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 endedJune 30,December 31, 2008
OR
   
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to                    
Commission File Number 1-3880
 
NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)
   
New Jersey 13-1086010
   
(State or other jurisdiction of
incorporation or organization)
 (I.R.S. Employer
Identification No.)
   
6363 Main Street
Williamsville, New York
 
14221
   
(Address of principal executive offices) (Zip Code)
(716) 857-7000
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. YESþ   NOo
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filerþ Accelerated filero Non-accelerated filero Smaller reporting companyo
    (Do not check if a smaller reporting company)  
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YESo   NOþ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
Common stock, $1 par value, outstanding at JulyJanuary 31, 2008: 81,475,9502009: 79,514,816 shares.
 
 

 


GLOSSARY OF TERMS
Frequently used abbreviations, acronyms, or terms used in this report:
National Fuel Gas Companies
 
National Fuel Gas Companies
  
Company The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Data-Track Data-Track Account Services, Inc.
Distribution Corporation National Fuel Gas Distribution Corporation
Empire Empire State Pipeline, Inc.
ESNE Energy Systems North East, LLC
Highland Highland Forest Resources, Inc.
Horizon Horizon Energy Development, Inc.
Horizon LFG Horizon LFG, Inc.
Horizon Power Horizon Power, Inc.
Leidy Hub Leidy Hub, Inc.
MidstreamNational Fuel Gas Midstream Corporation
Model City Model City Energy, LLC
National Fuel National Fuel Gas Company
NFR National Fuel Resources, Inc.
Registrant National Fuel Gas Company
SECI Seneca Energy Canada Inc.
Seneca Seneca Resources Corporation
Seneca Energy Seneca Energy II, LLC
Supply Corporation National Fuel Gas Supply Corporation
Regulatory Agencies
 
Regulatory Agencies
  
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
NTSBNational Transportation Safety Board
NYDEC New York State Department of Environmental Conservation
NYPSC State of New York Public Service Commission
PaPUC Pennsylvania Public Utility Commission
SEC Securities and Exchange Commission
Other
   
Other
20072008 Form 10-K The Company’s Annual Report on Form 10-K for the year ended September 30, 20072008, as amended
ARB 51 Accounting Research Bulletin No. 51, Consolidated Financial Statements
Bbl Barrel (of oil)
Bcf Billion cubic feet (of natural gas)
Board foot A measure of lumber and/or timber equal to 12 inches in length by 12 inches in width by one inch in thickness.
Btu British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.
Capital expenditure Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Cashout revenuesA cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper.
Degree day A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.
Development costsCosts incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
Dth Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.

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GLOSSARY OF TERMS (Cont.)
GLOSSARY OF TERMS (Cont.)
   
Exchange Act Securities Exchange Act of 1934, as amended
Expenditures for
   long-lived assets
 Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costsCosts 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.
LIBORLondon 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)
MMBtuMillion British thermal units
MMcf Million cubic feet (of natural gas)
NYMEXNew York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Open Season A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined (“Open Season”) time period are evaluated as if they had been submitted simultaneously.
Proved developed reserves Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive.
PRP Potentially responsible party
Reserves The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Restructuring Generally referring to partial “deregulation” of the utility industry by a statutory or regulatory process. Restructuring of federally regulated natural gas pipelines has resulted in the separation (or “unbundling”) of gas commodity service from transportation service for wholesale and large-volumelarge- 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

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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

-3-


GLOSSARY OF TERMS (Concl.)
SFAS 115 Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities
SFAS 123R Statement of Financial Accounting Standards No. 123R, Share-Based Payment
SFAS 131Statement 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 133Statement 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 Amendmentamendment of SFAS 87, 88, 106, and 132R
SFAS 159 Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of SFAS 115
SFAS 160 Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB 5151.
SFAS 161 Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS 133
Stock acquisitions Investments in corporations.
Unbundled service A service that has been separated from other services, with rates charged that reflect only the cost of the separated service.
VEBA Voluntary Employees’ Beneficiary Association
WNC Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.

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INDEX
   
  Page
  
   
  
   
 6 - 7
   
 87 - 98
   
 109
   
 1110
   
 1211 - 2223
   
 2324 - 4442
   
 4442
   
 44 - 4542
   
  
   
 4542
   
 4542 - 44
   
 45 - 46
   
Item 3. Defaults Upon Senior Securities §
   
Item 4. Submission of Matters to a Vote of Security Holders §
   
Item 5. Other Information §
   
 4645 - 4746
   
 4847
 EX-4.1EX-10.1
EX-10.2
EX-10.3
 EX-12
 EX-31.1
 EX-31.2
 EX-32
 EX-99
 
§The Company has nothing to report under this item.
The Company has nothing to report under this item.
     Reference to the “Company”“the Company” in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.
     This Form 10-Q contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2 — MD&A, under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction and other projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions.

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Part I. Financial Information
Item 1.Financial Statements
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
                
 Three Months Ended Three Months Ended
 June 30, December 31,
(Thousands of Dollars, Except Per Common Share Amounts) 2008 2007 2008 2007
    
INCOME
  
Operating Revenues
 $548,382 $448,779  $607,163 $568,268 
 
Operating Expenses
  
Purchased Gas 272,893 219,075  328,733 278,010 
Operation and Maintenance 102,602 90,390  101,334 102,455 
Property, Franchise and Other Taxes 19,135 17,622  18,762 17,672 
Depreciation, Depletion and Amortization 42,804 37,759  42,342 44,121 
Impairment of Oil and Gas Producing Properties 182,811  
 437,434 364,846  673,982 442,258 
Operating Income
 110,948 83,933 
Operating Income (Loss)
 (66,819)  126,010 
Other Income (Expense):
      
Income from Unconsolidated Subsidiaries 1,561 926 
Income (Loss) from Unconsolidated Subsidiaries  (686) 2,275 
Interest Income 3,086 1,377  1,892 3,093 
Other Income 1,649 787  5,327 1,253 
Interest Expense on Long-Term Debt  (19,468)  (18,226)  (18,056)  (16,289)
Other Interest Expense  (1,199)  (1,512) 375  (724)
Income from Continuing Operations Before Income Taxes
 96,577 67,285 
Income Tax Expense 36,722 26,073 
Income (Loss) Before Income Taxes
  (77,967) 115,618 
Income Tax Expense (Benefit)  (35,289) 45,014 
  
Income from Continuing Operations
 59,855 41,212 
 
Income from Discontinued Operations, Net of Tax
  5,586 
 
Net Income Available for Common Stock
 59,855 46,798 
Net Income (Loss) Available for Common Stock
  (42,678) 70,604 
  
EARNINGS REINVESTED IN THE BUSINESS
  
Balance at April 1 1,008,084 834,902 
Balance at October 1 953,799 983,776 
 1,067,939 881,700  911,121 1,054,380 
Share Repurchases  (17,083)  
Dividends on Common Stock (2008 - $0.325 per share; 2007 - $0.31 per share)  (26,479)  (25,897)
Cumulative Effect of the Adoption of FIN 48   (406)
Adoption of SFAS 158 Measurement Date Provision  (804)  
Dividends on Common Stock (2008 - $0.325; 2007 - $0.31)  (25,841)  (26,023)
Balance at June 30
 $1,024,377 $855,803 
Balance at December 31
 $884,476 $1,027,951 
  
Earnings Per Common Share:
  
Basic:  
Income from Continuing Operations $0.74 $0.49 
Income from Discontinued Operations  0.07 
Net Income Available for Common Stock $0.74 $0.56 
Net Income (Loss) Available for Common Stock
 $(0.54) $0.84 
Diluted:  
Income from Continuing Operations $0.72 $0.48 
Income from Discontinued Operations  0.07 
Net Income Available for Common Stock $0.72 $0.55 
Net Income (Loss) Available for Common Stock
 $(0.53) $0.82 
Weighted Average Common Shares Outstanding:
  
Used in Basic Calculation 81,342,788 83,483,718  79,289,005 83,611,177 
Used in Diluted Calculation 83,712,193 85,668,055  80,167,893 85,819,534 
See Notes to Condensed Consolidated Financial Statements

-6-


Item 1.Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statements of Income and EarningsBalance Sheets
Reinvested in the Business
(Unaudited)
         
  Nine Months Ended
  June 30,
(Thousands of Dollars, Except Per Common Share Amounts) 2008 2007
   
INCOME
        
Operating Revenues
 $2,002,503  $1,737,537 
 
         
Operating Expenses
        
Purchased Gas  1,082,340   938,918 
Operation and Maintenance  325,642   305,502 
Property, Franchise and Other Taxes  58,206   54,562 
Depreciation, Depletion and Amortization  129,337   115,561 
 
   1,595,525   1,414,543 
 
Operating Income
  406,978   322,994 
Other Income (Expense):
        
Income from Unconsolidated Subsidiaries  4,866   3,099 
Interest Income  8,356   3,098 
Other Income  4,982   4,028 
Interest Expense on Long-Term Debt  (52,045)  (52,158)
Other Interest Expense  (4,209)  (4,877)
 
Income from Continuing Operations Before Income Taxes
  368,928   276,184 
Income Tax Expense  143,465   108,804 
 
         
Income from Continuing Operations
  225,463   167,380 
 
         
Income from Discontinued Operations, Net of Tax
     12,385 
 
         
Net Income Available for Common Stock
  225,463   179,765 
 
         
EARNINGS REINVESTED IN THE BUSINESS
        
Balance at October 1  983,776   786,013 
 
   1,209,239   965,778 
Share Repurchases  (106,647)  (34,351)
Cumulative Effect of the Adoption of FIN 48  (406)   
Dividends on Common Stock (2008 - $0.945 per share; 2007 - $0.91 per share)  (77,809)  (75,624)
 
Balance at June 30
 $1,024,377  $855,803 
 
         
Earnings Per Common Share:
        
Basic:        
Income from Continuing Operations $2.72  $2.02 
Income from Discontinued Operations     0.15 
 
Net Income Available for Common Stock $2.72  $2.17 
 
Diluted:        
Income from Continuing Operations $2.65  $1.96 
Income from Discontinued Operations     0.15 
 
Net Income Available for Common Stock $2.65  $2.11 
 
Weighted Average Common Shares Outstanding:
        
Used in Basic Calculation  82,789,748   83,018,583 
 
Used in Diluted Calculation  85,000,381   85,192,777 
 
         
  December 31, September 30,
(Thousands of Dollars) 2008 2008
   
ASSETS        
Property, Plant and Equipment
 $4,982,596  $4,873,969 
Less — Accumulated Depreciation, Depletion and Amortization  1,938,841   1,719,869 
 
   3,043,755   3,154,100 
 
Current Assets
        
Cash and Temporary Cash Investments  136,685   68,239 
Hedging Collateral Deposits  3,743   1 
Receivables — Net of Allowance for Uncollectible Accounts of $41,369 and $33,117, Respectively  229,220   185,397 
Unbilled Utility Revenue  79,404   24,364 
Gas Stored Underground  64,279   87,294 
Materials and Supplies — at average cost  25,694   31,317 
Unrecovered Purchased Gas Costs  26,716   37,708 
Other Current Assets  56,385   65,158 
Deferred Income Taxes  6,340    
 
   628,466   499,478 
 
         
Other Assets
        
Recoverable Future Taxes  83,541   82,506 
Unamortized Debt Expense  13,531   13,978 
Other Regulatory Assets  190,890   189,587 
Deferred Charges  4,233   4,417 
Other Investments  69,801   80,640 
Investments in Unconsolidated Subsidiaries  13,443   16,279 
Goodwill  5,476   5,476 
Intangible Assets  25,620   26,174 
Prepaid Post-Retirement Benefit Costs  20,775   21,034 
Fair Value of Derivative Financial Instruments  111,303   28,786 
Other  13,353   7,732 
 
   551,966   476,609 
 
         
Total Assets
 $4,224,187  $4,130,187 
 
See Notes to Condensed Consolidated Financial Statements

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Item 1.Financial Statements (Cont.)
National Fuel Gas Company

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

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Item 1.Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Balance SheetsStatements of Cash Flows
(Unaudited)
         
  June 30, September 30,
(Thousands of Dollars) 2008 2007
   
CAPITALIZATION AND LIABILITIES        
Capitalization:
        
Comprehensive Shareholders’ Equity
        
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding – 81,473,550 Shares and 83,461,308 Shares, Respectively $81,474  $83,461 
Paid in Capital  583,693   569,085 
Earnings Reinvested in the Business  1,024,377   983,776 
 
Total Common Shareholder Equity Before Items of Other Comprehensive Loss  1,689,544   1,636,322 
Accumulated Other Comprehensive Loss  (105,872)  (6,203)
 
Total Comprehensive Shareholders’ Equity
  1,583,672   1,630,119 
Long-Term Debt, Net of Current Portion
  999,000   799,000 
 
Total Capitalization
  2,582,672   2,429,119 
 
         
Current and Accrued Liabilities
        
Notes Payable to Banks and Commercial Paper      
Current Portion of Long-Term Debt  100,000   200,024 
Accounts Payable  162,838   109,757 
Amounts Payable to Customers  12,864   10,409 
Dividends Payable  26,479   25,873 
Interest Payable on Long-Term Debt  15,774   18,158 
Customer Advances     22,863 
Other Accruals and Current Liabilities  136,458   36,062 
Fair Value of Derivative Financial Instruments  180,255   16,200 
 
   634,668   439,346 
 
         
Deferred Credits
        
Deferred Income Taxes  605,818   575,356 
Taxes Refundable to Customers  14,037   14,026 
Unamortized Investment Tax Credit  4,866   5,392 
Cost of Removal Regulatory Liability  101,251   91,226 
Other Regulatory Liabilities  95,846   76,659 
Post-Retirement Liabilities  60,152   70,555 
Asset Retirement Obligations  74,653   75,939 
Other Deferred Credits  119,898   110,794 
 
   1,076,521   1,019,947 
 
Commitments and Contingencies
      
 
         
Total Capitalization and Liabilities
 $4,293,861  $3,888,412 
 
         
  Three Months Ended
  December 31,
(Thousands of Dollars) 2008 2007
   
OPERATING ACTIVITIES
        
Net Income (Loss) Available for Common Stock $(42,678) $70,604 
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:        
Impairment of Oil and Gas Producing Properties  182,811    
Depreciation, Depletion and Amortization  42,342   44,121 
Deferred Income Taxes  (69,626)  5,296 
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions  1,032   431 
Impairment of Investment in Partnership  1,804    
Excess Tax Benefits Associated with Stock-Based Compensation Awards  (5,927)  (16,275)
Other  6,628   4,916 
Change in:        
Hedging Collateral Deposits  (3,742)  2,070 
Receivables and Unbilled Utility Revenue  (98,914)  (127,894)
Gas Stored Underground and Materials and Supplies  20,971   (186)
Unrecovered Purchased Gas Costs  10,992   2,583 
Prepayments and Other Current Assets  14,958   10,422 
Accounts Payable  3,705   42,398 
Amounts Payable to Customers  1,962   (1,228)
Customer Advances  (2,924)  635 
Other Accruals and Current Liabilities  30,407   25,400 
Other Assets  12,560   10,163 
Other Liabilities  (6,217)  1,889 
 
Net Cash Provided by Operating Activities
  100,144   75,345 
 
         
INVESTING ACTIVITIES
        
Capital Expenditures  (84,268)  (69,744)
Cash Held in Escrow     58,397 
Net Proceeds from Sale of Oil and Gas Producing Properties     1,500 
Other  (632)  (761)
 
Net Cash Used in Investing Activities
  (84,900)  (10,608)
 
         
FINANCING ACTIVITIES
        
Change in Notes Payable to Banks and Commercial Paper  66,000    
Excess Tax Benefits Associated with Stock-Based Compensation Awards  5,927   16,275 
Reduction of Long-Term Debt     (24)
Dividends Paid on Common Stock  (25,714)  (25,873)
Net Proceeds from Issuance of Common Stock  6,989   9,846 
 
Net Cash Provided by Financing Activities
  53,202   224 
 
         
Net Increase in Cash and Temporary Cash Investments
  68,446   64,961 
         
Cash and Temporary Cash Investments at October 1
  68,239   124,806 
 
         
Cash and Temporary Cash Investments at December 31
 $136,685  $189,767 
 
See Notes to Condensed Consolidated Financial Statements

-9-


Item 1.Financial Statements (Cont.)
National Fuel Gas Company
Consolidated StatementStatements of Cash FlowsComprehensive Income
(Unaudited)
         
  Nine Months Ended
  June 30,
(Thousands of Dollars) 2008 2007
   
OPERATING ACTIVITIES
        
Net Income Available for Common Stock $225,463  $179,765 
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:        
Depreciation, Depletion and Amortization  129,337   125,986 
Deferred Income Taxes  27,603   27,107 
Income from Unconsolidated Subsidiaries, Net of Cash Distributions  1,340   (1,486)
Excess Tax Benefits Associated with Stock-Based Compensation Awards  (16,275)  (13,689)
Other  (1,120)  4,722 
Change in:        
Hedging Collateral Deposits  (26,712)  16,276 
Receivables and Unbilled Utility Revenue  (129,102)  (43,733)
Gas Stored Underground and Materials and Supplies  14,819   34,725 
Unrecovered Purchased Gas Costs  9,089   12,970 
Prepayments and Other Current Assets  17,370   30,685 
Accounts Payable  53,081   (12,560)
Amounts Payable to Customers  2,455   (4,738)
Customer Advances  (22,863)  (29,417)
Other Accruals and Current Liabilities  94,031   77,842 
Other Assets  19,178   918 
Other Liabilities  17,373   (821)
 
Net Cash Provided by Operating Activities
  415,067   404,552 
 
         
INVESTING ACTIVITIES
        
Capital Expenditures  (264,728)  (206,509)
Investment in Partnership     (3,300)
Cash Held in Escrow  58,397    
Net Proceeds from Sale of Oil and Gas Producing Properties  5,675   5,137 
Other  (3,414)  (1,072)
 
Net Cash Used in Investing Activities
  (204,070)  (205,744)
 
         
FINANCING ACTIVITIES
        
Excess Tax Benefits Associated with Stock-Based Compensation Awards  16,275   13,689 
Shares Repurchased under Repurchase Plan  (129,592)  (43,344)
Net Proceeds from Issuance of Long-Term Debt  296,655    
Reduction of Long-Term Debt  (200,024)  (119,550)
Dividends Paid on Common Stock  (77,204)  (74,748)
Net Proceeds from Issuance of Common Stock  17,285   16,819 
 
Net Cash Used in Financing Activities
  (76,605)  (207,134)
 
         
Effect of Exchange Rates on Cash
     1,245 
 
         
Net Increase (Decrease) in Cash and Temporary Cash Investments
  134,392   (7,081)
         
Cash and Temporary Cash Investments at October 1
  124,806   69,611 
 
         
Cash and Temporary Cash Investments at June 30
 $259,198  $62,530 
 
         
  Three Months Ended
  December 31,
(Thousands of Dollars) 2008 2007
   
Net Income (Loss) Available for Common Stock $(42,678) $70,604 
 
Other Comprehensive Income (Loss), Before Tax:        
Foreign Currency Translation Adjustment  8   (18)
Unrealized Loss on Securities Available for Sale Arising During the Period  (10,032)  (1,201)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period  118,880   (20,859)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income  (28,792)  5,421 
 
Other Comprehensive Income (Loss), Before Tax  80,064   (16,657)
 
Income Tax Benefit Related to Unrealized Loss on Securities Available for Sale Arising During the Period  (3,791)  (59)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period  48,128   (8,648)
Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gains) Losses from Derivative Financial Instruments In Net Income  (11,411)  2,133 
 
Income Taxes – Net  32,926   (6,574)
 
Other Comprehensive Income (Loss)  47,138   (10,083)
 
Comprehensive Income $4,460  $60,521 
 
See Notes to Condensed Consolidated Financial Statements

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Item 1.Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statements of Comprehensive Income
(Unaudited)
         
  Three Months Ended
  June 30,
(Thousands of Dollars) 2008 2007
   
Net Income Available for Common Stock $59,855  $46,798 
 
Other Comprehensive Income (Loss), Before Tax:        
Foreign Currency Translation Adjustment  2   10,029 
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period  (1,603)  1,570 
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period  (139,684)  13,343 
Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income  33,082   5,581 
 
Other Comprehensive Income (Loss), Before Tax  (108,203)  30,523 
 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) On Securities Available for Sale Arising During the Period  (608)  562 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) On Derivative Financial Instruments Arising During the Period  (57,136)  5,433 
Reclassification Adjustment for Income Tax Benefit on Realized Losses on Derivative Financial Instruments In Net Income  13,546   2,277 
 
Income Taxes – Net  (44,198)  8,272 
 
Other Comprehensive Income (Loss)  (64,005)  22,251 
 
Comprehensive Income (Loss) $(4,150) $69,049 
 
         
  Nine Months Ended
  June 30,
(Thousands of Dollars) 2008 2007
   
Net Income Available for Common Stock $225,463  $179,765 
 
Other Comprehensive Income (Loss), Before Tax:        
Foreign Currency Translation Adjustment  (72)  6,384 
Minimum Pension Liability Adjustment     (320)
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period  (4,817)  2,844 
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period  (208,256)  2,388 
Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income  45,242   7,799 
 
Other Comprehensive Income (Loss), Before Tax  (167,903)  19,095 
 
Income Tax Expense (Benefit) Related to Minimum Pension Liability Adjustment     (121)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) On Securities Available for Sale Arising During the Period  (1,429)  1,046 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) On Derivative Financial Instruments Arising During the Period  (85,300)  669 
Reclassification Adjustment for Income Tax Benefit on Realized Losses on Derivative Financial Instruments In Net Income  18,495   3,933 
 
Income Taxes – Net  (68,234)  5,527 
 
Other Comprehensive Income (Loss)  (99,669)  13,568 
 
Comprehensive Income $125,794  $193,333 
 
See Notes to Condensed Consolidated Financial Statements

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Item 1.Financial Statements (Cont.)
National Fuel Gas Company
Notes to Condensed Consolidated Financial Statements
(Unaudited)
Note 1 — Summary of Significant Accounting Policies
Principles of Consolidation.The Company consolidates its majority owned entities. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated.
     The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassification.Certain prior year amounts have been reclassified to conform with current year presentation.
Earnings for Interim Periods.The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2008, 2007 2006 and 20052006 that are included in the Company’s 20072008 Form 10-K. The consolidated financial statements for the year ended September 30, 20082009 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.
     The earnings for the ninethree months ended June 30,December 31, 2008 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2008.2009. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 6 – Business Segment Information.
Consolidated Statement of Cash Flows.For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instrumentsinvestments purchased with a maturity of generally three months or less to be cash equivalents.
     At JuneDecember 31, 2008, the Company accrued $51.7 million of capital expenditures in the Exploration and Production segment, the majority of which was for lease acquisitions in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at December 31, 2008 since it represented a non-cash investing activity at that date.
     At September 30, 2008, the Company accrued $19.9$16.8 million of capital expenditures related to the construction of the Empire Connector project. This amount has beenwas excluded from the Consolidated Statement of Cash Flows at JuneSeptember 30, 2008 since it representsrepresented 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.CashThis is an account title for cash held in margin accounts servesfunded by the Company to serve as collateral for open positions on exchange-traded futures contracts exchange-traded options and over-the-counter swaps and collars.swap agreements.
     At December 31, 2008, the Company had hedging collateral deposits of $3.7 million related to its exchange-traded futures contracts. The Company’s over-the-counter swap agreements were in a significant asset position at December 31, 2008. Under the terms of those agreements, the Company was not required to fund any cash as hedging collateral; rather, the counterparties were required to provide collateral to the Company. The amount of the collateral received was $34.1 million. This amount

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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 ninethree months ended June 30, 2008,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.

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Item 1.Financial Statements (Cont.)
Gas Stored Underground — Current.In the Utility segment, gas stored underground – current is carried atvalued using the LIFO method. This value or cost is lower than the current market value of cost or market, on a LIFO method.the gas stored underground. Gas stored underground – current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $77.9$36.2 million at June 30,December 31, 2008, is reduced to zero by September 30 of each year as the inventory is replenished.
Property, Plant and Equipment.In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.
     Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
     Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying current market prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The Company’s capitalized costs exceeded the full cost ceiling for the Company’s oil and gas properties at December 31, 2008. As such, the Company recognized a pre-tax impairment of $182.8 million at December 31, 2008. Deferred income taxes of $74.6 million were recorded associated with this impairment.

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Item 1.Financial Statements (Cont.)
Accumulated Other Comprehensive Income (Loss).Income.The components of Accumulated Other Comprehensive Income, (Loss), net of related tax effect, are as follows (in thousands):
         
  At June 30, 2008  At September 30, 2007 
Funded Position of the Pension and Other Post-Retirement Benefit Plans Adjustment $(12,482) $(12,482)
Cumulative Foreign Currency Translation Adjustment  (155)  (83)
Net Unrealized Loss on Derivative Financial Instruments  (100,095)  (3,886)
Net Unrealized Gain on Securities Available for Sale  6,860   10,248 
       
Accumulated Other Comprehensive Loss $(105,872) $(6,203)
       
         
  At December 31, 2008  At September 30, 2008 
Funded Status of the Pension and Other Post-Retirement Benefit Plans $(19,741) $(19,741)
Cumulative Foreign Currency Translation Adjustment  (63)  (71)
Net Unrealized Gain on Derivative Financial Instruments  69,320   15,949 
Net Unrealized Gain on Securities Available for Sale(1)
  585   6,826 
       
Accumulated Other Comprehensive Income $50,101  $2,963 
       
(1)Includes a balanced equity mutual fund that is in an unrealized loss position of $3.3 million ($2.1 million after taxes) and $1.1 million ($0.7 million after taxes) at December 31, 2008 and September 30, 2008, respectively. The fair value of this investment was $10.9 million at December 31, 2008 and $12.4 million at September 30, 2008. This investment has been in an unrealized loss position for less than twelve months. Based on this fact and the fact that management has the intent and ability to hold the investment for a sufficient period of time for the asset to recover in value, management does not consider this investment to be other than temporarily impaired.
Earnings Per Common Share.Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflectsreflect 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 StatementsStatement of Income reflects the potential dilution as a result of these stock options and stock-settled SARs as determined using the Treasury Stock Method. Stock options and stock-settled SARs that are antidilutive are excluded from the calculation of diluted earnings per common share. For the quarter and nine months ended June 30,December 31, 2008, there were no765,000 stock options excluded as being antidilutive. There were 6,593 and 2,190365,000 stock-settled SARs excluded as being antidilutive for the quarter and nine months ended June 30, 2008, respectively.antidilutive. For the quarter and nine months ended June 30,December 31, 2007, there were no stock options excluded as being antidilutive. There were 1,817 and 271or stock-settled SARs excluded as being antidilutive for the quarter and nine months ended June 30, 2007, respectively.
Share Repurchases.The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is settled as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note 3 – Capitalization for further discussion of the share repurchase program.antidilutive.
Stock-Based Compensation.ForDuring the quarter ended June 30,December 31, 2008, the Company granted 30,000610,000 performance-based stock-settled SARs having a weighted average exercise price of $58.99 per share. For the nine months ended June 30, 2008, the Company granted 321,000 performance-based stock-settled SARs having a weighted average exercise price of $48.46$29.88 per share. The weighted average grant date fair value of these stock-settled SARs was $12.23$4.09 per share and $9.06 per share for the quarter and nine months ended June 30, 2008, respectively.share. The accounting treatment for such stock-settled SARs is the same under SFAS 123R as the accounting for stock options under SFAS 123R. The stock-settled SARs granted forduring the quarter and nine months ended June 30,December 31, 2008 vest and become exercisableexerciseable annually in one-third increments, provided that a performance condition is met. The performance condition for diluted earnings per shareeach fiscal year, generally stated, is met foran increase over the prior fiscal year.year of at least five percent in certain oil and natural gas production of the Exploration and Production segment. The weighted average grant date fair value of these stock-settled SARs

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Item 1.Financial Statements (Cont.)
granted during the current quarter and nine months ended June 30, 2008 was estimated on the date of grant using the same accounting treatment that is applied for stock options under SFAS 123R, and assumes that the performance conditions specified will be achieved. If such conditions are not met 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 granted during the quarter and nine months ended June 30, 2008. The Company granted 25,000or restricted share awards (non-vested stock as defined in SFAS 123R) during the nine months ended June 30, 2008. The weighted average fair value of such restricted shares was $48.41 per share. There were no restricted share awards granted during the quarter ended June 30,December 31, 2008.

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Item 1.Financial Statements (Cont.)
New Accounting Pronouncements.In September 2006, the FASB issued SFAS 157, “Fair Value Measurements”. SFAS 157 provides guidance for using fair value to measure assets and liabilities. The pronouncement serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. SFAS 157 is to be applied whenever another standard requires or allows assets or liabilities to be measured at fair value. In accordance with FASB Staff Position FAS No. 157-2, on October 1, 2008, the Company adopted SFAS 157 is effective for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009.basis. The same FASB Staff Position delays the effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value on a recurring basis, until the Company’s first quarter of fiscal 2010. For further discussion of the impact of the adoption of SFAS 157 for financial assets and financial liabilities, refer to Note 2 — Fair Value Measurements. The Company is currently evaluating the impact that the adoption of SFAS 157 for nonfinancial assets and nonfinancial liabilities will have on its consolidated financial statements. The Company has identified Goodwill as being the major nonfinancial asset that will be impacted by SFAS 157 and Asset Retirement Obligations as being the major nonfinancial liability that will be impacted by SFAS 157.
     In September 2006, the FASB also issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” (an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R). SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be fully adopted by the Company by the end of fiscal 2009. Currently, theThe Company measureshas historically measured its plan assets and benefit obligations using a June 30th measurement date. In anticipation of changing to a September 30th measurement date, the Company will be recording fifteen months of pension and other post-retirement benefit costs during fiscal 2009. In accordance with the provisions of SFAS 158, these costs have been calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $5.1 million and have been recorded by the Company during the quarter ended December 31, 2008 as a $3.8 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $1.3 million ($0.8 million after tax) adjustment to earnings reinvested in the business. For further discussion of the impact of adopting the measurement date provisions of SFAS 158, refer to Note 8 – Retirement Plan and Other Post-Retirement Benefits.
     In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of SFAS 115.” SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not otherwise required to be measured at fair value under GAAP. A company that elects the fair value option for an eligible item will be required to recognize in current earnings any changes in that item’s fair value in reporting periods subsequent to the date of adoption. SFAS 159 isbecame effective as offor the Company’s first quarter of fiscal 2009.Company on October 1, 2008. The Company is currently evaluatingdid not elect the impact, iffair value measurements option for any of its financial instruments other than those that the adoption of SFAS 159 will have on its consolidated financial statements.are already being measured at fair value.
     In December 2007, the FASB issued SFAS 141R, “Business Combinations.” SFAS 141R will significantly change the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies, acquisition costs, in process research and development and restructuring costs. In addition, under SFAS 141R, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income tax expense. SFAS 141R is effective as of the Company’s first quarter of fiscal 2010.

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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

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Item 1.Financial Statements (Cont.)
component of equity. This new consolidation method will significantly change the accounting for transactions with minority interest holders. SFAS 160 is effective as of the Company’s first quarter of fiscal 2010. The Company currently does not have any NCI.
     In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS 133.” SFAS 161 requires entities to provide enhanced disclosures related to an entity’s derivative instruments and hedging activities in order to enable investors to better understand how derivative instruments and hedging activities impact an entity’s financial reporting. The additional disclosures include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective as of the Company’s second quarter of fiscal 2009. The Company is currently evaluating the impact that the adoption of SFAS 161 will have on its disclosures in itsthe notes to the consolidated financial statements.
     On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and gas reserves to a 12-month average of the first day of the month price for each month within the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. The revised reporting and disclosure requirements are effective for the Company’s Form 10-K for the period ended September 30, 2010. Early adoption is not permitted. The Company is currently evaluating the impact that adoption of these rules will have on its consolidated financial statements.statements and MD&A disclosures.
Note 2 — Income Taxes– Fair Value Measurements
     Beginning in fiscal 2009, the Company adopted the provisions of SFAS 157, “Fair Value Measurements.” SFAS 157 establishes a fair-value hierarchy, which prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The adoption of SFAS 157 has not had a significant impact on the consolidated financial statements.
     The componentsfollowing table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of federal, stateDecember 31, 2008. As required by SFAS 157, financial assets and foreign income taxes includedliabilities are classified in their entirety based on the Consolidated Statementslowest level of Income are as follows (in thousands):
         
  Nine Months Ended 
  June 30, 
  2008  2007 
   
Operating Expenses:        
Current Income Taxes        
Federal $92,384  $65,629 
State  23,388   19,259 
Foreign  90   22 
  
Deferred Income Taxes        
Federal  18,906   18,221 
State  8,697   5,270 
Foreign     3,616 
   
   143,465   112,017 
Deferred Investment Tax Credit  (523)  (523)
   
         
Total Income Taxes $142,942  $111,494 
   
         
Presented as Follows:        
Other Income $(523) $(523)
Income Tax Expense – Continuing Operations  143,465   108,804 
Income from Discontinued Operations     3,213 
   
         
Total Income Taxes $142,942  $111,494 
   
     The U.S. and foreign components of income before income taxes are as follows (in thousands):
         
  Nine Months Ended
  June 30,
  2008 2007
   
U.S. $368,191  $275,196 
Foreign  214   16,063 
   
  $368,405  $291,259 
   
input that is significant to the fair value measurement.

-15-


Item 1.Financial Statements (Cont.)
                 
Recurring Fair Value Measures At fair value as of December 31, 2008
(Dollars in thousands) Level 1 Level 2 Level 3 Total
 
Assets:                
Cash Equivalents $114,547  $  $  $114,547 
Derivative Financial Instruments     28,273   83,030   111,303 
Other Investments  17,715         17,715 
Hedging Collateral Deposits  3,743         3,743 
   
Total $136,005  $28,273  $83,030  $247,308 
   
                 
Liabilities:                
Derivative Financial Instruments $2,941  $  $  $2,941 
   
Total $2,941  $  $  $2,941 
   
Derivative Financial Instruments
     The derivative financial instruments reported in Level 1 consist of NYMEX futures contracts. The hedging collateral deposits associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 consist of natural gas swap agreements used in the Company’s Exploration and Production segment and natural gas swap agreements used in the Energy Marketing segment. The fair value of these natural gas price swap agreements is based on an internal model that uses observable inputs. The fair market value of the price swap agreements reported in Level 2 as assets has been reduced by $0.7 million based on an assessment of counterparty credit risk. The derivative financial instruments reported in Level 3 consist of all of the Exploration and Production segment’s crude oil swap agreements and some of its natural gas swap agreements. The fair value of the crude oil and natural gas price swap agreements is based on an internal model that uses both observable and unobservable inputs. The fair market value of the price swap agreements reported in Level 3 as assets has been reduced by $2.7 million based on an assessment of counterparty credit risk. This credit reserve, as well as the credit reserve established for the Level 2 price swap agreement assets, was determined by applying default probabilities to the anticipated cash flows that the Company is either expecting from its counterparties or expecting to pay to its counterparties.
Cash Equivalents
     The cash equivalents reported in Level 1 consist of SEC registered money market mutual funds.
Other Investments
     The other investments reported in Level 1 consist of publicly traded equity securities and a publicly traded balanced equity mutual fund.
     The table listed below provides a reconciliation of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3.

-16-


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

-17-


         
  Nine Months Ended
  June 30,
  2008 2007
   
Income Tax Expense, Computed at Statutory Rate of 35% $128,942  $101,941 
         
Increase (Reduction) in Taxes Resulting From:        
State Income Taxes  20,855   15,944 
Miscellaneous  (6,855)  (6,391)
   
         
Total Income Taxes $142,942  $111,494 
   
Item 1.Financial Statements (Cont.)
         
  Three Months Ended
  December 31,
  2008 2007
   
U.S. Income (Loss) Before Income Taxes $(78,141) $115,444 
   
         
Income Tax Expense (Benefit), Computed at Federal Statutory Rate of 35% $(27,349) $40,405 
         
Increase (Reduction) in Taxes Resulting From:        
State Income Taxes  (5,039)  7,043 
Miscellaneous  (3,075)  (2,608)
   
         
Total Income Taxes $(35,463) $44,840 
   -
     Significant components of the Company’s deferred tax liabilities and assets arewere as follows (in thousands):
                
 At June 30, 2008 At September 30, 2007 At December 31, 2008 At September 30, 2008
    
Deferred Tax Liabilities:  
Property, Plant and Equipment $669,079 $612,648  $614,556 $673,313 
Pension and Other Post-Retirement Benefit Costs – SFAS 158 44,345 43,340 
Unrealized Hedging Gains 47,856 14,936 
Other 38,451 61,616  36,975 40,455 
    
Total Deferred Tax Liabilities 707,530 674,264  743,732 772,044 
    
  
Deferred Tax Assets:  
Fair Value of Derivative Instruments and Securities  (65,192)  
Pension and Other Post-Retirement Benefit Costs – SFAS 158  (44,831)  (43,340)
Other  (120,817)  (107,458)  (101,197)  (92,461)
    
Total Deferred Tax Assets  (186,009)  (107,458)  (146,028)  (135,801)
    
Total Net Deferred Income Taxes $521,521 $566,806  $597,704 $636,243 
    
  
Presented as Follows:  
Net Deferred Tax Asset – Current $(84,297) $(8,550)
Net Deferred Tax Liability/(Asset) – Current $(6,340) $1,871 
Net Deferred Tax Liability – Non-Current 605,818 575,356  604,044 634,372 
    
Total Net Deferred Income Taxes $521,521 $566,806  $597,704 $636,243 
    
     Regulatory liabilities representing the reduction of previously recorded deferred income taxes with rate-regulated activities that are expected to be refundable to customers amounted to $14.0$18.5 million and $18.4 million at both June 30,December 31, 2008 and September 30, 2007.2008, 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 $84.0$82.5 million at June 30,December 31, 2008 and September 30, 2007,2008, respectively.
     The Company adopted FIN 48 on October 1, 2007. As of the date of adoption, a cumulative effect adjustment was recorded that resulted in a decrease to retained earnings of $0.4 million. Upon adoption, the unrecognized tax benefits were $1.7 million, all of which would impact the effective tax rate (net of federal benefit) if recognized. There has been no change in the balance of unrecognized tax benefits through June 30, 2008 and the Company does not anticipate any significant change in this liability over the next twelve months.
     The Company recognizes estimated interest payable relating to income taxes in Other Interest Expense and estimated penalties relating to income taxes in Other Income. The Company has accrued interest of $0.5 million through June 30, 2008 and has not accrued any penalties.

-16-


Item 1.Financial Statements (Cont.)
     The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 2008 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. The IRS has issued a Full Acceptance Letter for the fiscal 2007 CAP audit, and is in the process of completing the post-filing review of this return. While the federal statute of limitations remains open for fiscal 2005 and later years, IRS examinations for yearsfiscal 2007 and prior to fiscal 2007years have been completed and the Company believes such years are effectively settled.

-18-


Item 1.Financial Statements (Cont.)
     ForThe Company is also subject to various routine state income tax examinations.  The Company’s  operating subsidiaries mainly operate in four states which have statutes of limitations that generally expire between three to four years from the major states in whichdate of filing of the various subsidiary companies operate, the earliestincome tax year open for examination is as follows:
New YorkFiscal 2002
PennsylvaniaFiscal 2003
CaliforniaFiscal 2003
TexasFiscal 2003
return.
Note 34 — Capitalization
Common Stock.During the ninethree months ended June 30,December 31, 2008, the Company issued 884,644687,180 original issue shares of common stock as a result of stock option exercises and 25,000 original issue shares for restricted stock awards (non-vested stock as defined in SFAS 123R).exercises. The Company also issued 7,2002,100 original issue shares of common stock to the eightseven 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 ninethree months ended June 30,December 31, 2008. Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the ninethree months ended June 30,December 31, 2008, 72,205297,108 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
     On December 8, 2005,Shareholder Rights Plan.In 1996, the Company’s Board of Directors authorized the Company to implementadopted a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up toshareholder rights plan (Plan). The Plan has been amended six times since it was adopted and is now embodied in an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. During the nine months ended June 30, 2008, the Company repurchased 2,832,397 shares for $129.6 million under this program, funded with cash provided by operating activities. Since the repurchase program was implemented, the Company has repurchased 6,667,275 shares for $262.8 million.
Shareholder Rights Plan.On February 21, 2008, the Board of Directors of the Company approved amendments to the Company’s Amended and Restated Rights Agreement (the “Rights Agreement”). The amendments modifyeffective December 4, 2008, a copy of which was included as an exhibit to the rights ofForm 8-K filed by the Company on December 4, 2008.
     Pursuant to the Plan, holders of the Company’s Common Stock Purchasecommon stock have one right (Right) for each of their shares. Each Right is initially evidenced by the Company’s common stock certificates representing the outstanding shares of common stock.
     The Rights (the “Rights”). The principal amendments are an extensionhave anti-takeover effects because they will cause substantial dilution of the expiration date of the Rights Agreement from July 31, 2008Company’s common stock if a person attempts to July 31, 2018 and an increase in the exercise price of the Rights from $65 to $150 per full share. The Board also approved amendments to the Rights Agreement (i) to provide that the phrase “then outstanding,” when used with reference to a person’s beneficial ownership of securities ofacquire the Company meanson terms not approved by the numberBoard of securities then issuedDirectors (an Acquiring Person).
     The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date Rights that are owned by an Acquiring Person will be null and outstanding together with the numbervoid. At any time following a Distribution Date, each holder of such securities not then actually issued and outstanding which such person would be deemeda Right may exercise its right to own beneficiallyreceive, upon payment of an amount calculated under the Rights Agreement, including, amongcommon stock of the Company (or, under certain circumstances, other things, certain derivativesecurities or synthetic arrangementsassets of the Company) having characteristicsa value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.
     A Distribution Date would occur upon the earlier of (i) ten days after the public announcement that a long position inperson or group has acquired, or obtained the right to acquire, beneficial ownership of the Company’s common stock or other voting stock (including Synthetic Long Positions as defined in the Plan) having 10% or more of the total voting power of the Company’s common stock and other voting stock and (ii) ten days after the commencement or announcement by a person or group of an intention to eliminate certain restrictive covenantsmake 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 appliedthe right to exercise its Rights to receive, upon exercise of the right, common stock of the acquiring company having a value equal to two times the amount paid to exercise the right. These situations would arise if the Company after the distribution dateis acquired in a merger or other business combination or if 50% or more of the Rights, and (iii) to clarify and update the Rights Agreement in various respects. The Company, on July 11, 2008, entered into an amended and restated Rights Agreement, reflecting the changes described in this paragraph, with the Bank of New York, as Rights Agent, and on July 15, 2008, filed with the SEC copies of that agreement as exhibits to Forms 8-A and Form 8-K.Company’s assets or earning power are sold or transferred.

-17--19-


Item 1.Financial Statements (Cont.)
Long-Term Debt.In April 2008,     At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company issued $300.0 million of 6.50% senior, unsecured notesmay redeem the Rights in a private placement exempt from registration under the Securities Act of 1933. The notes have a term of 10 years, with a maturity datewhole, but not in April 2018. The holders of the notes may require the Company to repurchase their notes in the event of a change in controlpart, at a price equalof $0.005 per Right, payable in cash or stock. A decision to 101%redeem the Rights requires the vote of 75% of the principal amount. In addition,Company’s full Board of Directors. Also, at any time following the Company is required to either offerDistribution Date, 75% of the Company’s full Board of Directors may vote to exchange the notes for substantially similar notes as are registered under the Securities Act of 1933Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain circumstances, register the resaleadjustments.
     Upon exercise of the notes. TheRights, the Company used $200.0 millionmay need additional regulatory approvals to satisfy the requirements of the proceedsRights Agreement. The Rights will expire on July 31, 2018, unless earlier than that date, they are exchanged or redeemed or the Plan is amended to refund $200.0 million of 6.303% medium-term notes that subsequently matured on May 27, 2008.extend the expiration date.
Note 45 — Commitments and Contingencies
Environmental Matters.The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.
     As disclosed in Note H of the Company’s 20072008 Form 10-K, the Company received, in 1998 and again in October 1999, notice thathas agreed with the NYDEC believes the Company is responsible for contamination discovered atto remediate a former manufactured gas plant site located in New York for which theYork. The Company had not been named ashas submitted a PRP. In February 2007, the NYDEC identified the Company as a PRP for the site and issued a proposed remedial action plan. The NYDEC estimated clean-up costs under its proposed remedy to be $8.9 million if implemented. Although the Company commentedRemedial Design/Remedial Action work plan to the NYDEC that the proposed remedial action plan contained a number of material errors, omissions and procedural defects, the NYDEC, in a March 2007 Record of Decision, selected the remedy it had previously proposed. In July 2007, the Company appealed the NYDEC’s Record of Decision to the New York State Supreme Court, Albany County. The Court dismissed the appeal in January 2008. The Company filed a notice of appeal in February 2008. In July 2008, the Company withdrew its appeal and agreed to the terms of an Order on Consent issued by the NYDEC. Pursuant to the order, the Company will remediate the site consistent with the remedy selected in the NYDEC’s Record of Decision. The Company will also reimburse the NYDEC in the amount of approximately $1.5 million for costs incurred in connection with the site from 1998 through May 30, 2007. The Company acknowledged that additional charges related to the site will be billed to the Company at a later date, including costs incurred by the NYDEC after May 30, 2007 and any costs incurred by the New York Department of Health. The Company has not received any estimates of such additional costs. The Company has recorded an estimated minimum liability for remediation of $10.4 million associated with this site.site of $16.4 million.
     At June 30,December 31, 2008, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $13.5$19.3 million to $17.2$23.5 million. The minimum estimated liability of $13.5$19.3 million, which includes the $16.4 million discussed above, has been recorded on the Consolidated Balance Sheet at June 30, 2008, including the $10.4 million discussed above.December 31, 2008. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet.
     The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.
Other.The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings

-18-


Item 1.Financial Statements (Cont.)
and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor toor have a material adverse effect on the financial condition of the Company.
Note 5 — Discontinued Operations
     On August 31, 2007, the Company, in its Exploration and Production segment, completed the sale of SECI, Seneca’s wholly owned subsidiary that operated in Canada. The Company received approximately $232.1 million of proceeds from the sale, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. The sale resulted in the recognition of a gain of approximately $120.3 million, net of tax, during the fourth quarter of 2007. SECI is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in the provinces of Alberta, Saskatchewan and British Columbia in Canada. The decision to sell was based on lower than expected returns from the Canadian oil and gas properties combined with difficulty in finding significant new reserves. Seneca will continue its exploration and development activities in Appalachia, the Gulf of Mexico, and California. As a result of the decision to sell SECI, the Company began presenting all SECI operations as discontinued operations during the fourth quarter of 2007.
     The following is selected financial information of the discontinued operations for SECI:
         
  Three Months Nine Months
  Ended Ended
  June 30, June 30,
(Thousands) 2007 2007
   
Operating Revenues $14,366  $42,004 
Operating Expenses  9,915   27,205 
   
Operating Income  4,451   14,799 
Interest Income  272   799 
   
Income before Income Taxes  4,723   15,598 
Income Tax Expense (Benefit)  (863)  3,213 
   
Income from Discontinued Operations $5,586  $12,385 
   
Note 6 Business Segment Information
     TheIn the Company’s 2008 Form 10-K, the Company hasreported financial results for five reportablebusiness segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing and Timber. The division of the Company’s operations into the reportablereported segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors. During the quarter ended December 31, 2008, management made the decision to eliminate the Timber segment as a reportable segment based on the fact that the Timber operations do not meet any of the quantitative thresholds specified by SFAS 131. Furthermore, from a qualitative standpoint, management’s focus has changed regarding the Timber operations. While the Timber segment will continue to harvest hardwood

-20-


Item 1.Financial Statements (Cont.)
timber and process lumber products that are used in high-end furniture, cabinetry and flooring, management no longer considers the Timber operations to be integral to the overall operations of the Company. As a result of this change in focus and the fact that the Timber operations cannot be aggregated into one of the other four reportable business segments, the Timber operations have been included in the All Other category in the disclosures that follow. Prior year segment information shown below has been restated to reflect this change in presentation.
     The data presented in the tables below reflect the reportablereported segments and reconciliations to consolidated amounts. As stated in the 20072008 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (where(when applicable). When these items are not applicable, the Company evaluates performance based on net income. There have been no changes in the basis of segmentation, other than as noted above, nor in the basis of measuring segment profit or loss, from those used in the Company’s 20072008 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the 20072008 Form 10-K. While the Exploration and Production segment reported a pre-tax impairment charge of $182.8 million at December 31, 2008, this reduction in segment assets was largely offset by increases in the asset position of its derivative financial instruments combined with the receipt of cash collateral on such derivative financial instruments.
Quarter Ended December 31, 2008 (Thousands)
                                 
          Exploration             Corporate and  
      Pipeline and and Energy Total Reportable     Intersegment Total
  Utility Storage Production Marketing Segments All Other Eliminations Consolidated
 
Revenue from External Customers $349,637  $35,267  $96,712  $115,007  $596,623  $10,325  $215  $607,163 
                                 
Intersegment Revenues $4,553  $20,837  $  $  $25,390  $2,322  $(27,712) $ 
                                 
Segment Profit:                                
                                 
Net Income (Loss) $22,088  $17,176  $(83,557) $599  $(43,694) $(868) $1,884  $(42,678)
Quarter Ended December 31, 2007 (Thousands)
                                 
          Exploration             Corporate and  
      Pipeline and and Energy Total Reportable     Intersegment Total
  Utility Storage Production Marketing Segments All Other Eliminations Consolidated
 
Revenue from External Customers $327,125  $31,884  $107,955  $86,719  $553,683  $14,450  $135  $568,268 
                                 
Intersegment Revenues $4,299  $20,347  $  $  $24,646  $2,714  $(27,360) $ 
                                 
Segment Profit:                                
                                 
Net Income (Loss) $20,217  $12,778  $34,022  $954  $67,971  $2,736  $(103) $70,604 

-19-


Item 1.Financial Statements (Cont.)
                                     
      Pipeline Exploration         Total      Corporate and   
      and and Energy     Reportable      Intersegment  Total 
Quarter Ended June 30, 2008 (Thousands)  Utility Storage Production Marketing Timber Segments  All Other  Eliminations  Consolidated 
 
Revenue from External Customers $217,339  $32,054  $126,154  $162,129  $10,114  $547,790  $395  $197  $548,382 
                                     
Intersegment Revenues $3,154  $20,131  $  $  $  $23,285  $4,439  $(27,724) $ 
                                     
Segment Profit (Loss):                                    
Net Income (Loss) $7,848  $12,534  $39,791  $478  $(2,066) $58,585  $1,106  $164  $59,855 
                                     
      Pipeline Exploration         Total     Corporate and  
      and and Energy     Reportable     Intersegment Total
Nine Months Ended June 30, 2008 (Thousands)  Utility Storage Production Marketing Timber Segments All Other Eliminations Consolidated
 
Revenue from External Customers $1,067,194  $101,871  $348,829  $440,111  $40,438  $1,998,443  $3,564  $496  $2,002,503 
                                     
Intersegment Revenues $13,567  $61,340  $  $  $  $74,907  $10,251  $(85,158) $ 
                                     
Segment Profit (Loss):                                    
Net Income (Loss) $62,228  $40,931  $108,385  $7,079  $2,214  $220,837  $5,137  $(511) $225,463 
                                     
      Pipeline Exploration         Total     Corporate and  
      and and Energy     Reportable     Intersegment Total 
Quarter Ended June 30, 2007 (Thousands)  Utility Storage Production Marketing Timber Segments All Other Eliminations Consolidated 
 
Revenue from External Customers $210,604  $30,128  $80,028  $113,380  $13,131  $447,271  $1,308  $200  $448,779 
                                     
Intersegment Revenues $2,586  $20,332  $  $  $  $22,918  $2,253  $(25,171) $ 
                                     
Segment Profit (Loss):                                    
Income (Loss) from Continuing Operations $3,705  $15,451  $18,849  $1,233  $(364) $38,874  $458  $1,880  $41,212 
                                     
      Pipeline Exploration         Total     Corporate and  
      and and Energy     Reportable     Intersegment Total
Nine Months Ended June 30, 2007 (Thousands)  Utility Storage Production Marketing Timber Segments All Other Eliminations Consolidated
 
Revenue from External Customers $1,000,860  $94,889  $233,708  $360,036  $43,079  $1,732,572  $4,387  $578  $1,737,537 
                                     
Intersegment Revenues $12,556  $61,585  $  $  $  $74,141  $6,540  $(80,681) $ 
                                     
Segment Profit:                                    
Income from Continuing Operations $54,322  $43,075  $52,573  $8,431  $3,053  $161,454  $1,911  $4,015  $167,380 

-20--21-


Item 1.Financial Statements (Cont.)
Note 7 — Intangible Assets
     The components of the Company’s intangible assets were as follows (in thousands):
                
 At September 30,                
 At June 30, 2008 2007 At September 30, 
 Gross Net Net At December 31, 2008 2008 
 Carrying Accumulated Carrying Carrying Gross Net Net 
 Amount Amortization Amount Amount Carrying Accumulated Carrying Carrying 
     Amount Amortization Amount Amount 
Intangible Assets Subject to Amortization:  
Long-Term Transportation Contracts $8,580 $(5,791) $2,789 $3,591  $8,580 $(6,213) $2,367 $2,522 
Long-Term Gas Purchase Contracts 31,864  (7,814) 24,050 25,245  31,864  (8,611) 23,253 23,652 
         
 $40,444 $(13,605) $26,839 $28,836  $40,444 $(14,824) $25,620 $26,174 
         
  
Aggregate Amortization Expense:  
(Thousands)  
Three Months Ended June 30, 2008 $666 
Three Months Ended June 30, 2007 $666 
Nine Months Ended June 30, 2008 $1,997 
Nine Months Ended June 30, 2007 $1,997 
Three Months Ended December 31, 2008 $554 
Three Months Ended December 31, 2007 $666 
     The gross carrying amount of intangible assets subject to amortization at June 30,December 31, 2008 remained unchanged from September 30, 2007.2008. 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 20082009 and $0.5 million for fiscal 2009. Amortization expense for transportation contracts is estimated to be $0.4 million annually for 2010, 2011, 2012 and 2012.2013. Amortization expense for the long-term gas purchase contracts is estimated to be $0.4$1.2 million for the remainder of 20082009 and $1.6 million annually for 2009, 2010, 2011, 2012 and 2012.2013.
Note 8 Retirement Plan and Other Post-Retirement Benefits
     Components of Net Periodic Benefit Cost (in thousands):
                         
  Retirement Plan Other Post-Retirement Benefits 
Three months ended June 30, 2008 2007 2008  2007 
Service Cost $3,149  $3,225  $1,276  $1,403 
Interest Cost  11,237   11,087   6,770   6,800 
Expected Return on Plan Assets  (13,750)  (12,809)  (8,428)  (6,740)
Amortization of Prior Service Cost  202   220   1   1 
Amortization of Transition Amount        1,782   1,782 
Amortization of Losses  2,766   3,382   732   2,053 
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)(1)
  783   (344)  4,354   3,382 
     
                 
Net Periodic Benefit Cost $4,387  $4,761  $6,487  $8,681 
     

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Item 1.Financial Statements (Cont.)Three months ended December 31,
                              
 Retirement Plan Other Post-Retirement Benefits  Retirement Plan Other Post-Retirement Benefits
Nine months ended June 30, 2008 2007 2008 2007 
 2008 2007 2008 2007
Service Cost $9,448 $9,674 $3,828 $4,210  $2,728 $3,150 $950 $1,276 
Interest Cost 33,712 33,263 20,311 20,399  11,709 11,237 6,875 6,771 
Expected Return on Plan Assets  (41,250)  (38,427)  (25,286)  (20,220)  (14,489)  (13,750)  (7,904)  (8,429)
Amortization of Prior Service Cost 606 661 3 3  183 202  (268) 1 
Amortization of Transition Amount   5,346 5,345    566 1,782 
Amortization of Losses 8,298 10,146 2,195 6,160  1,419 2,766 2,318 732 
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)(1)
 7,597 3,885 20,028 16,453 
Net Amortization and Deferral For Regulatory Purposes (Including Volumetric Adjustments)(1)
 3,240 1,100 4,339 7,212 
        
  
Net Periodic Benefit Cost $18,411 $19,202 $26,425 $32,350  $4,790 $4,705 $6,876 $9,345 
        
 
(1) The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.

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

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
     TheIn the Company’s 2008 Form 10-K, the Company is a diversified energy companyreported financial results for five business segments: Utility, Pipeline and reports its operating results in five reportable business segments. ForStorage, Exploration and Production, Energy Marketing and Timber. During the quarter ended June 30,December 31, 2008, management made the decision to eliminate the Timber segment as a reportable segment based on the fact that the Timber operations do not meet any of the quantitative thresholds specified by SFAS 131. Furthermore, from a qualitative standpoint, management’s focus has changed regarding the Timber operations. While the Timber segment will continue to harvest hardwood timber and process lumber products that are used in high-end furniture, cabinetry and flooring, management no longer considers the Timber operations to be integral to the overall operations of the Company. As a result of this change in focus and the fact that the Timber operations cannot be aggregated into one of the other four reportable business segments, the Timber operations have been included in the All Other category in the disclosures that follow. Prior year segment information shown below has been restated to reflect this change in presentation.
          The Company experienced a loss of $42.7 million for the quarter ended December 31, 2008 compared to earnings of $70.6 million for the quarter ended June 30, 2007,December 31, 2007. The loss for the Company has experiencedquarter ended December 31, 2008 was driven largely by an increase in earningsimpairment charge of $13.1$182.8 million primarily due to higher earnings($108.2 million after tax) recorded in the Exploration and Production segment. The Utility segment andIn the All Other category also contributed to the increase in earnings. These earnings increases discussed above were slightly offset by lower earnings in the Pipeline and Storage and Energy Marketing segments as well as in the Corporate category, combined with a higher loss in the Timber segment. For the nine months ended June 30, 2008 compared to the nine months ended June 30, 2007, the Company experienced an increase in earnings of $45.7 million, due primarily to higher earnings in the Exploration and Production segment. The Utility segment and the All Other category also contributed to the increase in earnings. These earnings increases discussed above were slightly offset by lower earnings in the Pipeline and Storage, Energy Marketing, and Timber segments as well as in the Corporate category. The Company’s earnings are discussed further in the Results of Operations section that follows.
     From a capital resources and liquidity perspective, the Company spent $284.6 million on capital expenditures during the nine months ended June 30, 2008, with approximately 49% being spent in the Exploration and Production segment, 37% in the Pipelineoil and Storage segment and 14% in the Utility segment. The amounts spent in the various segments reflect the Company’s belief that the Exploration and Production segment and the Pipeline and Storage segment currently provide the best earnings growth opportunities for shareholders. In the Exploration and Production segment, the Company’s principal focus continues to be the development of its nearly one million acres in the Appalachian region along with continuedgas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Such costs are subject to a quarterly ceiling test prescribed by SEC Regulation S-X Rule 4-10 that determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. At December 31, 2008, due to significant declines in crude oil and natural gas commodity prices (Cushing, Oklahoma West Texas Intermediate oil reported spot price of $44.60 per Bbl at December 31, 2008 versus a reported price of $100.70 per Bbl at September 30, 2008; Henry Hub natural gas reported spot price of $5.63 per MMBtu at December 31, 2008 versus a reported price of $7.12 per MMBtu at September 30, 2008), the book value of the Company’s oil and gas properties exceeded the ceiling, resulting in the Gulf and West Coast regions. In the Pipeline and Storage segment, the majorityimpairment charge mentioned above. (Note — Because actual pricing of the expendituresCompany’s various producing properties varies depending on their location, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Cushing oil and Henry Hub prices, which are only indicative.) If natural gas prices used in the ceiling test calculation at December 31, 2008 had been $1 per MMBtu lower, the Company would have recorded an additional impairment charge of approximately $51 million (after tax). If crude oil prices used in the ceiling test calculation at December 31, 2008 had been $5 per Bbl lower, the Company would have recorded an additional impairment charge of approximately $53 million (after tax). If both natural gas and crude oil prices used in the ceiling test calculation at December 31, 2008 were lower by $1 per MMBtu and $5 per Bbl, respectively, the Company would have recorded an additional impairment charge of approximately $104 million (after tax). These calculated impairment charges are based solely on price changes and do not take into account any other changes to the ceiling test calculation.
     Despite the loss for construction coststhe quarter ended December 31, 2008, the Company’s balance sheet remains strong with a capitalization structure of 58% equity and 42% debt at December 31, 2008. The Company also continues to have strong liquidity despite the generally reported problems in the credit markets. The Company has been able to borrow short-term funds under its credit lines and through the commercial paper market to fund working capital needs throughout the quarter. The Company maintains a number of individual uncommitted or discretionary lines of credit with financial institutions for general corporate purposes. These credit lines, which aggregate to $420.0 million, are revocable at the option of the Empire Connector project.financial institutions and are reviewed on an annual basis. The project is on scheduleCompany anticipates that these lines of credit will continue to be completedrenewed, or replaced by the planned in-service date of November 2008, although the actual in-service date will depend upon the completion of the Millennium Pipeline. This project and other capital expenditures are discussed further in the Capital Resources and Liquidity section that follows.
     The Company regularly considers the repurchase of outstanding shares of common stock under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to repurchase up to an aggregate amount of 8 million shares. Through June 30,similar lines. At December 31, 2008, the Company had repurchased 6,667,275 shares for $262.8borrowed $66.0 million under this program, including 2,832,397 shares for $129.6 million during the nine months ended June 30, 2008. These matters are discussed further in the Capital Resources and Liquidity section that follows.
its lines of credit. The Company has beguntotal amount available to explore the sale of Horizon LFG, a New York corporation that owns and operates short-distance landfill gas pipeline companies that are engaged in the purchase, sale and transportation of landfill gas in Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Horizon LFG is included inbe issued under the Company’s All Other category.commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million, which commitment extends through September 30, 2010. At December 31, 2008, the Company is also exploring the sale of Horizon Power’s unconsolidated subsidiaries. This includes ESNE, which generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania, as well as Seneca Energy and Model City, which generate and sell electricity using methane gas obtained from landfills owned by outside parties.did not have any borrowings under its committed credit facility.
CRITICAL ACCOUNTING ESTIMATES
     For a complete discussion of critical accounting estimates, refer to “Critical Accounting Estimates” in Item 7 of the Company’s 20072008 Form 10-K. There have been no subsequentmaterial changes to that disclosure.disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Oil and Gas Exploration and Development Costs.The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties. In accordance with this methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company’s oil and gas reserves based on current market prices (the “ceiling”) is compared with the book value of those reserves at the balance sheet date. If the book value of the reserves in any country exceeds the ceiling, a non-cash charge must be recorded to reduce the book value of the reserves to the calculated ceiling. As disclosed in the Company’s 2008 Form 10-K, at September 30, 2008, the ceiling exceeded the book value of the Company’s oil and gas properties by approximately $500 million. Because of declines in commodity prices since September 30, 2008, the book value of the Company’s oil and gas properties exceeded the ceiling at December 31, 2008. The quoted Cushing, Oklahoma spot price for West Texas Intermediate oil had declined from a reported price of $100.70 per Bbl at September 30, 2008 to a reported price of $44.60 per Bbl at December 31, 2008. The quoted Henry Hub spot price for natural gas had declined from a reported price of $7.12 per MMBtu at September 30, 2008 to a reported price of $5.63 per MMBtu at December 31, 2008. Consequently, the Company recorded an impairment charge of $182.8 million ($108.2 million after-tax) during the quarter ended December 31, 2008. (Note — Because actual pricing of the Company's various producing properties varies depending on their location, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Cushing oil and Henry Hub prices, which are only indicative.) If natural gas prices used in the ceiling test calculation at December 31, 2008 had been $1 per MMBtu lower, the Company would have recorded an additional impairment charge of approximately $51 million (after tax). If crude oil prices used in the ceiling test calculation at December 31, 2008 had been $5 per Bbl lower, the Company would have recorded an additional impairment charge of approximately $53 million (after tax). If both natural gas and crude oil prices used in the ceiling test calculation at December 31, 2008 were lower by $1 per MMBtu and $5 per Bbl, respectively, the Company would have recorded an additional impairment charge of approximately $104 million (after tax). These calculated impairment charges are based solely on price changes and do not take into account any other changes to the ceiling test calculation. For a more complete discussion of the full cost method of accounting, refer to “Oil and Gas Exploration and Development Costs” under “Critical Accounting Estimates” in Item 7 of the Company’s 2008 Form 10-K.
Accounting for Derivative Financial Instruments.The Company, in its Exploration and Production segment, Energy Marketing segment, and Pipeline and Storage segment, uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments are categorized as price swap agreements and futures contracts. Gains or losses associated with the derivative financial instruments are matched with gains or losses resulting from the underlying physical transaction that is being hedged. To the extent that the derivative financial instruments would ever be deemed to be ineffective based on the effectiveness testing, mark-to-market gains or losses from the derivative financial instruments would be recognized in the income statement without regard to an underlying physical transaction.
     The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The Company adopted SFAS 157 during the quarter ended December 31, 2008. As such, the fair value of such derivative financial instruments is determined under the provisions of SFAS 157. The fair value of exchange traded derivative financial instruments is determined from Level 1 inputs, which are quoted prices in active markets. The Company determines the fair value of non exchange-traded derivative financial instruments based on an internal model, which uses both observable and unobservable inputs other than quoted prices. These inputs are considered Level 2 or Level 3 inputs. All derivative financial instrument assets and liabilities are evaluated for the probability of default by either the counterparty or the Company. Credit reserves are applied against the fair values of such assets or liabilities. For a more complete discussion of the types of derivative financial instruments used by the Company, refer to the “Market Risk Sensitive Instruments” section in Item 7 of the Company’s 2008 Form 10-K.

-25-


Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
RESULTS OF OPERATIONS
Earnings
     The Company’s earnings were $59.9Company experienced a loss of $42.7 million for the quarter ended June 30,December 31, 2008 compared to earnings of $46.8$70.6 million for the quarter ended June 30, 2007. As previously discussed, the Company has presented its Canadian operations in the Exploration and Production segment (in conjunction with the sale of SECI) as discontinued operations. The Company’s earnings from continuing operations were $59.9 million for the quarter ended June 30, 2008 compared to earnings from continuing operations of $41.2 million for the quarter ended June 30,December 31, 2007. The increasedecrease in earnings from continuing operations of $18.7$113.3 million is primarily the result of higher earningsa loss recognized in the Exploration and Production segment. The UtilityLower earnings in the Energy Marketing segment, andas well as a loss in the All Other category, also contributed to the increase in earnings. These earnings increases discussed above were slightly offset by lowerdecrease. Higher earnings in the Utility and Pipeline and Storage and Energy Marketing segments as well as inand the Corporate category combined with a higher loss in the Timber segment.
slightly offset these decreases. The Company’s earnings were $225.5 millionloss for the nine monthsquarter ended June 30,December 31, 2008, compared to earnings of $179.8includes a non-cash $182.8 million for the nine months ended June 30, 2007. The Company’s earnings from continuing operations were $225.5impairment charge ($108.2 million after tax) for the nine months ended June 30, 2008 compared to earnings from continuing operations of $167.4 million for the nine months ended June 30, 2007. The increase in earnings from continuing operations of $58.1 million is primarily the result of higher earnings in the Exploration and Production segment. The Utility segmentsegment’s oil and gas producing properties under the All Other category also contributed tofull cost method of accounting using crude oil and natural gas commodity pricing at December 31, 2008, which were lower than the increase in earnings. These earnings increases discussed above were slightly offset by lower earnings inpricing at September 30, 2008, the Pipeline and Storage, Energy Marketing, and Timber segments as well as in the Corporate category.
last ceiling test measurement date. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after taxafter-tax amounts, unless otherwise noted.
Earnings (Loss) by Segment
                         
  Three Months Ended  Nine Months Ended 
  June 30,  June 30, 
          Increase/          Increase/ 
(Thousands) 2008  2007  (Decrease)  2008  2007  (Decrease) 
Utility $7,848  $3,705  $4,143  $62,228  $54,322  $7,906 
Pipeline and Storage  12,534   15,451   (2,917)  40,931   43,075   (2,144)
Exploration and Production  39,791   18,849   20,942   108,385   52,573   55,812 
Energy Marketing  478   1,233   (755)  7,079   8,431   (1,352)
Timber  (2,066)  (364)  (1,702)  2,214   3,053   (839)
                   
Total Reportable Segments  58,585   38,874   19,711   220,837   161,454   59,383 
All Other  1,106   458   648   5,137   1,911   3,226 
Corporate  164   1,880   (1,716)  (511)  4,015   (4,526)
                   
Total Earnings from Continuing Operations  59,855   41,212   18,643   225,463   167,380   58,083 
                   
Earnings from Discontinued Operations     5,586   (5,586)     12,385   (12,385)
                   
Total Consolidated $59,855  $46,798  $13,057  $225,463  $179,765  $45,698 
                   
Three Months Ended December 31(Thousands)
             
          Increase 
  2008  2007  (Decrease) 
Utility $22,088  $20,217  $1,871 
Pipeline and Storage  17,176   12,778   4,398 
Exploration and Production  (83,557)  34,022   (117,579)
Energy Marketing  599   954   (355)
          
Total Reportable Segments  (43,694)  67,971   (111,665)
All Other  (868)  2,736   (3,604)
Corporate  1,884   (103)  1,987 
          
Total Consolidated $(42,678) $70,604  $(113,282)
          
Utility
Utility Operating Revenues
Three Months Ended December 31(Thousands)
             
          Increase 
  2008  2007  (Decrease) 
Retail Sales Revenues:            
Residential $272,418  $246,797  $25,621 
Commercial  41,333   38,033   3,300 
Industrial  2,106   1,651   455 
          
   315,857   286,481   29,376 
          
Transportation  32,011   33,424   (1,413)
Off-System Sales  3,732   8,213   (4,481)
Other  2,590   3,306   (716)
          
  $354,190  $331,424  $22,766 
          

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Utility
Utility Operating Revenues
                         
  Three Months Ended  Nine Months Ended 
  June 30,  June 30, 
          Increase/          Increase/ 
(Thousands) 2008  2007  (Decrease)  2008  2007  (Decrease) 
Retail Sales Revenues:                        
Residential $153,058  $158,922  $(5,864) $793,124  $778,572  $14,552 
Commercial  20,459   24,380   (3,921)  124,582   127,485   (2,903)
Industrial  1,178   1,432   (254)  6,754   7,081   (327)
                   
   174,695   184,734   (10,039)  924,460   913,138   11,322 
                   
Transportation  21,584   21,017   567   97,345   86,358   10,987 
Off-System Sales  20,540   3,727   16,813   48,606   3,727   44,879 
Other  3,674   3,712   (38)  10,350   10,193   157 
                   
  $220,493  $213,190  $7,303  $1,080,761  $1,013,416  $67,345 
                   
Utility Throughput
                         
  Three Months Ended  Nine Months Ended 
  June 30,  June 30, 
          Increase/          Increase/ 
(MMcf) 2008  2007  (Decrease)  2008  2007  (Decrease) 
Retail Sales:                        
Residential  8,618   10,679   (2,061)  53,881   56,729   (2,848)
Commercial  1,334   1,836   (502)  9,197   10,132   (935)
Industrial  77   113   (36)  524   628   (104)
                   
   10,029   12,628   (2,599)  63,602   67,489   (3,887)
Transportation  12,086   12,981   (895)  55,966   53,556   2,410 
Off-System Sales  1,711   467   1,244   4,790   467   4,323 
                   
   23,826   26,076   (2,250)  124,358   121,512   2,846 
                   
Three Months Ended December 31(MMcf)
             
          Increase
  2008 2007 (Decrease)
Retail Sales:            
Residential  18,166   17,127   1,039 
Commercial  2,911   2,877   34 
Industrial  143   123   20 
             
   21,220   20,127   1,093 
Transportation  17,473   17,827   (354)
Off-System Sales  512   1,031   (519)
             
   39,205   38,985   220 
             
Degree Days
                     
              Percent Colder 
              (Warmer) Than 
  Normal  2008  2007  Normal  Prior Year 
Three Months Ended June 30                    
Buffalo  927   817   921   (11.9)  (11.3)
Erie  885   762   900   (13.9)  (15.3)
                
Nine Months Ended June 30                    
                
Buffalo  6,551   6,175   6,195   (5.7)  (0.3)
Erie  6,142   5,737   5,930   (6.6)  (3.3)
                
Three Months Ended December 31
                     
              Percent
              Colder (Warmer) Than
  Normal 2008 2007 Normal Prior Year
Buffalo  2,260   2,313   2,094   2.3   10.5 
Erie  2,081   2,067   1,871   (0.7)  10.5 
2008 Compared with 2007
     Operating revenues for the Utility segment increased $7.3$22.8 million for the quarter ended June 30,December 31, 2008 as compared with the quarter ended June 30,December 31, 2007. TheThis increase for the quarter is primarily attributable tolargely resulted from a $16.8$29.4 million increase in off-system sales revenue (see discussion below) partially offset byretail gas revenues coupled with a $10.0$4.5 million decrease in retailoff-system sales revenue.revenues and a $1.4 million decrease in transportation revenues.
     The $10.0 million decreaseincrease in retail gas sales revenues for the Utility segment was a functionprimarily due to higher retail sales volumes, as shown in the table above. The volume increase, most notably in the residential category, is primarily the result of lower throughput volumes, partially offset byweather that was 10.5 percent colder than the recovery of higher gas costs (subject to certain timing variations, gas costs are recovered dollar for dollarprior year in revenues) coupled withboth operating jurisdictions.
     In the revenue impact of a rate design change. In December 2007,New York jurisdiction, the NYPSC issued an order providing for an annual rate increase of $1.8 million beginning December 28, 2007. As part of this rate order, a rate design change was adopted that shifts a greater amount of cost recovery into the minimum bill amount, thus spreading the recovery of such costs more evenly throughout the year. As a result of this rate order, retail and transportation revenues for the quarter ended December 31, 2008 were $2.2 million lower than revenues for the quarter ended December 31, 2007.
     Total off-system sales revenues for the quarters ended December 31, 2008 and December 31, 2007 amounted to $3.7 million and $8.2 million, respectively. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was no material impact to margins for the quarters ended December 31, 2008 and 2007. On October 16, 2008, the FERC issued Order No. 717 (“Final Rule”).  The Final Rule regarding the standards of conduct was effective November 26, 2008.  The Final Rule seemingly holds that a local distribution company making off-system sales on unaffiliated pipelines would engage in “marketing” that would require compliance with the FERC’s standards of conduct.  Accordingly, pending clarification from the FERC of this issue, as of November 1, 2008, Distribution Corporation ceased off-system sales activities.
     The Utility segment’s earnings for the quarter ended December 31, 2008 were $22.1 million, an increase of $1.9 million when compared with earnings of $20.2 million for the quarter ended December 31, 2007. In the Pennsylvania jurisdiction, earnings increased $0.6 million. The major factors contributing to this increase were the positive earnings impact associated with colder weather ($0.8 million), a slight increase in usage per account ($0.2 million), and lower interest expense ($0.2 million), offset by higher operating expenses of $0.6 million (primarily bad debt expense due to higher gas costs and the possible impact current economic conditions may have on customers). In the New York jurisdiction, earnings increased $1.3 million. This increase was primarily the result of $1.9 million in lower operating expenses (primarily due to a decrease in other post-retirement benefit costs) and lower interest expense ($0.6 million). These increases were partly offset by the earnings impact of the December 28, 2007 rate order discussed above ($1.4 million). The

-25--27-


Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
thus spreadingphrase “usage per account” in this paragraph refers to the recovery of suchaverage gas consumption per customer account after factoring out any impact that weather may have had on consumption. The decrease in other post-retirement benefit costs more evenly throughoutdiscussed above stems from the year. ThisNYPSC rate design change resulted in lower retail and transportation revenuesorder that became effective December 28, 2007 whereby the rate allowance for post-retirement benefit costs was reduced given projected reductions in the quarter ended March 31, 2008 compared to the quarter ended March 31, 2007. The rate order caused higher retail and transportation revenues in the quarter ended June 30, 2008 compared to the quarter ended June 30, 2007. However, on a year-to-date basis, retail and transportation revenues for the nine months ended June 30, 2008 (exclusive of the impact of higher gas costs) are still lower than the nine months ended June 30, 2007other post-retirement benefit obligation as a result of the rate design change. It is expected that there will also be an increase in retailthe discount rate from 5% to 6.25% during 2006. The decreases to interest expense primarily reflect lower borrowings and transportation revenue in the fourth quarter of this year compared to the prior year as a result of the rate design change.
     Operating revenues for the Utility segment increased $67.3 million for the nine months ended June 30, 2008 as compared with the nine months ended June 30, 2007. This increase largely resulted from a $44.9 million increase in off-system sales revenue (see discussion below) and an $11.3 million increase in retail sales revenue coupled with an $11.0 million increase in transportation revenues. The increase in retail gas sales revenues for the Utility segment was largely a function of higher gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues) partially offset by the revenue impact of the rate design change discussed above. The increase in transportation revenues was primarily due to a 2.4 Bcf increase in transportation throughput, largely due to the migration of customers from retail sales to transportation service.
     As reported in 2006, on November 17, 2006, the U.S. Court of Appeals vacated and remanded the FERC’s Order No. 2004 regarding affiliate standards of conduct with respect to natural gas pipelines. The Court’s decision became effective on January 5, 2007, and on January 9, 2007, the FERC issued Order No. 690, its Interim Rule, designed to respond to the Court’s decision. In Order No. 690, as clarified by the FERC on March 21, 2007, the FERC readopted, on an interim basis, certain provisions that existed prior to the issuance of Order No. 2004 that had made it possible for the Utility segment to engage in certain off-system sales without triggering the adverse consequences that would otherwise arise under the Order No. 2004 standards of conduct. As a result, the Utility segment resumed engaging in off-system sales on non-affiliated pipelines as of May 2007. Total off-system sales revenues for the quarters ended June 30, 2008 and June 30, 2007 amounted to $20.5 million and $3.7 million, respectively. Total off-system sales revenues for the nine months ended June 30, 2008 and June 30, 2007 amounted to $48.6 million and $3.7 million, respectively. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was not a material impact to margins for the quarters and nine months ended June 30, 2008 and 2007.
     The Utility segment’s earnings for the quarter ended June 30, 2008 were $7.8 million, an increase of $4.1 million compared to earnings of $3.7 million for the quarter ended June 30, 2007. In the New York jurisdiction, earnings increased by $4.4 million. As a result of the rate design change in the New York jurisdiction, earnings for the third quarter of fiscal 2008 increased by $1.7 million from the third quarter of fiscal 2007. A $1.7 million decrease in operating costs (mostly due toslightly lower post-retirement benefit costs), a non-recurring regulatory adjustment made in 2007 ($0.9 million), and the positive impact of a lower effective tax rate ($0.8 million) also contributed to the overall increase in earnings for the New York jurisdiction. These increases were partly offset by lower usage per account ($1.0 million). In the Pennsylvania jurisdiction, earnings decreased by $0.3 million due primarily to lower usage per account offset in part by lower operating costs and lower interest expense.rates.
     The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. For the quarter ended June 30,December 31, 2008, the WNC preserved earnings of approximately $0.4 million, as weather was warmer than normal for the period. For the quarter ended June 30, 2007, the WNC did not have a significant impact on earnings as the weather was close to normal. For the quarter ended December 31, 2007, the WNC preserved $1.1 million of earnings, as weather was warmer than normal for the period. In periods of colder than normal weather, the WNC benefits Distribution Corporation’s New York customers.
Pipeline and Storage
Pipeline and Storage Operating Revenues
Three Months Ended December 31(Thousands)
             
  2008 2007 Increase
Firm Transportation $33,105  $31,406  $1,699 
Interruptible Transportation  1,103   991   112 
             
   34,208   32,397   1,811 
             
Firm Storage Service  16,686   16,621   65 
Other  5,210   3,213   1,997 
             
  $56,104  $52,231  $3,873 
             
Pipeline and Storage Throughput
Three Months Ended December 31(MMcf)
             
  2008 2007 Increase
Firm Transportation  110,315   92,883   17,432 
Interruptible Transportation  1,792   1,083   709 
             
   112,107   93,966   18,141 
             
2008 Compared with 2007
     Operating revenues for the Pipeline and Storage segment increased $3.9 million in the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. This increase consisted of a $1.8 million increase in firm and interruptible transportation revenues. The Pipeline and Storage segment was able to obtain multiple new contracts for firm transportation service in the quarter ended December 31, 2008 which resulted in higher reservation, commodity and surcharge, and overrun revenues. In addition, there were increased efficiency gas revenues ($2.0 million) reported as part of other revenues in the table above. Under Supply Corporation’s tariff with shippers, Supply Corporation is allowed to retain a set percentage of shipper-supplied gas to cover compressor fuel costs and other operational purposes. To the extent that Supply Corporation does not need all of the gas to cover such operational needs, it is allowed to keep the excess gas as inventory. That inventory is later sold to customers. The excess gas that is retained as inventory represents efficiency gas revenue to Supply Corporation. During the quarter ended December 31, 2008, Supply Corporation retained a higher volume of gas than was retained during the quarter ended December 31, 2007.
     The UtilityPipeline and Storage segment’s earnings for the nine monthsquarter ended June 30,December 31, 2008 were $62.2 million;$17.2 million, an increase of $7.9$4.4 million when compared with earnings of $54.3$12.8 million for the nine monthsquarter ended June 30,December 31, 2007. In the New York jurisdiction, earnings increased $5.2 million. Lower operating costs of $4.5 million (mostlyThe increase is largely attributable to higher transportation revenues ($1.2 million) due to lower post-retirement benefit coststhe addition of new contracts for firm transportation service and lower bad debt expense), the positive impact of non-recurring regulatory adjustments made in 2007higher efficiency gas revenues ($0.91.3 million), the positive impact of a lower effectiveas discussed above. In addition, there was an increase in allowance for funds

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
tax rate ($0.9 million), a routine regulatory adjustment ($0.7 million), lower property taxes ($0.7 million), and higher customer usage per account ($0.3 million) also contributed to the overallused during construction of $2.1 million. The increase in earnings for the New York jurisdiction. These increases were partly offset by a $3.1 million decrease in earnings associated with the rate design change discussed above. In the Pennsylvania jurisdiction, earnings increased $2.7 million due primarily to a base rate increase that became effective in January 2007 ($2.6 million), higher usage per account ($0.9 million), and a decrease in operating costs of $1.1 million (mostly due to lower bad debt expense). These increases were partially offset by the negative earnings impact associated with warmer weather ($1.5 million).
     For the nine months ended June 30, 2008, the WNC preserved earnings of approximately $2.5 million, as the weather was warmer than normal. For the nine months ended June 30, 2007, the WNC preserved earnings of approximately $2.3 million, as the weather was also warmer than normal.
Pipeline and Storage
Pipeline and Storage Operating Revenues
                         
  Three Months Ended  Nine Months Ended 
  June 30,  June 30, 
          Increase/          
(Thousands) 2008  2007  (Decrease)  2008  2007  Increase 
Firm Transportation $29,020  $28,556  $464  $93,427  $89,819  $3,608 
Interruptible Transportation  1,151   1,170   (19)  3,237   3,071   166 
                   
   30,171   29,726   445   96,664   92,890   3,774 
                   
Firm Storage Service  16,754   17,002   (248)  50,325   50,194   131 
Other  5,260   3,732   1,528   16,222   13,390   2,832 
           ��       
  $52,185  $50,460  $1,725  $163,211  $156,474  $6,737 
                   
Pipeline and Storage Throughput
                         
  Three Months Ended  Nine Months Ended 
  June 30,  June 30, 
(MMcf) 2008  2007  Decrease  2008  2007  Increase 
Firm Transportation  68,263   78,455   (10,192)  283,104   273,513   9,591 
Interruptible Transportation  1,540   1,670   (130)  3,844   3,597   247 
                   
   69,803   80,125   (10,322)  286,948   277,110   9,838 
                   
2008 Compared with 2007
     Operating revenues for the Pipeline and Storage segment increased $1.7 million for the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. The increase was primarily due to increased efficiency gas revenues ($1.9 million) reported as part of other revenues in the table above. The majority of this increase was due to higher gas prices in the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. Overall, throughput decreased during the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. While Supply Corporation’s and Empire’s transportation volumes decreased during the quarter, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight fixed-variable rate design and Empire’s modified fixed-variable rate design.
     Operating revenues for the nine months ended June 30, 2008 increased $6.7 million as compared with the nine months ended June 30, 2007. The increase was primarily due to a $3.8 million increase in transportation revenue primarily due to the fact that the Pipeline and Storage segment was able to renew existing contracts at higher rates due to favorable market conditions related to the demand for transportation service associated with storage. In addition, there was a $3.1 million increase in efficiency gas revenues reported as part of other revenues in the table above. This increase was due primarily to higher gas prices in the nine months ended June 30, 2008 as compared with the nine months ended June 30, 2007.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
     The Pipeline and Storage segment’s earnings for the quarter ended June 30, 2008 were $12.5 million, a decrease of $2.9 million when compared to earnings of $15.4 million for the quarter ended June 30, 2007. The decrease in earnings primarily reflects the earnings impact associated with higher operation and maintenance expenses resulting from the non-recurrence in 2008 of a reversal of a reserve for preliminary survey costs ($4.8 million) related to the Empire Connector project recognized in the quarter ended June 30, 2007. In addition, there was an earnings decrease associated with higher interest expense ($0.8 million). These earnings decreases were partially offset by an increase in the allowance for funds used during construction ($1.0 million), higher efficiency gas revenues ($1.2 million) andis a result of the earnings benefit associated with lower income taxes ($0.5 million).
     The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2008 were $40.9 million, a decreaseconstruction of $2.1 million when compared to earnings of $43.0 million for the nine months ended June 30, 2007. The main factors contributing to this decrease were higher operation and maintenance expenses ($5.7 million), resulting from the non-recurrence in 2008 of a reversal of a reserve for preliminary survey costs ($4.8 million) related to the Empire Connector, project recognized duringwhich was completed and placed in service on December 10, 2008. Construction of the quarter ended June 30, 2007. In addition, there was a $1.9 million positive earnings impact duringEmpire Connector began in September 2007 so the nine months ended June 30, 2007 associated with the discontinuance of hedge accounting for Empire’s interest rate collar that did not recur during the nine months ended June 30, 2008. There was also an earnings decrease associated with higher interest expense ($1.1 million). These earnings decreases were partially offset by an increase in thecalculated allowance for funds used during construction ($2.3 million),was relatively small during the quarter ended December 31, 2007. With much more significant construction work in progress balances during the quarter ended December 31, 2008, the calculated allowance for funds used during construction was much higher. These earnings increases were partially offset by higher efficiency gas revenues ($2.0 million), andinterest expense of $0.4 million. The increase in interest expense was due to higher transportation and storage revenues ($2.5 million).borrowings.
Exploration and Production
Exploration and Production Operating Revenues
                         
  Three Months Ended  Nine Months Ended 
  June 30,  June 30, 
          Increase/          Increase/ 
(Thousands) 2008  2007  (Decrease)  2008  2007  (Decrease) 
Gas (after Hedging) from Continuing Operations $56,591  $34,712  $21,879  $155,793  $107,976  $47,817 
Oil (after Hedging) from Continuing Operations  66,695   42,577   24,118   185,650   117,084   68,566 
Gas Processing Plant from Continuing Operations  13,566   10,466   3,100   35,674   28,212   7,462 
Other from Continuing Operations  (291)  (291)     (3,174)  165   (3,339)
Intrasegment Elimination from Continuing Operations (1)
  (10,407)  (7,436)  (2,971)  (25,114)  (19,729)  (5,385)
                   
Operating Revenues from Continuing Operations $126,154  $80,028  $46,126  $348,829  $233,708  $115,121 
                   
Operating Revenues from Canada – Discontinued Operations $  $14,366  $(14,366) $  $42,004  $(42,004)
                   
Three Months Ended December 31(Thousands)
             
          Increase 
  2008  2007  (Decrease) 
Gas (after Hedging) $41,093  $45,557  $(4,464)
Oil (after Hedging)  53,071   59,643   (6,572)
Gas Processing Plant  7,328   11,075   (3,747)
Other  417   (1,309)  1,726 
Intrasegment Elimination(1)
  (5,197)  (7,011)  1,814 
          
  $96,712  $107,955  $(11,243)
          
 
(1) Represents the elimination of certain West Coast gas production revenue included in “Gas (after Hedging) from Continuing Operations” in the table above that was sold to the gas processing plant shown in the table above. An elimination for the same dollar amount was made to reduce the gas processing plant’s Purchased Gas expense.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Production Volumes
                         
  Three Months Ended  Nine Months Ended 
  June 30,  June 30, 
          Increase/          Increase/ 
  2008  2007  (Decrease)  2008  2007  (Decrease) 
Gas Production(MMcf)
                        
Gulf Coast  3,019   2,317   702   8,868   7,934   934 
West Coast  1,007   1,019   (12)  3,010   2,883   127 
Appalachia  1,793   1,266   527   5,538   3,998   1,540 
                   
Total Production from Continuing Operations  5,819   4,602   1,217   17,416   14,815   2,601 
Canada — Discontinued Operations     1,639   (1,639)     5,216   (5,216)
                   
Total Production  5,819   6,241   (422)  17,416   20,031   (2,615)
                   
                         
Oil Production(Mbbl)
                        
Gulf Coast  124   165   (41)  409   540   (131)
West Coast  598   599   (1)  1,825   1,789   36 
Appalachia  23   32   (9)  88   91   (3)
                   
Total Production from Continuing Operations  745   796   (51)  2,322   2,420   (98)
Canada — Discontinued Operations     58   (58)     175   (175)
                   
Total Production  745   854   (109)  2,322   2,595   (273)
                   
Three Months Ended December 31
             
          Increase
  2008 2007 (Decrease)
Gas Production(MMcf)
            
Gulf Coast  1,746   2,826   (1,080)
West Coast  1,022   1,027   (5)
Appalachia  1,851   1,917   (66)
             
Total Production  4,619   5,770   (1,151)
             
             
Oil Production(Mbbl)
            
Gulf Coast  128   156   (28)
West Coast  682   629   53 
Appalachia  15   37   (22)
             
Total Production  825   822   3 
             
Average Prices
                         
  Three Months Ended Nine Months Ended
  June 30, June 30,
  2008 2007 Increase 2008 2007 Increase
Average Gas Price/Mcf
                        
Gulf Coast $12.17  $7.37  $4.80  $9.66  $6.74  $2.92 
West Coast $10.61  $7.20  $3.41  $8.43  $6.76  $1.67 
Appalachia $11.53  $8.59  $2.94  $9.25  $7.71  $1.54 
Weighted Average for Continuing Operations $11.71  $7.67  $4.04  $9.32  $7.01  $2.31 
Weighted Average After Hedging for Continuing Operations $9.73  $7.54  $2.19  $8.95  $7.29  $1.66 
Canada - Discontinued Operations  N/M  $6.82   N/M   N/M  $6.34   N/M 
                         
Average Oil Price/bbl
                        
Gulf Coast $124.43  $65.17  $59.26  $103.46  $59.37  $44.09 
West Coast $114.35  $57.77  $56.58  $94.64  $52.96  $41.68 
Appalachia $114.99  $60.43  $54.56  $94.18  $59.35  $34.83 
Weighted Average for Continuing Operations $116.05  $59.41  $56.64  $96.17  $54.63  $41.54 
Weighted Average After Hedging for Continuing Operations $89.55  $53.54  $36.01  $79.97  $48.39  $31.58 
Canada - Discontinued Operations  N/M  $51.58   N/M   N/M  $48.16   N/M 
Three Months Ended December 31
2008 Compared with 2007
     Operating revenues from continuing operations for the Exploration and Production segment increased $46.1 million for the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. Oil production revenue after hedging from continuing operations increased $24.1 million due to a
             
          Increase 
  2008  2007  (Decrease) 
Average Gas Price/Mcf
            
Gulf Coast $7.04  $7.14  $(0.10)
West Coast $5.02  $6.77  $(1.75)
Appalachia $8.53  $7.45  $1.08 
Weighted Average $7.19  $7.18  $0.01 
Weighted Average After Hedging $8.90  $7.90  $1.00 
             
Average Oil Price/Bbl
            
Gulf Coast $56.19  $89.84  $(33.65)
West Coast $48.01  $81.80  $(33.79)
Appalachia $69.06  $84.12  $(15.06)
Weighted Average $49.66  $83.43  $(33.77)
Weighted Average After Hedging $64.34  $72.59  $(8.25)

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
$36.012008 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 barrelBbl) was the primary cause, as a production increase in weighted average prices after hedging for continuing operations.the West Coast offset decreases in Gulf Coast and Appalachian production, keeping overall oil production flat. Gas production revenue after hedging from continuing operations increased $21.9 million due todecreased $4.5 million. A decrease in gas production (1,151 MMcf) more than offset an increase in the weighted average price of gas after hedging for continuing operations ($2.191.00 per Mcf) as well as an increase. The decrease in gas production of 1,217 MMcf. Theoccurred primarily in this segment’s Gulf Coast region (1,080 MMcf), which is mainly the result of this segment was primarily responsiblelingering shut-ins caused by Hurricane Ike in September 2008. While Seneca’s properties sustained only superficial damage from the hurricanes, two significant producing properties remained shut-in for the increase in natural gas production from continuing operations (702 MMcf). Production from new fields inquarter ended December 31, 2008 (primarily in the High Island area) outpaced declines in production from some existing fields, quarter to quarter. The Appalachian region of this segment also contributed to the increase in natural gas production from continuing operations (527 MMcf), consistent with increased drilling activity in the region.
     Operating revenues from continuing operations for the Exploration and Production segment increased $115.1 million for the nine months ended June 30, 2008 as compared with the nine months ended June 30, 2007. Oil production revenue after hedging from continuing operations increased $68.6 million due primarily to a $31.58 per barrel increase in weighted average prices after hedging for continuing operations. Gas production revenue after hedging from continuing operations increased $47.8 million due to an increase inrepair work on third party pipelines and onshore processing facilities. All pre-hurricane production is expected to be back on line by the weighted average priceend of gas after hedging for continuing operations ($1.66 per Mcf)the quarter ended March 31, 2009. Appalachian production was slightly lower due to compressor down time and an increase in gas production of 2,601 MMcf. The increase in gas production from continuing operations occurred primarily in the Appalachian region (1,540 MMcf), consistent with increased drilling activity in the region. The Gulf Coast region also contributed to the increase in natural gas production from continuing operations (934 MMcf). Production from new fields in 2008 (primarily in the High Island area) outpaced declines in production from some existing fields, period to period, as discussed above.pipeline constraints.
     The Exploration and Production segment’s earnings from continuing operationsloss for the quarter ended June 30,December 31, 2008 were $39.8was $83.6 million an increase of $21.0 million when compared with earnings from continuing operations of $18.8$34.0 million for the quarter ended June 30, 2007. HigherDecember 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 higherdecreased earnings by $5.9 million, and $4.4 million, respectively. Higher natural gas prices and higher natural gas production increased earningsslightly offset these decreases by $17.4 million, $8.3 million and $6.0 million, respectively, while lower crude oil production decreased earnings by $1.8$3.0 million. Higher lease operating costs ($4.2 million), higher depletion expense ($3.1 million), higher state income tax expense ($2.5 million) and higher general and administrative and other operating expenses ($1.5 million)of $1.7 million and higher lease operating expenses of $1.3 million also negatively impactedcontributed to the decrease in earnings. Lower interestdepletion expense of $2.1$0.6 million slightly offset these decreases.
made a small contribution to earnings. The Exploration and Production segment’s earnings from continuing operations for the nine months ended June 30, 2008 were $108.4 million, an increase of $55.8 million when compared with earnings from continuing operations of $52.6 million for the nine months ended June 30, 2007. Higher crude oil prices, higher natural gas prices and higher natural gas production increased earnings by $47.7 million, $18.8 million and $12.3 million, respectively, while lower crude oil production decreased earnings by $3.1 million. Higher lease operating costs ($9.0 million), higher depletion expense ($8.9 million), higher state income tax expense ($3.4 million), higherin general and administrative and other operating expenses ($3.8 million),is mainly due to a bad debt charge related to a customer’s bankruptcy filing combined with higher personnel costs in the Appalachian region. The increase in lease operating expenses is primarily due to higher production taxes related to increased production from the High Island 24L and mark-to-market adjustments on derivative financial instruments ($1.3 million) also negatively impacted earnings. Lower interest expense23L fields in the Gulf Coast region, higher property taxes and increased well repair costs associated with higher than normal activity in the West Coast region, and an increase in the number of $4.5 million and higher interest income of $1.6 million slightly offset these decreases.producing properties in the Appalachian region.
Energy Marketing
Energy Marketing Operating Revenues
                         
  Three Months Ended  Nine Months Ended 
  June 30,  June 30, 
          Increase/          Increase/ 
(Thousands) 2008  2007  (Decrease)  2008  2007  (Decrease) 
Natural Gas (after Hedging) $162,127  $113,351  $48,776  $440,123  $359,895  $80,228 
Other  2   29   (27)  (12)  141   (153)
                   
  $162,129  $113,380  $48,749  $440,111  $360,036  $80,075 
                   
Three Months Ended December 31(Thousands)
             
  2008  2007  Increase 
Natural Gas (after Hedging) $114,984  $86,735  $28,249 
Other  23   (16)  39 
          
  $115,007  $86,719  $28,288 
          
Energy Marketing Volumes
Three Months Ended December 31
             
  2008 2007 Increase
Natural Gas – (MMcf)  13,136   10,841   2,295 
2008 Compared with 2007
     Operating revenues for the Energy Marketing segment increased $28.3 million for the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. The increase primarily reflects an increase in volumes, largely attributable to sales transactions undertaken to offset certain basis risks that the Energy Marketing segment was exposed to under certain commodity purchase contracts. These offsetting transactions had the effect of increasing revenue and volumes sold with minimal impact to earnings.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
     The Energy Marketing Volumes
                         
  Three Months Ended Nine Months Ended
  June 30, June 30,
  2008 2007 Increase 2008 2007 Increase
Natural Gas — (MMcf)  14,641   13,014   1,627   47,189   44,063   3,126 
2008 Compared with 2007
     Operating revenues for the Energy Marketing segment increased $48.7 million and $80.1 million, respectively, for the quarter and nine months ended June 30, 2008 as compared with the quarter and nine months ended June 30, 2007. The increase for both the quarter and nine months ended June 30, 2008 is primarily due to higher gas sales revenue due to an increase in the price of natural gas that was recovered through revenues as well as an increase in volumes. The increase in volumes is attributable to an increase in volumes sold to low-margin wholesale customers, as well as an increase in the number of commercial and industrial customers served by the Energy Marketing segment.
     Earnings in the Energy Marketing segment decreased $0.8 million and $1.4 million, respectively, for the quarter and nine months ended June 30, 2008 as compared with the quarter and nine months ended June 30, 2007. For the quarter ended June 30, 2008, higher operating costs of $0.8 million, primarily due to an increase in bad debt expense, are responsible for the decrease in earnings. Despite higher operating revenues and volumes, margins did not change significantly because the volume increase is primarily attributable to low-margin customers. For the nine months ended June 30, 2008, higher operating costs of $1.0 million (primarily due to an increase in bad debt expense) coupled with lower margins of $0.5 million are responsible for the decrease in earnings. A major factor in the margin decrease is the non-recurrence of a purchased gas expense adjustment recorded during the quarter ended March 31, 2007. During that quarter, the Energy Marketing segment reversed an accrual for $2.3 million of purchased gas expense due to the resolution of a contingency. The increase in volumes noted above, the profitable sale of certain gas held as inventory, and the marketing flexibility that the Energy Marketing segment derives from its contracts for significant storage capacity partially offset this decrease.
Timber
Timber Operating Revenues
                         
  Three Months Ended  Nine Months Ended 
  June 30,  June 30, 
                      Increase/ 
(Thousands) 2008  2007  Decrease  2008  2007  (Decrease) 
Log Sales $2,726  $3,504  $(778) $16,649  $16,950  $(301)
Green Lumber Sales  958   1,318   (360)  3,872   3,582   290 
Kiln-Dried Lumber Sales  5,846   7,247   (1,401)  18,612   20,742   (2,130)
Other  584   1,062   (478)  1,305   1,805   (500)
                   
Operating Revenues $10,114  $13,131  $(3,017) $40,438  $43,079  $(2,641)
                   

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Timber Board Feet
                         
  Three Months Ended Nine Months Ended
  June 30, June 30,
                      Increase/
(Thousands) 2008 2007 Decrease 2008 2007 (Decrease)
Log Sales  1,527   1,724   (197)  7,140   6,458   682 
Green Lumber Sales  2,273   2,709   (436)  7,496   6,619   877 
Kiln-Dried Lumber Sales  3,436   4,001   (565)  10,536   10,953   (417)
                         
   7,236   8,434   (1,198)  25,172   24,030   1,142 
                         
2008 Compared with 2007
     Operating revenues for the Timber segment decreased $3.0 millionsegment’s earnings for the quarter ended June 30, 2008 as compared with the quarter ended June 30, 2007. The decrease can be primarily attributed to a decrease in both log sales and kiln-dried lumber sales of $0.8 million and $1.4 million, respectively. Overall, the Timber segment is currently selling a greater amount of lower priced, low margin species than higher margin species due to poor market conditions and wet weather that hampered harvesting, resulting in a decline in revenues. The decrease in log sales is due to a decline in cherry veneer log sales volumes of 106,000 board feet that can be attributed to the mix of logs being harvested in the current quarter as compared to the quarter ended June 30, 2007. Cherry veneer logs are more valuable and sell at higher prices than other species and have the largest impact on overall log sales revenue. The decrease in kiln-dried lumber sales is due to both a decline in sales volumes of 565,000 board feet as well as a decline in the market price of kiln-dried lumber.
     Operating revenues for the Timber segment decreased $2.6 million for the nine months ended June 30, 2008 as compared with the nine months ended June 30, 2007. This decrease is largely due to a decline in kiln-dried lumber sales of $2.1 million. The decrease in kiln-dried lumber sales is due to both a decline in the market price of kiln-dried lumber as well as a decline in kiln-dried lumber sales volumes of 417,000 board feet. Log sales also decreased $0.3 million primarily due to a decline in cherry veneer log sales volumes of 130,000 board feet, partially offset by increases in log sales volumes from lower priced logs. Cherry veneer logs are more valuable and sell at higher prices than other species and have the largest impact on overall log sales revenue.
     The Timber segment recorded a loss of $2.1 million for the quarter ended June 30, 2008, a decrease of $1.7 million when compared with a loss of $0.4 million for the quarter ended June 30, 2007. This decrease was the result of lower margins of $1.7 million, largely from lumber and log sales due to the decrease in revenues noted above.
     The Timber segment’s earnings for the nine months ended June 30,December 31, 2008 were $2.2$0.6 million, a decrease of $0.9$0.4 million when compared with earnings of $3.1$1.0 million for the nine monthsquarter ended June 30,December 31, 2007. The decrease wasDespite colder weather, earnings decreased primarily due to an increase in depletion and depreciation expense of $0.6 million due to harvesting more timber from Company owned land than the prior year combined with the addition of a lumber sorter for Highland’s sawmill operations that was placed into service in October 2007. Lower margins of $0.1 million also contributed to the decrease in earnings. During the six months ended March 31, 2008, margins were up over the prior year, largely due to favorable weather conditions, resulting in an increase in the harvesting of higher margin species. The change in market and weather conditions in the quarter ended June 30, 2008, as discussed above, eliminated the margin improvements seen during the six months ended March 31, 2008.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)lower margins.
Corporate and All Other
2008 Compared with 2007
     Corporate and All Other operations recorded earnings of $1.3$1.0 million for the quarter ended June 30,December 31, 2008, a decrease of $1.6 million when compared withto the earnings of $2.3$2.6 million recorded for the quarter ended June 30,December 31, 2007. The positivedecrease in earnings impacts of higherwas 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 ($0.40.8 million), and lower income tax expense ($0.4 million) were more than offset by higher interest expense ($1.20.5 million). In addition, during the quarter ended December 31, 2008, ESNE, an unconsolidated subsidiary of Horizon Power, recorded an impairment charge of $3.6 million. Horizon Power’s 50% share of the impairment was $1.8 million ($1.1 million on an after tax basis). ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. The impairment was driven by a significant decrease in “run time” for the plant given the economic downturn and the resulting decrease in demand for electric power. The decreases were partially offset by lower operating expenses ($1.1 million) and higher operating costs ($0.8 million). The increase in operating costs can be attributed to the proxy contest with New Mountain Vantage GP, L.L.C.
     For the nine months ended June 30, 2008, Corporate and All Other had earnings of $4.6 million compared with earnings of $5.9 million for the nine months ended June 30, 2007. The positive earnings impacts of higher income from unconsolidated subsidiaries ($1.1 million), lower income tax expense ($0.8 million), lower interest expense ($0.7 million), a gain resulting from a death benefit on corporate-owned life insurance policies held by the sale of a turbine by Horizon PowerCompany ($0.62.3 million), and slightly higher margins by Horizon LFG ($0.3 million) were more than offset by higher operating costs ($4.5 million) and lower interest income ($0.6 million). The increase in operating costs can be attributed to the proxy contest with New Mountain Vantage GP, L.L.C.
Interest Income
     Interest income was $1.7$1.2 million higherlower in the quarter ended June 30,December 31, 2008 as compared to the quarter ended June 30,December 31, 2007. For the nine months ended June 30, 2008, interestInterest income increased $5.3 million as compared with the nine months ended June 30, 2007. These increases are mainly due to higher interest income (excluding intercompany interest income) in the Exploration and Production segment of $1.1was $1.6 million and $4.0 million, respectively, forlower during the quarter and nine months ended June 30,December 31, 2008 as compared to the quarter and nine months ended June 30,December 31, 2007 as a result of lower interest rates and lower average temporary cash investment balances.
Other Income
     Other Income increased $4.1 million for the investmentquarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. This increase is attributable to an increase in the allowance for funds used during construction of cash$2.1 million in the Pipeline and Storage segment associated with the Empire Connector project, as well as a death benefit gain on life insurance proceeds received fromof $2.3 million recognized in the sale of SECI in August 2007.Corporate category.
Interest Expense on Long-Term Debt
     Interest on long-term debt increased $1.2$1.8 million for the quarter ended June 30,December 31, 2008 as compared with the quarter ended June 30,December 31, 2007. For the nine months ended June 30, 2008, interest onThis increase can be attributed to a higher average amount of long-term debt decreased $0.1 million as compared with the nine months ended June 30, 2007. The increase in the quarter ended June 30, 2008 is due to the issuance inoutstanding. In April 2008, of athe Company issued $300 million of 6.5% Notesenior, unsecured notes due in April 2018. This increase was partially offset slightly by the repayment of $200 million of 6.303% medium-term notes that matured on May 27, 2008. The decrease in the nine months ended June 30, 2008 as compared to the nine months ended June 30, 2007 is due to an overall decline in interest on long-term debt as a result of a lower average amount of long-term debt outstanding. The Company repaid $22.8 million of Empire’s secured debt in December 2006. It also redeemed $96.3 million of 6.5% unsecured notes in April 2007.
CAPITAL RESOURCES AND LIQUIDITY
     The Company’s primary sourcessource of cash during the nine-month periodthree-month periods ended June 30,December 31, 2008 and December 31, 2007 consisted of cash provided by operating activities and proceeds from the issuance of long-term debt. These sourcesactivities. This source of cash werewas supplemented by issuesissuances of new shares of common stock as a result of stock option exercises.exercises and by short-term borrowings (for the quarter ended December 31, 2008). During the ninethree months ended June 30,December 31, 2008 and December 31, 2007, the common stock used to fulfill the requirements of the Company’s 401(k) plans and Direct Stock Purchase and Dividend Reinvestment Plan was obtained via open market purchases. During fiscal 2006, the Company began repurchasing outstanding shares of its common stock under a share repurchase program, which is discussed below under Financing Cash Flow.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Operating Cash Flow
     Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, impairment of investment in partnerships, deferred income taxes, and income or loss from unconsolidated subsidiaries net of cash distributions.
     Cash provided by operating activities in the Utility and the Pipeline and Storage segments may vary from period to period because of the impact of rate cases. In the Utility segment, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation’s straight fixed-variable rate design.
     Because of the seasonal nature of the heating business in the Utility and Energy Marketing segments, revenues in these segments are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the balances receivable at September 30.
     The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve is reduced as the inventory is replenished.
     Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil. The Company uses various derivative financial instruments, including price swap agreements no cost collars and futures contracts in an attempt to manage this energy commodity price risk.
     Net cash provided by operating activities totaled $415.1$100.1 million for the ninethree months ended June 30,December 31, 2008, an increase of $10.5$24.8 million when compared with $404.6the $75.3 million provided by operating activities for the ninethree months ended June 30,December 31, 2007. The increase is partiallyprimarily due to lower working capital requirementshigher cash provided by operating activities in the Utility segment for the nine months ended June 30, 2008 as compared to the nine months ended June 30, 2007. In the Exploration and Production segment. Despite lower crude oil prices and lower natural gas production, this segment for the nine months ended June 30, 2008 as compared to the nine months ended June 30, 2007, cash provided by operations increased due to higher commodity prices, partially offset by the decreaseexperienced an increase in cash provided by operations that resultedoperating activities due to the receipt of hedging collateral deposits from some of the sale of SECI in August 2007. Offsetting these increases were higher working capital requirements in the Energy Marketing segment.counterparties to its derivative financial instruments.
Investing Cash Flow
Expenditures for Long-Lived Assets
     The Company’s expenditures for long-lived assets totaled $284.6$119.2 million duringfor the ninethree months ended June 30, 2008.December 31, 2008 and $69.7 million for the three months ended December 31, 2007. The table below presents these expenditures:

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
NineTotal Expenditures for Long-Lived Assets
Three Months Ended June 30, 2008 (in millions of dollars)December 31,
(Millions)
                
 Total  Increase
 Expenditures for  2008 2007 (Decrease)
 Long-Lived Assets 
Utility $38.8  $13.6 $12.7 $0.9 
Pipeline and Storage(1)
 106.2  19.5 25.3  (5.8)
Exploration and Production(2) 140.6  86.4 30.7 55.7 
Timber 1.2 
Corporate and All Other 0.2 
Eliminations(2)
  (2.4)
All Other  1.0  (1.0)
Eliminations(3)
  (0.3)   (0.3)
   
 $284.6  $119.2 $69.7 $49.5 
   
 
(1) Amount includes $19.9for the three months ended December 31, 2008 excludes $16.8 million of accrued capital expenditures related to the Empire Connector project.project accrued at September 30, 2008 and paid during the three months ended December 31, 2008. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at that date. The amount has been included in the Consolidated Statement of Cash Flows at December 31, 2008.
(2)Amount includes $51.7 million of accrued capital expenditures at December 31, 2008, the majority of which was for lease acquisitions in the Appalachian region. This amount has been excluded from the Consolidated Statement of Cash Flows at June 30,December 31, 2008 since it represents a non-cash investing activity at that date.
 
(2)(3) Represents $2.4$0.3 million of capital expenditures included in the Pipeline and Storage segment for the purchase of pipeline facilities from the Appalachian region of the Exploration and Production segment for the purchase of storage facilities, buildings, and base gas from Supply Corporation during the quarter ended MarchDecember 31, 2008.
Utility
     The majority of the Utility capital expenditures for the ninethree months ended June 30,December 31, 2008 and December 31, 2007 were made for replacement of mains and main extensions, as well as for the replacement of service lines.
Pipeline and Storage
     The majority of the Pipeline and Storage capital expenditures for the ninethree months ended June 30,December 31, 2008 and December 31, 2007 were related to the Empire Connector project, costs, which is discussed below, as well as for additions, improvements, and replacements to this segment’s transmission and gas storage systems.was placed into service on December 10, 2008.
     The Company continues to explore various opportunities to expand its capabilities to transport gas to the East Coast, either through the Supply Corporation or Empire systems or in partnership with others. Construction of the Empire Connector, a pipeline designed to transport up to approximately 250 MDth of natural gas per day that will connect the Empire Pipeline with the Millennium Pipeline, began in September 2007. The Empire Connector is on schedule to be completed by the planned in-service date of November 2008, although the actual in-service date will depend upon the completion of the Millennium Pipeline. Refer to the Rate and Regulatory Matters section that follows for further discussion of this matter. The total cost to the Company of the Empire Connector project is estimated at $180 million, after giving effect to sales tax exemptions worth approximately $3.7 million.     As of June 30,December 31, 2008, the Company had incurred approximately $107.7$181.7 million in costs related to this project. Of this amount, $42.7$17.0 million and $88.0$25.1 million (including an accrued allowance for funds used during construction of $2.6 million and $0.5 million, respectively) were incurred during the quarterquarters ended December 31, 2008 and nine months ended June 30, 2008, respectively, and $2.1 million and $3.5 million were incurred during2007, respectively.
     In light of the quarter and nine months ended June 30, 2007, respectively. All project costs incurred as of June 30, 2008 have been capitalized as Construction Workgrowing demand for pipeline capacity to move natural gas from new wells being drilled in Progress. The Company anticipates financing the remaining cost of this project with cash on hand.
     Supply Corporation continues to view its potential Tuscarora Extension project as an important link to Millennium and potential storage developmentAppalachia — specifically in the Corning, New York area. This new pipeline, which would expand the Supply Corporation system from its Tuscarora storage field to the intersection of the proposed Millennium and Empire Connector pipelines, could be designed initially to transport up to approximately 130 MDth of natural gas per day. It may also provide Supply Corporation with the opportunity to increase the deliverability of the existing Tuscarora storage field. Using the results of a preliminary Open Season,Marcellus Shale producing area — Supply Corporation is also exploring a new project (theactively pursuing development of its Appalachian Lateral pipeline project. The Appalachian Lateral is expected to be routed through areas in Pennsylvania where producers are actively drilling and are seeking market access for their newly discovered reserves. The Appalachian Lateral will complement Supply Corporation’s original West to East project) that would provide for new capacity(“W2E”) project, which was designed to transport Rockies gas supply from Clarington, Ohio to the Rockies Express Project,Ellisburg/Leidy/Corning area and includes the Tuscarora-to-Corning facilities previously referred to as the Tuscarora Extension. The Appalachian production, storage and otherLateral will transport gas supply from Pennsylvania’s producing area to the Overbeck area of Supply Corporation’s existing system, where the facilities associated with the W2E project will move the gas to eastern market points, toincluding Leidy, and to interconnections with Millennium and Empire at Corning. The WestEngineering analyses to East project could include the Tuscarora Extension project, or could be a second phase followingevaluate routing options and the development of an updated project cost estimate are under way.
     In conjunction with the Tuscarora Extension project.Appalachian Lateral/W2E transportation projects, Supply Corporation has plans to develop new storage capacity by expansion of certain of its existing storage facilities. The expansion of these fields, which Supply Corporation is pursuing concurrent with the Appalachian Lateral/W2E transportation projects, could provide approximately 8.5 MMDth of incremental storage

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
     In light of the rapidly growing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, Supply Corporation recently initiated a new Open Season for its “Appalachian Lateral,” a project designed to complement the West to East project. The Appalachian Lateral is expected to be located through an area where producers are actively drilling and seeking to find access to the market for their newly discovered reserves.
     In conjunction with the West to East and Appalachian Lateral projects, Supply Corporation has plans to develop new storage capacity by pursuing expansion of certain of its existing storage facilities. The expansion of these fields, which Supply Corporation hopes to market through one offering at market-based rates, could provide approximately 8.5 Bcf of incremental storage capacity with incremental withdrawal deliverability of up to 121 MDth of natural gas per day, available inwith service commencing as early as 2011. Supply Corporation expects that the availability of this incremental storage capacity will complement the West to East and Appalachian LateralLateral/W2E pipeline transportation projects and help meetbalance the demand for storage created by the prospective increasedincreasing flow of RockiesAppalachian and AppalachianRockies gas supply into the western Pennsylvania area, although traditionaland the growing demand for gas supplies will also be able to take advantage of this incremental storage capacity. An Open Season for this storage capacity is planned to be held later in 2008.on the east coast.
     The timeline associated with Supply Corporation’s pipeline and storage projects depends on market development. Should the market materialize, the Company anticipates financing the Tuscarora Extension project and/or the storage expansion(s) with cash on hand and/or through the use of the Company’s lines of credit. The capital cost of the WestAppalachian Lateral/W2E transportation projects is estimated to Eastbe in the range of $750 million to $1 billion, and Appalachian Lateral projects would amountis expected to at least $700 million, which would be financed by a combination of debt and equity. As of June 30,December 31, 2008, there have been no costs incurred by Supply Corporation related to the Tuscarora Extension project, $0.1$0.2 million has been spent to study the West to East and Appalachian LateralLateral/W2E transportation projects, and approximately $0.2$0.8 million has been spent to study the storage expansion project. Costs associated with these projects have been included in preliminary survey and investigation charges and have been fully reserved for at December 31, 2008. Supply Corporation has not yet filed an application with the FERC for the authority to build either pipeline project or the storage expansion(s).expansion.
Exploration and Production
     The Exploration and Production segment capital expenditures for the ninethree months ended June 30,December 31, 2008 were primarily well drilling and completion expenditures and included approximately $46.9$11.9 million for the Gulf Coast region, substantially all of which was for the off-shore program in the shallow waters of the Gulf of Mexico, $51.1$10.4 million for the West Coast region and $42.6$64.1 million for the Appalachian region. The Appalachian region capital expenditures include $2.4 million for the purchase of storage facilities, buildings, and base gas from Supply Corporation, as shown in the table on the previous page. These amounts included approximately $20.7$10.2 million spent to develop proved undeveloped reserves.
Timber For all of 2009, the Company expects to spend $244 million on Exploration and Production segment capital expenditures. Previously reported 2009 capital expenditures for the Exploration and Production segment were $285 million. The decrease in estimated capital expenditures is primarily due to low commodity prices. Estimated capital expenditures in the Gulf Coast region will decrease from $35.0 million to $19.0 million. Estimated capital expenditures in the West Coast region will decrease from $54.0 million to $35.0 million. In the Appalachian region, estimated capital expenditures will decrease from $196.0 million to $190.0 million.
     The majority of the TimberExploration and Production segment capital expenditures for the ninethree months ended June 30, 2008 wereDecember 31, 2007 included approximately $6.8 million for constructionthe Gulf Coast region, substantially all of a lumber sorterwhich was for Highland’s sawmill operations that was placed into service in October 2007 as well as for purchases of equipment for Highland’s sawmill and kiln operations.
All Other
     In March 2008, Horizon Power sold a gas-powered turbine that it had planned to usethe off-shore program in the developmentGulf of a co-generation plant. Horizon Power received proceeds of $5.3Mexico, $12.8 million for the West Coast region and recorded a pre-tax gain of $0.9$11.1 million associated withfor the sale.Appalachian region. These amounts included $4.5 million spent to develop proved undeveloped reserves.
     The Company continuously evaluates capital expenditures and investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, timber or natural gas storage facilities and the expansion of natural gas transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Financing Cash Flow
     The Company did not have any outstandingConsolidated short-term notes payable to banks or commercial paper at June 30,debt increased $66.0 million during the three months ended December 31, 2008. However, theThe Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, repurchases of stock, and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At December 31, 2008, the Company had outstanding short-term notes payable to banks of $66.0 million. There was no outstanding commercial paper at December 31, 2008. As for bank loans, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines, which aggregate to $430.0$420.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed, or replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility which totalstotaling $300.0 million, andwhich commitment extends through September 30, 2010.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
     Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September 30, 2010. At June 30,December 31, 2008, the Company’s debt to capitalization ratio (as calculated under the facility) was .41..42. The constraints specified in the committed credit facility would permit an additional $1.84$1.79 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio would exceed .65. If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its committed credit facility, uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.
     Under the Company’s existing indenture covenants, at June 30,December 31, 2008, the Company would have been permitted to issue up to a maximum of $1.2$0.9 billion in additional long-term unsecured indebtedness at then-currentthen current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands. However, if the Company was to experience another impairment of oil and gas properties this year, it is possible that these indenture covenants would restrict the Company’s ability to issue additional long-term unsecured indebtedness. This would not preclude the Company from issuing new indebtedness to replace maturing debt.
     The Company’s 1974 indenture, pursuant to which $199.0 million (or 18%) of the Company’s long-term debt (as of June 30,December 31, 2008) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to (i) pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
     The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fail to make a payment when due of any principal or interest on any other indebtedness aggregating $20.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $20.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of June 30,December 31, 2008, the Company had no debt outstanding under the committed credit facility.
     In April 2008, the Company issued $300.0 million of 6.50% senior, unsecured notes in a private placement exempt from registration under the Securities Act of 1933. The notes have a term of 10 years, with a maturity date in April 2018. The holders of the notes may require the Company to repurchase their notes in the event of a change in control at a price equal to 101% of the principal amount. In addition, the

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Company iswas required to either offer to exchange the notes for substantially similar notes as are registered under the Securities Act of 1933 or, in certain circumstances, register the resale of the notes. In November 2008, the Company filed a registration statement with the SEC in connection with the Company’s plan to offer to exchange the notes for substantially similar registered notes. The Company used $200.0 million of the proceeds to refund $200.0 million of 6.303% medium-term notes that subsequently matured on May 27, 2008.
     On December 8, 2005, In January 2009, the Company’s Board of Directors authorizedSEC declared the registration statement, as amended, effective, and the Company commenced the exchange offer. The Company expects the exchange offer to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. As of June 30, 2008, the Company has repurchased 6,667,275 shares for $262.8 million under this program, including 439,722 and 2,832,397 shares for $20.7 million and $129.6 million, respectively, during the quarter and nine months ended June 30, 2008. These share repurchases were funded with cash provided by operating activities and/or through the use of the Company’s lines of credit. In the future, it is expected that this share repurchase program will continue to be funded with cash provided by operating activities and/or through the use of the Company’s lines of credit. It is anticipated that open market repurchases will continue from time to time dependingexpire on market conditions.February 18, 2009.
     The Company may issue debt or equity securities in a public offering or a private placement from time to time. The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
OFF-BALANCE SHEET ARRANGEMENTS
     The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating and capital leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Utility and the Pipeline and Storage segments, having a remaining lease commitment of approximately $30.7$30.5 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters computer equipment and other items and are accounted for as operating leases. The Company’s unconsolidated subsidiaries, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $3.9$2.8 million. The Company has guaranteed 50% or $2.0$1.4 million of these capital lease commitments.
OTHER MATTERS
     In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
Market Risk Sensitive Instruments
     For a complete discussion of market risk sensitive instruments, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 20072008 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Rate and Regulatory Matters
Utility Operation
     Base rate adjustments in both the New York and Pennsylvania rate jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities.
New York Jurisdiction
     On January 29, 2007, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by $52.0 million. Following standard procedure, the NYPSC suspended the proposed tariff amendments to enable its staff and intervenors to conduct a routine investigation and hold hearings. Distribution Corporation explained in the filing that its request for rate relief was necessitated by decreased revenues resulting from customer conservation efforts and increased customer uncollectibles, among other things. The rate filing also included a proposal for an efficiency and conservation initiative with a revenue decoupling mechanism designed to render the Company indifferent to throughput reductions resulting from conservation. On September 20, 2007, the NYPSC issued an order approving, with modifications, Distribution Corporation’s conservation program for implementation on an accelerated basis. Associated ratemaking issues, however, were reserved for consideration in the rate case.rate.
     On December 21, 2007, the NYPSC issued a rate order providing for an annual rate increase of $1.8 million, together with a monthly bill surcharge that would collect up to $10.8 million to recover expenses for implementation of the conservation program. The rate increase and bill surcharge became effective December 28, 2007. The rate order further provided for a return on equity of 9.1%. The rate

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
order also adopted Distribution Corporation’s proposed revenue decoupling mechanism. The revenue decoupling mechanism, like others, “decouples” revenues from throughput by enabling the Company to collect from small volume customers its allowed margin on average weather normalized usage per customer. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. The Company surcharges or credits any difference from the average weather normalized usage per customer account. The surcharge or credit is calculated to recover total margin for the most recent twelve-month period ending December 31, and applied to customer bills annually, beginning March 1st.
     On April 18, 2008, Distribution Corporation filed an appeal with Supreme Court, Albany County, seeking review of the rate order. The appeal contends that portions of the rate order should be invalidated because they fail to meet the applicable legal standard for agency decisions. Among the issues challenged by the Company are the reasonableness of the NYPSC’s disallowance of expense items, including health care costs, and the methodology used for calculating rate of return, which the appeal contends understated the Company’s cost of equity. The Company cannot predict the outcome of the appeal at this time.
     In a proposed budget delivered on December 16, 2008, the Governor of the State of New York included revenue from a planned amendment to the Public Service Law increasing the utility assessment from the current rate of 1/3 of one percent to one percent of a utility’s in-state gross operating revenue, together with a temporary surcharge equal to an additional one percent of the utility’s gross operating revenue. If adopted into law, the Governor’s proposal would increase the assessment charged to Distribution’s New York Division, based on the most current calculation, from $2.3 million to approximately $14 million, all other things being equal. The Company is unable to ascertain the outcome of the Governor’s proposed increase to the assessment at this time. Should it become law, the Company would seek to recover the increased expense by petitioning the Public Service Commission for an increase in rates or such other means of recovery as is available under the law.
      The increase in the utility assessment would also impact marketing companies. If adopted into law, the Governor’s proposal would establish a new assessment charged to NFR for the first time. While the proposed legislation mandates that such assessment be added as a separate item to bills rendered by marketing companies to their customers, NFR management is evaluating the proposed legislation to determine the extent to which, and the details of how it will pass along this cost increase to its customers. NFR management is also evaluating potential legal challenges to certain aspects of the assessment.
      Based on management’s most recent estimates, the annual assessment imposed on NFR could range from approximately $4.4 million to approximately $8.3 million. It is the opinion of NFR management that the proposed legislation fails to adequately define key language necessary to compute the assessment, leading to a certain degree of uncertainty concerning the impact and size of the assessment.
Pennsylvania Jurisdiction
     On June 1, 2006, Distribution Corporation filed proposed tariff amendments with PaPUC to increase annual revenues by $25.9 million to cover increases in the cost of service to be effective July 30, 2006. The rate request was filed to address increased costs associated with Distribution Corporation’s ongoing construction program as well as increases in operating costs, particularly uncollectible accounts. Following standard regulatory procedure, the PaPUC issued an order on July 20, 2006 instituting a rate proceeding and suspending the proposed tariff amendments until March 2, 2007. On October 2, 2006, the parties, including Distribution Corporation, Staff of the PaPUC and intervenors, executed an agreement (Settlement) proposing to settle all issues in the rate proceeding. The Settlement includesincluded an increase in annual revenues of $14.3 million to non-gas revenues, an agreement not to file a rate case until January 28, 2008 at the earliest and an early implementation date. The Settlement was approved by the PaPUC at its meeting on November 30, 2006, and the new rates became effective January 1, 2007.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
     On June 8, 2006, the NTSB issued safety recommendations to Distribution Corporation, the PaPUC and certain other parties as a result of an investigation of a natural gas explosion that occurred on Distribution Corporation’s system in Dubois, Pennsylvania in August 2004. The explosion destroyed a residence, resulting in the death of two people who lived there, and damaged a number of other houses in the immediate vicinity. Without admitting liability, Distribution Corporation settled all significant third-party claims against it related to the explosion.
     The NTSB’s safety recommendations to Distribution Corporation involved revisions to its butt-fusion procedures for joining plastic pipe, and revisions to its procedures for qualifying personnel who perform plastic fusions. Although not required by law to do so, Distribution Corporation implemented those recommendations. In December 2006, the NTSB classified its recommendations as “closed” after determining that Distribution Corporation took acceptable action with respect to the recommendations.
     The NTSB’s recommendation to the PaPUC was to require an analysis of the integrity of butt-fusion joints in Distribution Corporation’s system and replacement of those joints that are determined to have unacceptable characteristics. Distribution Corporation has worked cooperatively with the Staff of the PaPUC to permit the PaPUC to undertake the analysis recommended by the NTSB.
     In late November 2007, Distribution Corporation reached a tentative settlement with the Law Bureau Prosecutory Staff of the PaPUC (the “Law Bureau”) regarding the explosion and the PaPUC’s subsequent investigation. The Law Bureau and Distribution Corporation jointly submitted the terms of the settlement to the PaPUC for approval. The PaPUC issued the Settlement Agreement for public comment with a comment period ending April 3, 2008. While no comments were filed, the Chairman of the PaPUC recommended that, pursuant to revised provisions of the Settlement Agreement, Distribution Corporation should, without admitting liability, make a $100,000 payment to an assistance fund for payment-troubled customers and make an additional $50,000 payment to fund safety-related activities. The PaPUC adopted the Chairman’s recommendation unanimously at its public meeting held on May 1, 2008, and a tentative final order was issued on May 21, 2008. Distribution Corporation accepted the proposed Settlement Agreement. No other comments were filed, and by its terms the tentative order approving the Settlement Agreement became final on June 5, 2008 without further action by the PaPUC. On June 19, 2008, Distribution Corporation fulfilled the last condition for closing the proceeding by providing notice to the Secretary of the PaPUC that the $100,000 payment to the assistance fund had been made. Distribution Corporation is working with the Staff of the PaPUC to determine how the additional $50,000 in safety-related funding will be spent.
Pipeline and Storage
     Supply Corporation currently does not have a rate case on file with the FERC. AThe rate settlement approved by the FERC on February 9, 2007 requires Supply Corporation to make a general rate filing to be effective December 1, 2011, and bars Supply Corporation from making a general rate filing before then, with some exceptions specified in the settlement.

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     Empire currently does not have a rate case on file with the NYPSC. Among the issues resolved in connection with Empire’s FERC application to build the Empire Connector are the rates
Item 2.Management’s Discussion and termsAnalysis of service that will become applicable to allFinancial Condition and Results of Empire’s business, effective upon Empire constructing and placing its new facilities into service (currently expected for November 2008). At that time, Empire will become an interstate pipeline subject to FERC regulation. The order described in the following paragraph requires Empire to make a filing at the FERC within three years after the in-service date justifying Empire’s existing recourse rates or proposing alternative rates.Operations (Cont.)
     On December 21, 2006, the FERC issued an order granting a Certificate of Public Convenience and Necessity authorizing the construction and operation of the Empire Connector and various other related pipeline projects by other unaffiliated companies. The Empire Certificate contains various environmental and other conditions. Empire accepted that Certificate and received additional environmental permits from the U.S. Army Corps of Engineers and state environmental agencies. Empire also received, from all six upstate New York counties in which it will buildbuilt the Empire Connector

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
project, final approval of sales tax exemptions and temporary partial property tax abatements. In June 2007, Empire signed a firm transportation service agreement with KeySpan Gas East Corporation, under which Empire is obligated to provide transportation service that will requirerequired construction of this project. Construction began in September 2007 and isThe new facilities were placed into service on scheduleDecember 10, 2008. As of that date, Empire became an interstate pipeline subject to be completed byFERC regulation. The order described above requires Empire to make a filing at the plannedFERC, within three years after the in-service date, of November 2008, although the actual in-service date will depend upon the completion of the Millennium Pipeline.justifying Empire’s existing recourse rates or proposing alternative rates.
Environmental Matters
     The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.
     The Company received, in 1998 and again in October 1999, notice thathas agreed with the NYDEC believes the Company is responsible for contamination discovered atto remediate a former manufactured gas plant site located in New York for which theYork. The Company had not been named ashas submitted a PRP. In February 2007, the NYDEC identified the Company as a PRP for the site and issued a proposed remedial action plan. The NYDEC estimated clean-up costs under its proposed remedy to be $8.9 million if implemented. Although the Company commentedRemedial Design/Remedial Action work plan to the NYDEC that the proposed remedial action plan contained a number of material errors, omissions and procedural defects, the NYDEC, in a March 2007 Record of Decision, selected the remedy it had previously proposed. In July 2007, the Company appealed the NYDEC’s Record of Decision to the New York State Supreme Court, Albany County. The Court dismissed the appeal in January 2008. The Company filed a notice of appeal in February 2008. In July 2008, the Company withdrew its appeal and agreed to the terms of an Order on Consent issued by the NYDEC. Pursuant to the order, the Company will remediate the site consistent with the remedy selected in the NYDEC’s Record of Decision. The Company will also reimburse the NYDEC in the amount of approximately $1.5 million for costs incurred in connection with the site from 1998 through May 30, 2007. The Company acknowledged that additional charges related to the site will be billed to the Company at a later date, including costs incurred by the NYDEC after May 30, 2007 and any costs incurred by the New York Department of Health. The Company has not received any estimates of such additional costs. The Company has recorded an estimated minimum liability for remediation of $10.4 million associated with this site.site of $16.4 million.
     At June 30,December 31, 2008, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $13.5$19.3 million to $17.2$23.5 million. The minimum estimated liability of $13.5$19.3 million, which includes the $16.4 million discussed above, has been recorded on the Consolidated Balance Sheet at June 30, 2008, including the $10.4 million discussed above.December 31, 2008. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet.
     The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations or other factors could adversely impact the Company.
New Accounting Pronouncements
     In September 2006, the FASB issued SFAS 157. SFAS 157 provides guidance for using fair value to measure assets and liabilities. The pronouncement serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. SFAS 157 is to be applied whenever another standard requires or allows assets or liabilities to be measured at fair value. In accordance with FASB Staff Position FAS No. 157-2, on October 1, 2008, the Company adopted SFAS 157 is effective for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009.basis. The same FASB Staff Position delays the effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value on a recurring basis, until the Company’s first quarter of fiscal 2010. For further discussion of the impact of the adoption of SFAS 157 for financial assets and financial liabilities, refer to Part I, Item 1 at Note 2 — Fair Value Measurements. The Company is currently evaluating the impact that the adoption of SFAS 157 for nonfinancial assets and nonfinancial liabilities will have on its consolidated financial statements. The Company has identified Goodwill as being the major nonfinancial asset that will be impacted by SFAS 157 and Asset Retirement Obligations as being the major nonfinancial liability that will be impacted by SFAS 157.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
items that are recognized or disclosed at fair value on a recurring basis, until the Company’s first quarter of fiscal 2010. The Company is currently evaluating the impact that the adoption of SFAS 157 will have on its consolidated financial statements.
     In September 2006, the FASB also issued SFAS 158, (anan amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R).132R. SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be fully adopted by the Company by the end of fiscal 2009. Currently, theThe Company measureshas historically measured its plan assets and benefit obligations using a June 30th measurement date. In anticipation of changing to a September 30th measurement date, the Company will be recording fifteen months of pension and other post-retirement benefit costs during fiscal 2009. In accordance with the provisions of SFAS 158, these costs have been calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $5.1 million and have been recorded by the Company during the quarter ended December 31, 2008 as a $3.8 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $1.3 million ($0.8 million after tax) adjustment to earnings reinvested in the business. For further discussion of the impact of adopting the measurement date provisions of SFAS 158, refer to Part I, Item 1 at Note 8 — Retirement Plan and Other Post-Retirement Benefits.
     In February 2007, the FASB issued SFAS 159. SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not otherwise required to be measured at fair value under GAAP. A company that elects the fair value option for an eligible item will be required to recognize in current earnings any changes in that item’s fair value in reporting periods subsequent to the date of adoption. SFAS 159 isbecame effective as offor the Company’s first quarter of fiscal 2009.Company on October 1, 2008. The Company is currently evaluatingdid not elect the impact, iffair value measurement option for any of its financial instruments other than those that the adoption of SFAS 159 will have on its consolidated financial statements.are already being measured at fair value.
     In December 2007, the FASB issued SFAS 141R. SFAS 141R will significantly change the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies, acquisition costs, in process research and development and restructuring costs. In addition, under SFAS 141R, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income tax expense. SFAS 141R is effective as of the Company’s first quarter of fiscal 2010.
     In December 2007, the FASB issued SFAS 160. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests (NCI) and classified as a component of equity. This new consolidation method will significantly change the accounting for transactions with minority interest holders. SFAS 160 is effective as of the Company’s first quarter of fiscal 2010. The Company currently does not have any NCI.
     In March 2008, the FASB issued SFAS 161. SFAS 161 requires entities to provide enhanced disclosures related to an entity’s derivative instruments and hedging activities in order to enable investors to better understand how derivative instruments and hedging activities impact an entity’s financial reporting. The additional disclosures include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective as of the Company’s second quarter of fiscal 2009. The Company is currently evaluating the impact that the adoption of SFAS 161 will have on its disclosures in itsthe 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

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. The revised reporting and disclosure requirements are effective for the Company’s Form 10-K for the period ended September 30, 2010. Early adoption is not permitted. The Company is currently evaluating the impact that adoption of these rules will have on its consolidated financial statements.statements and MD&A disclosures.
Safe Harbor for Forward-Looking Statements
     The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking” statements“forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
1.Financial and economic conditions, including the availability of credit, and their effect on the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments;
2.Occurrences affecting the Company’s ability to obtain financing under credit lines or other credit facilities or through the issuance of commercial paper, other short-term notes or debt or equity securities, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;
3. Changes in economic conditions, including economicglobal, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;
4.The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
5.Economic disruptions caused byor uninsured losses resulting from terrorist activities, acts of war, or major accidents, and downturns in economic activity including nationalfires, hurricanes, other severe weather, pest infestation or regional recessions;other natural disasters;
 
2.6.Changes in actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;
7. Changes in demographic patterns and weather conditions, including the occurrence of severe weather such as hurricanes;conditions;

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
 
3.8.  Changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments or the valuation of the Company’s natural gas and oil reserves;
 
4.9. Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
10. Uncertainty of oil and gas reserve estimates;
 
5.11. Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including shortages, delays or unavailability of equipment and services required in drilling operations;
 
6.12. Significant changes from expectations in the Company’s actual production levels for natural gas or oil;
 
7.13. Changes in the availability and/or price of derivative financial instruments;
 
8.14. Changes in the price differentials between various types of oil;
 
9.15. Inability to obtain new customers or retain existing ones;
 
10.16. Significant changes in competitive factors affecting the Company;
 
11.17. Changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations;
 
12.18. Governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements;
 
13.19. Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;
 
14.20. Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs or plans;

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Concl.)
15.
21. The nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits;
 
16.Occurrences affecting the Company’s ability to obtain funds from operations, from borrowings under our credit lines or other credit facilities or from issuances of other short-term notes or debt or equity securities to finance needed capital expenditures and other investments, including any downgrades in the Company’s credit ratings;
17.22. Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties;
 
18.Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
19.Changes in the market price of timber and the impact such changes might have on the types and quantity of timber harvested by the Company;
20.23. Significant changes in tax rates or policies or in rates of inflation or interest;
 
21.24. Significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur;
 
22.25. Changes in accounting principles or the application of such principles to the Company;
 
23.26. The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
 
24.Changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefit plans;
25.27. Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or
 
26.28. Increasing costs of insurance, changes in coverage and the ability to obtain insurance.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Concl.)
     The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Item 3.Quantitative and Qualitative Disclosures About Market Risk
     Refer to the “Market Risk Sensitive Instruments” section in Item 2 — MD&A.
Item 4.Controls and Procedures
Evaluation of Disclosure Controls and Procedures
     The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30,December 31, 2008.

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Item 4.Controls and Procedures (Concl.)
Changes in Internal ControlsControl Over Financial Reporting
     There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended June 30,December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Part II. Other Information
Item 1.Legal Proceedings
     On June 8, 2006, the NTSB issued safety recommendations to Distribution Corporation, the PaPUC and certain others as a result of its investigation of a natural gas explosion that occurred on Distribution Corporation’s system in Dubois, Pennsylvania in August 2004. For a discussion of this matter, refer to Part II, Item 7 — MD&A of this report under the heading “Other Matters — Rate and Regulatory Matters.”
     For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 45 — Commitments and Contingencies, and Part I, Item 2 — MD&A of this report under the heading “Other Matters — Environmental Matters.”
     In addition to thethese matters, referenced above, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service, and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
Item 1A.Risk Factors
     The risk factors in Item 1A of the Company’s 20072008 Form 10-K as amended by Item 1A of the Company’s Form 10-Q for the quarter ended March 31, 2008, have not materially changed other than as set forth below. The risk factorfactors presented below supersedessupersede the risk factorfactors having the same captioncaptions in the 20072008 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2007 Form 10-K and the March 31, 2008 Form 10-Q.10-K.

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Item 1A.Risk Factors (Cont.)
National Fuel may be adversely affected by economic conditions.conditions and their impact on our suppliers and customers.
     Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect National Fuel’s revenues and cash flows or restrict its future growth. Economic conditions in National Fuel’s utility service territories and energy marketing territories also impact its collections of accounts receivable. All of National Fuel’s segments are exposed to risks associated with the creditworthiness or performance of key suppliers and customers, many of which may be adversely affected by volatile conditions in the financial markets. These conditions could result in financial instability or other adverse effects at any of our suppliers or customers. For example, counterparties to National Fuel’s commodity hedging arrangements or commodity sales contracts might not be able to perform their obligations under these arrangements or contracts. Customers of National Fuel’s Utility and Energy Marketing segments may have particular trouble paying their bills during periods of declining economic activity and high commodity prices, potentially resulting in increased bad debt expense and reduced earnings. Any of these events could have a material adverse effect on National Fuel’s results of operations, financial condition and cash flows.
National Fuel’s need to comply with comprehensive, complex, and sometimes unpredictable government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.
     While National Fuel generally refers to its Utility segment and its Pipeline and Storage segment as its “regulated segments,” there are many governmental regulations that have an impact on almost every aspect of National Fuel’s businesses. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may affect its business in ways that the Company cannot predict.
      A December 2008 New York State budget proposal to increase the assessment on utility companies’ gross operating revenues from intrastate utility operations, and to extend, for the first time, that assessment to energy marketing companies, such as NFR, could have a material adverse effect on the Company’s results of operations, financial condition or cash flows. The risk of an adverse effect is greatest if Distribution Corporation is unable to recover any increase in its assessment in the regulated rates it charges to its New York utility customers, or if NFR, which does not have regulated rates, is unable to collect any assessment against it from its customers.
     In its Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC and the PaPUC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or if Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costs that may be incurred in connection with governmental investigations or proceedings or mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.
     In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have sought to establish competitive markets in which customers may purchase supplies of gas from marketers, rather than from utility companies. In June 1999, the Governor of Pennsylvania signed into law the Natural Gas Choice and Competition Act. The Act revised the Public Utility Code relating to the restructuring of the natural gas industry, to permit consumer choice of natural gas suppliers. The early programs instituted to comply with the Act did not result in significant change, and many residential customers currently continue to purchase natural gas from the utility companies. In October 2005, the PaPUC concluded that “effective competition” does not exist in the retail natural gas supply market statewide. On September 11, 2008, the PaPUC adopted a Final Order and Action Plan designed to “increase effective competition in the retail market for natural gas services.” The plan sets forth a schedule of action items for utilities and the PaPUC in order to remove “barriers in the market structure” that, in the opinion of the PaPUC, prevented the full participation of unregulated natural gas suppliers in

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Item 1A.Risk Factors (Concl.)
Pennsylvania retail markets. In New York, in August 2004, the NYPSC issued its Statement of Policy on Further Steps Toward Competition in Retail Energy Markets. This policy statement has a similar goal of encouraging customer choice of alternative natural gas providers. In 2005, the NYPSC stepped up its efforts to encourage customer choice at the retail residential level, and customer choice activities increased in Distribution Corporation’s New York service territory. In April 2007, the NYPSC, noting that the retail energy marketplace in New York is established and continuing to expand, commenced a review to determine if existing programs initially designed to promote competition had outlived their usefulness and whether the cost of programs currently funded by utility rate payers should be shifted to market competitors. Increased retail choice activities, to the extent they occur, may increase Distribution Corporation’s cost of doing business, put an additional portion of its business at regulatory risk, and create uncertainty for the future, all of which may make it more difficult to manage Distribution Corporation’s business profitably.
     Both the NYPSC and the PaPUC have instituted proceedings for the purpose of promoting conservation of energy commodities, including natural gas. In New York, Distribution Corporation implemented a Conservation Incentive Program that promotes conservation and efficient use of natural gas by offering customer rebates for high-efficiency appliances, among other things. The intent of conservation and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers results in decreased revenues to the Utility. To prevent revenue erosion caused by conservation, the NYPSC approved a “revenue decoupling mechanism” that renders Distribution Corporation’s New York division financially indifferent to the effects of conservation. In Pennsylvania, although a proceeding is pending, the PaPUC has not yet directed Distribution Corporation to implement conservation measures. If the NYPSC were to revoke the revenue decoupling mechanism in a future proceeding or the PaPUC were to adopt a conservation program without a revenue decoupling mechanism or other changes in rate design, reduced customer usage could decrease revenues, forcing Distribution Corporation to file for rate relief.
     In its Pipeline and Storage segment, National Fuel is subject to the jurisdiction of the FERC with respect to Supply Corporation and Empire. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their natural gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. State commissions can also petition the FERC to investigate whether Supply Corporation’s and Empire’s rates are still just and reasonable, and if not, to reduce those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to reduce the rates it charges its natural gas transportation and/or storage customers, or if Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation’s or Empire’s earnings may decrease.
Financial accounting requirements regarding exploration and production activities may affect National Fuel’s profitability.
     National Fuel accounts for its exploration and production activities under the full cost method of accounting. Each quarter, National Fuel must compare the level of its unamortized investment in oil and natural gas properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses quarter-end spot prices for oil and natural gas (as adjusted for hedging). If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be “impaired,” and the full cost accounting rules require that the investment must be written down to the calculated net present value. Such an instance would require National Fuel to recognize an immediate expense in that quarter, and its earnings would be reduced. National Fuel’s Exploration and Production segment recorded an impairment charge under the full cost method of accounting in the quarter ended December 31, 2008. If spot market prices at a subsequent quarter end are lower than prices at December 31, 2008, absent any changes in other factors affecting the present value of the future net revenue projected to be recovered from the Company’s oil and natural gas properties, the Company would be required to record an additional impairment charge. Depending on the magnitude of the decrease in prices, that charge could be material.

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Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
     On AprilOctober 1, 2008, the Company issued a total of 2,4002,100 unregistered shares of Company common stock to the eightseven non-employee directors of the Company who receivethen serving on the Board of Directors of the Company and receiving compensation under the Company’s Retainer Policy for Non-Employee Directors, 300 shares to each such director. All of these unregistered shares were issued as partial consideration for thesuch directors’ services during the quarter ended June 30,December 31, 2008. These transactions were exempt from registration byunder Section 4(2) of the Securities Act of 1933, as transactions not involving a public offering.

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Item 2.Unregistered Sales of Equity Securities and Use of Proceeds (Concl.)
Issuer Purchases of Equity Securities
                 
          Total Number of Maximum Number
          Shares Purchased of Shares that May
          as Part of Publicly Yet Be Purchased
  Total Number of     Announced Share Under Share
  Shares Average Price Repurchase Plans Repurchase Plans
Period Purchased(a) Paid per Share or Programs or Programs(b)
Apr. 1 - 30, 2008  446,666  $46.99   439,722   1,332,725 
May 1 - 31, 2008  32,337  $57.99      1,332,725 
June 1 - 30, 2008  9,686  $58.43      1,332,725 
              
Total  488,689  $47.94   439,722   1,332,725 
                 
          Total Number of Maximum Number
          Shares Purchased of Shares that May
          as Part of Publicly Yet Be Purchased
  Total Number of     Announced Share Under Share
  Shares Average Price Repurchase Plans Repurchase Plans
Period Purchased(a) Paid per Share or Programs or Programs(b)
Oct. 1-31, 2008  10,929   $35.07      6,971,019 
Nov. 1-30, 2008  11,005   $32.31      6,971,019 
Dec. 1-31, 2008  309,344   $29.79      6,971,019 
                 
Total  331,278   $30.05      6,971,019 
                 
 
(a) Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes, and (iii)taxes. During the quarter ended December 31, 2008, the Company did not purchase any shares of its common stock of the Company purchased on the open market pursuant to the Company’sits publicly announced share repurchase program. SharesOf the 331,278 shares purchased other than through a publicly announced share repurchase program, totaled 6,944 in April 2008, 32,337 in May 2008 and 9,686 in June 2008 (a three month total of 48,967). Of those shares, 19,36334,170 were purchased for the Company’s 401(k) plans and 29,604297,108 were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock.
 
(b) OnIn December 8, 2005, the Company’s Board of Directors authorized the repurchase of up to eight million shares of the Company’s common stock. RepurchasesThe Company completed the repurchase of the eight million shares during 2008. In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares of the Company’s common stock. The Company had, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. However, such repurchases may be made from time to timein the future if conditions improve. Such repurchases would be made in the open market or through private transactions.
Item 6.Exhibits
     (a) Exhibits
   
Exhibit  
Number Description of Exhibit
  
3(ii)By-Laws:
National Fuel Gas Company By-Laws as amended June 11, 2008 (incorporated herein by reference to Exhibit 3.1, Form 8-K dated June 16, 2008).
4Instruments defining the rights of security holders:
4.1Officer’s Certificate establishing 6.50% Notes due 2018, dated April 11, 2008
 
 Amended and Restated Rights Agreement, dated as of July 11,December 4, 2008, between National Fuel Gas Company and The Bank of New York as rights agent (incorporated herein by reference to Exhibit 4.1, Form 8-K dated July 15,December 4, 2008).
   
1010.1 Material contracts:
Director Services Agreement, dated asDescription of June 1, 2008, betweenlong-term performance incentives under the National Fuel Gas Company and Philip C. Ackerman (incorporated herein by reference to Exhibit 99, Form 8-K dated June 16, 2008).Performance Incentive Program.
   
1210.2 Statements regarding ComputationForm of Ratios:
Ratio of Earnings to Fixed Charges forStock Appreciation Right Award Notice under the Twelve Months Ended June 30, 2008National Fuel Gas Company 1997 Award and the Fiscal Years Ended September 30, 2004 through 2007.Option Plan.

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Item 6.Exhibits (Concl.)
   
Exhibit  
Number Description of Exhibit
10.3Description of performance goals under the Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program and the National Fuel Gas Company Executive Annual Cash Incentive Program.
12Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the Twelve Months Ended December 31, 2008 and the Fiscal Years Ended September 30, 2004 through 2008.
  
31.1 Written statements of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
   
31.2 Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
   
32 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
   
99 National Fuel Gas Company Consolidated Statement of Income for the Twelve Months Ended June 30,December 31, 2008 and 2007.
Incorporated herein by reference as indicated.

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SIGNATURESSIGNATURE
     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
     
 NATIONAL FUEL GAS COMPANY
       ��            (Registrant)
 
 
 /s/ R. J. Tanski   
 R. J. Tanski  
 Treasurer and Principal Financial Officer  
 
   
 /s/ K. M. Camiolo   
 K. M. Camiolo  
 Controller and Principal Accounting Officer  
 
Date: August 8, 2008February 6, 2009

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