FORM 10-Q
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2008
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number 1-3880
 
NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)
     
New Jersey   13-1086010
     
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
     
6363 Main Street
Williamsville, New York
  14221
     
(Address of principal executive offices)   (Zip Code)
(716) 857-7000
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. YES þ   NO o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ   Accelerated filer o  Non-accelerated filer o  Smaller reporting company o
        (Do not check if a smaller reporting company)    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o   NO þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
Common stock, $1 par value, outstanding at January 31, 2009: 79,514,816 shares.
 
 

 


Table of Contents

GLOSSARY OF TERMS
Frequently used abbreviations, acronyms, or terms used in this report:
National Fuel Gas Companies
     
Company
  The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Data-Track
  Data-Track Account Services, Inc.
Distribution Corporation
  National Fuel Gas Distribution Corporation
Empire
  Empire Pipeline, Inc.
ESNE
  Energy Systems North East, LLC
Highland
  Highland Forest Resources, Inc.
Horizon
  Horizon Energy Development, Inc.
Horizon LFG
  Horizon LFG, Inc.
Horizon Power
  Horizon Power, Inc.
Leidy Hub
  Leidy Hub, Inc.
Midstream
  National Fuel Gas Midstream Corporation
Model City
  Model City Energy, LLC
National Fuel
  National Fuel Gas Company
NFR
  National Fuel Resources, Inc.
Registrant
  National Fuel Gas Company
SECI
  Seneca Energy Canada Inc.
Seneca
  Seneca Resources Corporation
Seneca Energy
  Seneca Energy II, LLC
Supply Corporation
  National Fuel Gas Supply Corporation
Regulatory Agencies
     
FASB
  Financial Accounting Standards Board
FERC
  Federal Energy Regulatory Commission
NYDEC
  New York State Department of Environmental Conservation
NYPSC
  State of New York Public Service Commission
PaPUC
  Pennsylvania Public Utility Commission
SEC
  Securities and Exchange Commission
Other
     
2008 Form 10-K
  The Company’s Annual Report on Form 10-K for the year ended September 30, 2008, as amended
ARB 51
  Accounting Research Bulletin No. 51, Consolidated Financial Statements
Bbl
  Barrel (of oil)
Bcf
  Billion cubic feet (of natural gas)
Board foot
 
A measure of lumber and/or timber equal to 12 inches in length by 12 inches in width by one inch in thickness.
Btu
 
British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.
Capital expenditure
 
Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Degree day
 
A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative
 
A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.
Development costs
 
Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
Dth
 
Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.

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Table of Contents

GLOSSARY OF TERMS (Cont.)
     
Exchange Act
  Securities Exchange Act of 1934, as amended
Expenditures for
   long-lived assets
  Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costs
 
Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
FIN
  FASB Interpretation Number
FIN 48
 
FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of SFAS 109
Firm transportation
   and/or storage
 
The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP
 
Accounting principles generally accepted in the United States of America
Goodwill
 
An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging
 
A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub
 
Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
Interruptible transportation
   and/or storage
 
The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LIBOR
  London Interbank Offered Rate
LIFO
  Last-in, first-out
Mbbl
  Thousand barrels (of oil)
Mcf
  Thousand cubic feet (of natural gas)
MD&A
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth
  Thousand decatherms (of natural gas)
MMBtu
  Million British thermal units
MMcf
  Million cubic feet (of natural gas)
NYMEX
 
New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Open Season
 
A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined (“Open Season”) time period are evaluated as if they had been submitted simultaneously.
Proved developed reserves
 
Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves
 
Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive.
PRP
  Potentially responsible party
Reserves
 
The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Restructuring
 
Generally referring to partial “deregulation” of the utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundling”) of gas commodity service from transportation service for wholesale and large- volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.
SAR
  Stock-settled stock appreciation right
SFAS
  Statement of Financial Accounting Standards
SFAS 87
 
Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions

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Table of Contents

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

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INDEX
     
    Page
   
 
   
   
 
   
  6
 
   
  7 - 8
 
   
  9
 
   
  10
 
   
  11 - 23
 
   
  24 - 42
 
   
  42
 
   
  42
 
   
   
 
   
  42
 
   
  42 - 44
 
   
  45
 
   
Item 3. Defaults Upon Senior Securities
 
 
   
Item 4. Submission of Matters to a Vote of Security Holders
 
 
   
Item 5. Other Information
 
 
   
  45 - 46
 
   
  47
 EX-10.1
 EX-10.2
 EX-10.3
 EX-12
 EX-31.1
 EX-31.2
 EX-32
 EX-99
 
  The Company has nothing to report under this item.
     Reference to “the Company” in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.
     This Form 10-Q contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2 — MD&A, under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction and other projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions.

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Table of Contents

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

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Table of Contents

Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
                 
    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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Table of Contents

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

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Table of Contents

Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statements of Cash Flows
(Unaudited)
                 
    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

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Table of Contents

Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statements of Comprehensive Income
(Unaudited)
                 
    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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Table of Contents

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.
Earnings for Interim Periods. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2008, 2007 and 2006 that are included in the Company’s 2008 Form 10-K. The consolidated financial statements for the year ended September 30, 2009 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.
     The earnings for the three months ended December 31, 2008 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2009. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year.
Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid investments purchased with a maturity of generally three months or less to be cash equivalents.
     At December 31, 2008, the Company accrued $51.7 million of capital expenditures in the Exploration and Production segment, the majority of which was for lease acquisitions in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at December 31, 2008 since it represented a non-cash investing activity at that date.
     At September 30, 2008, the Company accrued $16.8 million of capital expenditures related to the construction of the Empire Connector project. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2008 and have been included in the Consolidated Statement of Cash Flows at December 31, 2008.
Hedging Collateral Deposits. This is an account title for cash held in margin accounts funded by the Company to serve as collateral for open positions on exchange-traded futures contracts and over-the-counter swap agreements.
     At December 31, 2008, the Company had hedging collateral deposits of $3.7 million related to its exchange-traded futures contracts. The Company’s over-the-counter swap agreements were in a significant asset position at December 31, 2008. Under the terms of those agreements, the Company was not required to fund any cash as hedging collateral; rather, the counterparties were required to provide collateral to the Company. The amount of the collateral received was $34.1 million. This amount

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Table of Contents

Item 1. Financial Statements (Cont.)
is included in Accounts Payable on the Consolidated Balance Sheet at December 31, 2008. It is the Company’s policy to not offset hedging collateral deposits paid or received against the derivative financial instruments liability or asset balances.
Cash Held in Escrow. On August 31, 2007, the Company received approximately $232.1 million of proceeds from the sale of SECI, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. The escrow account was a Canadian dollar denominated account. On a U.S. dollar basis, the value of this account was $62.0 million at September 30, 2007. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. To hedge against foreign currency exchange risk related to the cash being held in escrow, the Company held a forward contract to sell Canadian dollars. For presentation purposes on the Consolidated Statement of Cash Flows, for the three months ended December 31, 2007, the Cash Held in Escrow line item within Investing Activities reflects the net proceeds to the Company (received on January 8, 2008) after adjusting for the impact of the foreign currency hedge.
Gas Stored Underground — Current. In the Utility segment, gas stored underground – current is valued using the LIFO method. This value or cost is lower than the current market value of the gas stored underground. Gas stored underground – current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $36.2 million at December 31, 2008, is reduced to zero by September 30 of each year as the inventory is replenished.
Property, Plant and Equipment. In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.
     Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
     Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying current market prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The Company’s capitalized costs exceeded the full cost ceiling for the Company’s oil and gas properties at December 31, 2008. As such, the Company recognized a pre-tax impairment of $182.8 million at December 31, 2008. Deferred income taxes of $74.6 million were recorded associated with this impairment.

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Table of Contents

Item 1. Financial Statements (Cont.)
Accumulated Other Comprehensive Income. The components of Accumulated Other Comprehensive Income, net of related tax effect, are as follows (in thousands):
                 
    At December 31, 2008     At September 30, 2008  
Funded Status of the Pension and Other Post-Retirement Benefit Plans
  $ (19,741 )   $ (19,741 )
Cumulative Foreign Currency Translation Adjustment
    (63 )     (71 )
Net Unrealized Gain on Derivative Financial Instruments
    69,320       15,949  
Net Unrealized Gain on Securities Available for Sale (1)
    585       6,826  
 
           
Accumulated Other Comprehensive Income
  $ 50,101     $ 2,963  
 
           
 
(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 reflect the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining diluted earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options and stock-settled SARs. The diluted weighted average shares outstanding shown on the Consolidated Statement of Income reflects the potential dilution as a result of these stock options and stock-settled SARs as determined using the Treasury Stock Method. Stock options and stock-settled SARs that are antidilutive are excluded from the calculation of diluted earnings per common share. For the quarter ended December 31, 2008, there were 765,000 stock options and 365,000 stock-settled SARs excluded as being antidilutive. For the quarter ended December 31, 2007, there were no stock options or stock-settled SARs excluded as being antidilutive.
Stock-Based Compensation. During the quarter ended December 31, 2008, the Company granted 610,000 performance-based stock-settled SARs having a weighted average exercise price of $29.88 per share. The weighted average grant date fair value of these stock-settled SARs was $4.09 per share. The accounting treatment for such stock-settled SARs is the same under SFAS 123R as the accounting for stock options under SFAS 123R. The stock-settled SARs granted during the quarter ended December 31, 2008 vest and become exerciseable annually in one-third increments, provided that a performance condition is met. The performance condition for each fiscal year, generally stated, is an increase over the prior fiscal year of at least five percent in certain oil and natural gas production of the Exploration and Production segment. The weighted average grant date fair value of these stock-settled SARs granted during the current quarter was estimated on the date of grant using the same accounting treatment that is applied for stock options under SFAS 123R, and assumes that the performance conditions specified will be achieved. If such conditions are not met or it is not considered probable that such conditions will be met, no compensation expense is recognized and any previously recognized compensation expense is reversed.
     There were no stock options or restricted share awards (non-vested stock as defined in SFAS 123R) granted during the quarter ended December 31, 2008.

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Table of Contents

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

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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 component of equity. This new consolidation method will significantly change the accounting for transactions with minority interest holders. SFAS 160 is effective as of the Company’s first quarter of fiscal 2010. The Company currently does not have any NCI.
     In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS 133.” SFAS 161 requires entities to provide enhanced disclosures related to an entity’s derivative instruments and hedging activities in order to enable investors to better understand how derivative instruments and hedging activities impact an entity’s financial reporting. The additional disclosures include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective as of the Company’s second quarter of fiscal 2009. The Company is currently evaluating the impact that the adoption of SFAS 161 will have on its disclosures in the notes to the consolidated financial statements.
     On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and gas reserves to a 12-month average of the first day of the month price for each month within the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. The revised reporting and disclosure requirements are effective for the Company’s Form 10-K for the period ended September 30, 2010. Early adoption is not permitted. The Company is currently evaluating the impact that adoption of these rules will have on its consolidated financial statements and MD&A disclosures.
Note 2 – Fair Value Measurements
     Beginning in fiscal 2009, the Company adopted the provisions of SFAS 157, “Fair Value Measurements.” SFAS 157 establishes a fair-value hierarchy, which prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The adoption of SFAS 157 has not had a significant impact on the consolidated financial statements.
     The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

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Table of Contents

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.

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Table of Contents

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):

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Table of Contents

Item 1. Financial Statements (Cont.)
                 
    Three Months Ended
    December 31,
    2008   2007
     
U.S. Income (Loss) Before Income Taxes
  $ (78,141 )   $ 115,444  
     
 
               
Income Tax Expense (Benefit), Computed at Federal Statutory Rate of 35%
  $ (27,349 )   $ 40,405  
 
               
Increase (Reduction) in Taxes Resulting From:
               
State Income Taxes
    (5,039 )     7,043  
Miscellaneous
    (3,075 )     (2,608 )
     
 
               
Total Income Taxes
  $ (35,463 )   $ 44,840  
     -
     Significant components of the Company’s deferred tax liabilities and assets were as follows (in thousands):
                 
    At December 31, 2008   At September 30, 2008
     
Deferred Tax Liabilities:
               
Property, Plant and Equipment
  $ 614,556     $ 673,313  
Pension and Other Post-Retirement Benefit Costs – SFAS 158
    44,345       43,340  
Unrealized Hedging Gains
    47,856       14,936  
Other
    36,975       40,455  
     
Total Deferred Tax Liabilities
    743,732       772,044  
     
 
               
Deferred Tax Assets:
               
Pension and Other Post-Retirement Benefit Costs – SFAS 158
    (44,831 )     (43,340 )
Other
    (101,197 )     (92,461 )
     
Total Deferred Tax Assets
    (146,028 )     (135,801 )
     
Total Net Deferred Income Taxes
  $ 597,704     $ 636,243  
     
 
               
Presented as Follows:
               
Net Deferred Tax Liability/(Asset) – Current
  $ (6,340 )   $ 1,871  
Net Deferred Tax Liability – Non-Current
    604,044       634,372  
     
Total Net Deferred Income Taxes
  $ 597,704     $ 636,243  
     
     Regulatory liabilities representing the reduction of previously recorded deferred income taxes with rate-regulated activities that are expected to be refundable to customers amounted to $18.5 million and $18.4 million at December 31, 2008 and September 30, 2008, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $83.5 million and $82.5 million at December 31, 2008 and September 30, 2008, respectively.
     The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 2008 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. While the federal statute of limitations remains open for fiscal 2005 and later years, IRS examinations for fiscal 2007 and prior years have been completed and the Company believes such years are effectively settled.

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Item 1. Financial Statements (Cont.)
     The Company is also subject to various routine state income tax examinations.  The Company’s  operating subsidiaries mainly operate in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.
Note 4 — Capitalization
Common Stock. During the three months ended December 31, 2008, the Company issued 687,180 original issue shares of common stock as a result of stock option exercises. The Company also issued 2,100 original issue shares of common stock to the seven non-employee directors of the Company who receive compensation under the Company’s Retainer Policy for Non-Employee Directors, as partial consideration for the directors’ services during the three months ended December 31, 2008. Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the three months ended December 31, 2008, 297,108 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
Shareholder Rights Plan. In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). The Plan has been amended six times since it was adopted and is now embodied in an Amended and Restated Rights Agreement effective December 4, 2008, a copy of which was included as an exhibit to the Form 8-K filed by the Company on December 4, 2008.
     Pursuant to the Plan, holders of the Company’s common stock have one right (Right) for each of their shares. Each Right is initially evidenced by the Company’s common stock certificates representing the outstanding shares of common stock.
     The Rights have anti-takeover effects because they will cause substantial dilution of the Company’s common stock if a person attempts to acquire the Company on terms not approved by the Board of Directors (an Acquiring Person).
     The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date Rights that are owned by an Acquiring Person will be null and void. At any time following a Distribution Date, each holder of a Right may exercise its right to receive, upon payment of an amount calculated under the Rights Agreement, common stock of the Company (or, under certain circumstances, other securities or assets of the Company) having a value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.
     A Distribution Date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company’s common stock or other voting stock (including Synthetic Long Positions as defined in the Plan) having 10% or more of the total voting power of the Company’s common stock and other voting stock and (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquiring, or obtaining the right to acquire, beneficial ownership of the Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s common stock and other voting stock.
     In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company’s stock as described above, each holder of a Right will have the right to exercise its Rights to receive, upon exercise of the right, common stock of the acquiring company having a value equal to two times the amount paid to exercise the right. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company’s assets or earning power are sold or transferred.

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Item 1. Financial Statements (Cont.)
     At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company may redeem the Rights in whole, but not in part, at a price of $0.005 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company’s full Board of Directors. Also, at any time following the Distribution Date, 75% of the Company’s full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments.
 
     Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2018, unless earlier than that date, they are exchanged or redeemed or the Plan is amended to extend the expiration date.
Note 5 — Commitments and Contingencies
Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.
     As disclosed in Note H of the Company’s 2008 Form 10-K, the Company has agreed with the NYDEC to remediate a former manufactured gas plant site located in New York. The Company has submitted a Remedial Design/Remedial Action work plan to the NYDEC and has recorded an estimated minimum liability for remediation of this site of $16.4 million.
     At December 31, 2008, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $19.3 million to $23.5 million. The minimum estimated liability of $19.3 million, which includes the $16.4 million discussed above, has been recorded on the Consolidated Balance Sheet at December 31, 2008. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet.
     The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.
Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, or have a material adverse effect on the financial condition of the Company.
Note 6 – Business Segment Information
     In the Company’s 2008 Form 10-K, the Company reported financial results for five business segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing and Timber. The division of the Company’s operations into the reported segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors. During the quarter ended December 31, 2008, management made the decision to eliminate the Timber segment as a reportable segment based on the fact that the Timber operations do not meet any of the quantitative thresholds specified by SFAS 131. Furthermore, from a qualitative standpoint, management’s focus has changed regarding the Timber operations. While the Timber segment will continue to harvest hardwood

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

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Item 1. Financial Statements (Cont.)
Note 7 — Intangible Assets
     The components of the Company’s intangible assets were as follows (in thousands):
                                 
                            At September 30,  
    At December 31, 2008     2008  
    Gross             Net     Net  
    Carrying     Accumulated     Carrying     Carrying  
    Amount     Amortization     Amount     Amount  
Intangible Assets Subject to Amortization:
                               
Long-Term Transportation Contracts
  $ 8,580     $ (6,213 )   $ 2,367     $ 2,522  
Long-Term Gas Purchase Contracts
    31,864       (8,611 )     23,253       23,652  
           
 
  $ 40,444     $ (14,824 )   $ 25,620     $ 26,174  
           
 
                               
Aggregate Amortization Expense:
                               
(Thousands)
                               
Three Months Ended December 31, 2008
  $ 554                          
Three Months Ended December 31, 2007
  $ 666                          
     The gross carrying amount of intangible assets subject to amortization at December 31, 2008 remained unchanged from September 30, 2008. The only activity with regard to intangible assets subject to amortization was amortization expense as shown in the table above. Amortization expense for the long-term transportation contracts is estimated to be $0.3 million for the remainder of 2009 and $0.4 million annually for 2010, 2011, 2012 and 2013. Amortization expense for the long-term gas purchase contracts is estimated to be $1.2 million for the remainder of 2009 and $1.6 million annually for 2010, 2011, 2012 and 2013.
Note 8 – Retirement Plan and Other Post-Retirement Benefits
     Components of Net Periodic Benefit Cost (in thousands):
Three months ended December 31,
                                 
    Retirement Plan   Other Post-Retirement Benefits
    2008   2007   2008   2007
Service Cost
  $ 2,728     $ 3,150     $ 950     $ 1,276  
Interest Cost
    11,709       11,237       6,875       6,771  
Expected Return on Plan Assets
    (14,489 )     (13,750 )     (7,904 )     (8,429 )
Amortization of Prior Service Cost
    183       202       (268 )     1  
Amortization of Transition Amount
                566       1,782  
Amortization of Losses
    1,419       2,766       2,318       732  
Net Amortization and Deferral For Regulatory Purposes (Including Volumetric Adjustments) (1)
    3,240       1,100       4,339       7,212  
         
 
                               
Net Periodic Benefit Cost
  $ 4,790     $ 4,705     $ 6,876     $ 9,345  
         
 
(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 three months ended December 31, 2008, the Company contributed $7.0 million to its retirement plan and $6.6 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2009, the Company expects to contribute in the range of $8.0 million to $13.0 million to its retirement plan. As a result of the recent downturn in the stock markets and general economic conditions, it is likely that the Company will have to fund larger amounts to the retirement plan subsequent to fiscal 2009 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2009, the Company expects to contribute in the range of $18.0 million to $23.0 million to its VEBA trusts and 401(h) accounts.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
     In the Company’s 2008 Form 10-K, the Company reported financial results for five business segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing and Timber. During the quarter ended December 31, 2008, management made the decision to eliminate the Timber segment as a reportable segment based on the fact that the Timber operations do not meet any of the quantitative thresholds specified by SFAS 131. Furthermore, from a qualitative standpoint, management’s focus has changed regarding the Timber operations. While the Timber segment will continue to harvest hardwood timber and process lumber products that are used in high-end furniture, cabinetry and flooring, management no longer considers the Timber operations to be integral to the overall operations of the Company. As a result of this change in focus and the fact that the Timber operations cannot be aggregated into one of the other four reportable business segments, the Timber operations have been included in the All Other category in the disclosures that follow. Prior year segment information shown below has been restated to reflect this change in presentation.
          The Company experienced a loss of $42.7 million for the quarter ended December 31, 2008 compared to earnings of $70.6 million for the quarter ended December 31, 2007. The loss for the quarter ended December 31, 2008 was driven largely by an impairment charge of $182.8 million ($108.2 million after tax) recorded in the Exploration and Production segment. In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Such costs are subject to a quarterly ceiling test prescribed by SEC Regulation S-X Rule 4-10 that determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. At December 31, 2008, due to significant declines in crude oil and natural gas commodity prices (Cushing, Oklahoma West Texas Intermediate oil reported spot price of $44.60 per Bbl at December 31, 2008 versus a reported price of $100.70 per Bbl at September 30, 2008; Henry Hub natural gas reported spot price of $5.63 per MMBtu at December 31, 2008 versus a reported price of $7.12 per MMBtu at September 30, 2008), the book value of the Company’s oil and gas properties exceeded the ceiling, resulting in the impairment charge mentioned above. (Note — Because actual pricing of the Company’s various producing properties varies depending on their location, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Cushing oil and Henry Hub prices, which are only indicative.) If natural gas prices used in the ceiling test calculation at December 31, 2008 had been $1 per MMBtu lower, the Company would have recorded an additional impairment charge of approximately $51 million (after tax). If crude oil prices used in the ceiling test calculation at December 31, 2008 had been $5 per Bbl lower, the Company would have recorded an additional impairment charge of approximately $53 million (after tax). If both natural gas and crude oil prices used in the ceiling test calculation at December 31, 2008 were lower by $1 per MMBtu and $5 per Bbl, respectively, the Company would have recorded an additional impairment charge of approximately $104 million (after tax). These calculated impairment charges are based solely on price changes and do not take into account any other changes to the ceiling test calculation.
     Despite the loss for the quarter ended December 31, 2008, the Company’s balance sheet remains strong with a capitalization structure of 58% equity and 42% debt at December 31, 2008. The Company also continues to have strong liquidity despite the generally reported problems in the credit markets. The Company has been able to borrow short-term funds under its credit lines and through the commercial paper market to fund working capital needs throughout the quarter. The Company maintains a number of individual uncommitted or discretionary lines of credit with financial institutions for general corporate purposes. These credit lines, which aggregate to $420.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed, or replaced by similar lines. At December 31, 2008, the Company had borrowed $66.0 million under its lines of credit. The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million, which commitment extends through September 30, 2010. At December 31, 2008, the Company did not have any borrowings under its committed credit facility.
CRITICAL ACCOUNTING ESTIMATES
     For a complete discussion of critical accounting estimates, refer to “Critical Accounting Estimates” in Item 7 of the Company’s 2008 Form 10-K. There have been no material changes to that disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K.

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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.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
RESULTS OF OPERATIONS
Earnings
     The Company experienced a loss of $42.7 million for the quarter ended December 31, 2008 compared to earnings of $70.6 million for the quarter ended December 31, 2007. The decrease in earnings of $113.3 million is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the Energy Marketing segment, as well as a loss in the All Other category, also contributed to the decrease. Higher earnings in the Utility and Pipeline and Storage segments and the Corporate category slightly offset these decreases. The Company’s loss for the quarter ended December 31, 2008, includes a non-cash $182.8 million impairment charge ($108.2 million after tax) for the Exploration and Production segment’s oil and gas producing properties under the full cost method of accounting using crude oil and natural gas commodity pricing at December 31, 2008, which were lower than the pricing at September 30, 2008, the last ceiling test measurement date. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.
Earnings (Loss) by Segment
Three Months Ended December 31 (Thousands)
                         
                    Increase  
    2008     2007     (Decrease)  
Utility
  $ 22,088     $ 20,217     $ 1,871  
Pipeline and Storage
    17,176       12,778       4,398  
Exploration and Production
    (83,557 )     34,022       (117,579 )
Energy Marketing
    599       954       (355 )
 
                 
Total Reportable Segments
    (43,694 )     67,971       (111,665 )
All Other
    (868 )     2,736       (3,604 )
Corporate
    1,884       (103 )     1,987  
 
                 
Total Consolidated
  $ (42,678 )   $ 70,604     $ (113,282 )
 
                 
Utility
Utility Operating Revenues
Three Months Ended December 31 (Thousands)
                         
                    Increase  
    2008     2007     (Decrease)  
Retail Sales Revenues:
                       
Residential
  $ 272,418     $ 246,797     $ 25,621  
Commercial
    41,333       38,033       3,300  
Industrial
    2,106       1,651       455  
 
                 
 
    315,857       286,481       29,376  
 
                 
Transportation
    32,011       33,424       (1,413 )
Off-System Sales
    3,732       8,213       (4,481 )
Other
    2,590       3,306       (716 )
 
                 
 
  $ 354,190     $ 331,424     $ 22,766  
 
                 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Utility Throughput
Three Months Ended December 31 (MMcf)
                         
                    Increase
    2008   2007   (Decrease)
Retail Sales:
                       
Residential
    18,166       17,127       1,039  
Commercial
    2,911       2,877       34  
Industrial
    143       123       20  
 
                       
 
    21,220       20,127       1,093  
Transportation
    17,473       17,827       (354 )
Off-System Sales
    512       1,031       (519 )
 
                       
 
    39,205       38,985       220  
 
                       
Degree Days
Three Months Ended December 31
                                         
                            Percent
                            Colder (Warmer) Than
    Normal   2008   2007   Normal   Prior Year
Buffalo
    2,260       2,313       2,094       2.3       10.5  
Erie
    2,081       2,067       1,871       (0.7 )     10.5  
2008 Compared with 2007
     Operating revenues for the Utility segment increased $22.8 million for the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. This increase largely resulted from a $29.4 million increase in retail gas revenues coupled with a $4.5 million decrease in off-system sales revenues and a $1.4 million decrease in transportation revenues.
     The increase in retail gas sales revenues for the Utility segment was primarily due to higher retail sales volumes, as shown in the table above. The volume increase, most notably in the residential category, is primarily the result of weather that was 10.5 percent colder than the prior year in both operating jurisdictions.
     In the New York jurisdiction, the NYPSC issued an order providing for an annual rate increase of $1.8 million beginning December 28, 2007. As part of this rate order, a rate design change was adopted that shifts a greater amount of cost recovery into the minimum bill amount, thus spreading the recovery of such costs more evenly throughout the year. As a result of this rate order, retail and transportation revenues for the quarter ended December 31, 2008 were $2.2 million lower than revenues for the quarter ended December 31, 2007.
     Total off-system sales revenues for the quarters ended December 31, 2008 and December 31, 2007 amounted to $3.7 million and $8.2 million, respectively. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was no material impact to margins for the quarters ended December 31, 2008 and 2007. On October 16, 2008, the FERC issued Order No. 717 (“Final Rule”).  The Final Rule regarding the standards of conduct was effective November 26, 2008.  The Final Rule seemingly holds that a local distribution company making off-system sales on unaffiliated pipelines would engage in “marketing” that would require compliance with the FERC’s standards of conduct.  Accordingly, pending clarification from the FERC of this issue, as of November 1, 2008, Distribution Corporation ceased off-system sales activities.
     The Utility segment’s earnings for the quarter ended December 31, 2008 were $22.1 million, an increase of $1.9 million when compared with earnings of $20.2 million for the quarter ended December 31, 2007. In the Pennsylvania jurisdiction, earnings increased $0.6 million. The major factors contributing to this increase were the positive earnings impact associated with colder weather ($0.8 million), a slight increase in usage per account ($0.2 million), and lower interest expense ($0.2 million), offset by higher operating expenses of $0.6 million (primarily bad debt expense due to higher gas costs and the possible impact current economic conditions may have on customers). In the New York jurisdiction, earnings increased $1.3 million. This increase was primarily the result of $1.9 million in lower operating expenses (primarily due to a decrease in other post-retirement benefit costs) and lower interest expense ($0.6 million). These increases were partly offset by the earnings impact of the December 28, 2007 rate order discussed above ($1.4 million). The

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
phrase “usage per account” in this paragraph refers to the average gas consumption per customer account after factoring out any impact that weather may have had on consumption. The decrease in other post-retirement benefit costs discussed above stems from the NYPSC rate order that became effective December 28, 2007 whereby the rate allowance for post-retirement benefit costs was reduced given projected reductions in the other post-retirement benefit obligation as a result of an increase in the discount rate from 5% to 6.25% during 2006. The decreases to interest expense primarily reflect lower borrowings and slightly lower rates.
     The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. For the quarter ended December 31, 2008, the WNC did not have a significant impact on earnings as the weather was close to normal. For the quarter ended December 31, 2007, the WNC preserved $1.1 million of earnings, as weather was warmer than normal for the period. In periods of colder than normal weather, the WNC benefits Distribution Corporation’s New York customers.
Pipeline and Storage
Pipeline and Storage Operating Revenues
Three Months Ended December 31 (Thousands)
                         
    2008   2007   Increase
Firm Transportation
  $ 33,105     $ 31,406     $ 1,699  
Interruptible Transportation
    1,103       991       112  
 
                       
 
    34,208       32,397       1,811  
 
                       
Firm Storage Service
    16,686       16,621       65  
Other
    5,210       3,213       1,997  
 
                       
 
  $ 56,104     $ 52,231     $ 3,873  
 
                       
Pipeline and Storage Throughput
Three Months Ended December 31 (MMcf)
                         
    2008   2007   Increase
Firm Transportation
    110,315       92,883       17,432  
Interruptible Transportation
    1,792       1,083       709  
 
                       
 
    112,107       93,966       18,141  
 
                       
2008 Compared with 2007
     Operating revenues for the Pipeline and Storage segment increased $3.9 million in the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. This increase consisted of a $1.8 million increase in firm and interruptible transportation revenues. The Pipeline and Storage segment was able to obtain multiple new contracts for firm transportation service in the quarter ended December 31, 2008 which resulted in higher reservation, commodity and surcharge, and overrun revenues. In addition, there were increased efficiency gas revenues ($2.0 million) reported as part of other revenues in the table above. Under Supply Corporation’s tariff with shippers, Supply Corporation is allowed to retain a set percentage of shipper-supplied gas to cover compressor fuel costs and other operational purposes. To the extent that Supply Corporation does not need all of the gas to cover such operational needs, it is allowed to keep the excess gas as inventory. That inventory is later sold to customers. The excess gas that is retained as inventory represents efficiency gas revenue to Supply Corporation. During the quarter ended December 31, 2008, Supply Corporation retained a higher volume of gas than was retained during the quarter ended December 31, 2007.
     The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2008 were $17.2 million, an increase of $4.4 million when compared with earnings of $12.8 million for the quarter ended December 31, 2007. The increase is largely attributable to higher transportation revenues ($1.2 million) due to the addition of new contracts for firm transportation service and higher efficiency gas revenues ($1.3 million), as discussed above. In addition, there was an increase in allowance for funds

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
used during construction of $2.1 million. The increase in allowance for funds used during construction is a result of the construction of the Empire Connector, which was completed and placed in service on December 10, 2008. Construction of the Empire Connector began in September 2007 so the calculated allowance for funds used during construction was relatively small during the quarter ended December 31, 2007. With much more significant construction work in progress balances during the quarter ended December 31, 2008, the calculated allowance for funds used during construction was much higher. These earnings increases were partially offset by higher interest expense of $0.4 million. The increase in interest expense was due to higher borrowings.
Exploration and Production
Exploration and Production Operating Revenues
Three Months Ended December 31 (Thousands)
                         
                    Increase  
    2008     2007     (Decrease)  
Gas (after Hedging)
  $ 41,093     $ 45,557     $ (4,464 )
Oil (after Hedging)
    53,071       59,643       (6,572 )
Gas Processing Plant
    7,328       11,075       (3,747 )
Other
    417       (1,309 )     1,726  
Intrasegment Elimination (1)
    (5,197 )     (7,011 )     1,814  
 
                 
 
  $ 96,712     $ 107,955     $ (11,243 )
 
                 
 
(1)   Represents the elimination of certain West Coast gas production revenue included in “Gas (after Hedging)” 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.
Production Volumes
Three Months Ended December 31
                         
                    Increase
    2008   2007   (Decrease)
Gas Production (MMcf)
                       
Gulf Coast
    1,746       2,826       (1,080 )
West Coast
    1,022       1,027       (5 )
Appalachia
    1,851       1,917       (66 )
 
                       
Total Production
    4,619       5,770       (1,151 )
 
                       
 
                       
Oil Production (Mbbl)
                       
Gulf Coast
    128       156       (28 )
West Coast
    682       629       53  
Appalachia
    15       37       (22 )
 
                       
Total Production
    825       822       3  
 
                       
Average Prices
Three Months Ended December 31
                         
                    Increase  
    2008     2007     (Decrease)  
Average Gas Price/Mcf
                       
Gulf Coast
  $ 7.04     $ 7.14     $ (0.10 )
West Coast
  $ 5.02     $ 6.77     $ (1.75 )
Appalachia
  $ 8.53     $ 7.45     $ 1.08  
Weighted Average
  $ 7.19     $ 7.18     $ 0.01  
Weighted Average After Hedging
  $ 8.90     $ 7.90     $ 1.00  
 
                       
Average Oil Price/Bbl
                       
Gulf Coast
  $ 56.19     $ 89.84     $ (33.65 )
West Coast
  $ 48.01     $ 81.80     $ (33.79 )
Appalachia
  $ 69.06     $ 84.12     $ (15.06 )
Weighted Average
  $ 49.66     $ 83.43     $ (33.77 )
Weighted Average After Hedging
  $ 64.34     $ 72.59     $ (8.25 )

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
2008 Compared with 2007
     Operating revenues for the Exploration and Production segment decreased $11.2 million for the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. Oil production revenue after hedging decreased $6.6 million. A decrease in the weighted average price of oil after hedging ($8.25 per Bbl) was the primary cause, as a production increase in the West Coast offset decreases in Gulf Coast and Appalachian production, keeping overall oil production flat. Gas production revenue after hedging decreased $4.5 million. A decrease in gas production (1,151 MMcf) more than offset an increase in the weighted average price of gas after hedging ($1.00 per Mcf). The decrease in gas production occurred primarily in this segment’s Gulf Coast region (1,080 MMcf), which is mainly the result of lingering shut-ins caused by Hurricane Ike in September 2008. While Seneca’s properties sustained only superficial damage from the hurricanes, two significant producing properties remained shut-in for the quarter ended December 31, 2008 due to repair work on third party pipelines and onshore processing facilities. All pre-hurricane production is expected to be back on line by the end of the quarter ended March 31, 2009. Appalachian production was slightly lower due to compressor down time and pipeline constraints.
     The Exploration and Production segment’s loss for the quarter ended December 31, 2008 was $83.6 million compared with earnings of $34.0 million for the quarter ended December 31, 2007, a decrease of $117.6 million. The decrease in earnings is primarily the result of an impairment charge of $108.2 million, as discussed above. Also, lower natural gas production and lower crude oil prices decreased earnings by $5.9 million, and $4.4 million, respectively. Higher natural gas prices slightly offset these decreases by $3.0 million. Higher general and administrative and other operating expenses of $1.7 million and higher lease operating expenses of $1.3 million also contributed to the decrease in earnings. Lower depletion expense of $0.6 million made a small contribution to earnings. The increase in general and administrative and other operating expenses is mainly due to a bad debt charge related to a customer’s bankruptcy filing combined with higher personnel costs in the Appalachian region. The increase in lease operating expenses is primarily due to higher production taxes related to increased production from the High Island 24L and 23L fields in the Gulf Coast region, higher property taxes and increased well repair costs associated with higher than normal activity in the West Coast region, and an increase in the number of producing properties in the Appalachian region.
Energy Marketing
Energy Marketing Operating Revenues
Three Months Ended December 31 (Thousands)
                         
    2008     2007     Increase  
Natural Gas (after Hedging)
  $ 114,984     $ 86,735     $ 28,249  
Other
    23       (16 )     39  
 
                 
 
  $ 115,007     $ 86,719     $ 28,288  
 
                 
Energy Marketing Volumes
Three Months Ended December 31
                         
    2008   2007   Increase
Natural Gas – (MMcf)
    13,136       10,841       2,295  
2008 Compared with 2007
     Operating revenues for the Energy Marketing segment increased $28.3 million for the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. The increase primarily reflects an increase in volumes, largely attributable to sales transactions undertaken to offset certain basis risks that the Energy Marketing segment was exposed to under certain commodity purchase contracts. These offsetting transactions had the effect of increasing revenue and volumes sold with minimal impact to earnings.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
     The Energy Marketing segment’s earnings for the quarter ended December 31, 2008 were $0.6 million, a decrease of $0.4 million when compared with earnings of $1.0 million for the quarter ended December 31, 2007. Despite colder weather, earnings decreased primarily due to lower margins.
Corporate and All Other
2008 Compared with 2007
     Corporate and All Other operations recorded earnings of $1.0 million for the quarter ended December 31, 2008, a decrease of $1.6 million when compared to the earnings of $2.6 million recorded for the quarter ended December 31, 2007. The decrease in earnings was due to lower margins from log and lumber sales ($1.3 million), lower interest income ($1.2 million), lower equity method income from Horizon Power’s investments in unconsolidated subsidiaries ($0.8 million), and higher interest expense ($0.5 million). In addition, during the quarter ended December 31, 2008, ESNE, an unconsolidated subsidiary of Horizon Power, recorded an impairment charge of $3.6 million. Horizon Power’s 50% share of the impairment was $1.8 million ($1.1 million on an after tax basis). ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. The impairment was driven by a significant decrease in “run time” for the plant given the economic downturn and the resulting decrease in demand for electric power. The decreases were partially offset by lower operating expenses ($1.1 million) and a gain resulting from a death benefit on corporate-owned life insurance policies held by the Company ($2.3 million).
Interest Income
     Interest income was $1.2 million lower in the quarter ended December 31, 2008 as compared to the quarter ended December 31, 2007. Interest income in the Exploration and Production segment was $1.6 million lower during the quarter ended December 31, 2008 as compared to the quarter ended December 31, 2007 as a result of lower interest rates and lower average temporary cash investment balances.
Other Income
     Other Income increased $4.1 million for the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. This increase is attributable to an increase in the allowance for funds used during construction of $2.1 million in the Pipeline and Storage segment associated with the Empire Connector project, as well as a death benefit gain on life insurance proceeds of $2.3 million recognized in the Corporate category.
Interest Expense on Long-Term Debt
     Interest on long-term debt increased $1.8 million for the quarter ended December 31, 2008 as compared with the quarter ended December 31, 2007. This increase can be attributed to a higher average amount of long-term debt outstanding. In April 2008, the Company issued $300 million of 6.5% senior, unsecured notes due in April 2018. This increase was partially offset by the repayment of $200 million of 6.303% medium-term notes that matured on May 27, 2008.
CAPITAL RESOURCES AND LIQUIDITY
     The Company’s primary source of cash during the three-month periods ended December 31, 2008 and December 31, 2007 consisted of cash provided by operating activities. This source of cash was supplemented by issuances of new shares of common stock as a result of stock option exercises and by short-term borrowings (for the quarter ended December 31, 2008). During the three months ended December 31, 2008 and December 31, 2007, the common stock used to fulfill the requirements of the Company’s 401(k) plans and Direct Stock Purchase and Dividend Reinvestment Plan was obtained via open market purchases.

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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 and futures contracts in an attempt to manage this energy commodity price risk.
     Net cash provided by operating activities totaled $100.1 million for the three months ended December 31, 2008, an increase of $24.8 million when compared with the $75.3 million provided by operating activities for the three months ended December 31, 2007. The increase is primarily due to higher cash provided by operating activities in the Exploration and Production segment. Despite lower crude oil prices and lower natural gas production, this segment experienced an increase in cash provided by operating activities due to the receipt of hedging collateral deposits from some of the counterparties to its derivative financial instruments.
Investing Cash Flow
Expenditures for Long-Lived Assets
     The Company’s expenditures for long-lived assets totaled $119.2 million for the three months ended 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.)
Total Expenditures for Long-Lived Assets
Three Months Ended December 31,
(Millions)
                         
                    Increase
    2008   2007   (Decrease)
 
Utility
  $ 13.6     $ 12.7     $ 0.9  
Pipeline and Storage (1)
    19.5       25.3       (5.8 )
Exploration and Production (2)
    86.4       30.7       55.7  
All Other
          1.0       (1.0 )
Eliminations (3)
    (0.3 )           (0.3 )
 
 
  $ 119.2     $ 69.7     $ 49.5  
 
 
(1)   Amount for the three months ended December 31, 2008 excludes $16.8 million of capital expenditures related to the Empire Connector 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 December 31, 2008 since it represents a non-cash investing activity at that date.
 
(3)   Represents $0.3 million of capital expenditures in the Pipeline and Storage segment for the purchase of pipeline facilities from the Appalachian region of the Exploration and Production segment during the quarter ended December 31, 2008.
Utility
     The majority of the Utility capital expenditures for the three months ended 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 three months ended December 31, 2008 and December 31, 2007 were related to the Empire Connector project, which was placed into service on December 10, 2008.
     As of December 31, 2008, the Company had incurred approximately $181.7 million in costs related to this project. Of this amount, $17.0 million and $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 quarters ended December 31, 2008 and 2007, respectively.
     In light of the growing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus Shale producing area — Supply Corporation is actively pursuing development of its Appalachian Lateral pipeline project. The Appalachian Lateral is expected to be routed through areas in Pennsylvania where producers are actively drilling and are seeking market access for their newly discovered reserves. The Appalachian Lateral will complement Supply Corporation’s original West to East (“W2E”) project, which was designed to transport Rockies gas supply from Clarington, Ohio to the Ellisburg/Leidy/Corning area and includes the Tuscarora-to-Corning facilities previously referred to as the Tuscarora Extension. The Appalachian Lateral will transport gas supply from Pennsylvania’s producing area to the Overbeck area of Supply Corporation’s existing system, where the facilities associated with the W2E project will move the gas to eastern market points, including Leidy, and to interconnections with Millennium and Empire at Corning. Engineering analyses to evaluate routing options and the development of an updated project cost estimate are under way.
     In conjunction with the 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.)
capacity with incremental withdrawal deliverability of up to 121 MDth of natural gas per day, with service commencing as early as 2011. Supply Corporation expects that the availability of this incremental storage capacity will complement the Appalachian Lateral/W2E pipeline transportation projects and help balance the increasing flow of Appalachian and Rockies gas supply into the western Pennsylvania area, and the growing demand for gas on the east coast.
     The timeline associated with Supply Corporation’s pipeline and storage projects depends on market development. The capital cost of the Appalachian Lateral/W2E transportation projects is estimated to be in the range of $750 million to $1 billion, and is expected to be financed by a combination of debt and equity. As of December 31, 2008, $0.2 million has been spent to study the Appalachian Lateral/W2E transportation projects, and approximately $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.
Exploration and Production
     The Exploration and Production segment capital expenditures for the three months ended December 31, 2008 were primarily well drilling and completion expenditures and included approximately $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, $10.4 million for the West Coast region and $64.1 million for the Appalachian region. These amounts included approximately $10.2 million spent to develop proved undeveloped reserves. 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 Exploration and Production segment capital expenditures for the three months ended December 31, 2007 included approximately $6.8 million for the Gulf Coast region, substantially all of which was for the off-shore program in the Gulf of Mexico, $12.8 million for the West Coast region and $11.1 million for the Appalachian region. These amounts included $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.
Financing Cash Flow
     Consolidated short-term debt increased $66.0 million during the three months ended December 31, 2008. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, 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 $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 totaling $300.0 million, which commitment extends through September 30, 2010.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
     Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September 30, 2010. At December 31, 2008, the Company’s debt to capitalization ratio (as calculated under the facility) was .42. The constraints specified in the committed credit facility would permit an additional $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 December 31, 2008, the Company would have been permitted to issue up to a maximum of $0.9 billion in additional long-term unsecured indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands. 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 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 pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
     The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fail to make a payment when due of any principal or interest on any other indebtedness aggregating $20.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $20.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of December 31, 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 Company was 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. In January 2009, the SEC declared the registration statement, as amended, effective, and the Company commenced the exchange offer. The Company expects the exchange offer to expire on 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 $30.5 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters and other items and are accounted for as operating leases. The Company’s unconsolidated subsidiaries, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $2.8 million. The Company has guaranteed 50% or $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 2008 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.
Rate and Regulatory Matters
Utility Operation
     Base rate adjustments in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities.
New York Jurisdiction
     On January 29, 2007, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by $52.0 million. Following standard procedure, the NYPSC suspended the proposed tariff amendments to enable its staff and intervenors to conduct a routine investigation and hold hearings. Distribution Corporation explained in the filing that its request for rate relief was necessitated by decreased revenues resulting from customer conservation efforts and increased customer uncollectibles, among other things. The rate filing also included a proposal for an 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.
     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 included an increase in annual revenues of $14.3 million to non-gas revenues, an agreement not to file a rate case until January 28, 2008 at the earliest and an early implementation date. The Settlement was approved by the PaPUC at its meeting on November 30, 2006, and the new rates became effective January 1, 2007.
Pipeline and Storage
     Supply Corporation currently does not have a rate case on file with the FERC. The rate settlement approved by the FERC on February 9, 2007 requires Supply Corporation to make a general rate filing to be effective December 1, 2011, and bars Supply Corporation from making a general rate filing before then, with some exceptions specified in the settlement.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of 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 built the Empire Connector 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 required construction of this project. The new facilities were placed into service on December 10, 2008. As of that date, Empire became an interstate pipeline subject to FERC regulation. The order described above 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.
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 has agreed with the NYDEC to remediate a former manufactured gas plant site located in New York. The Company has submitted a Remedial Design/Remedial Action work plan to the NYDEC and has recorded an estimated minimum liability for remediation of this site of $16.4 million.
     At December 31, 2008, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $19.3 million to $23.5 million. The minimum estimated liability of $19.3 million, which includes the $16.4 million discussed above, has been recorded on the Consolidated Balance Sheet at December 31, 2008. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet.
     The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations 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 for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis. The same FASB Staff Position delays the effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value on a recurring basis, until the Company’s first quarter of fiscal 2010. For further discussion of the impact of the adoption of SFAS 157 for financial assets and financial liabilities, refer to 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.)
     In September 2006, the FASB issued SFAS 158, an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R. SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be fully adopted by the Company by the end of fiscal 2009. The Company has historically measured its plan assets and benefit obligations using a June 30th measurement date. In anticipation of changing to a September 30th measurement date, the Company will be recording fifteen months of pension and other post-retirement benefit costs during fiscal 2009. In accordance with the provisions of SFAS 158, these costs have been calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $5.1 million and have been recorded by the Company during the quarter ended December 31, 2008 as a $3.8 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $1.3 million ($0.8 million after tax) adjustment to earnings reinvested in the business. For further discussion of the impact of adopting the measurement date provisions of SFAS 158, refer to 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 at fair value that are not otherwise required to be measured at fair value under GAAP. A company that elects the fair value option for an eligible item will be required to recognize in current earnings any changes in that item’s fair value in reporting periods subsequent to the date of adoption. SFAS 159 became effective for the Company on October 1, 2008. The Company did not elect the fair value measurement option for any of its financial instruments other than those that are already being measured at fair value.
     In December 2007, the FASB issued SFAS 141R. 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 the notes to the consolidated financial statements.
     On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and gas reserves to a 12-month average of the first day of the month price for each month within the reporting period. The final rule also permits

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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 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 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” 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 global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;
 
  4.   The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
 
  5.   Economic disruptions or uninsured losses resulting from terrorist activities, acts of war, major accidents, fires, hurricanes, other severe weather, pest infestation or other natural disasters;
 
  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;

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
  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;
 
  9.    Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
 
  10.   Uncertainty of oil and gas reserve estimates;
 
  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;
 
  12.   Significant changes from expectations in the Company’s actual production levels for natural gas or oil;
 
  13.   Changes in the availability and/or price of derivative financial instruments;
 
  14.   Changes in the price differentials between various types of oil;
 
  15.   Inability to obtain new customers or retain existing ones;
 
  16.   Significant changes in competitive factors affecting the Company;
 
  17.   Changes in laws and regulations to which the Company is subject, including tax, environmental, safety and employment laws and regulations;
 
  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;
 
  19.   Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;
 
  20.   Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs or plans;
 
  21.   The nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits;
 
  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;
 
  23.   Significant changes in tax rates or policies or in rates of inflation or interest;
 
  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;
 
  25.   Changes in accounting principles or the application of such principles to the Company;
 
  26.   The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
 
  27.   Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or
 
  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 December 31, 2008.
Changes in Internal Control Over Financial Reporting
     There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 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
     For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 5 — Commitments and Contingencies, and Part I, Item 2 — MD&A of this report under the heading “Other Matters — Environmental Matters.”
     In addition to these matters, 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 2008 Form 10-K have not materially changed other than as set forth below. The risk factors presented below supersede the risk factors having the same captions in the 2008 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2008 Form 10-K.

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Item 1A. Risk Factors (Cont.)
National Fuel may be adversely affected by economic 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 October 1, 2008, the Company issued a total of 2,100 unregistered shares of Company common stock to the seven non-employee directors of the Company then 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 such directors’ services during the quarter ended December 31, 2008. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as transactions not involving a public offering.
Issuer Purchases of Equity Securities
                                 
                    Total Number of   Maximum Number
                    Shares Purchased   of Shares that May
                    as Part of Publicly   Yet Be Purchased
    Total Number of           Announced Share   Under Share
    Shares   Average Price   Repurchase Plans   Repurchase Plans
Period   Purchased (a)   Paid per Share   or Programs   or Programs (b)
Oct. 1-31, 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. During the quarter ended December 31, 2008, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 331,278 shares purchased other than through a publicly announced share repurchase program, 34,170 were purchased for the Company’s 401(k) plans and 297,108 were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock.
 
(b)   In December 2005, the Company’s Board of Directors authorized the repurchase of up to eight million shares of the Company’s common stock. The Company completed the repurchase of the eight million shares during 2008. In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares of the Company’s common stock. The Company had, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. However, such repurchases may be made in the future if conditions improve. Such repurchases would be made in the open market or through private transactions.
Item 6. Exhibits
     (a) Exhibits
     
Exhibit    
Number   Description of Exhibit
 
   
  Amended and Restated Rights Agreement, dated as of December 4, 2008, between National Fuel Gas Company and The Bank of New York (incorporated herein by reference to Exhibit 4.1, Form 8-K dated December 4, 2008).
 
   
10.1
  Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program.
 
   
10.2
  Form of Stock Appreciation Right Award Notice under the National Fuel Gas Company 1997 Award and Option Plan.

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Item 6. Exhibits (Concl.)
     
Exhibit    
Number   Description of Exhibit
10.3
  Description 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.
 
   
12
  Statements 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 December 31, 2008 and 2007.
 
  Incorporated herein by reference as indicated.

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Table of Contents

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

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