2008				2007
Current Income Taxes
Federal		$	26,518			$	34,259
State			7,819				5,459
Deferred Income Taxes
Federal			(54,055	)			(80	)
State			(15,571	)			5,376
			(35,289	)			45,014
Deferred Investment Tax Credit			(174	)			(174	)
Total Income Taxes		$	(35,463	)		$	44,840
Presented as Follows:
Other Income		$	(174	)		$	(174	)
Income Tax Expense (Benefit)			(35,289	)			45,014
Total Income Taxes		$	(35,463	)		$	44,840

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

Item 1. Financial Statements (Cont.)

		Three Months Ended
		December 31,
		2008				2007
U.S. Income (Loss) Before Income Taxes		$	(78,141	)		$	115,444
Income Tax Expense (Benefit), Computed at Federal Statutory Rate of 35%		$	(27,349	)		$	40,405
Increase (Reduction) in Taxes Resulting From:
State Income Taxes			(5,039	)			7,043
Miscellaneous			(3,075	)			(2,608	)
Total Income Taxes		$	(35,463	)		$	44,840
		-

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

		At December 31, 2008				At September 30, 2008
Deferred Tax Liabilities:
Property, Plant and Equipment		$	614,556			$	673,313
Pension and Other Post-Retirement Benefit Costs – SFAS 158			44,345				43,340
Unrealized Hedging Gains			47,856				14,936
Other			36,975				40,455
Total Deferred Tax Liabilities			743,732				772,044
Deferred Tax Assets:
Pension and Other Post-Retirement Benefit Costs – SFAS 158			(44,831	)			(43,340	)
Other			(101,197	)			(92,461	)
Total Deferred Tax Assets			(146,028	)			(135,801	)
Total Net Deferred Income Taxes		$	597,704			$	636,243
Presented as Follows:
Net Deferred Tax Liability/(Asset) – Current		$	(6,340	)		$	1,871
Net Deferred Tax Liability – Non-Current			604,044				634,372
Total Net Deferred Income Taxes		$	597,704			$	636,243

     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 $18.5 million and $18.4 million at December 31, 2008 and September 30, 2008, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $83.5 million and $82.5 million at December 31, 2008 and September 30, 2008, respectively.

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

Item 1. Financial Statements (Cont.)

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

Note 4 — Capitalization

Common Stock. During the three months ended December 31, 2008, the Company issued 687,180 original issue shares of common stock as a result of stock option exercises. The Company also issued 2,100 original issue shares of common stock to the seven non-employee directors of the Company who receive compensation under the Company’s Retainer Policy for Non-Employee Directors, as partial consideration for the directors’ services during the three months ended December 31, 2008. Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the three months ended December 31, 2008, 297,108 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

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

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

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

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

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

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

Item 1. Financial Statements (Cont.)

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

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

Note 5 — Commitments and Contingencies

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

     As disclosed in Note H of the Company’s 2008 Form 10-K, the Company has agreed with the NYDEC to remediate a former manufactured gas plant site located in New York. The Company has submitted a Remedial Design/Remedial Action work plan to the NYDEC and has recorded an estimated minimum liability for remediation of this site of $16.4 million.

     At December 31, 2008, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $19.3 million to $23.5 million. The minimum estimated liability of $19.3 million, which includes the $16.4 million discussed above, has been recorded on the Consolidated Balance Sheet at December 31, 2008. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet.

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

Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, or have a material adverse effect on the financial condition of the Company.

Note 6 – Business Segment Information

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

Item 1. Financial Statements (Cont.)

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

     The data presented in the tables below reflect the reported segments and reconciliations to consolidated amounts. As stated in the 2008 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, other than as noted above, nor in the basis of measuring segment profit or loss, from those used in the Company’s 2008 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the 2008 Form 10-K. While the Exploration and Production segment reported a pre-tax impairment charge of $182.8 million at December 31, 2008, this reduction in segment assets was largely offset by increases in the asset position of its derivative financial instruments combined with the receipt of cash collateral on such derivative financial instruments.

Quarter Ended December 31, 2008 (Thousands)

										Exploration																Corporate and
						Pipeline and				and				Energy				Total Reportable								Intersegment				Total
		Utility				Storage				Production				Marketing				Segments				All Other				Eliminations				Consolidated
Revenue from External Customers		$	349,637			$	35,267			$	96,712			$	115,007			$	596,623			$	10,325			$	215			$	607,163
Intersegment Revenues		$	4,553			$	20,837			$	—			$	—			$	25,390			$	2,322			$	(27,712	)		$	—
Segment Profit:
Net Income (Loss)		$	22,088			$	17,176			$	(83,557	)		$	599			$	(43,694	)		$	(868	)		$	1,884			$	(42,678	)

Quarter Ended December 31, 2007 (Thousands)

										Exploration																Corporate and
						Pipeline and				and				Energy				Total Reportable								Intersegment				Total
		Utility				Storage				Production				Marketing				Segments				All Other				Eliminations				Consolidated
Revenue from External Customers		$	327,125			$	31,884			$	107,955			$	86,719			$	553,683			$	14,450			$	135			$	568,268
Intersegment Revenues		$	4,299			$	20,347			$	—			$	—			$	24,646			$	2,714			$	(27,360	)		$	—
Segment Profit:
Net Income (Loss)		$	20,217			$	12,778			$	34,022			$	954			$	67,971			$	2,736			$	(103	)		$	70,604

Item 1. Financial Statements (Cont.)

Note 7 — Intangible Assets

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

														At September 30,
		At December 31, 2008												2008
		Gross								Net				Net
		Carrying				Accumulated				Carrying				Carrying
		Amount				Amortization				Amount				Amount
Intangible Assets Subject to Amortization:
Long-Term Transportation Contracts		$	8,580			$	(6,213	)		$	2,367			$	2,522
Long-Term Gas Purchase Contracts			31,864				(8,611	)			23,253				23,652
		$	40,444			$	(14,824	)		$	25,620			$	26,174
Aggregate Amortization Expense:
(Thousands)
Three Months Ended December 31, 2008		$	554
Three Months Ended December 31, 2007		$	666

     The gross carrying amount of intangible assets subject to amortization at December 31, 2008 remained unchanged from September 30, 2008. The only activity with regard to intangible assets subject to amortization was amortization expense as shown in the table above. Amortization expense for the long-term transportation contracts is estimated to be $0.3 million for the remainder of 2009 and $0.4 million annually for 2010, 2011, 2012 and 2013. Amortization expense for the long-term gas purchase contracts is estimated to be $1.2 million for the remainder of 2009 and $1.6 million annually for 2010, 2011, 2012 and 2013.

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
		2008				2007				2008				2007
Service Cost		$	2,728			$	3,150			$	950			$	1,276
Interest Cost			11,709				11,237				6,875				6,771
Expected Return on Plan Assets			(14,489	)			(13,750	)			(7,904	)			(8,429	)
Amortization of Prior Service Cost			183				202				(268	)			1
Amortization of Transition Amount			—				—				566				1,782
Amortization of Losses			1,419				2,766				2,318				732
Net Amortization and Deferral For Regulatory Purposes (Including Volumetric Adjustments) (1)			3,240				1,100				4,339				7,212
Net Periodic Benefit Cost		$	4,790			$	4,705			$	6,876			$	9,345

Item 1. Financial Statements (Cont.)

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

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

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

OVERVIEW

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

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

     Despite the loss for the quarter ended December 31, 2008, the Company’s balance sheet remains strong with a capitalization structure of 58% equity and 42% debt at December 31, 2008. The Company also continues to have strong liquidity despite the generally reported problems in the credit markets. The Company has been able to borrow short-term funds under its credit lines and through the commercial paper market to fund working capital needs throughout the quarter. The Company maintains a number of individual uncommitted or discretionary lines of credit with financial institutions for general corporate purposes. These credit lines, which aggregate to $420.0 million, are revocable at the option of the 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. At December 31, 2008, the Company had borrowed $66.0 million under its lines of credit. The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million, which commitment extends through September 30, 2010. At December 31, 2008, the Company did not have any borrowings under its committed credit facility.

CRITICAL ACCOUNTING ESTIMATES

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

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

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

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

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

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

RESULTS OF OPERATIONS

Earnings

     The Company experienced a loss of $42.7 million for the quarter ended December 31, 2008 compared to earnings of $70.6 million for the quarter ended December 31, 2007. The decrease in earnings of $113.3 million is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the Energy Marketing segment, as well as a loss in the All Other category, also contributed to the decrease. Higher earnings in the Utility and Pipeline and Storage segments and the Corporate category slightly offset these decreases. The Company’s loss for the quarter ended December 31, 2008, includes a non-cash $182.8 million impairment charge ($108.2 million after tax) for the Exploration and Production segment’s oil and gas producing properties under the full cost method of accounting using crude oil and natural gas commodity pricing at December 31, 2008, which were lower than the pricing at September 30, 2008, the last ceiling test measurement date. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.

Earnings (Loss) by Segment

Three Months Ended December 31 (Thousands)

										Increase
		2008				2007				(Decrease)
Utility		$	22,088			$	20,217			$	1,871
Pipeline and Storage			17,176				12,778				4,398
Exploration and Production			(83,557	)			34,022				(117,579	)
Energy Marketing			599				954				(355	)
Total Reportable Segments			(43,694	)			67,971				(111,665	)
All Other			(868	)			2,736				(3,604	)
Corporate			1,884				(103	)			1,987
Total Consolidated		$	(42,678	)		$	70,604			$	(113,282	)

Utility

Utility Operating Revenues

Three Months Ended December 31 (Thousands)

										Increase
		2008				2007				(Decrease)
Retail Sales Revenues:
Residential		$	272,418			$	246,797			$	25,621
Commercial			41,333				38,033				3,300
Industrial			2,106				1,651				455
			315,857				286,481				29,376
Transportation			32,011				33,424				(1,413	)
Off-System Sales			3,732				8,213				(4,481	)
Other			2,590				3,306				(716	)
		$	354,190			$	331,424			$	22,766

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

Utility Throughput

Three Months Ended December 31 (MMcf)

										Increase
		2008				2007				(Decrease)
Retail Sales:
Residential			18,166				17,127				1,039
Commercial			2,911				2,877				34
Industrial			143				123				20
			21,220				20,127				1,093
Transportation			17,473				17,827				(354	)
Off-System Sales			512				1,031				(519	)
			39,205				38,985				220

Degree Days

Three Months Ended December 31

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

2008 Compared with 2007

     Operating revenues for the Utility segment increased $22.8 million for the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. This increase largely resulted from a $29.4 million increase in retail gas revenues coupled with a $4.5 million decrease in off-system sales revenues and a $1.4 million decrease in transportation revenues.

     The increase in retail gas sales revenues for the Utility segment was primarily due to higher retail sales volumes, as shown in the table above. The volume increase, most notably in the residential category, is primarily the result of weather that was 10.5 percent colder than the prior year in both operating jurisdictions.

     In the New York jurisdiction, the NYPSC issued an order providing for an annual rate increase of $1.8 million beginning December 28, 2007. As part of this rate order, a rate design change was adopted that shifts a greater amount of cost recovery into the minimum bill amount, thus spreading the recovery of such costs more evenly throughout the year. As a result of this rate order, retail and transportation revenues for the quarter ended December 31, 2008 were $2.2 million lower than revenues for the quarter ended December 31, 2007.

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

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

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

phrase “usage per account” in this paragraph refers to the average gas consumption per customer account after factoring out any impact that weather may have had on consumption. The decrease in other post-retirement benefit costs discussed above stems from the NYPSC rate order that became effective December 28, 2007 whereby the rate allowance for post-retirement benefit costs was reduced given projected reductions in the other post-retirement benefit obligation as a result of an increase in the discount rate from 5% to 6.25% during 2006. The decreases to interest expense primarily reflect lower borrowings and slightly lower rates.

     The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. For the quarter ended December 31, 2008, the WNC did not have a significant impact on earnings as the weather was close to normal. For the quarter ended December 31, 2007, the WNC preserved $1.1 million of earnings, as weather was warmer than normal for the period. In periods of colder than normal weather, the WNC benefits Distribution Corporation’s New York customers.

Pipeline and Storage

Pipeline and Storage Operating Revenues

Three Months Ended December 31 (Thousands)

		2008				2007				Increase
Firm Transportation		$	33,105			$	31,406			$	1,699
Interruptible Transportation			1,103				991				112
			34,208				32,397				1,811
Firm Storage Service			16,686				16,621				65
Other			5,210				3,213				1,997
		$	56,104			$	52,231			$	3,873

Pipeline and Storage Throughput

Three Months Ended December 31 (MMcf)

		2008				2007				Increase
Firm Transportation			110,315				92,883				17,432
Interruptible Transportation			1,792				1,083				709
			112,107				93,966				18,141

2008 Compared with 2007

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

     The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2008 were $17.2 million, an increase of $4.4 million when compared with earnings of $12.8 million for the quarter ended December 31, 2007. The increase is largely attributable to higher transportation revenues ($1.2 million) due to the addition of new contracts for firm transportation service and higher efficiency gas revenues ($1.3 million), as discussed above. In addition, there was an increase in allowance for funds

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

used during construction of $2.1 million. The increase in allowance for funds used during construction is a result of the construction of the Empire Connector, which was completed and placed in service on December 10, 2008. Construction of the Empire Connector began in September 2007 so the calculated allowance for funds used during construction was relatively small during the quarter ended December 31, 2007. With much more significant construction work in progress balances during the quarter ended December 31, 2008, the calculated allowance for funds used during construction was much higher. These earnings increases were partially offset by higher interest expense of $0.4 million. The increase in interest expense was due to higher borrowings.

Exploration and Production

Exploration and Production Operating Revenues

Three Months Ended December 31 (Thousands)

										Increase
		2008				2007				(Decrease)
Gas (after Hedging)		$	41,093			$	45,557			$	(4,464	)
Oil (after Hedging)			53,071				59,643				(6,572	)
Gas Processing Plant			7,328				11,075				(3,747	)
Other			417				(1,309	)			1,726
Intrasegment Elimination (1)			(5,197	)			(7,011	)			1,814
		$	96,712			$	107,955			$	(11,243	)

Production Volumes

Three Months Ended December 31

										Increase
		2008				2007				(Decrease)
Gas Production (MMcf)
Gulf Coast			1,746				2,826				(1,080	)
West Coast			1,022				1,027				(5	)
Appalachia			1,851				1,917				(66	)
Total Production			4,619				5,770				(1,151	)
Oil Production (Mbbl)
Gulf Coast			128				156				(28	)
West Coast			682				629				53
Appalachia			15				37				(22	)
Total Production			825				822				3

Average Prices

Three Months Ended December 31

										Increase
		2008				2007				(Decrease)
Average Gas Price/Mcf
Gulf Coast		$	7.04			$	7.14			$	(0.10	)
West Coast		$	5.02			$	6.77			$	(1.75	)
Appalachia		$	8.53			$	7.45			$	1.08
Weighted Average		$	7.19			$	7.18			$	0.01
Weighted Average After Hedging		$	8.90			$	7.90			$	1.00
Average Oil Price/Bbl
Gulf Coast		$	56.19			$	89.84			$	(33.65	)
West Coast		$	48.01			$	81.80			$	(33.79	)
Appalachia		$	69.06			$	84.12			$	(15.06	)
Weighted Average		$	49.66			$	83.43			$	(33.77	)
Weighted Average After Hedging		$	64.34			$	72.59			$	(8.25	)

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

2008 Compared with 2007

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

     The Exploration and Production segment’s loss for the quarter ended December 31, 2008 was $83.6 million compared with earnings of $34.0 million for the quarter ended December 31, 2007, a decrease of $117.6 million. The decrease in earnings is primarily the result of an impairment charge of $108.2 million, as discussed above. Also, lower natural gas production and lower crude oil prices decreased earnings by $5.9 million, and $4.4 million, respectively. Higher natural gas prices slightly offset these decreases by $3.0 million. Higher general and administrative and other operating expenses of $1.7 million and higher lease operating expenses of $1.3 million also contributed to the decrease in earnings. Lower depletion expense of $0.6 million made a small contribution to earnings. The increase in general and administrative and other operating expenses is mainly due to a bad debt charge related to a customer’s bankruptcy filing combined with higher personnel costs in the Appalachian region. The increase in lease operating expenses is primarily due to higher production taxes related to increased production from the High Island 24L and 23L fields in the Gulf Coast region, higher property taxes and increased well repair costs associated with higher than normal activity in the West Coast region, and an increase in the number of producing properties in the Appalachian region.

Energy Marketing

Energy Marketing Operating Revenues

Three Months Ended December 31 (Thousands)

		2008				2007				Increase
Natural Gas (after Hedging)		$	114,984			$	86,735			$	28,249
Other			23				(16	)			39
		$	115,007			$	86,719			$	28,288

Energy Marketing Volumes

Three Months Ended December 31

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

2008 Compared with 2007

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

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

     The Energy Marketing segment’s earnings for the quarter ended December 31, 2008 were $0.6 million, a decrease of $0.4 million when compared with earnings of $1.0 million for the quarter ended December 31, 2007. Despite colder weather, earnings decreased primarily due to lower margins.

Corporate and All Other

2008 Compared with 2007

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

Interest Income

     Interest income was $1.2 million lower in the quarter ended December 31, 2008 as compared to the quarter ended December 31, 2007. Interest income in the Exploration and Production segment was $1.6 million lower during the quarter ended December 31, 2008 as compared to the quarter ended December 31, 2007 as a result of lower interest rates and lower average temporary cash investment balances.

Other Income

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

Interest Expense on Long-Term Debt

     Interest on long-term debt increased $1.8 million for the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. This increase can be attributed to a higher average amount of long-term debt outstanding. In April 2008, the Company issued $300 million of 6.5% senior, unsecured notes due in April 2018. This increase was partially offset by the repayment of $200 million of 6.303% medium-term notes that matured on May 27, 2008.

CAPITAL RESOURCES AND LIQUIDITY

     The Company’s primary source of cash during the three-month periods ended December 31, 2008 and 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 and by short-term borrowings (for the quarter ended December 31, 2008). During the three months ended December 31, 2008 and December 31, 2007, the common stock used to fulfill the requirements of the Company’s 401(k) plans and Direct Stock Purchase and Dividend Reinvestment Plan was obtained via open market purchases.

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

Operating Cash Flow

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

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