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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
 
  þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Fiscal Year Ended September 30, 2008
 
  o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Transition Period from           to          
 
Commission File Number 1-3880
 
National Fuel Gas Company
(Exact name of registrant as specified in its charter)
 
     
New Jersey   13-1086010
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
6363 Main Street
Williamsville, New York
(Address of principal executive offices)
  14221
(Zip Code)
 
(716) 857-7000
Registrant’s telephone number, including area code
 
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
    Name of
    Each Exchange
    on Which
Title of Each Class
 
Registered
 
Common Stock, $1 Par Value, and
Common Stock Purchase Rights
  New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  þ      No  o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act.  Yes  o      No  þ
 
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   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 Act).  Yes  o      No  þ
 
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $3,768,755,000 as of March 31, 2008.
 
Common Stock, $1 Par Value, outstanding as of October 31, 2008: 79,124,644 shares.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the registrant’s definitive Proxy Statement for its 2009 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.
 


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Glossary of Terms
 
Frequently used abbreviations, acronyms, or terms used in this report:
 
   National Fuel Gas Companies
 
Company The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
 
Data-Track Data-Track Account Services, Inc.
 
Distribution Corporation National Fuel Gas Distribution Corporation
 
Empire Empire State Pipeline
 
ESNE Energy Systems North East, LLC
 
Highland Highland Forest Resources, Inc.
 
Horizon Horizon Energy Development, Inc.
 
Horizon B.V. Horizon Energy Development B.V.
 
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
 
Toro Toro Partners, LP
 
U.E. United Energy, a.s.
 
   Regulatory Agencies
 
EPA United States Environmental Protection Agency
 
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
 
APB 18 Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock
 
APB 25 Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees
 
ARB 51 Accounting Research Bulletin No. 51, Consolidated Financial Statements
 
Bbl Barrel (of oil)
 
Bcf Billion cubic feet (of natural gas)
 
Bcfe (or Mcfe) — represents Bcf (or Mcf) Equivalent The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. National Fuel uses a conversion formula of 1 barrel of oil = 6 Mcf 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.
 
Development well A well drilled to a known producing formation in a previously discovered field.
 
Dth Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
 
Exchange Act Securities Exchange Act of 1934, as amended
 
Expenditures for long-lived assets Includes capital expenditures, stock acquisitions and/or investments in partnerships.
 
Exploitation Development of a field, including the location, drilling, completion and equipment of wells necessary to produce the commercially recoverable oil and gas in the field.
 
Exploration costs Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
 
Exploratory well A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
 
FIN  FASB Interpretation Number
 
FIN 47 FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations — an Interpretation of SFAS 143.
 
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.
 
Grid The layout of the electrical transmission system or a synchronized transmission network.
 
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)
 
MMcf Million cubic feet (of natural gas)
 
MMcfe Million cubic feet equivalent
 
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 time period are evaluated as if they had been submitted simultaneously.
 
Order 636 An order issued by FERC entitled “Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission’s Regulations.”
 
PCB Polychlorinated Biphenyl
 
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
 
PUHCA 1935 Public Utility Holding Company Act of 1935
 
PUHCA 2005 Public Utility Holding Company Act of 2005
 
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 “unbundled”) 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 5 Statement of Financial Accounting Standards No. 5, Accounting for Contingencies
 
SFAS 69 Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities
 
SFAS 71 Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation
 
SFAS 87 Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions
 
SFAS 88 Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits
 
SFAS 106 Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions.
 
SFAS 109 Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes
 
SFAS 112 Statement of Financial Accounting Standards No. 112, Employers’ Accounting for Postemployment Benefits, an amendment of SFAS 5 and 43
 
SFAS 115 Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities
 
SFAS 123 Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation
 
SFAS 123R Statement of Financial Accounting Standards No. 123R, Share-Based Payment
 
SFAS 132R Statement of Financial Accounting Standards No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits
 
SFAS 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 142 Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets
 
SFAS 143 Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations
 
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
 
Spot gas purchases The purchase of natural gas on a short-term basis.
 
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.
 


Table of Contents

 
For the Fiscal Year Ended September 30, 2008
 
CONTENTS
 
                 
        Page
 
      BUSINESS     3  
          The Company and its Subsidiaries     3  
          Rates and Regulation     5  
          The Utility Segment     5  
          The Pipeline and Storage Segment     5  
          The Exploration and Production Segment     6  
          The Energy Marketing Segment     7  
          The Timber Segment     7  
          All Other Category and Corporate Operations     7  
          Discontinued Operations     7  
          Sources and Availability of Raw Materials     7  
          Competition     8  
          Seasonality     9  
          Capital Expenditures     10  
          Environmental Matters     10  
          Miscellaneous     10  
          Executive Officers of the Company     11  
      RISK FACTORS     12  
      UNRESOLVED STAFF COMMENTS     19  
      PROPERTIES     19  
        General Information on Facilities     19  
        Exploration and Production Activities     20  
      LEGAL PROCEEDINGS     23  
      SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS     24  
 
      MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES     24  
      SELECTED FINANCIAL DATA     25  
      MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS     27  
      QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK     58  
      FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA     59  
      CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE     116  
      CONTROLS AND PROCEDURES     116  
      OTHER INFORMATION     116  


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        Page
 
      DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE     116  
      EXECUTIVE COMPENSATION     117  
      SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS     117  
      CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE     118  
      PRINCIPAL ACCOUNTANT FEES AND SERVICES     118  
 
      EXHIBITS AND FINANCIAL STATEMENT SCHEDULES     118  
       
    124  
  EX-10.1
  EX-10.2
  EX-10.3
  EX-10.4
  EX-10.5
  EX-12
  EX-21
  EX-23.1
  EX-23.2
  EX-31.1
  EX-31.2
  EX-32
  EX-99.1
  EX-99.2


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This Form 10-K contains “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements included in this Form 10-K at Item 7, 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,” and “may” and similar expressions.
 
PART I
 
Item 1    Business
 
The Company and its Subsidiaries
 
National Fuel Gas Company (the Registrant), incorporated in 1902, is a holding company organized under the laws of the State of New Jersey. Except as otherwise indicated below, the Registrant owns directly or indirectly all of the outstanding securities of its subsidiaries. Reference to “the Company” in this report means the Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure. Also, all references to a certain year in this report relate to the Company’s fiscal year ended September 30 of that year unless otherwise noted.
 
The Company is a diversified energy company and reports financial results for five business segments.
 
1. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation sells natural gas or provides natural gas transportation services to approximately 727,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.
 
2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation, and Empire State Pipeline (Empire), a New York joint venture between two wholly owned subsidiaries of the Company. Supply Corporation provides interstate natural gas transportation and storage services for affiliated and nonaffiliated companies through (i) an integrated gas pipeline system extending from southwestern Pennsylvania to the New York-Canadian border at the Niagara River and eastward to Ellisburg and Leidy, Pennsylvania, and (ii) 27 underground natural gas storage fields owned and operated by Supply Corporation as well as four other underground natural gas storage fields owned and operated jointly with other interstate gas pipeline companies. Empire, an intrastate pipeline company acquired by the Company in 2003, transports natural gas for Distribution Corporation and for other utilities, large industrial customers and power producers in New York State. Empire owns the Empire Pipeline, which is a 157-mile pipeline that extends from the United States/Canadian border at the Niagara River near Buffalo, New York to near Syracuse, New York. Empire is constructing the Empire Connector project, which consists of a compressor station and a 77-mile pipeline extension from near Rochester, New York to an interconnection near Corning, New York with the unaffiliated Millennium Pipeline project, which is also under construction. The Millennium Pipeline is expected to serve the New York City area upon its completion. Upon completion of the Empire Connector and Millennium Pipeline projects, which is currently expected to occur in December 2008, the Company expects that Empire will become an interstate pipeline company and will merge into Empire Pipeline, Inc. as described below.
 
3. The Exploration and Production segment operations are carried out by Seneca Resources Corporation (Seneca), a Pennsylvania corporation. Seneca is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, in Wyoming, and in the Gulf Coast region of Texas, Louisiana, and Alabama, including offshore areas in federal


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waters and some state waters. At September 30, 2008, the Company had U.S. reserves of 46,198 Mbbl of oil and 225,899 MMcf of natural gas.
 
In 2007, Seneca sold its subsidiary, Seneca Energy Canada Inc. (SECI), which conducted exploration and production operations in the provinces of Alberta, Saskatchewan and British Columbia in Canada.
 
4. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation, which markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
 
5. The Timber segment operations are carried out by Highland Forest Resources, Inc. (Highland), a New York corporation, and by a division of Seneca known as its Northeast Division. This segment markets timber from its New York and Pennsylvania land holdings, owns two sawmill operations in northwestern Pennsylvania and processes timber consisting primarily of high quality hardwoods. At September 30, 2008, the Company owned 103,680 acres of timber property and managed an additional 3,122 acres of timber rights.
 
Financial information about each of the Company’s business segments can be found in Item 7, MD&A and also in Item 8 at Note J — Business Segment Information.
 
The Company’s other direct wholly owned subsidiaries are not included in any of the five reported business segments and consist of the following:
 
  •  Horizon Energy Development, Inc. (Horizon), a New York corporation formed to engage in foreign and domestic energy projects through investments as a sole or substantial owner in various business entities. These entities include Horizon’s wholly owned subsidiary, Horizon Energy Holdings, Inc., a New York corporation, which owns 100% of Horizon Energy Development B.V. (Horizon B.V.). Horizon B.V. is a Dutch company that is in the process of winding up or selling certain power development projects in Europe;
 
  •  Horizon LFG, Inc. (Horizon LFG), a New York corporation engaged through subsidiaries in the purchase, sale and transportation of landfill gas in Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Horizon LFG and one of its wholly owned subsidiaries own all of the partnership interests in Toro Partners, LP (Toro), a limited partnership which owns and operates short-distance landfill gas pipeline companies. The Company acquired Toro in June 2003;
 
  •  Leidy Hub, Inc. (Leidy Hub), a New York corporation formed to provide various natural gas hub services to customers in the eastern United States;
 
  •  Data-Track Account Services, Inc. (Data-Track), a New York corporation formed to provide collection services principally for the Company’s subsidiaries;
 
  •  Horizon Power, Inc. (Horizon Power), a New York corporation which is an “exempt wholesale generator” under PUHCA 2005 and is developing or operating mid-range independent power production facilities and landfill gas electric generation facilities;
 
  •  Empire Pipeline, Inc., a New York corporation formed in 2005 to be the surviving corporation of a planned future merger with Empire, which is expected to occur after construction of the Empire Connector project (described below under the heading “Rates and Regulation” and under Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters”); and
 
  •  National Fuel Gas Midstream Corporation, a Pennsylvania corporation formed to build, own and operate natural gas processing and pipeline gathering facilities in the Appalachian region.
 
No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 2008.


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Rates and Regulation
 
The Registrant is a holding company as defined under PUHCA 2005. PUHCA 2005 repealed PUHCA 1935, to which the Company was formerly subject, and granted the FERC and state public utility commissions access to certain books and records of companies in holding company systems. Pursuant to the FERC’s regulations under PUHCA 2005, the Company and its subsidiaries are exempt from the FERC’s books and records regulations under PUHCA 2005.
 
The Utility segment’s rates, services and other matters are regulated by the NYPSC with respect to services provided within New York and by the PaPUC with respect to services provided within Pennsylvania. For additional discussion of the Utility segment’s rates and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 at Note C — Regulatory Matters.
 
The Pipeline and Storage segment’s rates, services and other matters are currently regulated by the FERC with respect to Supply Corporation and by the NYPSC with respect to Empire. The FERC has authorized Empire to construct and operate additional facilities (the Empire Connector project) and to become a FERC-regulated interstate pipeline company upon placement of those facilities into service, which is currently expected to occur in December 2008. For additional discussion of the Pipeline and Storage segment’s rates and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 at Note C — Regulatory Matters. For further discussion of the Empire Connector project, refer to Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters.”
 
The discussion under Item 8 at Note C — Regulatory Matters includes a description of the regulatory assets and liabilities reflected on the Company’s Consolidated Balance Sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company’s Consolidated Balance Sheets and such accounting treatment would be discontinued.
 
In addition, the Company and its subsidiaries are subject to the same federal, state and local (including foreign) regulations on various subjects, including environmental matters, to which other companies doing similar business in the same locations are subject.
 
The Utility Segment
 
The Utility segment contributed approximately 22.9% of the Company’s 2008 net income available for common stock.
 
Additional discussion of the Utility segment appears below in this Item 1 under the headings “Sources and Availability of Raw Materials,” “Competition: The Utility Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
The Pipeline and Storage Segment
 
The Pipeline and Storage segment contributed approximately 20.1% of the Company’s 2008 net income available for common stock.
 
Supply Corporation has service agreements for all of its firm storage capacity, totaling 68,408 MDth. The Utility segment has contracted for 27,865 MDth or 40.7% of the total firm storage capacity, and the Energy Marketing segment accounts for another 4,811 MDth or 7.1% of the total firm storage capacity. Nonaffiliated customers have contracted for the remaining 35,732 MDth or 52.2% of the total firm storage capacity. The majority of Supply Corporation’s storage and transportation services are performed under contracts that allow Supply Corporation or the shipper to terminate the contract upon six or twelve months’ notice effective at the end of the contract term. The contracts also typically include “evergreen” language designed to allow the contracts to extend year-to-year at the end of the primary term. At the beginning of 2009, 72.0% of Supply Corporation’s total firm storage capacity was committed under contracts that, subject to 2008 shipper or Supply Corporation notifications, could have been terminated effective in 2009. Supply Corporation did not issue or


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receive any such storage contract termination notifications in 2008. The strong demand for market-area storage enabled Supply Corporation to eliminate its remaining storage service rate discounts in 2007, and effective April 1, 2008, all storage services were contracted at the maximum tariff rates.
 
Supply Corporation’s firm transportation capacity is not limited to a fixed quantity, due to the diverse weblike nature of its pipeline system, and is subject to change as the market identifies different transportation paths and receipt/delivery point combinations. Supply Corporation currently has firm transportation service agreements for approximately 2,117 MDth per day (contracted transportation capacity). The Utility segment accounts for approximately 1,065 MDth per day or 50.3% of contracted transportation capacity, and the Energy Marketing and Exploration and Production segments represent another 102 MDth per day or 4.8% of contracted transportation capacity. The remaining 950 MDth or 44.9% of contracted transportation capacity is subject to firm contracts with nonaffiliated customers.
 
At the beginning of 2009, 49.3% of Supply Corporation’s contracted transportation capacity was committed under affiliate contracts that were scheduled to expire in 2009 or, subject to 2008 shipper or Supply Corporation notifications, could have been terminated effective in 2009. Based on contract expirations and termination notices received in 2008 for 2009 termination, and taking into account any known contract additions, contracted transportation capacity with affiliates is expected to decrease 0.3% in 2009. Similarly, 26.7% of contracted transportation capacity was committed under unaffiliated shipper contracts that were scheduled to expire in 2009 or, subject to 2008 shipper or Supply Corporation notifications, could have been terminated effective in 2009. Based on contract expirations and termination notices received in 2008 for 2009 termination, and taking into account any known contract additions, contracted transportation capacity with unaffiliated shippers is expected to increase 9.4% in 2009. This increase is due largely to the addition of compression at various facilities throughout the system as well as other projects designed to create incremental transportation capacity. Supply Corporation previously has been successful in marketing and obtaining executed contracts for available transportation capacity (at discounted rates when necessary), and expects this success to continue.
 
For the 2008-2009 winter period, Empire has service agreements in place for the full amount of its firm transportation capacity to its existing delivery points, totaling approximately 547 MDth per day. Most of Empire’s firm capacity (91.2%) has been contracted as long-term full-year deals. A small number of those contracts are due to expire during fiscal 2009, representing 1.4% of Empire’s firm capacity. In addition, Empire has some seasonal (winter-only) contracts that extend for multiple years, representing 2.7% of Empire’s firm capacity. One of those seasonal contracts is due to expire during fiscal 2009; representing 1.1% of Empire’s firm capacity. Arrangements for the remaining 6.1% of Empire’s firm capacity are seasonal or annual contracts that expire before the end of fiscal 2009. Empire expects that all available capacity arising from expiring agreements will be re-contracted under new seasonal or annual agreements. The Utility segment accounts for approximately 7.8% of Empire’s firm capacity, and the Energy Marketing segment accounts for approximately 1.9% of Empire’s firm capacity, with the remaining 90.3% of Empire’s firm capacity subject to contracts with nonaffiliated customers.
 
Upon the completion of the Empire Connector project, Empire will have expansion capacity for the 2008-2009 winter period. Empire has a firm service agreement for 150.7 MDth per day of this expansion capacity. This long-term full-year agreement represents approximately 60% of the Empire Connector expansion capacity. The Company continues to market the remaining capacity on both a firm and interruptible basis. None of this contracted expansion capacity will expire during fiscal 2009.
 
Additional discussion of the Pipeline and Storage segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Pipeline and Storage Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
The Exploration and Production Segment
 
The Exploration and Production segment contributed approximately 54.6% of the Company’s 2008 net income available for common stock.


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Additional discussion of the Exploration and Production segment appears below under the headings “Discontinued Operations,” “Sources and Availability of Raw Materials” and “Competition: The Exploration and Production Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
The Energy Marketing Segment
 
The Energy Marketing segment contributed approximately 2.2% of the Company’s 2008 net income available for common stock.
 
Additional discussion of the Energy Marketing segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Energy Marketing Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
The Timber Segment
 
The Timber segment’s contribution to the Company’s 2008 net income available for common stock was not significant.
 
Additional discussion of the Timber segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Timber Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
All Other Category and Corporate Operations
 
The All Other category and Corporate operations contributed approximately 0.2% of the Company’s 2008 net income available for common stock.
 
Additional discussion of the All Other category and Corporate operations appears below in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
Discontinued Operations
 
In August 2007, Seneca sold all of the issued and outstanding shares of SECI. SECI’s operations are presented in the Company’s financial statements as discontinued operations.
 
In July 2005, Horizon B.V. sold its entire 85.16% interest in United Energy, a.s. (U.E.), a district heating and electric generation business in the Czech Republic. United Energy’s operations are presented in the Company’s financial statements as discontinued operations.
 
Additional discussion of the Company’s discontinued operations appears in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
Sources and Availability of Raw Materials
 
Natural gas is the principal raw material for the Utility segment. In 2008, the Utility segment purchased 76.0 Bcf of gas for core market demand. All such purchases were made from non-affiliated companies. Gas purchased from producers and suppliers in the southwestern United States and Canada under firm contracts (seasonal and longer) accounted for 89% of these purchases. Purchases of gas on the spot market (contracts for one month or less) accounted for 11% of the Utility segment’s 2008 purchases. Purchases from Total Gas & Power North America Inc. (18%), Chevron Natural Gas (17%), ConocoPhillips Company (16%) and BP Canada (11%) accounted for 62% of the Utility’s 2008 gas purchases. No other producer or supplier provided the Utility segment with more than 10% of its gas requirements in 2008.
 
Supply Corporation transports and stores gas owned by its customers, whose gas originates in the southwestern, mid-continent and Appalachian regions of the United States as well as in Canada. Empire transports gas owned by its customers, whose gas originates in the southwestern and mid-continent regions of the United States as well as in Canada. Additional discussion of proposed pipeline projects appears below under “Competition: The Pipeline and Storage Segment” and in Item 7, MD&A.


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The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as further described in this report in Item 7, MD&A and Item 8 at Note J — Business Segment Information and Note O — Supplementary Information for Oil and Gas Producing Activities.
 
With respect to the Timber segment, Highland requires an adequate supply of timber to process in its sawmill and kiln operations. Fifty-two percent of the timber processed during 2008 in Highland’s sawmill operations came from land owned by the Company’s subsidiaries, and 48% came from outside sources. Timber cut for gas well drilling locations, access roads, and pipelines constituted an increasing portion of Highland’s timber supply, both from land owned by the Company’s subsidiaries and from outside sources. In addition, Highland purchased approximately 5.4 million board feet of green lumber to augment lumber supply for its kiln operations.
 
The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2008, this segment purchased 57 Bcf of gas, including 56 Bcf for core market demands. The remaining 1 Bcf largely represents gas used in operations. The gas purchased by the Energy Marketing segment originates in either the Appalachian or mid-continent regions of the United States or in Canada.
 
Competition
 
Competition in the natural gas industry exists among providers of natural gas, as well as between natural gas and other sources of energy. The natural gas industry has gone through various stages of regulation. Apart from environmental and state utility commission regulation, the natural gas industry has experienced considerable deregulation. This has enhanced the competitive position of natural gas relative to other energy sources, such as fuel oil or electricity, since some of the historical regulatory impediments to adding customers and responding to market forces have been removed. In addition, management believes that the environmental advantages of natural gas have enhanced its competitive position relative to other fuels.
 
The electric industry has been moving toward a more competitive environment as a result of changes in federal law in 1992 and initiatives undertaken by the FERC and various states. It remains unclear what the impact of any further restructuring in response to legislation or other events may be.
 
The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this “Competition” heading, do not compete with the Company to any significant extent.
 
Competition: The Utility Segment
 
The changes precipitated by the FERC’s restructuring of the natural gas industry in Order No. 636, which was issued in 1992, continue to reshape the roles of the gas utility industry and the state regulatory commissions. In both New York and Pennsylvania, Distribution Corporation has retained substantial numbers of residential and small commercial customers as sales customers. However, for many years almost all the industrial and a substantial number of commercial customers have purchased their gas supplies from marketers and utilized Distribution Corporation’s gas transportation services. Regulators in both New York and Pennsylvania have adopted retail competition programs for natural gas supply purchases by the remaining utility sales customers. To date, the Utility segment’s traditional distribution function remains largely unchanged; however, in New York, the Utility segment has instituted a number of programs to accommodate more widespread customer choice. In Pennsylvania, the PaPUC issued a report in October 2005 that concluded “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 Pennsylvania retail markets.
 
Competition for large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment’s service territories without use of the utility’s facilities (i.e., bypass). In addition, competition continues with fuel oil suppliers and may increase with electric utilities making retail energy sales.


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The Utility segment competes in its most vulnerable markets (the large commercial and industrial markets) by offering unbundled, flexible services. The Utility segment continues to develop or promote new sources and uses of natural gas or new services, rates and contracts. The Utility segment also emphasizes and provides high quality service to its customers.
 
Competition: The Pipeline and Storage Segment
 
Supply Corporation competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and with other companies providing gas storage services. Supply Corporation has some unique characteristics which enhance its competitive position. Its facilities are located adjacent to Canada and the northeastern United States and provide part of the link between gas-consuming regions of the eastern United States and gas-producing regions of Canada and the southwestern, southern and other continental regions of the United States. This location offers the opportunity for increased transportation and storage services in the future.
 
Empire competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and upstate New York in particular. Empire is well situated to provide transportation from Canadian sourced gas, and its facilities are readily expandable. These characteristics provide Empire the opportunity to compete for an increased share of the gas transportation markets. As noted above, Empire is constructing the Empire Connector project, which will expand its natural gas pipeline and enable Empire to serve new markets in New York and elsewhere in the Northeast. For further discussion of this project, refer to Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters.”
 
Competition: The Exploration and Production Segment
 
The Exploration and Production segment competes with other oil and natural gas producers and marketers with respect to sales of oil and natural gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other oil and natural gas producers with respect to exploration and development prospects.
 
To compete in this environment, Seneca originates and acts as operator on certain of its prospects, seeks to minimize the risk of exploratory efforts through partnership-type arrangements, utilizes technology for both exploratory studies and drilling operations, and seeks market niches based on size, operating expertise and financial criteria.
 
Competition: The Energy Marketing Segment
 
The Energy Marketing segment competes with other marketers of natural gas and with other providers of energy supply. Competition in this area is well developed with regard to price and services from local, regional and, more recently, national marketers.
 
Competition: The Timber Segment
 
With respect to the Timber segment, Highland competes with other sawmill operations and with other suppliers of timber, logs and lumber. These competitors may be local, regional, national or international in scope. This competition, however, is primarily limited to those entities which either process or supply high quality hardwood species such as cherry, oak and maple as veneer logs, saw logs, export logs or lumber ultimately used in the production of high-end furniture, cabinetry and flooring. The Timber segment sells its products in domestic and international markets.
 
Seasonality
 
Variations in weather conditions can materially affect the volume of gas delivered by the Utility segment, as virtually all of its residential and commercial customers use gas for space heating. The effect that this has on Utility segment margins in New York is mitigated by a WNC, which covers the eight-month period from October through May. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills.
 
Volumes transported and stored by Supply Corporation may vary materially depending on weather, without materially affecting its revenues. Supply Corporation’s allowed rates are based on a straight fixed-variable rate


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design which allows recovery of fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed to recover only the variable costs associated with actual transportation or storage of gas.
 
Volumes transported by Empire may vary materially depending on weather, which can have a moderate effect on its revenues. Empire’s allowed rates currently are based on a modified fixed-variable rate design, which allows recovery of most fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed to recover variable costs associated with actual transportation of gas, to recover return on equity, and to recover income taxes. When Empire becomes a FERC-regulated interstate pipeline company (which is currently expected to occur in December 2008), Empire’s allowed rates, like Supply Corporation’s, will be based on a straight fixed-variable design. Under that rate design, weather-related variations in transportation volumes will not materially affect revenues.
 
Variations in weather conditions materially affect the volume of gas consumed by customers of the Energy Marketing segment. Volume variations have a corresponding impact on revenues within this segment.
 
The activities of the Timber segment vary on a seasonal basis and are subject to weather constraints. Traditionally, the timber harvesting season occurs when timber growth is dormant and runs from approximately September to March. The operations conducted in the summer months typically focus on pulpwood and on thinning lower-grade or lower value trees from timber stands to encourage the growth of higher-grade or higher value trees.
 
Capital Expenditures
 
A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading “Investing Cash Flow.”
 
Environmental Matters
 
A discussion of material environmental matters involving the Company is included in Item 7, MD&A under the heading “Environmental Matters” and in Item 8, Note H — Commitments and Contingencies.
 
Miscellaneous
 
The Company and its wholly owned or majority-owned subsidiaries had a total of 1,943 full-time employees at September 30, 2008. This is a decrease of approximately one-half of one percent from the 1,952 employees in the Company’s U.S. operations at September 30, 2007.
 
In 2008 the Company entered into new agreements with collective bargaining units in New York. The new agreements went into effect in February 2008 and expire in February 2013. In November 2008 the Company entered into a new agreement with a collective bargaining unit in Pennsylvania. The agreement will go into effect in April 2009 and expire in April 2014. An agreement covering employees in another collective bargaining unit in Pennsylvania is scheduled to expire in May 2009. In November 2008 the Company reached a new agreement with the local leadership of that collective bargaining unit. The members of the collective bargaining unit are scheduled to vote on the agreement in December 2008.
 
The Utility segment has numerous municipal franchises under which it uses public roads and certain other rights-of-way and public property for the location of facilities. When necessary, the Utility segment renews such franchises.
 
The Company makes its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, available free of charge on the Company’s internet website, www.nationalfuelgas.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. The information available at the Company’s internet website is not part of this Form 10-K or any other report filed with or furnished to the SEC.


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Executive Officers of the Company as of November 15, 2008(1)
 
     
    Current Company
    Positions and
    Other Material
    Business Experience
Name and Age (as of
  During Past
November 15, 2008)
  Five Years
 
David F. Smith
(55)
  Chief Executive Officer of the Company since February 2008 and President of the Company since February 2006. Mr. Smith previously served as Chief Operating Officer of the Company from February 2006 through January 2008; President of Supply Corporation from April 2005 through June 2008; President of Empire from April 2005 through January 2008; Vice President of the Company from April 2005 through January 2006; President of Distribution Corporation from July 1999 to April 2005; and Senior Vice President of Supply Corporation from July 2000 to April 2005.
Ronald J. Tanski
(56)
  Treasurer and Principal Financial Officer of the Company since April 2004; President of Supply Corporation since July 2008. Mr. Tanski previously served as President of Distribution Corporation from February 2006 through June 2008; Treasurer of Distribution Corporation from April 2004 through September 2008; Controller of the Company from February 2003 through March 2004; Senior Vice President of Distribution Corporation from July 2001 through January 2006; and Controller of Distribution Corporation from February 1997 through March 2004.
Matthew D. Cabell
(50)
  President of Seneca since December 2006. Prior to joining Seneca, Mr. Cabell served as Executive Vice President and General Manager of Marubeni Oil & Gas (USA) Inc., an exploration and production company, from June 2003 to December 2006. From January 2002 to June 2003, Mr. Cabell served as a consultant assisting oil companies in upstream acquisition and divestment transactions as well as Gulf of Mexico entry strategy, first as an independent consultant and then as Vice President of Randall & Dewey, Inc., a major oil and gas transaction advisory firm. Mr. Cabell’s prior employers are not subsidiaries or affiliates of the Company.
Anna Marie Cellino
(55)
  President of Distribution Corporation since July 2008. Ms. Cellino previously served as Secretary of the Company from October 1995 through June 2008; Secretary of Distribution Corporation from September 1999 through September 2008; and Senior Vice President of Distribution Corporation from July 2001 through June 2008.
Karen M. Camiolo
(49)
  Controller and Principal Accounting Officer of the Company since April 2004; Controller of Distribution Corporation and Supply Corporation since April 2004; and Chief Auditor of the Company from July 1994 through March 2004.
Carl M. Carlotti
(53)
  Senior Vice President of Distribution Corporation since January 2008. Mr. Carlotti previously served as Vice President of Distribution Corporation from October 1998 to January 2008.
Paula M. Ciprich
(48)
  Secretary of the Company since July 2008; General Counsel of the Company since January 2005; Secretary of Distribution Corporation since July 2008. Ms. Ciprich previously served as General Counsel of Distribution Corporation from February 1997 through February 2007 and as Assistant Secretary of Distribution Corporation from February 1997 through June 2008.
Donna L. DeCarolis
(49)
  Vice President Business Development of the Company since October 2007. Ms. DeCarolis previously served as President of NFR from January 2005 to October 2007; Secretary of NFR from March 2002 to October 2007; and Vice President of NFR from May 2001 to January 2005.
John R. Pustulka
(56)
  Senior Vice President of Supply Corporation since July 2001.
James D. Ramsdell
(53)
  Senior Vice President of Distribution Corporation since July 2001.
 
 
(1) The executive officers serve at the pleasure of the Board of Directors. The information provided relates to the Company and its principal subsidiaries. Many of the executive officers also have served or currently serve as officers or directors of other subsidiaries of the Company.


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Item 1A    Risk Factors
 
As a holding company, National Fuel depends on its operating subsidiaries to meet its financial obligations.
 
National Fuel is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, National Fuel relies exclusively on repayments of principal and interest on intercompany loans made by National Fuel to its operating subsidiaries and income from dividends and other cash flow from the subsidiaries. Such operating subsidiaries may not generate sufficient net income to pay upstream dividends or generate sufficient cash flow to make payments of principal or interest on such intercompany loans.
 
Recent disruptions in financial markets may affect National Fuel’s ability to obtain financing or refinance maturing debt on reasonable terms and may have other adverse effects.
 
Widely-documented disruptions in financial markets have resulted in a severe tightening of credit availability in the United States. Liquidity in credit markets has contracted significantly, making terms for certain financings less attractive. Ongoing turmoil in the credit markets may make it difficult for National Fuel to obtain financing on acceptable terms or at all for working capital, capital expenditures and other investments and to refinance maturing debt on favorable terms. These difficulties could adversely affect National Fuel’s operations and financial performance.
 
National Fuel is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies.
 
In addition to its longer term debt that is issued to the public under its indentures, National Fuel relies upon shorter term bank borrowings and commercial paper to finance a portion of its operations. National Fuel is dependent on these capital sources to provide capital to its subsidiaries to allow them to acquire, maintain and develop their properties. The availability and cost of these credit sources is cyclical and these capital sources may not remain available to National Fuel or National Fuel may not be able to obtain money at a reasonable cost in the future. Recent access to the commercial paper markets has been on less favorable terms as a result of ongoing turmoil in the credit markets, and the commercial paper markets may not consistently be a reliable source of short-term financing for National Fuel in the future. National Fuel’s ability to borrow under its credit facilities and commercial paper agreements depends on National Fuel’s compliance with its obligations under the facilities and agreements. In addition, all of National Fuel’s short-term bank loans are in the form of floating rate debt or debt that may have rates fixed for very short periods of time. At present, National Fuel has no active interest rate hedges in place to protect against interest rate fluctuations on short-term bank debt. In addition, the interest rates on National Fuel’s short-term bank loans and the ability of National Fuel to issue commercial paper are affected by its debt credit ratings published by Standard & Poor’s Ratings Service (“S&P”), Moody’s Investors Service and Fitch Ratings Service. On October 15, 2008, National Fuel’s senior unsecured credit rating of BBB+ was placed on CreditWatch-with negative implications by S&P. A ratings downgrade could increase the interest cost of debt issued by National Fuel and decrease future availability of money from banks, commercial paper purchasers and other sources. National Fuel’s debt securities are currently rated at investment grade and the Company believes it is important to maintain investment grade credit ratings to conduct its business.
 
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


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instability or other adverse effects at any of our suppliers or customers. For example, counterparties to National Fuel’s commodity hedging arrangements might not be able to perform their obligations under these arrangements. 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.
 
The increasing costs of certain employee and retiree benefits could adversely affect National Fuel’s results.
 
National Fuel’s earnings and cash flow may be impacted by the amount of income or expense it expends or records for employee benefit plans. This is particularly true for pension plans, which are dependent on actual plan asset returns and factors used to determine the value and current costs of plan benefit obligations. In addition, if medical costs rise at a rate faster than the general inflation rate, National Fuel might not be able to mitigate the rising costs of medical benefits. Increases to the costs of pension and medical benefits could have an adverse effect on National Fuel’s financial results.
 
National Fuel’s credit ratings may not reflect all the risks of an investment in its securities.
 
National Fuel’s credit ratings are an independent assessment of its ability to pay its obligations. Consequently, real or anticipated changes in the Company’s credit ratings will generally affect the market value of the specific debt instruments that are rated, as well as the market value of the Company’s common stock. National Fuel’s credit ratings, however, may not reflect the potential impact on the value of its common stock of risks related to structural, market or other factors discussed in this Form 10-K.
 
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.
 
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


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suppliers in 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 to the jurisdiction of the NYPSC with respect to Empire. The FERC has authorized Empire to construct and operate the Empire Connector project. When Empire completes construction and commences operations of the Empire Connector, Empire will at that time become a FERC-regulated pipeline company. The FERC and the NYPSC, among other things, approve the rates that Supply Corporation and Empire, respectively, 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 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.
 
National Fuel’s liquidity, and in certain circumstances, its earnings, could be adversely affected by the cost of purchasing natural gas during periods in which natural gas prices are rising significantly.
 
Tariff rate schedules in each of the Utility segment’s service territories contain purchased gas adjustment clauses which permit Distribution Corporation to file with state regulators for rate adjustments to recover increases in the cost of purchased gas. Assuming those rate adjustments are granted, increases in the cost of purchased gas have no direct impact on profit margins. Nevertheless, increases in the cost of purchased gas affect cash flows and can therefore impact the amount or availability of National Fuel’s capital resources. National Fuel has issued commercial paper and used short-term borrowings in the past to temporarily finance storage inventories and purchased gas costs, and although National Fuel expects to do so in the future, it may not be able to access the markets for such borrowings at attractive interest rates or at all. Distribution Corporation is required to file an accounting reconciliation with the regulators in each of the Utility segment’s service territories regarding the costs of purchased gas. Due to the nature of the regulatory process, there is a risk of a disallowance of full recovery of these costs during any period in which there has been a substantial upward spike in these costs. Any material disallowance of purchased gas costs could have a material adverse effect on cash flow and earnings. In addition, even when Distribution Corporation is allowed full recovery of these purchased


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gas costs, during periods when natural gas prices are significantly higher than historical levels, customers may have trouble paying the resulting higher bills, and Distribution Corporation’s bad debt expenses may increase and ultimately reduce earnings.
 
Changes in interest rates may affect National Fuel’s ability to finance capital expenditures and to refinance maturing debt.
 
National Fuel’s ability to finance capital expenditures and to refinance maturing debt will depend in part upon interest rates. The direction in which interest rates may move is uncertain. Declining interest rates have generally been believed to be favorable to utilities, while rising interest rates are generally believed to be unfavorable, because of the levels of debt that utilities may have outstanding. In addition, National Fuel’s authorized rate of return in its regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, National Fuel’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, National Fuel’s ability to earn its authorized rate of return may be adversely impacted.
 
Decreased oil and natural gas prices could adversely affect revenues, cash flows and profitability.
 
National Fuel’s exploration and production operations are materially dependent on prices received for its oil and natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, gathering and processing oil and natural gas. Oil and natural gas prices can be volatile and can be affected by: weather conditions, including natural disasters; the supply and price of foreign oil and natural gas; the level of consumer product demand; national and worldwide economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents; political conditions in foreign countries; the price and availability of alternative fuels; the proximity to, and availability of capacity on transportation facilities; regional levels of supply and demand; energy conservation measures; and government regulations, such as regulation of natural gas transportation, royalties, and price controls. National Fuel sells most of its oil and natural gas at current market prices rather than through fixed-price contracts, although as discussed below, National Fuel frequently hedges the price of a significant portion of its future production in the financial markets. The prices National Fuel receives depend upon factors beyond National Fuel’s control, including the factors affecting price mentioned above. National Fuel believes that any prolonged reduction in oil and natural gas prices would restrict its ability to continue the level of exploration and production activity National Fuel otherwise would pursue, which could have a material adverse effect on its revenues, cash flows and results of operations.
 
National Fuel has significant transactions involving price hedging of its oil and natural gas production as well as its fixed price purchase and sale commitments.
 
In order to protect itself to some extent against unusual price volatility and to lock in fixed pricing on oil and natural gas production for certain periods of time, National Fuel periodically enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may at any time cover as much as approximately 80% of National Fuel’s expected energy production during the upcoming 12-month period. These contracts reduce exposure to subsequent price drops but can also limit National Fuel’s ability to benefit from increases in commodity prices. In addition, the Energy Marketing segment enters into certain hedging arrangements, primarily with respect to its fixed price purchase and sales commitments and its volumes of gas stored underground. National Fuel’s Pipeline and Storage segment enters into hedging arrangements with respect to certain sales of efficiency gas, and the All Other category has hedging arrangements in place with respect to certain volumes of landfill gas committed for sale.
 
Under applicable accounting rules, the Company’s hedging arrangements are subject to quarterly effectiveness tests. Inherent within those effectiveness tests are assumptions concerning the long-term price differential between different types of crude oil, assumptions concerning the difference between published natural gas price indexes established by pipelines in which hedged natural gas production is delivered and the reference price established in the hedging arrangements, assumptions regarding the levels of production that will be achieved and, with regard to fixed price commitments, assumptions regarding the creditworthiness of


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certain customers and their forecasted consumption of natural gas. Depending on market conditions for natural gas and crude oil and the levels of production actually achieved, it is possible that certain of those assumptions may change in the future, and, depending on the magnitude of any such changes, it is possible that a portion of the Company’s hedges may no longer be considered highly effective. In that case, gains or losses from the ineffective derivative financial instruments would be marked-to-market on the income statement without regard to an underlying physical transaction. Gains would occur to the extent that natural gas and crude oil hedge prices exceed market prices for the Company’s natural gas and crude oil production, and losses would occur to the extent that market prices for the Company’s natural gas and crude oil production exceed hedge prices.
 
Use of energy commodity price hedges also exposes National Fuel to the risk of non-performance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements.
 
It is National Fuel’s policy that the use of commodity derivatives contracts comply with various restrictions in effect in respective business segments. For example, in the Exploration and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production, and in the Energy Marketing segment, commodity derivatives with respect to fixed price purchase and sales commitments must be matched against commitments reasonably certain to be fulfilled. Similar restrictions apply in the Pipeline and Storage segment and the All Other category. National Fuel maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose National Fuel to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of oil and natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.
 
You should not place undue reliance on reserve information because such information represents estimates.
 
This Form 10-K contains estimates of National Fuel’s proved oil and natural gas reserves and the future net cash flows from those reserves that were prepared by National Fuel’s petroleum engineers and audited by independent petroleum engineers. Petroleum engineers consider many factors and make assumptions in estimating National Fuel’s oil and natural gas reserves and future net cash flows. These factors include: historical production from the area compared with production from other producing areas; the assumed effect of governmental regulation; and assumptions concerning oil and natural gas prices, production and development costs, severance and excise taxes, and capital expenditures. Lower oil and natural gas prices generally cause estimates of proved reserves to be lower. Estimates of reserves and expected future cash flows prepared by different engineers, or by the same engineers at different times, may differ substantially. Ultimately, actual production, revenues and expenditures relating to National Fuel’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of National Fuel’s reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.
 
If conditions remain constant, then National Fuel is reasonably certain that its reserve estimates represent economically recoverable oil and natural gas reserves and future net cash flows. If conditions change in the future, then subsequent reserve estimates may be revised accordingly. You should not assume that the present value of future net cash flows from National Fuel’s proved reserves is the current market value of National Fuel’s estimated oil and natural gas reserves. In accordance with SEC requirements, National Fuel bases the estimated discounted future net cash flows from its proved reserves on prices and costs as of the date of the estimate. Actual future prices and costs may differ materially from those used in the net present value estimate. Any significant price changes will have a material effect on the present value of National Fuel’s reserves.
 
Petroleum engineering is a subjective process of estimating underground accumulations of natural gas and other hydrocarbons that cannot be measured in an exact manner. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Future economic and operating conditions are uncertain, and changes in those conditions could cause a revision to National Fuel’s reserve


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estimates in the future. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, and the assumed effects of regulations by governmental agencies. Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the production and operating costs incurred, the amount and timing of future development and abandonment expenditures, and the price received for the production.
 
The amount and timing of actual future oil and natural gas production and the cost of drilling are difficult to predict and may vary significantly from reserves and production estimates, which may reduce National Fuel’s earnings.
 
There are many risks in developing oil and natural gas, including numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures. The future success of National Fuel’s Exploration and Production segment depends on its ability to develop additional oil and natural gas reserves that are economically recoverable, and its failure to do so may reduce National Fuel’s earnings. The total and timing of actual future production may vary significantly from reserves and production estimates. National Fuel’s drilling of development wells can involve significant risks, including those related to timing, success rates, and cost overruns, and these risks can be affected by lease and rig availability, geology, and other factors. Drilling for oil and natural gas can be unprofitable, not only from non-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their cancellation. The cost of drilling, completing, and operating wells is often uncertain, and new wells may not be productive or National Fuel may not recover all or any portion of its investment. Without continued successful exploitation or acquisition activities, National Fuel’s reserves and revenues will decline as a result of its current reserves being depleted by production. National Fuel cannot assure you that it will be able to find or acquire additional reserves at acceptable costs.
 
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 last recorded an impairment charge under the full cost method of accounting in 2006. Because of the variability in National Fuel’s investment in oil and natural gas properties and the volatile nature of commodity prices, National Fuel cannot predict when in the future it may again be affected by such an impairment calculation.
 
Environmental regulation significantly affects National Fuel’s business.
 
National Fuel’s business operations are subject to federal, state, and local laws and regulations relating to environmental protection. These laws and regulations concern the generation, storage, transportation, disposal or discharge of contaminants into the environment and the general protection of public health, natural resources, wildlife and the environment. Costs of compliance and liabilities could negatively affect National Fuel’s results of operations, financial condition and cash flows. In addition, compliance with environmental


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laws and regulations could require unexpected capital expenditures at National Fuel’s facilities. Because the costs of complying with environmental regulations are significant, additional regulation could negatively affect National Fuel’s business. Although National Fuel cannot predict the impact of the interpretation or enforcement of EPA standards or other federal, state and local regulations, National Fuel’s costs could increase if environmental laws and regulations become more strict.
 
The nature of National Fuel’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.
 
National Fuel’s operations in its various segments are subject to inherent hazards and risks such as: fires; natural disasters; explosions; geological formations with abnormal pressures; blowouts during well drilling; collapses of wellbore casing or other tubulars; pipeline ruptures; spills; and other hazards and risks that may cause personal injury, death, property damage, environmental damage or business interruption losses. Additionally, National Fuel’s facilities, machinery, and equipment may be subject to sabotage. Any of these events could cause a loss of hydrocarbons, environmental pollution, claims for personal injury, death, property damage or business interruption, or governmental investigations, recommendations, claims, fines or penalties. As protection against operational hazards, National Fuel maintains insurance coverage against some, but not all, potential losses. In addition, many of the agreements that National Fuel executes with contractors provide for the division of responsibilities between the contractor and National Fuel, and National Fuel seeks to obtain an indemnification from the contractor for certain of these risks. National Fuel is not always able, however, to secure written agreements with its contractors that contain indemnification, and sometimes National Fuel is required to indemnify others.
 
Insurance or indemnification agreements when obtained may not adequately protect National Fuel against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, the imposition of fines, penalties or mandated programs by governmental authorities, the failure of a contractor to meet its indemnification obligations, or the failure of an insurance company to pay valid claims could result in substantial losses to National Fuel. In addition, insurance may not be available, or if available may not be adequate, to cover any or all of these risks. It is also possible that insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive.
 
Due to the significant cost of insurance coverage for named windstorms in the Gulf of Mexico, National Fuel determined that it was not economical to purchase insurance to fully cover its exposures related to such storms. It is possible that named windstorms in the Gulf of Mexico could have a material adverse effect on National Fuel’s results of operations, financial condition and cash flows.
 
Hazards and risks faced by National Fuel, and insurance and indemnification obtained or provided by National Fuel, may subject National Fuel to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against National Fuel or be resolved on unfavorable terms, the result of which could have a material adverse effect on National Fuel’s results of operations, financial condition and cash flows.
 
Significant shareholders or potential shareholders may attempt to effect changes at National Fuel or acquire control over National Fuel, which could adversely affect National Fuel’s results of operations and financial condition.
 
In January 2008, National Fuel entered into an agreement with New Mountain Vantage GP, L.L.C. (“New Mountain”) and certain parties related to New Mountain, including the California Public Employees’ Retirement System (collectively, “Vantage”), to settle a proxy contest pertaining to the election of directors to National Fuel’s Board of Directors at National Fuel’s 2008 Annual Meeting of Stockholders. Pursuant to the settlement agreement, National Fuel and Vantage agreed, among other things, to a standstill whereby, until September 2009, Vantage will not, among other things, acquire voting securities that would increase its beneficial ownership to more than 9.6% of National Fuel’s voting securities; engage in any proxy solicitations or advance any shareholder proposals; attempt to control National Fuel’s Board of Directors, management or


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policies; call a meeting of shareholders; obtain additional representation to the Board of Directors; or effect the removal of any member of the Board of Directors. At the end of the standstill period, Vantage may again seek to effect changes at National Fuel or acquire control over National Fuel. In addition, other existing or potential shareholders may engage in proxy solicitations, advance shareholder proposals or otherwise attempt to effect changes or acquire control over National Fuel.
 
Campaigns by shareholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term shareholder value through actions such as changes in strategy or management, changes to the board of directors, restructuring, increased financial leverage, special dividends, stock repurchases or sales of assets or the entire company. Responding to proxy contests and other actions by activist shareholders can be costly and time-consuming, disrupting National Fuel’s operations and diverting the attention of National Fuel’s Board of Directors and senior management. As a result, shareholder campaigns could adversely affect National Fuel’s results of operations and financial condition.
 
Item 1B    Unresolved Staff Comments
 
None
 
Item 2    Properties
 
General Information on Facilities
 
The net investment of the Company in property, plant and equipment was $3.2 billion at September 30, 2008. Approximately 62% of this investment was in the Utility and Pipeline and Storage segments, which are primarily located in western and central New York and northwestern Pennsylvania. The Exploration and Production segment, which has the next largest investment in net property, plant and equipment (35%), is primarily located in California, in the Appalachian region of the United States, in Wyoming, and in the Gulf Coast region of Texas, Louisiana, and Alabama. The remaining net investment in property, plant and equipment consisted of the Timber segment (2%) which is located primarily in northwestern Pennsylvania, and All Other and Corporate operations (1%). During the past five years, the Company has made additions to property, plant and equipment in order to expand and improve transmission and distribution facilities for both retail and transportation customers. Net property, plant and equipment has increased $163.1 million, or 5.5%, since 2003. During 2007, the Company sold SECI, Seneca’s wholly owned subsidiary that operated in Canada. The net property, plant and equipment of SECI at the date of sale was $107.7 million. In addition, during 2005, the Company sold its majority interest in U.E., a district heating and electric generation business in the Czech Republic. The net property, plant and equipment of U.E. at the date of sale was $223.9 million.
 
The Utility segment had a net investment in property, plant and equipment of $1.1 billion at September 30, 2008. The net investment in its gas distribution network (including 14,819 miles of distribution pipeline) and its service connections to customers represent approximately 52% and 34%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2008.
 
The Pipeline and Storage segment had a net investment of $826.5 million in property, plant and equipment at September 30, 2008. Transmission pipeline represents 27% of this segment’s total net investment and includes 2,371 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities represent 21% of this segment’s total net investment and consist of 31 storage fields, four of which are jointly owned and operated with certain pipeline suppliers, and 429 miles of pipeline. Net investment in storage facilities includes $94.8 million of gas stored underground-noncurrent, representing the cost of the gas utilized to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other purposes, including that needed for no-notice transportation service. The Pipeline and Storage segment has 27 compressor stations with 75,104 installed compressor horsepower that represent 11% of this segment’s total net investment in property, plant and equipment.
 
The Exploration and Production segment had a net investment in property, plant and equipment of $1.1 billion at September 30, 2008.


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The Timber segment had a net investment in property, plant and equipment of $86.4 million at September 30, 2008. Located primarily in northwestern Pennsylvania, the net investment includes two sawmills, 103,680 acres of land and timber, and 3,122 acres of timber rights.
 
The Utility and Pipeline and Storage segments’ facilities provided the capacity to meet the Company’s 2008 peak day sendout, including transportation service, of 1,632 MMcf, which occurred on February 10, 2008. Withdrawals from storage of 768.3 MMcf provided approximately 47.1% of the requirements on that day.
 
Company maps are included in exhibit 99.2 of this Form 10-K and are incorporated herein by reference.
 
Exploration and Production Activities
 
The Company is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, in Wyoming, and in the Gulf Coast region of Texas, Louisiana, and Alabama. Also, Exploration and Production operations were conducted in the provinces of Alberta, Saskatchewan and British Columbia in Canada, until the sale of these properties on August 31, 2007. Further discussion of the sale of the Canadian oil and gas properties is included in Item 8, Note I — Discontinued Operations. Further discussion of oil and gas producing activities is included in Item 8, Note O — Supplementary Information for Oil and Gas Producing Activities. Note O sets forth proved developed and undeveloped reserve information for Seneca. Seneca’s proved developed and undeveloped natural gas reserves increased from 205 Bcf at September 30, 2007 to 226 Bcf at September 30, 2008. This increase is attributed primarily to extensions and discoveries (40.1 Bcf), primarily in the Appalachian region (31.3 Bcf). This increase was partially offset by production of 22.3 Bcf. Seneca’s proved developed and undeveloped oil reserves decreased from 47,586 Mbbl at September 30, 2007 to 46,198 Mbbl at September 30, 2008. This decrease is attributed to production (3,070 Mbbl), primarily occurring in California (2,460 Mbbl) and sales of minerals in place (1,334 Mbbl). These decreases were partially offset by purchases of minerals in place (2,084 Mbbl) and extensions and discoveries (827 Mbbl). On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 491 Bcfe at September 30, 2007 to 503 Bcfe at September 30, 2008. Seneca’s proved developed and undeveloped natural gas reserves decreased from 233 Bcf at September 30, 2006 to 205 Bcf at September 30, 2007. This decrease is attributed primarily to the sale of the Canadian gas properties (40.1 Bcf) and production of 26.3 Bcf. These decreases were partially offset by extensions and discoveries of 34.6 Bcf, primarily in the Appalachian region (29.7 Bcf). Seneca’s proved developed and undeveloped oil reserves decreased from 58,018 Mbbl at September 30, 2006 to 47,586 Mbbl at September 30, 2007. This decrease is attributed to revisions of previous estimates (5,963 Mbbl), primarily occurring in California, production (3,450 Mbbl) and the sale of the Canadian oil properties (1,458 Mbbl). On a Bcfe basis, Seneca’s proved developed and undeveloped reserves decreased from 581 Bcfe at September 30, 2006 to 491 Bcfe at September 30, 2007.
 
Seneca’s oil and gas reserves reported in Item 8 at Note O as of September 30, 2008 were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Netherland, Sewell & Associates, Inc. Seneca reports its oil and gas reserve information on an annual basis to the Energy Information Administration (EIA), a statistical agency of the U.S. Department of Energy. The oil and gas reserve information reported to the EIA showed 204 Bcf and 49,899 Mbbl of gas and oil reserves, respectively, which differs from the reserve information summarized in Item 8 at Note O. The reasons for this difference are as follows: (a) reserves are reported to the EIA on a calendar year basis, while reserves disclosed in Item 8 at Note O are shown on a fiscal year basis; (b) reserves reported to the EIA include only properties operated by Seneca, while reserves disclosed in Item 8 at Note O included both Seneca operated properties and non-operated properties in which Seneca has an interest; and (c) reserves are reported to the EIA on a gross basis versus the reserves disclosed in Item 8 at Note O, which are reported on a net revenue interest basis.


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The following is a summary of certain oil and gas information taken from Seneca’s records. All monetary amounts are expressed in U.S. dollars.
 
Production
 
                         
    For The Year Ended September 30  
    2008     2007     2006  
 
United States
                       
Gulf Coast Region
                       
Average Sales Price per Mcf of Gas
  $ 10.03     $ 6.58     $ 8.01  
Average Sales Price per Barrel of Oil
  $ 107.27     $ 63.04     $ 64.10  
Average Sales Price per Mcf of Gas (after hedging)
  $ 9.49     $ 6.87     $ 5.89  
Average Sales Price per Barrel of Oil (after hedging)
  $ 98.56     $ 64.09     $ 47.46  
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced
  $ 1.63     $ 1.08     $ 0.86  
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)
    38       40       36  
West Coast Region
                       
Average Sales Price per Mcf of Gas
  $ 8.71     $ 6.54     $ 7.93  
Average Sales Price per Barrel of Oil
  $ 98.17     $ 56.86     $ 56.80  
Average Sales Price per Mcf of Gas (after hedging)
  $ 8.22     $ 6.82     $ 7.19  
Average Sales Price per Barrel of Oil (after hedging)
  $ 77.64     $ 47.43     $ 37.69  
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced
  $ 2.01     $ 1.54     $ 1.35  
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)
    51       50       53  
Appalachian Region
                       
Average Sales Price per Mcf of Gas
  $ 9.73     $ 7.48     $ 9.53  
Average Sales Price per Barrel of Oil
  $ 97.40     $ 62.26     $ 65.28  
Average Sales Price per Mcf of Gas (after hedging)
  $ 8.85     $ 8.25     $ 8.90  
Average Sales Price per Barrel of Oil (after hedging)
  $ 97.40     $ 62.26     $ 65.28  
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced
  $ 0.77     $ 0.69     $ 0.69  
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)
    22       17       15  
Total United States
                       
Average Sales Price per Mcf of Gas
  $ 9.70     $ 6.82     $ 8.42  
Average Sales Price per Barrel of Oil
  $ 99.64     $ 58.43     $ 58.47  
Average Sales Price per Mcf of Gas (after hedging)
  $ 9.05     $ 7.25     $ 7.02  
Average Sales Price per Barrel of Oil (after hedging)
  $ 81.75     $ 51.68     $ 40.26  
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced
  $ 1.64     $ 1.23     $ 1.09  
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)
    111       108       104  


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    For The Year Ended September 30  
    2008     2007     2006  
 
Canada — Discontinued Operations
                       
Average Sales Price per Mcf of Gas
  $     $ 6.09     $ 7.14  
Average Sales Price per Barrel of Oil
  $     $ 50.06     $ 51.40  
Average Sales Price per Mcf of Gas (after hedging)
  $     $ 6.17     $ 7.47  
Average Sales Price per Barrel of Oil (after hedging)
  $     $ 50.06     $ 51.40  
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced
  $     $ 1.94     $ 1.57  
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)
          21       26  
Total Company
                       
Average Sales Price per Mcf of Gas
  $ 9.70     $ 6.64     $ 8.04  
Average Sales Price per Barrel of Oil
  $ 99.64     $ 57.93     $ 57.94  
Average Sales Price per Mcf of Gas (after hedging)
  $ 9.05     $ 6.98     $ 7.15  
Average Sales Price per Barrel of Oil (after hedging)
  $ 81.75     $ 51.58     $ 41.10  
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced
  $ 1.64     $ 1.35     $ 1.18  
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)
    111       129       130  
 
Productive Wells
 
                                                                 
    Gulf Coast
    West Coast
    Appalachian
             
    Region     Region     Region     Total Company  
At September 30, 2008
  Gas     Oil     Gas     Oil     Gas     Oil     Gas     Oil  
 
Productive Wells — Gross
    25       42             1,437       2,641       6       2,666       1,485  
Productive Wells — Net
    14       14             1,426       2,570       5       2,584       1,445  
 
Developed and Undeveloped Acreage
 
                                 
    Gulf
    West
             
    Coast
    Coast
    Appalachian
    Total
 
At September 30, 2008
  Region     Region     Region     Company  
 
Developed Acreage
                               
— Gross
    113,934       11,360       531,743       657,037  
— Net
    80,852       10,945       501,411       593,208  
Undeveloped Acreage
                               
— Gross
    142,118             458,894       601,012  
— Net
    102,831             438,040       540,871  
 
As of September 30, 2008, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 38,811 acres in 2009 (23,289 net acres), 23,302 acres in 2010 (11,754 net acres), 82,165 acres in 2011 (67,472 net acres), and 456,734 acres thereafter (438,356 net acres).

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Drilling Activity
 
                                                 
    Productive     Dry  
For the Year Ended September 30
  2008     2007     2006     2008     2007     2006  
 
United States
                                               
Gulf Coast Region
                                               
Net Wells Completed
                                               
— Exploratory
    1.14       1.31       2.94       0.37       1.42       0.85  
— Development
          1.00       0.78             0.67        
West Coast Region
                                               
Net Wells Completed
                                               
— Exploratory
    1.00       0.50                          
— Development
    62.00       58.99       92.98       1.00       2.00       1.00  
Appalachian Region
                                               
Net Wells Completed
                                               
— Exploratory
    8.00       8.10       3.88       1.00              
— Development
    186.00       184.00       140.58             2.00       1.75  
Total United States
                                               
Net Wells Completed
                                               
— Exploratory
    10.14       9.91       6.82       1.37       1.42       0.85  
— Development
    248.00       243.99       234.34       1.00       4.67       2.75  
Canada — Discontinued Operations
                                               
Net Wells Completed
                                               
— Exploratory
          6.38       12.60                   1.35  
— Development
          1.80       2.50                   1.00  
Total
                                               
Net Wells Completed
                                               
— Exploratory
    10.14       16.29       19.42       1.37       1.42       2.20  
— Development
    248.00       245.79       236.84       1.00       4.67       3.75  
 
Present Activities
 
                                 
    Gulf
    West
             
    Coast
    Coast
    Appalachian
    Total
 
At September 30, 2008
  Region     Region     Region     Company  
 
Wells in Process of Drilling(1)
                               
— Gross
    2.00       1.00       148.00       151.00  
— Net
    0.59       1.00       146.00       147.59  
 
 
(1) Includes wells awaiting completion.
 
Item 3    Legal Proceedings
 
For a discussion of various environmental and other matters, refer to Part II, Item 7, MD&A and Item 8 at Note H — Commitments and Contingencies. 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


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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 4    Submission of Matters to a Vote of Security Holders
 
No matter was submitted to a vote of security holders during the quarter ended September 30, 2008.
 
PART II
 
Item 5    Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Information regarding the market for the Company’s common equity and related stockholder matters appears under Item 12 at Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, Item 8 at Note E — Capitalization and Short-Term Borrowings and Note N — Market for Common Stock and Related Shareholder Matters (unaudited).
 
On July 2, 2008, the Company issued a total of 2,400 unregistered shares of Company common stock to the eight 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 September 30, 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
    Maximum Number
 
                of Shares
    of Shares
 
                Purchased as
    that May
 
                Part of
    Yet Be
 
                Publicly Announced
    Purchased Under
 
    Total Number
    Average Price
    Share Repurchase
    Share Repurchase
 
    of Shares
    Paid per
    Plans or
    Plans or
 
Period
  Purchased(a)     Share     Programs     Programs(b)  
 
July 1-31, 2008
    6,404     $ 54.02             1,332,725  
Aug. 1-31, 2008
    544,982     $ 46.72       537,165       795,560  
Sept. 1-30, 2008
    1,832,488     $ 45.08       1,824,541       6,971,019  
                                 
Total
    2,383,874     $ 45.48       2,361,706       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, (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes, and (iii) shares of common stock of the Company purchased on the open market pursuant to the Company’s publicly announced share repurchase program. Shares purchased other than through a publicly announced share repurchase program totaled 6,404 in July 2008, 7,817 in August 2008 and 7,947 in September 2008 (a three-month total of 22,168). All of those shares were purchased for the Company’s 401(k) plans.
 
(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.


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Item 6    Selected Financial Data
 
                                         
    Year Ended September 30  
    2008     2007     2006     2005     2004  
    (Thousands)  
 
Summary of Operations
                                       
Operating Revenues
  $ 2,400,361     $ 2,039,566     $ 2,239,675     $ 1,860,774     $ 1,867,875  
                                         
Operating Expenses:
                                       
Purchased Gas
    1,235,157       1,018,081       1,267,562       959,827       949,452  
Operation and Maintenance
    432,871       396,408       395,289       388,094       374,010  
Property, Franchise and Other Taxes
    75,585       70,660       69,202       68,164       68,378  
Depreciation, Depletion and Amortization
    170,623       157,919       151,999       156,502       159,184  
                                         
      1,914,236       1,643,068       1,884,052       1,572,587       1,551,024  
Loss on Sale of Timber Properties
                            (1,252 )
                                         
Operating Income
    486,125       396,498       355,623       288,187       315,599  
Other Income (Expense):
                                       
Income from Unconsolidated Subsidiaries
    6,303       4,979       3,583       3,362       805  
Impairment of Investment in Partnership
                      (4,158 )      
Interest Income
    10,815       1,550       9,409       6,236       1,771  
Other Income
    7,376       4,936       2,825       12,744       2,908  
Interest Expense on Long-Term Debt
    (70,099 )     (68,446 )     (72,629 )     (73,244 )     (82,989 )
Other Interest Expense
    (3,870 )     (6,029 )     (5,952 )     (9,069 )     (6,354 )
                                         
Income from Continuing Operations Before Income Taxes
    436,650       333,488       292,859       224,058       231,740  
Income Tax Expense
    167,922       131,813       108,245       85,621       89,820  
                                         
Income from Continuing Operations
    268,728       201,675       184,614       138,437       141,920  
                                         
Discontinued Operations:
                                       
Income (Loss) from Operations, Net of Tax
          15,479       (46,523 )     25,277       24,666  
Gain on Disposal, Net of Tax
          120,301             25,774        
                                         
Income (Loss) from Discontinued Operations, Net of Tax
          135,780       (46,523 )     51,051       24,666  
                                         
Net Income Available for Common Stock
  $ 268,728     $ 337,455     $ 138,091     $ 189,488     $ 166,586  
                                         


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    Year Ended September 30  
    2008     2007     2006     2005     2004  
    (Thousands)  
 
Per Common Share Data
                                       
Basic Earnings from Continuing Operations per Common Share
  $ 3.27     $ 2.43     $ 2.20     $ 1.66     $ 1.73  
Diluted Earnings from Continuing Operations per Common Share
  $ 3.18     $ 2.37     $ 2.15     $ 1.63     $ 1.71  
Basic Earnings per Common Share(1)
  $ 3.27     $ 4.06     $ 1.64     $ 2.27     $ 2.03  
Diluted Earnings per Common Share(1)
  $ 3.18     $ 3.96     $ 1.61     $ 2.23     $ 2.01  
Dividends Declared
  $ 1.27     $ 1.22     $ 1.18     $ 1.14     $ 1.10  
Dividends Paid
  $ 1.26     $ 1.21     $ 1.17     $ 1.13     $ 1.09  
Dividend Rate at Year-End
  $ 1.30     $ 1.24     $ 1.20     $ 1.16     $ 1.12  
At September 30:
                                       
Number of Registered Shareholders
    16,544       16,989       17,767       18,369       19,063  
                                         
Net Property, Plant and Equipment
                                       
Utility
  $ 1,125,859     $ 1,099,280     $ 1,084,080     $ 1,064,588     $ 1,048,428  
Pipeline and Storage
    826,528       681,940       674,175       680,574       696,487  
Exploration and Production(2)
    1,095,960       982,698       1,002,265       974,806       923,730  
Energy Marketing
    98       102       59       97       80  
Timber
    86,392       89,902       90,939       94,826       82,838  
All Other
    11,946       16,735       17,394       18,098       21,172  
Corporate(3)
    7,317       7,748       8,814       6,311       234,029  
                                         
Total Net Plant
  $ 3,154,100     $ 2,878,405     $ 2,877,726     $ 2,839,300     $ 3,006,764  
                                         
Total Assets
  $ 4,130,187     $ 3,888,412     $ 3,763,748     $ 3,749,753     $ 3,738,103  
                                         
Capitalization
                                       
Comprehensive Shareholders’ Equity
  $ 1,603,599     $ 1,630,119     $ 1,443,562     $ 1,229,583     $ 1,253,701  
Long-Term Debt, Net of Current Portion
    999,000       799,000       1,095,675       1,119,012       1,133,317  
                                         
Total Capitalization
  $ 2,602,599     $ 2,429,119     $ 2,539,237     $ 2,348,595     $ 2,387,018  
                                         
 
 
(1) Includes discontinued operations.
 
(2) Includes net plant of SECI discontinued operations as follows: $0 for 2008 and 2007, $88,023 for 2006, $170,929 for 2005, and $142,860 for 2004.
 
(3) Includes net plant of the former international segment as follows: $29 for 2008, $38 for 2007, $27 for 2006, $20 for 2005, and $227,905 for 2004.

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Item 7    Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
OVERVIEW
 
The Company is a diversified energy company and reports financial results for five business segments. Refer to Item 1, Business, for a more detailed description of each of the segments. This Item 7, MD&A, provides information concerning:
 
  1.  The critical accounting estimates of the Company;
 
  2.  Changes in revenues and earnings of the Company under the heading, “Results of Operations;”
 
  3.  Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity;”
 
  4.  Off-Balance Sheet Arrangements;
 
  5.  Contractual Obligations; and
 
  6.  Other Matters, including: (a) 2008 and 2009 funding for the Company’s pension and other post-retirement benefits, (b) realizability of deferred tax assets, (c) disclosures and tables concerning market risk sensitive instruments, (d) rate and regulatory matters in the Company’s New York, Pennsylvania and FERC regulated jurisdictions, (e) environmental matters, and (f) new accounting pronouncements.
 
The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report.
 
Overall, 2008 was a strong year for the Company. Income from continuing operations in 2008 benefited primarily from higher crude oil and natural gas prices in the Exploration and Production segment combined with an overall increase in natural gas production, primarily in the Appalachian region. These factors led to a $67.1 million increase in income from continuing operations compared to the prior year. In 2007, the Company recorded $135.8 million of income from discontinued operations, consisting of a $120.3 million gain, net of tax, on the sale of SECI and $15.5 million of income from SECI prior to its sale in August 2007. SECI, Seneca’s wholly owned subsidiary, was engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in the provinces of Alberta, Saskatchewan and British Columbia in Canada. Combining both income from continuing operations and discontinued operations, the Company’s net income available for common stock decreased $68.7 million in 2008 compared to the prior year. The Company’s earnings are discussed further in the Results of Operations section that follows.
 
The Company spent $414.5 million on capital expenditures during 2008, with approximately 46 percent being spent in the Exploration and Production segment and 40 percent being spent in the Pipeline and Storage segment. Management continues to believe that these segments provide the best earnings growth opportunities for shareholders. In the Exploration and Production segment, the Company’s principal focus continues to be the development of its nearly one million acres in the Appalachian region along with continued exploration and development in the Gulf and West Coast regions. In the Pipeline and Storage segment, the majority of the expenditures were for construction costs of the Empire Connector project. The Empire Connector is anticipated to be ready to commence service in December 2008 on or before the in-service date of the Millennium Pipeline. The Company’s capital expenditure program is discussed further in the Capital Resources and Liquidity section that follows.
 
Despite the positives mentioned above, the economy of the United States has become constrained by significant volatility and turmoil in the capital and credit markets. The government’s Troubled Asset Relief Program and decreases in federal funds rates have not been enough to stem the reluctance on the part of lenders to extend credit to businesses. In the current period these events have not had a material impact on the Company, although further disruption in the markets and tightening of credit availability could negatively impact future periods. At September 30, 2008, the Company had a strong balance sheet and liquidity. The Company had no outstanding short-term notes payable to banks or commercial paper at that date. However, since that date, the Company has borrowed short-term funds under its credit lines and through the commercial paper market to fund working capital needs. The Company maintains a number of individual uncommitted or


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discretionary lines of credit with certain 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. 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 that extends through September 30, 2010.
 
During 2006, the Company began repurchasing outstanding shares of common stock under a share repurchase program authorized by the Company’s Board of Directors. The program authorized the Company to repurchase up to an aggregate amount of eight million shares. This threshold was reached during 2008 for a total program cost of $324.2 million (of which 4,165,122 shares were repurchased during the year ended September 30, 2008 for $191.0 million). In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares. Under this new authorization, the Company repurchased 1,028,981 shares for $46.0 million through September 17, 2008. The Company 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.
 
During 2009, the Company expects to finance its capital expenditure program, dividends, and operating expenses (including Retirement Plan and other post-retirement benefit funding) with cash from operations, proceeds from the sale of assets, and/or short-term borrowings. As oil and gas commodity prices have decreased significantly from their highs during 2008, it is possible that the Company may have to rely more heavily on short-term borrowings to meet its cash needs. It is also possible that the Company may choose to reduce its 2009 capital expenditures.
 
With the turmoil in the credit markets has come a significant decline in the stock markets. This has had a significant impact on the asset values of the Company’s Retirement Plan and its VEBA trusts and 401(h) accounts. The Company anticipates funding $15.0 million to $20.0 million to the Retirement Plan and $25.0 million to $30.0 million to its VEBA trusts and 401(h) accounts during 2009. However, under the current funding requirements of the Pension Protection Act, should market conditions at September 30, 2008 remain unchanged, contributions in future years could increase significantly. This issue is discussed further in the Other Matters section that follows.
 
CRITICAL ACCOUNTING ESTIMATES
 
The Company has prepared its consolidated financial statements in conformity with GAAP. The preparation of these financial statements 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. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting estimates, which are defined as those estimates whereby judgments or uncertainties could affect the application of accounting policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Item 8 at Note A — Summary of Significant Accounting Policies.
 
Oil and Gas Exploration and Development Costs.   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 accounting 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.


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The Company believes that determining the amount of the Company’s proved reserves is a critical accounting estimate. Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full cost method of accounting (on a units-of-production basis). Unproved properties are excluded from the depletion calculation 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.
 
In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. 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. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in oil and gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. Because of the decline in the price of natural gas during the third and fourth quarters of 2006, the book value of the Company’s Canadian oil and gas properties exceeded the ceiling at both June 30, 2006 and September 30, 2006. Consequently, SECI recorded impairment charges of $62.4 million ($39.5 million after-tax) in the third quarter of 2006 and $42.3 million ($29.1 million after-tax) in the fourth quarter of 2006. These impairment charges are included in the loss from discontinued operations for 2006 due to the sale of SECI during 2007. At September 30, 2008, the ceiling exceeded the book value of the Company’s oil and gas properties by approximately $500 million. Declines in commodity prices since that date have reduced the ceiling. Using more up to date pricing of $6 per Mcf for natural gas and $60 per barrel for crude oil, the ceiling at September 30, 2008 would have exceeded the book value of the Company’s oil and gas properties by approximately $80 million.
 
It is difficult to predict what factors could lead to future impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations in or subtractions from proved reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.
 
Upon the adoption of SFAS 143 on October 1, 2002, the Company recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and capitalized such costs in property, plant and equipment (i.e. the full cost pool). Prior to the adoption of SFAS 143, plugging and abandonment costs were accounted for solely through the Company’s units-of-production depletion calculation. An estimate of such costs was added to the depletion base, which also included capitalized costs in the full cost pool and estimated future expenditures to be incurred in developing proved reserves. With the adoption of SFAS 143, plugging and abandonment costs are already


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included in capitalized costs and the units-of-production depletion calculation has been modified to exclude from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
 
Prior to the adoption of SFAS 143, in calculating the full cost ceiling, the Company reduced the future net cash flows from proved oil and gas reserves by the estimated plugging and abandonment costs. Such future net cash flows would then be compared to capitalized costs in the full cost pool, with any excess capitalized costs being expensed. With the adoption of SFAS 143, since the full cost pool now includes an amount associated with plugging and abandoning the wells, the calculation of the full cost ceiling has been changed so that future net cash flows from proved oil and gas reserves are no longer reduced by the estimated plugging and abandonment costs.
 
Regulation.   The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to SFAS 71, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows the Company to defer expenses and income on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratesetting process in a period different from the period in which they would have been reflected in the income statement by an unregulated company. These deferred regulatory assets and liabilities are then flowed through the income statement in the period in which the same amounts are reflected in rates. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note C — Regulatory Matters.
 
Accounting for Derivative Financial Instruments.   The Company, in its Exploration and Production segment, Energy Marketing segment, Pipeline and Storage segment and All Other category, 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, no cost collars and futures contracts. The Company, in its Pipeline and Storage segment, previously used an interest rate collar to limit interest rate fluctuations on certain variable rate debt. In accordance with the provisions of SFAS 133, the Company accounted for these instruments as effective cash flow hedges or fair value hedges. In 2007, the Company discontinued hedge accounting for the interest rate collar, which resulted in a gain being recognized. 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 fair values of the non exchange-traded derivative financial instruments are based on valuations determined by the counterparties. The Company used a model to substantiate the values reported by the counterparties. At September 30, 2008, the Company established a credit reserve of $0.6 million against the asset recorded on its books for non-exchange traded derivative financial instruments. The credit reserve was determined by applying default probabilities to the anticipated cash flows that the Company is expecting from its counterparties. Refer to the “Market Risk Sensitive Instruments” section below for further discussion of the Company’s derivative financial instruments.
 
Pension and Other Post-Retirement Benefits.   The amounts reported in the Company’s financial statements related to its pension and other post-retirement benefits are determined on an actuarial basis, which uses many assumptions in the calculation of such amounts. These assumptions include the discount rate, the expected return on plan assets, the rate of compensation increase and, for other post-retirement benefits, the expected


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annual rate of increase in per capita cost of covered medical and prescription benefits. The Company utilizes a yield curve model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year’s anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments. The expected return on plan assets assumption used by the Company reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets. Changes in actuarial assumptions and actuarial experience, including deviations between actual versus expected return on plan assets, could have a material impact on the amount of pension and post-retirement benefit costs and funding requirements experienced by the Company. However, the Company expects to recover substantially all of its net periodic pension and other post-retirement benefit costs attributable to employees in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization. For financial reporting purposes, the difference between the amounts of pension cost and post-retirement benefit cost recoverable in rates and the amounts of such costs as determined under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate, as discussed above under “Regulation.” Pension and post-retirement benefit costs for the Utility and Pipeline and Storage segments represented 97% and 93%, respectively, of the Company’s total pension and post-retirement benefit costs as determined under SFAS 87 and SFAS 106 for the years ended September 30, 2008 and 2007.
 
Changes in actuarial assumptions and actuarial experience could also have an impact on the benefit obligation and the funded status related to the Company’s pension and other post-retirement benefits and could impact the Company’s equity. For example, the discount rate was changed from 6.25% in 2007 to 6.75% in 2008. The change in the discount rate from 2007 to 2008 reduced the Retirement Plan projected benefit obligation by $38.6 million and the accumulated post-retirement benefit obligation by $26.3 million. Other examples include actual versus expected return on plan assets, which has an impact on the funded status of the plans, and actual versus expected benefit payments, which has an impact on the pension plan projected benefit obligation and the accumulated post-retirement benefit obligation. For 2008, actual versus expected return on plan assets resulted in a decrease to the funded status of the Retirement Plan ($94.2 million) and the VEBA trusts and 401(h) accounts ($77.2 million). The actual versus expected benefit payments for 2008 caused an increase of $0.1 million to the projected benefit obligation and a decrease of $3.6 million to the accumulated post-retirement benefit obligation, respectively. In calculating the projected benefit obligation for the Retirement Plan and the accumulated post-retirement obligation, the actuary takes into account the average remaining service life of active participants. The average remaining service life of active participants is 11 years for the Retirement Plan and 13 years for those eligible for other post-retirement benefits. For further discussion of the Company’s pension and other post-retirement benefits, refer to Other Matters in this Item 7, which includes a discussion of funding for the current year and the adoption of SFAS 158, and to Item 8 at Note G — Retirement Plan and Other Post Retirement Benefits.


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RESULTS OF OPERATIONS
 
EARNINGS
 
2008 Compared with 2007
 
The Company’s earnings were $268.7 million in 2008 compared with earnings of $337.5 million in 2007. As previously discussed, the Company presented its Canadian operations in the Exploration and Production segment (in conjunction with the sale of SECI) as discontinued operations. The Company’s earnings from continuing operations were $268.7 million in 2008 compared with $201.7 million in 2007. The Company’s earnings from discontinued operations were $135.8 million in 2007. The increase in earnings from continuing operations is primarily the result of higher earnings in the Exploration and Production and Utility segments and the All Other category, slightly offset by lower earnings in the Corporate category and the Timber, Pipeline and Storage, and Energy Marketing segments, as shown in the table below. In the discussion that follows, note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings from continuing operations and discontinued operations were impacted by several events in 2008 and 2007, including:
 
2008 Events
 
  •  A $0.6 million gain in the All Other category associated with the sale of Horizon Power’s gas-powered turbine;
 
2007 Events
 
  •  A $120.3 million gain on the sale of SECI, which was completed in August 2007. This amount is included in earnings from discontinued operations;
 
  •  A $4.8 million benefit to earnings in the Pipeline and Storage segment due to the reversal of a reserve established for all costs incurred related to the Empire Connector project recognized during June 2007;
 
  •  A $1.9 million benefit to earnings in the Pipeline and Storage segment associated with the discontinuance of hedge accounting for Empire’s interest rate collar; and
 
  •  A $2.3 million benefit to earnings in the Energy Marketing segment related to the resolution of a purchased gas contingency.
 
2007 Compared with 2006
 
The Company’s earnings were $337.5 million in 2007 compared with earnings of $138.1 million in 2006. As previously discussed, the Company has presented its Canadian operations in the Exploration and Production segment (in conjunction with the sale of SECI) as discontinued operations. The Company’s earnings from continuing operations were $201.7 million in 2007 compared with $184.6 million in 2006. The Company’s earnings from discontinued operations were $135.8 million in 2007 compared with a loss of $46.5 million in 2006. The increase in earnings from continuing operations of $17.1 million is primarily the result of higher earnings in the Exploration and Production, Utility, Pipeline and Storage, and Energy Marketing segments and the Corporate and All Other categories, slightly offset by lower earnings in the Timber segment, as shown in the table below. The increase in earnings from discontinued operations primarily resulted from the gain on the sale of SECI recognized in 2007 as well as the non-recurrence of $68.6 million of impairment charges recognized in 2006 related to the Exploration and Production segment’s Canadian oil and gas assets. Earnings from continuing operations and discontinued operations were impacted by several events discussed above and the following 2006 events:


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2006 Events
 
  •  $68.6 million of impairment charges related to the Exploration and Production segment’s Canadian oil and gas assets under the full cost method of accounting using natural gas pricing at June 30, 2006 and September 30, 2006;
 
  •  An $11.2 million benefit to earnings in the Exploration and Production segment ($6.1 million in continuing operations and $5.1 million in discontinued operations) related to income tax adjustments recognized during 2006; and
 
  •  A $2.6 million benefit to earnings in the Utility segment related to the correction of Distribution Corporation’s calculation of the symmetrical sharing component of New York’s gas adjustment rate.
 
Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.
 
Earnings (Loss) by Segment
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands)  
 
Utility
  $ 61,472     $ 50,886     $ 49,815  
Pipeline and Storage
    54,148       56,386       55,633  
Exploration and Production
    146,612       74,889       67,494  
Energy Marketing
    5,889       7,663       5,798  
Timber
    107       3,728       5,704  
                         
Total Reported Segments
    268,228       193,552       184,444  
All Other
    5,672       2,564       359  
Corporate
    (5,172 )     5,559       (189 )
                         
Total Earnings from Continuing Operations
    268,728       201,675       184,614  
Earnings (Loss) from Discontinued Operations
          135,780       (46,523 )
                         
Total Consolidated
  $ 268,728     $ 337,455     $ 138,091  
                         
 
UTILITY
 
Revenues
 
Utility Operating Revenues
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands)  
 
Retail Revenues:
                       
Residential
  $ 876,677     $ 848,693     $ 993,928  
Commercial
    135,361       136,863       166,779  
Industrial
    7,419       8,271       13,484  
                         
      1,019,457       993,827       1,174,191  
                         
Off-System Sales
    58,225       9,751        
Transportation
    113,901       102,534       92,569  
Other
    18,686       14,612       14,003  
                         
    $ 1,210,269     $ 1,120,724     $ 1,280,763  
                         


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Utility Throughput — million cubic feet (MMcf)
 
                         
    Year Ended September 30  
    2008     2007     2006  
 
Retail Sales:
                       
Residential
    57,463       60,236       59,443  
Commercial
    9,769       10,713       10,681  
Industrial
    552       727       985  
                         
      67,784       71,676       71,109  
                         
Off-System Sales
    5,686       1,355        
Transportation
    64,267       62,240       57,950  
                         
      137,737       135,271       129,059  
                         
 
Degree Days
 
                                         
                      Percent (Warmer)
 
                      Colder Than  
Year Ended September 30
        Normal     Actual     Normal     Prior Year  
 
2008:
    Buffalo       6,729       6,277       (6.7 )%     0.1 %
      Erie       6,277       5,779       (7.9 )%     (3.8 )%
2007:
    Buffalo       6,692       6,271       (6.3 )%     5.1 %
      Erie       6,243       6,007       (3.8 )%     5.6 %
2006:
    Buffalo       6,692       5,968       (10.8 )%     (9.4 )%
      Erie       6,243       5,688       (8.9 )%     (8.9 )%
 
2008 Compared with 2007
 
Operating revenues for the Utility segment increased $89.5 million in 2008 compared with 2007. This increase largely resulted from a $48.5 million increase in off-system sales revenue (see discussion below), a $25.6 million increase in retail gas sales revenues, an $11.3 million increase in transportation revenues, and a $4.1 million increase in other operating revenues.
 
The increase in retail gas sales revenues for the Utility segment was largely a function of the recovery of higher gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues), which more than offset the revenue impact of lower retail sales volumes, as shown in the table above. See further discussion of purchased gas below under the heading “Purchased Gas.” This change was also affected by a base rate increase in the Pennsylvania jurisdiction (effective January 2007) that increased operating revenues by $4.0 million for 2008. The increase is included within both retail and transportation revenues in the table above.
 
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. This rate design change resulted in lower retail and transportation revenues (exclusive of the impact of higher gas costs) during the winter months compared to the prior year and higher retail and transportation revenues in the spring and summer months compared to the prior year. On a cumulative basis for 2008, the impact of this rate order has been to lower operating revenues by $1.4 million. It is expected that there will be an increase in retail and transportation revenue in the first quarter of 2009 compared to the prior year as a result of the rate design change. The increase in transportation revenues was also due to a 2.0 Bcf increase in transportation throughput, largely the result of the migration of customers from retail sales to transportation service.
 
As reported in 2006, on November 17, 2006 the U.S. Court of Appeals vacated and remanded the FERC’s Order No. 2004 regarding affiliate standards of conduct, with respect to natural gas pipelines. The Court’s


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decision became effective on January 5, 2007, and on January 9, 2007, the FERC issued Order No. 690, its Interim Rule, designed to respond to the Court’s decision. In Order No. 690, as clarified by the FERC on March 21, 2007, the FERC readopted, on an interim basis, certain provisions that existed prior to the issuance of Order No. 2004 that had made it possible for the Utility segment to engage in certain off-system sales without triggering the adverse consequences that would otherwise arise under the Order No. 2004 standards of conduct. As a result, the Utility segment resumed engaging in off-system sales on non-affiliated pipelines as of May 2007, resulting in total off-system sales revenues of $58.2 million and $9.8 million for 2008 and 2007, respectively. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was not a material impact to margins in 2008 and 2007.
 
The increase in other operating revenues of $4.1 million is largely related to amounts recorded pursuant to rate settlements approved by the NYPSC. In accordance with these settlements, Distribution Corporation was allowed to utilize certain refunds from upstream pipeline companies and certain other credits (referred to as the “cost mitigation reserve”) to offset certain specific expense items. In 2008, Distribution Corporation utilized $5.6 million of the cost mitigation reserve, which increased other operating revenues, to recover previous undercollections of pension expenses. The impact of that increase in other operating revenues was offset by an equal amount of operation and maintenance expense (thus there is no earnings impact).
 
2007 Compared with 2006
 
Operating revenues for the Utility segment decreased $160.0 million in 2007 compared with 2006. This decrease largely resulted from a $180.4 million decrease in retail gas sales revenues. This decrease was partially offset by a $10.0 million increase in transportation revenues and a $9.8 million increase in off-system sales revenues.
 
The decrease in retail gas sales revenues for the Utility segment was largely a function of the recovery of lower gas costs (gas costs are recovered dollar for dollar in revenues), which more than offset the revenue impact of higher retail sales volumes, as shown in the table above. See further discussion of purchased gas below under the heading “Purchased Gas.” This decrease was offset slightly by a base rate increase in the Pennsylvania jurisdiction, effective January 2007, which increased operating revenues by $8.5 million for 2007. The increase is included within both retail and transportation revenues in the table above.
 
The increase in transportation revenues was primarily due to a 4.3 Bcf increase in transportation throughput, largely due to the migration of retail sales customers to transportation service. The corresponding $10.0 million increase in transportation revenues would have been greater if not for a $3.9 million out-of-period adjustment recorded in the first quarter of 2006 to correct Distribution Corporation’s calculation of the symmetrical sharing component of New York’s gas adjustment rate.
 
The increase in off-system sales revenue is due to the resumption of off-system sales in May 2007 pursuant to FERC authorization, as discussed above.
 
Purchased Gas
 
The cost of purchased gas is the Company’s single largest operating expense. Annual variations in purchased gas costs are attributed directly to changes in gas sales volumes, the price of gas purchased and the operation of purchased gas adjustment clauses.
 
Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation and six other upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers, and for storage service with Supply Corporation and three nonaffiliated companies. In addition, Distribution Corporation satisfies a portion of its gas requirements through spot market purchases. Changes in wellhead prices have a direct impact on the cost of purchased gas. Distribution Corporation’s average cost of purchased gas, including the cost of transportation and storage, was $11.23 per Mcf in 2008, an increase of 12% from the average cost of $10.04 per Mcf in 2007. The average cost of purchased gas in 2007 was 17% lower than the average cost of $12.07 per Mcf in 2006. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.


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Earnings
 
2008 Compared with 2007
 
The Utility segment’s earnings in 2008 were $61.5 million, an increase of $10.6 million when compared with earnings of $50.9 million in 2007.
 
In the New York jurisdiction, earnings increased by $6.9 million. This was primarily due to a $3.6 million overall decrease in operating expenses (mostly other post-retirement benefits and bad debt expense), higher non-cash interest income on a pension-related regulatory asset ($2.6 million), a decrease in property, franchise, and other taxes ($0.9 million), a decrease in depreciation expense ($0.8 million), lower income tax expense ($0.7 million), lower interest expense ($0.2 million), and increased usage per account ($0.5 million). The impact of these items more than offset lower base rates due to the rate design change described above ($0.9 million), and routine regulatory adjustments that reduced earnings by $1.8 million.
 
In the Pennsylvania jurisdiction, earnings increased by $3.7 million. This was primarily due to a base rate increase ($2.6 million) that became effective January 2007, an increase in normalized usage ($1.3 million), a decrease in bad debt expense ($1.1 million), and a decrease in property, franchise, and other taxes ($0.3 million). Warmer weather ($1.6 million) partially offset these increases.
 
The impact of weather on the Utility segment’s New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. In 2008 and 2007, the WNC preserved earnings of approximately $2.5 million and $2.3 million, respectively, as the weather was warmer than normal.
 
2007 Compared with 2006
 
The Utility segment’s earnings in 2007 were $50.9 million, an increase of $1.1 million when compared with earnings of $49.8 million in 2006.
 
In the New York jurisdiction, earnings decreased by $6.2 million. This was primarily due to lower interest income ($4.5 million). The New York division’s current rate agreement with the NYPSC allows the Company to accrue interest on a pension-related regulatory asset. The amount of interest that can be accrued is reduced as the funded status of the pension plan improves. The fair market value of the pension plan assets exceeded the accumulated benefit obligation at September 30, 2007 resulting in a significant reduction in the interest accrual on this regulatory asset. The out-of-period symmetrical sharing adjustment discussed above ($2.6 million), higher bad debt and other operating costs ($0.8 million), higher property taxes ($0.6 million), and higher interest expense ($0.5 million) also contributed to this decrease. The positive impact associated with a lower effective tax rate ($1.9 million) and increased usage per account ($1.9 million) partially offset the overall decrease.
 
In the Pennsylvania jurisdiction, earnings increased by $7.3 million. This was primarily due to a base rate increase ($5.5 million) that became effective January 2007, colder weather ($2.5 million), and the positive impact associated with a lower effective tax rate ($1.1 million). Higher intercompany and other interest expense ($0.8 million), coupled with a decrease in normalized usage ($0.3 million), partially offset these increases.
 
The impact of weather on the Utility segment’s New York rate jurisdiction is tempered by a WNC. The WNC, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. In 2007 and 2006, the WNC preserved earnings of approximately $2.3 million and $6.2 million, respectively, as the weather was warmer than normal.


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PIPELINE AND STORAGE
 
Revenues
 
Pipeline and Storage Operating Revenues
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands)  
 
Firm Transportation
  $ 122,321     $ 118,771     $ 118,551  
Interruptible Transportation
    4,330       4,161       4,858  
                         
      126,651       122,932       123,409  
                         
Firm Storage Service
    67,020       66,966       66,718  
Interruptible Storage Service
    14       169       39  
                         
      67,034       67,135       66,757  
Other
    22,871       21,899       24,186  
                         
    $ 216,556     $ 211,966     $ 214,352  
                         
 
Pipeline and Storage Throughput — (MMcf)
 
                         
    Year Ended September 30  
    2008     2007     2006  
 
Firm Transportation
    353,173       351,113       363,379  
Interruptible Transportation
    5,197       4,975       11,609  
                         
      358,370       356,088       374,988  
                         
 
2008 Compared with 2007
 
Operating revenues for the Pipeline and Storage segment increased $4.6 million in 2008 as compared with 2007. The majority of the increase was the result of increased transportation revenues ($3.7 million) due to the fact that the Pipeline & Storage segment was able to renew existing contracts at higher rates due to favorable market conditions for transportation service associated with storage. In addition, there were increased efficiency gas revenues ($0.8 million) reported as part of other revenues in the table above. The majority of this increase was due to higher gas prices in the current year.
 
2007 Compared with 2006
 
Operating revenues for the Pipeline and Storage segment decreased $2.4 million in 2007 as compared with 2006, which was due mostly to a decrease in other revenues ($2.3 million). The decrease in other revenues is primarily due to a $4.2 million decrease in efficiency gas revenues. This decrease was due to the Company’s recent settlement with the FERC, which decreased efficiency gas retainage allowances. Offsetting this decrease, there was a $1.4 million increase in other revenues attributable to the lease termination fee adjustment in 2006 (an intercompany transaction) for the Company’s former headquarters, which did not recur in 2007. While Supply Corporation’s transportation volumes decreased during the year, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight-fixed variable rate design.
 
Earnings
 
2008 Compared with 2007
 
The Pipeline and Storage segment’s earnings in 2008 were $54.1 million, a decrease of $2.2 million when compared with earnings of $56.4 million in 2007. The main factors contributing to this decrease were higher operation and maintenance expenses ($6.1 million), primarily caused by the non-recurrence in 2008 of a reversal of a reserve for preliminary survey costs related to the Empire Connector project during 2007


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($4.8 million). In addition, there was a $1.9 million positive earnings impact during 2007 associated with the discontinuance of hedge accounting for Empire’s interest rate collar that did not recur during 2008, and the Pipeline and Storage segment experienced higher interest costs ($1.5 million). These earnings decreases were offset by the earnings impact associated with higher transportation revenues ($2.4 million), an increase in the allowance for funds used during construction ($4.2 million) and the earnings impact associated with higher efficiency gas revenues ($0.5 million).
 
2007 Compared with 2006
 
The Pipeline and Storage segment’s earnings in 2007 were $56.4 million, an increase of $0.8 million when compared with earnings of $55.6 million in 2006. The main factor contributing to this increase was the reversal of a reserve for preliminary survey costs ($4.8 million) related to the Empire Connector project. Based on the signing of a service agreement with KeySpan Gas East Corporation during the quarter ended June 30, 2007, management determined that it was probable that the project would go forward and that such preliminary survey costs were properly capitalizable in accordance with the FERC’s Uniform System of Accounts and SFAS 71. In addition, there was a $2.5 million increase in earnings associated with the decrease in depreciation expense as a result of the most recent settlement with the FERC, which reduced depreciation rates. There was also a $1.9 million positive earnings impact associated with the discontinuance of hedge accounting for Empire’s interest rate collar. On December 8, 2006, Empire repaid $22.8 million of secured debt. The interest costs of this secured debt were hedged by the interest rate collar. Since the hedged transaction was settled and there will be no future cash flows associated with the secured debt, the unrealized gain in accumulated other comprehensive income associated with the interest rate collar was reclassified to the income statement. These earnings increases were offset by higher interest expense ($3.2 million), the earnings impact associated with lower efficiency gas revenues ($2.7 million), a $1.5 million increase in operating costs (primarily post-retirement benefit costs), and the earnings decrease associated with a higher effective tax rate ($0.9 million).
 
EXPLORATION AND PRODUCTION
 
Revenues
 
Exploration and Production Operating Revenues
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands)  
 
Gas (after Hedging) from Continuing Operations
  $ 202,153     $ 143,785     $ 126,969  
Oil (after Hedging) from Continuing Operations
    250,965       167,627       134,307  
Gas Processing Plant from Continuing Operations
    49,090       37,528       42,252  
Other from Continuing Operations
    (944 )     1,147       3,072  
Intrasegment Elimination from Continuing Operations(1)
    (34,504 )     (26,050 )     (31,704 )
                         
Operating Revenues from Continuing Operations
  $ 466,760     $ 324,037     $ 274,896  
                         
Operating Revenues from Canada — Discontinued Operations
  $     $ 50,495     $ 71,984  
                         
 
 
(1) Represents the elimination of certain West Coast gas production revenue included in “Gas (after Hedging) from Continuing Operations” in the table above that is sold to the gas processing plant shown in the table above. An elimination for the same dollar amount was made to reduce the gas processing plant’s Purchased Gas expense.


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Production Volumes
 
                         
    Year Ended September 30  
    2008     2007     2006  
 
Gas Production (MMcf)
                       
Gulf Coast
    11,033       10,356       9,110  
West Coast
    4,039       3,929       3,880  
Appalachia
    7,269       5,555       5,108  
                         
Total Production from Continuing Operations
    22,341       19,840       18,098  
Canada — Discontinued Operations
          6,426       7,673  
                         
Total Production
    22,341       26,266       25,771  
                         
Oil Production (Mbbl)
                       
Gulf Coast
    505       717       685  
West Coast
    2,460       2,403       2,582  
Appalachia
    105       124       69  
                         
Total Production from Continuing Operations
    3,070       3,244       3,336  
Canada — Discontinued Operations
          206       272  
                         
Total Production
    3,070       3,450       3,608  
                         
 
Average Prices
 
                         
    Year Ended September 30  
    2008     2007     2006  
 
Average Gas Price/Mcf
                       
Gulf Coast
  $ 10.03     $ 6.58     $ 8.01  
West Coast
  $ 8.71     $ 6.54     $ 7.93  
Appalachia
  $ 9.73     $ 7.48     $ 9.53  
Weighted Average for Continuing Operations
  $ 9.70     $ 6.82     $ 8.42  
Weighted Average After Hedging for Continuing Operations(1)
  $ 9.05     $ 7.25     $ 7.02  
Canada — Discontinued Operations
  $     $ 6.09     $ 7.14  
Average Oil Price/Barrel (bbl)
                       
Gulf Coast
  $ 107.27     $ 63.04     $ 64.10  
West Coast(2)
  $ 98.17     $ 56.86     $ 56.80  
Appalachia
  $ 97.40     $ 62.26     $ 65.28  
Weighted Average for Continuing Operations
  $ 99.64     $ 58.43     $ 58.47  
Weighted Average After Hedging for Continuing Operations(1)
  $ 81.75     $ 51.68     $ 40.26  
Canada — Discontinued Operations
  $     $ 50.06     $ 51.40  
 
 
(1) Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note F — Financial Instruments in Item 8 of this report.
 
(2) Includes low gravity oil which generally sells for a lower price.
 
2008 Compared with 2007
 
Operating revenues from continuing operations for the Exploration and Production segment increased $142.7 million in 2008 as compared with 2007. Oil production revenue after hedging from continuing operations increased $83.3 million due primarily to a $30.07 per barrel increase in weighted average prices after hedging, which more than offset a decrease in oil production of 174,000 barrels. Gas production revenue


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after hedging from continuing operations increased $58.4 million due to a $1.80 per Mcf increase in weighted average prices after hedging and a 2,501 MMcf increase in production. The increase in gas production from continuing operations occurred primarily in the Appalachian region (1,714 MMcf), consistent with increased drilling activity in the region. The Gulf Coast region also contributed significantly to the increase in natural gas production from continuing operations (677 MMcf). Production from new fields in 2008 (primarily in the High Island area) outpaced declines in production from some existing fields, period to period. Production in this region would have been higher if not for the hurricane activity during the month of September 2008. As a result of hurricanes Edouard, Gustav and Ike, production was shut in for much of the month of September, resulting in estimated lost production of approximately 804 MMcf of natural gas and 45 Mbbl of oil. While Seneca’s properties sustained only superficial damage from the hurricanes, approximately 50% of the pre-hurricane production remains shut-in due to repair work on third party pipelines and onshore processing facilities. The majority of this production is anticipated to return by December 1, 2008.
 
Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.
 
2007 Compared with 2006
 
Operating revenues from continuing operations for the Exploration and Production segment increased $49.1 million in 2007 as compared with 2006. Oil production revenue after hedging increased $33.3 million due primarily to an $11.42 per barrel increase in weighted average prices after hedging, which more than offset a slight decrease in oil production of 92,000 barrels. Gas production revenue after hedging increased $16.8 million in 2007 as compared with 2006. An increase in gas production of 1,742 MMcf and an increase in weighted average prices after hedging of $0.23 per Mcf both contributed to the increase. The increase in gas production occurred primarily in the Gulf Coast region (1,246 MMcf). During the quarter ended December 31, 2005, Seneca experienced significant production delays due largely to the impact of hurricane damage to pipeline infrastructure in the Gulf of Mexico. Seneca had substantially all of its pre-hurricane Gulf of Mexico production back on line at the beginning of fiscal 2007. Production also increased in this segment’s Appalachian region (447 MMcf), primarily due to increased drilling in this region during 2007, as highlighted in Item 2 under “Exploration and Production Activities.”
 
Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.
 
Earnings
 
2008 Compared with 2007
 
The Exploration and Production segment’s earnings from continuing operations for 2008 were $146.6 million, an increase of $71.7 million when compared with earnings from continuing operations of $74.9 million for 2007. Higher crude oil prices, higher natural gas prices and higher natural gas production increased earnings by $60.0 million, $26.2 million and $11.8 million, respectively, while lower crude oil production decreased earnings by $5.8 million. Higher lease operating costs ($11.9 million), higher depletion expense ($9.1 million), higher income tax expense ($1.1 million) and higher general and administrative and other operating expenses ($6.2 million) also negatively impacted earnings. Lower interest expense and higher interest income of $6.6 million and $0.7 million, respectively, partially offset these decreases to earnings. The increase in lease operating costs resulted from the start-up of production at the High Island 24L field in October 2007, higher steaming costs in California, and an increase in costs associated with a higher number of producing properties in Appalachia. The increase in depletion expense was caused by higher production and an increase in the depletable base. The increase in general and administrative and other operating expenses resulted from an increase in staffing and associated costs for the growing Appalachia division combined with the recognition of actual plugging costs in excess of previously accrued amounts.


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2007 Compared with 2006
 
The Exploration and Production segment’s earnings from continuing operations for 2007 were $74.9 million, an increase of $7.4 million when compared with earnings from continuing operations of $67.5 million for 2006. Higher crude oil prices, higher natural gas production and higher natural gas prices increased earnings by $24.1 million, $7.9 million and $3.0 million, respectively. These increases were partly offset by the non-recurrence of $6.1 million of tax benefits recognized during 2006, as well as by higher depletion expense and higher lease operating expense of $7.2 million and $4.6 million, respectively. Slightly lower crude oil production and higher general and administrative expenses also decreased earnings by $2.4 million and $0.6 million, respectively. Earnings were also negatively impacted by higher income tax expense ($6.3 million).
 
ENERGY MARKETING
 
Revenues
 
Energy Marketing Operating Revenues
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands)  
 
Natural Gas (after Hedging)
  $ 551,243     $ 413,405     $ 496,769  
Other
    (11 )     207       300  
                         
    $ 551,232     $ 413,612     $ 497,069  
                         
 
Energy Marketing Volumes
 
                         
    Year Ended September 30  
    2008     2007     2006  
 
Natural Gas — (MMcf)
    56,120       50,775       45,270  
 
2008 Compared with 2007
 
Operating revenues for the Energy Marketing segment increased $137.6 million in 2008 as compared with 2007. The increase is primarily due to higher gas sales revenue, as a result of an increase in the price of natural gas that was recovered through revenues, coupled with an increase in volumes. The increase in volumes is primarily attributable to an increase in volumes sold to low-margin wholesale customers, as well as an increase in the number of commercial and industrial customers served by the Energy Marketing segment. The increase in volumes also reflects certain sales transactions undertaken to offset certain basis risks that the Energy Marketing segment was exposed to under certain commodity purchase contracts. The offsetting purchase and sale transactions had the effect of increasing revenue and volumes sold with minimal impact to earnings.
 
2007 Compared with 2006
 
Operating revenues for the Energy Marketing segment decreased $83.5 million in 2007 as compared with 2006. The decrease primarily reflects lower gas sales revenue due to a decrease in natural gas commodity prices for the period that were recovered through revenues, offset in part by an increase in volumes. The increase in volumes was due to the addition of certain large, low-margin commercial and industrial customers, an increase in sales to wholesale customers, and colder weather.
 
Earnings
 
2008 Compared with 2007
 
The Energy Marketing segment’s earnings in 2008 were $5.9 million, a decrease of $1.8 million when compared with earnings of $7.7 million in 2007. Higher operating costs of $1.1 million (primarily due to an increase in bad debt expense) coupled with lower margins of $1.1 million are primarily responsible for the decrease in earnings. A major factor in the margin decrease is the non-recurrence of a purchased gas expense


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adjustment recorded during the quarter ended March 31, 2007. During that quarter, the Energy Marketing segment reversed an accrual for $2.3 million of purchased gas expense due to a resolution of a contingency. The increase in volumes noted above, the profitable sale of certain gas held as inventory, and the marketing flexibility that the Energy Marketing segment derives from its contracts for significant storage capacity partially offset the margin decrease associated with the purchased gas adjustment.
 
2007 Compared with 2006
 
The Energy Marketing segment’s earnings in 2007 were $7.7 million, an increase of $1.9 million when compared with earnings of $5.8 million in 2006. Higher margins of $2.3 million are responsible for the increase in earnings. The increase in margin is mainly the result of a $2.3 million reversal of an accrual for purchased gas expense related to the resolution of a contingency during 2007. While volumes increased, as noted above, much of this increase in volume is related to sales to low margin customers.
 
TIMBER
 
Revenues
 
Timber Operating Revenues
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands)  
 
Log Sales
  $ 19,989     $ 21,927     $ 23,077  
Green Lumber Sales
    4,864       5,097       7,123  
Kiln-Dried Lumber Sales
    22,914       27,908       32,809  
Other
    1,749       3,965       2,020  
                         
    $ 49,516     $ 58,897     $ 65,029  
                         
 
Timber Board Feet
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands)  
 
Log Sales
    9,272       8,660       9,527  
Green Lumber Sales
    9,747       9,358       10,454  
Kiln-Dried Lumber Sales
    13,425       14,778       16,862  
                         
      32,444       32,796       36,843  
                         
 
2008 Compared with 2007
 
Operating revenues for the Timber segment decreased $9.4 million in 2008 as compared with 2007. Unfavorable market conditions for cherry logs and lumber combined with wet weather conditions that hampered harvesting were the main factors causing the decrease. The decrease consisted of a $5.0 million decline in kiln-dried lumber sales. The decrease in kiln-dried lumber sales was due to both a decline in the market price of kiln-dried lumber as well as a 1,353,000 board feet decline in kiln-dried lumber sales volumes (primarily kiln-dried cherry lumber sales volumes). Log sales also decreased $1.9 million primarily due to a decline in cherry veneer log sales volumes of 328,000 board feet. Cherry veneer logs are more valuable and sell at higher prices than other species and have the largest impact on overall log sales revenue. In addition, in 2007 the Timber segment sold 3.1 million board feet of timber rights and recorded a gain of $1.6 million in other revenues. This event did not recur in 2008.


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2007 Compared with 2006
 
Operating revenues for the Timber segment decreased $6.1 million in 2007 as compared with 2006. This decrease is attributed to unfavorable weather conditions primarily during the fall of 2006 and the spring of 2007 that greatly limited the harvesting of logs. These conditions consisted of warm, wet weather that made it difficult to bring logging trucks into the forests. Weather conditions were significantly more favorable throughout fiscal 2006. These unfavorable conditions for harvesting resulted in a decline in log sales of $1.2 million or 867,000 board feet. There was also a decline in both green lumber and kiln-dried lumber sales of $2.0 million and $4.9 million, respectively, primarily because there were fewer logs available for processing. Declines in market prices for the cherry and maple species also contributed to the decrease in green lumber and kiln-dried lumber sales. Additionally, the processing of a greater amount of lumber species other than cherry (due to the mix of species on the areas being harvested) contributed to the decline in kiln-dried lumber sales since lumber species other than cherry are sold at a lower price than kiln-dried cherry lumber. Offsetting the decreases discussed above, other revenues increased $1.9 million largely due to the sale of 3.1 million board feet of timber rights ($1.6 million).
 
Earnings
 
2008 Compared with 2007
 
The Timber segment earnings in 2008 were $0.1 million, a decrease of $3.6 million when compared with earnings of $3.7 million in 2007. The decrease was primarily due to lower margins from lumber, log and timber rights sales ($4.2 million) as a result of the decline in revenues noted above. This decrease was partially offset by the earnings benefit associated with a lower effective tax rate ($0.8 million).
 
2007 Compared with 2006
 
The Timber segment earnings in 2007 were $3.7 million, a decrease of $2.0 million when compared with earnings of $5.7 million in 2006. The decrease was primarily due to lower margins from lumber and log sales ($2.5 million) as a result of the decline in revenues noted above, as well as higher general and administrative expenses of $0.3 million. Partially offsetting this decrease was a decline in depletion expense of $1.2 million. The decrease in depletion expense reflects the cutting of more low cost or no cost basis timber from Company owned land as well as the overall decrease in logs harvested.
 
ALL OTHER AND CORPORATE OPERATIONS
 
All Other and Corporate operations primarily includes the operations of Horizon LFG, Horizon Power, former International segment activity and corporate operations. Horizon LFG owns and operates short-distance landfill gas pipeline companies. Horizon Power’s activity primarily consists of equity method investments in Seneca Energy, Model City and ESNE. Horizon Power has a 50% ownership interest in each of these entities. The income from these equity method investments is reported as Income from Unconsolidated Subsidiaries on the Consolidated Statements of Income. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania.
 
Earnings
 
2008 Compared with 2007
 
All Other and Corporate operations had earnings of $0.5 million in 2008, a decrease of $7.6 million compared with earnings of $8.1 million for 2007. The positive earnings impact of higher income from unconsolidated subsidiaries ($0.9 million) and a gain on the sale of a turbine by Horizon Power ($0.6 million) were more than offset by higher operating costs ($6.1 million), higher income tax expense ($1.7 million) and lower interest income ($1.3 million). The increase in operating costs is primarily the result of the proxy contest with New Mountain Vantage GP, L.L.C.


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2007 Compared with 2006
 
All Other and Corporate operations had earnings of $8.1 million in 2007, an increase of $7.9 million compared with earnings of $0.2 million for 2006. This improvement was largely due to an increase in interest income of $4.1 million (primarily intercompany interest). In the All Other category, Horizon LFG’s earnings benefited from higher margins of $1.0 million in 2007 as compared to 2006, and Horizon Power’s income from unconsolidated subsidiaries increased $0.9 million, also contributing to the increase in earnings. The Corporate and All Other categories also had an earnings benefit associated with lower income tax expense ($2.0 million).
 
INTEREST INCOME
 
Interest income was $9.3 million higher in 2008 as compared to 2007. The main reason for this increase was a $4.0 million increase in interest income on a pension-related regulatory asset in the Utility segment’s New York jurisdiction. The Exploration and Production segment also contributed $3.8 million to this increase as a result of the investment of cash proceeds from the sale of SECI in August 2007.
 
Interest income was $7.9 million lower in 2007 as compared to 2006. As discussed in the Utility earnings section above, the main reason for this decrease was a $7.4 million decrease in interest income on a pension-related regulatory asset in the Utility segment’s New York jurisdiction.
 
OTHER INCOME
 
Other income was $2.4 million higher in 2008 as compared to 2007. This increase is attributed to the increase in the allowance for funds used during construction, in the Pipeline and Storage segment, associated with the Empire Connector project of $4.2 million. This increase was partially offset by the non-recurrence of a death benefit gain on life insurance proceeds of $1.9 million recognized in the Corporate category in 2007.
 
Other income was $2.1 million higher in 2007 as compared to 2006. The increase is attributed to a death benefit gain on life insurance proceeds of $1.9 million recognized in the Corporate category.
 
INTEREST CHARGES
 
Although most of the variances in Interest Charges are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis:
 
Interest on long-term debt increased $1.7 million in 2008 as compared to 2007. The increase in 2008 was primarily the result of 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.
 
Interest on long-term debt decreased $4.2 million in 2007 as compared to 2006. The decrease in 2007 was primarily the result of a lower average amount of long-term debt outstanding. In addition, the Company recognized a $1.9 million benefit to interest expense as a result of the discontinuance of hedge accounting for Empire’s interest rate collar, as discussed above under Pipeline and Storage. The underlying long-term debt associated with this interest rate collar was repaid in December 2006 and the unrealized gain recorded in accumulated other comprehensive income associated with the interest rate collar was reclassified to interest expense during the quarter ended December 31, 2006.
 
Other interest charges decreased $2.2 million in 2008 compared to 2007. Other interest charges did not change significantly in 2007 as compared to 2006. The decrease in 2008 was primarily caused by a $1.7 million increase in the allowance for borrowed funds used during construction related to the Empire Connector project.


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CAPITAL RESOURCES AND LIQUIDITY
 
The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
 
Sources (Uses) of Cash
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Millions)  
 
Provided by Operating Activities
  $ 482.8     $ 394.2     $ 471.4  
Capital Expenditures
    (397.7 )     (276.7 )     (294.2 )
Investment in Partnership
          (3.3 )      
Net Proceeds from Sale of Foreign Subsidiaries
          232.1        
Cash Held in Escrow
    58.4       (58.2 )      
Net Proceeds from Sale of Oil and Gas Producing Properties
    5.9       5.1        
Other Investing Activities
    4.4       (0.8 )     (3.2 )
Reduction of Long-Term Debt
    (200.0 )     (119.6 )     (9.8 )
Net Proceeds from Issuance of Long-Term Debt
    296.6              
Issuance of Common Stock
    17.4       17.5       23.3  
Dividends Paid on Common Stock
    (103.7 )     (100.6 )     (98.2 )
Excess Tax Benefits Associated with Stock- Based Compensation Awards
    16.3       13.7       6.5  
Shares Repurchased under Repurchase Plan
    (237.0 )     (48.1 )     (85.2 )
Effect of Exchange Rates on Cash
          (0.1 )     1.4  
                         
Net Increase (Decrease) in Cash and Temporary Cash Investments
  $ (56.6 )   $ 55.2     $ 12.0  
                         
 
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 partnership, deferred income taxes, income or loss from unconsolidated subsidiaries net of cash distributions and gain on sale of discontinued operations.
 
Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, 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.
 
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 $482.8 million in 2008, an increase of $88.6 million compared with the $394.2 million provided by operating activities in 2007. The increase is partially due to lower working capital requirements in the Utility segment. In the Exploration and Production segment, cash provided by operations increased due to higher commodity prices, partially offset by the decrease in cash provided by operations that resulted from the sale of SECI in August 2007. Offsetting these increases were higher working capital requirements in the Energy Marketing segment.


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INVESTING CASH FLOW
 
Expenditures for Long-Lived Assets
 
The Company’s expenditures for long-lived assets totaled $414.5 million in 2008. The table below presents these expenditures:
 
         
    Year Ended
 
    September 30,
 
    2008  
    Total Expenditures
 
    For Long-Lived
 
    Assets  
    (Millions)  
 
Utility
  $ 57.5  
Pipeline and Storage(1)
    165.5  
Exploration and Production
    192.2  
Timber
    1.4  
All Other and Corporate
    0.3  
Eliminations(2)
    (2.4 )
         
    $ 414.5  
         
 
 
(1) Amount includes $16.8 million of accrued capital expenditures related to the Empire Connector project. This amount has been excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represents a non-cash investing activity at that date.
 
(2) Represents $2.4 million of capital expenditures included in the Appalachian region of the Exploration and Production segment for the purchase of storage facilities, buildings, and base gas from Supply Corporation during the quarter ended March 31, 2008.
 
Utility
 
The majority of the Utility capital expenditures 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 segment’s capital expenditures were related to the Empire Connector project costs, which is discussed below under Estimated Capital Expenditures, as well as for additions, improvements and replacements to this segment’s transmission and gas storage systems.
 
Exploration and Production
 
The Exploration and Production segment’s capital expenditures were primarily well drilling and completion expenditures and included approximately $63.6 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, $62.8 million for the West Coast region and $65.8 million for the Appalachian region. These amounts included approximately $25.4 million spent to develop proved undeveloped reserves. The Appalachian region capital expenditures include $2.4 million for the purchase of storage facilities, buildings, and base gas from Supply Corporation, as shown in the table above.
 
Timber
 
The majority of the Timber segment capital expenditures were for construction of a lumber sorter for Highland’s sawmill operations that was placed into service in October 2007 as well as for purchases of equipment for Highland’s sawmill and kiln operations.


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All Other and Corporate
 
In March 2008, Horizon Power sold a gas-powered turbine that it had planned to use in the development of a co-generation plant. Horizon Power received proceeds of $5.3 million and recorded a pre-tax gain of $0.9 million associated with the sale.
 
Estimated Capital Expenditures
 
The Company’s estimated capital expenditures for the next three years are:
 
                         
    Year Ended September 30  
    2009     2010     2011  
    (Millions)  
 
Utility
  $ 58.0     $ 60.0     $ 56.0  
Pipeline and Storage
    73.0       76.0       46.0  
Exploration and Production(1)
    285.0       227.0       244.0  
Timber
    1.0       1.0       1.0  
                         
    $ 417.0     $ 364.0     $ 347.0  
                         
 
 
(1) Includes estimated expenditures for the years ended September 30, 2009, 2010 and 2011 of approximately $48 million, $42 million and $18 million, respectively, to develop proved undeveloped reserves.
 
Estimated capital expenditures for the Utility segment in 2009 will be concentrated in the areas of main and service line improvements and replacements and, to a lesser extent, the purchase of new equipment.
 
Estimated capital expenditures for the Pipeline and Storage segment in 2009 will be concentrated on the completion of the Empire Connector project as discussed below, the replacement of transmission and storage lines, the reconditioning of storage wells and improvements of compressor stations.
 
The Company continues to explore various opportunities to expand its capabilities to transport gas to the East Coast, either through the Supply Corporation or Empire systems or in partnership with others. Construction of the Empire Connector, a pipeline designed to transport up to approximately 250 MDth of natural gas per day that will connect the Empire Pipeline with the Millennium Pipeline, began in September 2007. The Empire Connector is anticipated to be ready to commence service in December 2008, on or before the in-service date of the Millennium Pipeline. Refer to the Rate and Regulatory Matters section that follows for further discussion of this matter. The total cost to the Company of the Empire Connector project is estimated at $187 million, after giving effect to sales tax exemptions worth approximately $3.7 million. As of September 30, 2008, the Company had incurred approximately $164.7 million in costs related to this project. Of this amount, $145.0 million, $13.7 million and $2.0 million were incurred during the years ended September 30, 2008, 2007 and 2006, respectively. All project costs incurred as of September 30, 2008 have been capitalized as Construction Work in Progress. The Company anticipates financing the remaining cost of this project with cash from operations.
 
In light of the rapidly 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 recently completed an Open Season for its Appalachian Lateral (“AppLat”) pipeline project. The AppLat 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 AppLat will complement Supply’s original West to East (“W2E”) project, which was designed to transport Rockies gas supply from Clarington to the Ellisburg/Leidy/Corning area and includes the Tuscarora-to-Corning facilities previously referred to as the Tuscarora Extension. The AppLat 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.
 
In conjunction with the W2E and AppLat transportation projects, Supply Corporation has plans to develop new storage capacity by pursuing expansion of certain of its existing storage facilities. The expansion of these


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fields, which Supply Corporation is marketing through a recently completed Open Season concurrent with its AppLat Open Season, could provide approximately 8.5 MMDth of incremental storage 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 W2E and AppLat pipeline projects and help meet the demand for storage created by the prospective increased flow of Appalachian and Rockies gas supply into the western Pennsylvania area, although traditional gas supplies will also be able to take advantage of this incremental storage capacity.
 
The timeline associated with Supply Corporation’s pipeline and storage projects depends on market development. The capital cost of the AppLat/W2E project is estimated to be approximately $800 million, and is expected to be financed by a combination of debt and equity. As of September 30, 2008, $0.2 million has been spent to study the W2E and AppLat projects, and approximately $0.6 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 September 30, 2008. Supply Corporation has not yet filed an application with the FERC for the authority to build either pipeline project or the storage expansion.
 
Estimated capital expenditures in 2009 for the Exploration and Production segment include approximately $35.0 million for the Gulf Coast region, substantially all of which is for the off-shore program in the Gulf of Mexico, $53.6 million for the West Coast region and $196.3 million for the Appalachian region.
 
Estimated capital expenditures in 2009 in the Timber segment will be concentrated on the purchase of new equipment, vehicles and improvements to facilities for this segment’s lumber yard, sawmill and kiln operations.
 
The Company continuously evaluates capital expenditures and investments in corporations, partnerships and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, timber or natural gas storage facilities and the expansion of natural gas transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.
 
FINANCING CASH FLOW
 
The Company did not have any outstanding short-term notes payable to banks or commercial paper at September 30, 2008. However, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, repurchases of stock, and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As for bank loans, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines, which aggregate to $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 that extends through September 30, 2010.
 
Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September 30, 2010. At September 30, 2008, the Company’s debt to capitalization ratio (as calculated under the facility) was .41. The constraints specified in the committed credit facility would permit an additional $1.88 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


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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 September 30, 2008, the Company would have been permitted to issue up to a maximum of $1.3 billion in additional long-term unsecured indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands.
 
The Company’s 1974 indenture, pursuant to which $199.0 million (or 18%) of the Company’s long-term debt (as of September 30, 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 September 30, 2008, the Company had no debt outstanding under the committed credit facility.
 
The Company’s embedded cost of long-term debt was 6.5% at September 30, 2008 and 6.4% at September 30, 2007. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.
 
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 is 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. 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 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 will seek to have the SEC declare the registration statement effective as of a date coinciding with or following the date of this report.
 
In December 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of eight million shares in the open market or through privately negotiated transactions. The Company completed the repurchase of the eight million shares during 2008 for a total program cost of $324.2 million (of which 4,165,122 shares were repurchased during the year ended September 30, 2008 for $191.0 million). In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares. Under this new authorization, the Company repurchased 1,028,981 shares for $46.0 million through September 17, 2008. The Company 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. All share repurchases mentioned above were funded with cash provided by operating activities and/or through the use of the Company’s lines of credit.
 
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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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 $32.3 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 $3.0 million. The Company has guaranteed 50%, or $1.5 million, of these capital lease commitments.
 
CONTRACTUAL OBLIGATIONS
 
The following table summarizes the Company’s expected future contractual cash obligations as of September 30, 2008, and the twelve-month periods over which they occur:
 
                                                         
    Payments by Expected Maturity Dates  
    2009     2010     2011     2012     2013     Thereafter     Total  
    (Millions)  
 
Long-Term Debt, including interest expense(1)
  $ 167.5     $ 65.0     $ 252.2     $ 191.4     $ 282.3     $ 565.0     $ 1,523.4  
Operating Lease Obligations
  $ 6.0     $ 4.6     $ 3.6     $ 3.2     $ 2.5     $ 12.4     $ 32.3  
Capital Lease Obligations
  $ 0.5     $ 0.4     $ 0.4     $ 0.2     $     $     $ 1.5  
Purchase Obligations:
                                                       
Gas Purchase Contracts(2)
  $ 745.8     $ 122.3     $ 14.5     $ 10.3     $ 10.3     $ 83.8     $ 987.0  
Transportation and Storage Contracts
  $ 47.4     $ 45.7     $ 41.1     $ 36.7     $ 11.3     $ 16.9     $ 199.1  
Empire Connector Project Obligations
  $ 13.5     $     $     $     $     $     $ 13.5  
Other
  $ 12.4     $ 10.5     $ 4.2     $ 4.0     $ 3.5     $ 12.6     $ 47.2  
 
 
(1) Refer to Note E — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense.
 
(2) Gas prices are variable based on the NYMEX prices adjusted for basis.
 
The Company has made certain other guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the consolidated balance sheet in accordance with SFAS 133 (see Item 7, MD&A under the heading “Critical Accounting Estimates — Accounting for Derivative Financial Instruments”); (ii) NFR obligations to purchase gas or to purchase gas transportation/storage services where the amounts due on those obligations each month are included on the consolidated balance sheet as a current liability; and (iii) other obligations which are reflected on the consolidated balance sheet. The Company believes that the likelihood it would be required to make payments under the guarantees is remote, and therefore has not included them in the table above.
 
OTHER MATTERS
 
In addition to the environmental and other matters discussed in this Item 7 and in Item 8 at Note H — Commitments and Contingencies, 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 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.
 
The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) that covers a majority of the Company’s employees. The Company has been making contributions to the Retirement Plan over the last several years and anticipates that it will continue making contributions to the Retirement Plan. During 2008, the Company contributed $16.0 million to the Retirement Plan. The Company anticipates that the


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annual contribution to the Retirement Plan in 2009 will be in the range of $15.0 million to $20.0 million. 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 2009 in order to be in compliance with the Pension Protection Act of 2006. The Company expects that all subsidiaries having employees covered by the Retirement Plan will make contributions to the Retirement Plan. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments or through short-term borrowings or through cash from operations.
 
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company has been making contributions to its VEBA trusts and 401(h) accounts over the last several years and anticipates that it will continue making contributions to the VEBA trusts and 401(h) accounts. During 2008, the Company contributed $29.1 million to its VEBA trusts and 401(h) accounts. The Company anticipates that the annual contribution to its VEBA trusts and 401(h) accounts in 2009 will be in the range of $25.0 million to $30.0 million. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments.
 
MARKET RISK SENSITIVE INSTRUMENTS
 
Energy Commodity Price Risk
 
The Company, in its Exploration and Production segment, Energy Marketing segment, Pipeline and Storage segment, and All Other category, uses various derivative financial instruments (derivatives), including price swap agreements, no cost collars and futures contracts, as part of the Company’s overall energy commodity price risk management strategy. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas and crude oil, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 2008 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas and crude oil transactions that are related to the financial instruments.
 
The following tables disclose natural gas and crude oil price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2008. At September 30, 2008, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2011.
 
Natural Gas Price Swap Agreements
 
                                 
    Expected Maturity Dates        
    2009     2010     2011     Total  
 
Notional Quantities (Equivalent Bcf)
    11.8       3.3       0.0 (1)     15.1  
Weighted Average Fixed Rate (per Mcf)
  $ 9.35     $ 10.89     $ 10.55     $ 9.69  
Weighted Average Variable Rate (per Mcf)
  $ 8.10     $ 8.74     $ 9.30     $ 8.24  
 
 
(1) The Energy Marketing segment has natural gas swap agreements covering approximately 40,000 Mcf in 2011.


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Crude Oil Price Swap Agreements
 
                                 
    Expected Maturity Dates        
    2009     2010     2011     Total  
 
Notional Quantities (Equivalent bbls)
    1,260,000       600,000       60,000       1,920,000  
Weighted Average Fixed Rate (per bbl)
  $ 83.12     $ 102.52     $ 125.25     $ 90.50  
Weighted Average Variable Rate (per bbl)
  $ 103.08     $ 104.17     $ 105.21     $ 103.49  
 
At September 30, 2008, the Company would have received from its respective counterparties an aggregate of approximately $20.3 million to terminate the natural gas price swap agreements outstanding at that date. The Energy Marketing segment also used natural gas swaps to hedge basis risk on their fixed price purchase commitments. At September 30, 2008, the Company had natural gas basis swap agreements covering 1.4 Bcf at a weighted average fixed rate of $0.47 (per Mcf) and a weighted average variable rate of $0.64 (per Mcf). These natural gas swap agreements are treated as fair value hedges and the Company would have had to pay $0.2 million at September 30, 2008 to terminate the agreements. The Company would have had to pay an aggregate of approximately $0.8 million to its counterparties to terminate the crude oil price swap agreements outstanding at September 30, 2008.
 
At September 30, 2007, the Company had natural gas price swap agreements covering 13.2 Bcf at a weighted average fixed rate of $8.20 per Mcf. The Company also had crude oil price swap agreements covering 1,485,000 bbls at a weighted average fixed rate of $57.35 per bbl.
 
The following table discloses the net contract volumes purchased (sold), weighted average contract prices and weighted average settlement prices by expected maturity date for futures contracts used to manage natural gas price risk. At September 30, 2008, the Company held no futures contracts with maturity dates extending beyond 2012.
 
Futures Contracts
 
                                         
    Expected Maturity Dates  
    2009     2010     2011     2012     Total  
 
Net Contract Volumes Purchased (Sold)
(Equivalent Bcf)
    2.1       0.3       (1)     (1)     2.4  
Weighted Average Contract Price (per Mcf)
  $ 10.02     $ 9.59     $ 8.05     $ 8.68     $ 9.99  
Weighted Average Settlement Price (per Mcf)
  $ 9.41     $ 9.85     $ 7.49     $ 8.27     $ 9.43  
 
 
(1) The Energy Marketing segment has purchased 7 and 6 futures contracts (1 contract = 2,500 Dth) for 2011 and 2012, respectively.
 
At September 30, 2008, the Company would have received $8.7 million to terminate these futures contracts.
 
At September 30, 2007, the Company had futures contracts covering 2.8 Bcf (net long position) at a weighted average contract price of $9.11 per Mcf.
 
The Company may be exposed to credit risk on some of the derivatives disclosed above. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check and then, on an ongoing basis, monitors counterparty credit exposure. Management has obtained guarantees from many of the parent companies of the respective counterparties to its derivatives. At September 30, 2008, the Company had eleven counterparties for its over the counter derivative financial instruments and no individual counterparty represented greater than 42% of total credit risk (measured as volumes hedged by an individual counterparty as a percentage of the Company’s total over the counter volumes hedged). The Company recorded a $0.6 million reduction to the fair market value of its derivative assets based on its assessment of counterparty credit risk. This credit reserve was determined by applying default probabilities to the anticipated cash flows that the Company is expecting from its counterparties.


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Interest Rate Risk
 
The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt as well as the other long-term debt of certain of the Company’s subsidiaries. The interest rates for the variable rate debt are based on those in effect at September 30, 2008:
 
                                                         
    Principal Amounts by Expected Maturity Dates  
    2009     2010     2011     2012     2013     Thereafter     Total  
    (Dollars in millions)        
 
Long-Term Fixed Rate Debt
  $ 100.0 (1)   $     $ 200.0     $ 150.0     $ 250.0     $ 399.0     $ 1,099.0  
Weighted Average Interest Rate Paid
    6.0 %           7.5 %     6.7 %     5.3 %     6.7 %     6.5 %
Fair Value of Long-Term Fixed Rate Debt = $1,027.1
                                                       
 
 
(1) These notes have been classified as Current Portion of Long-Term Debt on the Company’s Consolidated Balance Sheet.
 
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 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


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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.
 
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.
 
Empire currently does not have a rate case on file with the NYPSC. Among the issues resolved in connection with Empire’s FERC application to build the Empire Connector are the rates and terms of service that will become applicable to all of Empire’s business, effective upon Empire constructing and placing its new facilities into service (currently expected for December 2008). At that time, Empire will become an interstate pipeline subject to FERC regulation. The order described in the following paragraph requires Empire to make a filing at the FERC, within three years after the in-service date, justifying Empire’s existing recourse rates or proposing alternative rates.
 
On December 21, 2006, the FERC issued an order granting a Certificate of Public Convenience and Necessity authorizing the construction and operation of the Empire Connector and various other related pipeline projects by other unaffiliated companies. The Empire Certificate contains various environmental and other conditions. Empire accepted that Certificate and received additional environmental permits from the U.S. Army Corps of Engineers and state environmental agencies. Empire also received, from all six upstate New York counties in which it will build 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. Construction began in September 2007 and is anticipated to be ready to commence service in December 2008, on or before the in-service date of the Millennium Pipeline to which it will connect.
 
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. At September 30, 2008, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $19.4 million to $23.6 million. The minimum estimated liability of $19.4 million has been recorded on the Consolidated Balance Sheet at September 30, 2008. The Company expects to recover its environmental clean-up costs from a combination


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of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet. Other than discussed in Note H (referred to below), 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.
 
For further discussion refer to Item 8 at Note H — Commitments and Contingencies under the heading “Environmental Matters.”
 
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, SFAS 157 is effective for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009. 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. The Company does not expect that SFAS 157 will have a significant impact on its consolidated financial statements.
 
In September 2006, the FASB also issued SFAS 158, an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R. SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be adopted by the Company by the end of fiscal 2009. Currently, the Company measures its plan assets and benefit obligations using a June 30th measurement date. At September 30, 2007, in order to recognize the funded status of its pension and post-retirement benefit plans in accordance with SFAS 158, the Company recorded additional liabilities or reduced assets by a cumulative amount of $78.7 million ($71.1 million net of deferred tax benefits recognized for the portion recorded as an increase to Accumulated Other Comprehensive Loss). Of the $71.1 million recognized, $61.9 million was recorded as an increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments, $12.5 million (net of deferred tax benefits of $7.6 million) was recorded as an increase to Accumulated Other Comprehensive Loss, and $3.3 million was recorded as an increase to Other Regulatory Liabilities in the Company’s Utility segment. The Company has recorded amounts to Other Regulatory Assets or Other Regulatory Liabilities in the Utility and Pipeline and Storage segments in accordance with the provisions of SFAS 71. The Company, in those segments, has certain regulatory commission authorizations, which allow the Company to defer as a regulatory asset or liability the difference between pension and post-retirement benefit costs as calculated in accordance with SFAS 87 and SFAS 106 and what is collected in rates. Refer to Item 8 at Note G — Retirement Plan and Other Post-Retirement Benefits for further disclosures regarding the impact of SFAS 158 on the Company’s consolidated financial statements.
 
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 is effective as of the Company’s first quarter of fiscal 2009. The Company does not plan to 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,


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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.
 
EFFECTS OF INFLATION
 
Although the rate of inflation has been relatively low over the past few years, the Company’s operations remain sensitive to increases in the rate of inflation because of its capital spending and the regulated nature of a significant portion of its business.
 
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
 
The Company is including the following cautionary statement in this Form 10-K 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


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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;
 
  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;


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23.  Changes in the market price of timber and the impact such changes might have on the types and quantity of timber harvested by the Company;
 
24.  Significant changes in tax rates or policies or in rates of inflation or interest;
 
25.  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;
 
26.  Changes in accounting principles or the application of such principles to the Company;
 
27.  The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
 
28.  Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or
 
29.  Increasing costs of insurance, changes in coverage and the ability to obtain insurance.
 
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
 
Item 7A    Quantitative and Qualitative Disclosures About Market Risk
 
Refer to the “Market Risk Sensitive Instruments” section in Item 7, MD&A.


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Item 8    Financial Statements and Supplementary Data
 
Index to Financial Statements
 
         
    Page
 
Financial Statements:
       
       
    60  
    61  
    62  
    63  
    64  
    65  
Financial Statement Schedules:
       
For the three years ended September 30, 2008
       
    115  
 
All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.
 
Supplementary Data
 
Supplementary data that is included in Note M — Quarterly Financial Data (unaudited) and Note O — Supplementary Information for Oil and Gas Producing Activities (unaudited), appears under this Item, and reference is made thereto.


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of National Fuel Gas Company:
 
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of National Fuel Gas Company and its subsidiaries at September 30, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
PricewaterhouseCoopers LLP
 
Buffalo, New York
November 26, 2008


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NATIONAL FUEL GAS COMPANY
 
CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS
REINVESTED IN THE BUSINESS
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands of dollars, except per common
 
    share amounts)  
 
INCOME
                       
Operating Revenues
  $ 2,400,361     $ 2,039,566     $ 2,239,675  
                         
Operating Expenses
                       
Purchased Gas
    1,235,157       1,018,081       1,267,562  
Operation and Maintenance
    432,871       396,408       395,289  
Property, Franchise and Other Taxes
    75,585       70,660       69,202  
Depreciation, Depletion and Amortization
    170,623       157,919       151,999  
                         
      1,914,236       1,643,068       1,884,052  
                         
Operating Income
    486,125       396,498       355,623  
Other Income (Expense):
                       
Income from Unconsolidated Subsidiaries
    6,303       4,979       3,583  
Other Income
    7,376       4,936       2,825  
Interest Income
    10,815       1,550       9,409  
Interest Expense on Long-Term Debt
    (70,099 )     (68,446 )     (72,629 )
Other Interest Expense
    (3,870 )     (6,029 )     (5,952 )
                         
Income from Continuing Operations Before Income Taxes
    436,650       333,488       292,859  
Income Tax Expense
    167,922       131,813       108,245  
                         
Income from Continuing Operations
    268,728       201,675       184,614  
Discontinued Operations:
                       
Income (Loss) from Operations, Net of Tax
          15,479       (46,523 )
Gain on Disposal, Net of Tax
          120,301        
                         
Income (Loss) from Discontinued Operations, Net of Tax
          135,780       (46,523 )
                         
Net Income Available for Common Stock
    268,728       337,455       138,091  
                         
EARNINGS REINVESTED IN THE BUSINESS
                       
Balance at Beginning of Year
    983,776       786,013       813,020  
                         
      1,252,504       1,123,468       951,111  
Share Repurchases
    (194,776 )     (38,196 )     (66,269 )
Cumulative Effect of Adoption of FIN 48
    (406 )            
Dividends on Common Stock
    (103,523 )     (101,496 )     (98,829 )
                         
Balance at End of Year
  $ 953,799     $ 983,776     $ 786,013  
                         
Earnings Per Common Share:
                       
Basic:
                       
Income from Continuing Operations
  $ 3.27     $ 2.43     $ 2.20  
Income (Loss) from Discontinued Operations
          1.63       (0.56 )
                         
Net Income Available for Common Stock
  $ 3.27     $ 4.06     $ 1.64  
                         
Diluted:
                       
Income from Continuing Operations
  $ 3.18     $ 2.37     $ 2.15  
Income (Loss) from Discontinued Operations
          1.59       (0.54 )
                         
Net Income Available for Common Stock
  $ 3.18     $ 3.96     $ 1.61  
                         
Weighted Average Common Shares Outstanding:
                       
Used in Basic Calculation
    82,304,335       83,141,640       84,030,118  
                         
Used in Diluted Calculation
    84,474,839       85,301,361       86,028,466  
                         
 
See Notes to Consolidated Financial Statements


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NATIONAL FUEL GAS COMPANY
 
CONSOLIDATED BALANCE SHEETS
 
                 
    At September 30  
    2008     2007  
    (Thousands of dollars)  
 
ASSETS
Property, Plant and Equipment
  $ 4,873,969     $ 4,461,586  
Less — Accumulated Depreciation, Depletion and Amortization
    1,719,869       1,583,181  
                 
      3,154,100       2,878,405  
                 
Current Assets
               
Cash and Temporary Cash Investments
    68,239       124,806  
Cash Held in Escrow
          61,964  
Hedging Collateral Deposits
    1       4,066  
Receivables — Net of Allowance for Uncollectible Accounts of $33,117 and $28,654, Respectively
    185,397       172,380  
Unbilled Utility Revenue
    24,364       20,682  
Gas Stored Underground
    87,294       66,195  
Materials and Supplies — at average cost
    31,317       35,669  
Unrecovered Purchased Gas Costs
    37,708       14,769  
Other Current Assets
    65,158       45,057  
Deferred Income Taxes
          8,550  
                 
      499,478       554,138  
                 
Other Assets
               
Recoverable Future Taxes
    82,506       83,954  
Unamortized Debt Expense
    13,978       12,070  
Other Regulatory Assets
    189,587       137,577  
Deferred Charges
    4,417       5,545  
Other Investments
    80,640       85,902  
Investments in Unconsolidated Subsidiaries
    16,279       18,256  
Goodwill
    5,476       5,476  
Intangible Assets
    26,174       28,836  
Prepaid Pension and Other Post-Retirement Benefit Costs
    21,034       61,006  
Fair Value of Derivative Financial Instruments
    28,786       9,188  
Other
    7,732       8,059  
                 
      476,609       455,869  
                 
Total Assets
  $ 4,130,187     $ 3,888,412  
                 
 
CAPITALIZATION AND LIABILITIES
Capitalization:
               
Comprehensive Shareholders’ Equity
               
Common Stock, $1 Par Value
               
Authorized — 200,000,000 Shares; Issued and Outstanding — 79,120,544 Shares and 83,461,308 Shares, Respectively
  $ 79,121     $ 83,461  
Paid In Capital
    567,716       569,085  
Earnings Reinvested in the Business
    953,799       983,776  
                 
Total Common Shareholders’ Equity Before Items Of Other Comprehensive Income (Loss)
    1,600,636       1,636,322  
Accumulated Other Comprehensive Income (Loss)
    2,963       (6,203 )
                 
Total Comprehensive Shareholders’ Equity
    1,603,599       1,630,119  
Long-Term Debt, Net of Current Portion
    999,000       799,000  
                 
Total Capitalization
    2,602,599       2,429,119  
                 
Current and Accrued Liabilities
               
Notes Payable to Banks and Commercial Paper
           
Current Portion of Long-Term Debt
    100,000       200,024  
Accounts Payable
    142,520       109,757  
Amounts Payable to Customers
    2,753       10,409  
Dividends Payable
    25,714       25,873  
Interest Payable on Long-Term Debt
    22,114       18,158  
Customer Advances
    33,017       22,863  
Other Accruals and Current Liabilities
    45,220       36,062  
Deferred Income Taxes
    1,871        
Fair Value of Derivative Financial Instruments
    1,362       16,200  
                 
      374,571       439,346  
                 
Deferred Credits
               
Deferred Income Taxes
    634,372       575,356  
Taxes Refundable to Customers
    18,449       14,026  
Unamortized Investment Tax Credit
    4,691       5,392  
Cost of Removal Regulatory Liability
    103,100       91,226  
Other Regulatory Liabilities
    91,933       76,659  
Pension and Other Post-Retirement Liabilities
    78,909       70,555  
Asset Retirement Obligations
    93,247       75,939  
Other Deferred Credits
    128,316       110,794  
                 
      1,153,017       1,019,947  
                 
Commitments and Contingencies
           
                 
Total Capitalization and Liabilities
  $ 4,130,187     $ 3,888,412  
                 
 
See Notes to Consolidated Financial Statements


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NATIONAL FUEL GAS COMPANY
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands of dollars)  
 
Operating Activities
                       
Net Income Available for Common Stock
  $ 268,728     $ 337,455     $ 138,091  
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
                       
Gain on Sale of Discontinued Operations
          (159,873 )      
Impairment of Oil and Gas Producing Properties
                104,739  
Depreciation, Depletion and Amortization
    170,623       170,803       179,615  
Deferred Income Taxes
    72,496       52,847       (5,230 )
Income from Unconsolidated Subsidiaries, Net of Cash Distributions
    1,977       (3,366 )     1,067  
Excess Tax Benefits Associated with Stock-Based Compensation Awards
    (16,275 )     (13,689 )     (6,515 )
Other
    4,858       16,399       4,829  
Change in:
                       
Hedging Collateral Deposits
    4,065       15,610       58,108  
Receivables and Unbilled Utility Revenue
    (16,815 )     5,669       (12,343 )
Gas Stored Underground and Materials and Supplies
    (22,116 )     (5,714 )     1,679  
Unrecovered Purchased Gas Costs
    (22,939 )     (1,799 )     1,847  
Prepayments and Other Current Assets
    (36,376 )     18,800       (39,572 )
Accounts Payable
    32,763       (26,002 )     (23,144 )
Amounts Payable to Customers
    (7,656 )     (13,526 )     22,777  
Customer Advances
    10,154       (6,554 )     4,946  
Other Accruals and Current Liabilities
    (3,641 )     8,950       (17,754 )
Other Assets
    (11,887 )     4,109       (22,700 )
Other Liabilities
    54,817       (5,922 )     80,960  
                         
Net Cash Provided by Operating Activities
    482,776       394,197       471,400  
                         
Investing Activities
                       
Capital Expenditures
    (397,734 )     (276,728 )     (294,159 )
Investment in Partnership
          (3,300 )      
Net Proceeds from Sale of Foreign Subsidiaries
          232,092        
Cash Held in Escrow
    58,397       (58,248 )      
Net Proceeds from Sale of Oil and Gas Producing Properties
    5,969       5,137       13  
Other
    4,376       (725 )     (3,230 )
                         
Net Cash Used in Investing Activities
    (328,992 )     (101,772 )     (297,376 )
                         
Financing Activities
                       
Excess Tax Benefits Associated with Stock-Based Compensation Awards
    16,275       13,689       6,515  
Shares Repurchased under Repurchase Plan
    (237,006 )     (48,070 )     (85,168 )
Net Proceeds from Issuance of Long-Term Debt
    296,655              
Reduction of Long-Term Debt
    (200,024 )     (119,576 )     (9,805 )
Net Proceeds from Issuance of Common Stock
    17,432       17,498       23,339  
Dividends Paid on Common Stock
    (103,683 )     (100,632 )     (98,266 )
                         
Net Cash Used in Financing Activities
    (210,351 )     (237,091 )     (163,385 )
                         
Effect of Exchange Rates on Cash
          (139 )     1,365  
                         
Net Increase (Decrease) in Cash and Temporary Cash Investments
    (56,567 )     55,195       12,004  
Cash and Temporary Cash Investments At Beginning of Year
    124,806       69,611       57,607  
                         
Cash and Temporary Cash Investments At End of Year
  $ 68,239     $ 124,806     $ 69,611  
                         
Supplemental Disclosure of Cash Flow Information
                       
Cash Paid For:
                       
Interest
  $ 69,841     $ 75,987     $ 78,003  
                         
Income Taxes
  $ 103,154     $ 97,961     $ 54,359  
                         
 
See Notes to Consolidated Financial Statements


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NATIONAL FUEL GAS COMPANY
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands of dollars)  
 
Net Income Available for Common Stock
  $ 268,728     $ 337,455     $ 138,091  
                         
Other Comprehensive Income (Loss), Before Tax:
                       
Minimum Pension Liability Adjustment
                165,914  
Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans
    (13,584 )            
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans
    1,924              
Foreign Currency Translation Adjustment
    12       7,874       7,408  
Reclassification Adjustment for Realized Foreign Currency Translation Gain in Net Income
          (42,658 )     (716 )
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
    (4,856 )     4,747       2,573  
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
    (31,490 )     8,495       90,196  
Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income
    64,645       5,106       91,743  
                         
Other Comprehensive Income (Loss), Before Tax
    16,651       (16,436 )     357,118  
                         
Income Tax Expense Related to Minimum Pension Liability Adjustment
                58,070  
Income Tax Benefit Related to the Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans
    (5,127 )            
Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans
    726              
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
    (1,434 )     1,724       894  
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
    (13,228 )     3,153       34,772  
Reclassification Adjustment for Income Tax Benefit on Realized Losses on Derivative Financial Instruments In Net Income
    26,548       2,824       35,338  
                         
Income Taxes — Net
    7,485       7,701       129,074  
                         
Other Comprehensive Income (Loss)
    9,166       (24,137 )     228,044  
                         
Comprehensive Income
  $ 277,894     $ 313,318     $ 366,135  
                         
 
See Notes to Consolidated Financial Statements


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
Note A — 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 Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
 
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.
 
Regulation
 
The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note C — Regulatory Matters for further discussion.
 
Revenue Recognition
 
The Company’s Utility segment records revenue as bills are rendered, except that service supplied but not billed is reported as unbilled utility revenue and is included in operating revenues for the year in which service is furnished.
 
The Company’s Energy Marketing segment records revenue as bills are rendered for service supplied on a calendar month basis.
 
The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services. Revenue from reservation charges on firm contracted capacity is recognized through equal monthly charges over the contract period regardless of the amount of gas that is transported or stored. Commodity charges on firm contracted capacity and interruptible contracts are recognized as revenue when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage field. The point of delivery into the pipeline or injection or withdrawal from storage is the point at which ownership and risk of loss transfers to the buyer of such transportation and storage services.
 
The Company’s Timber segment records revenue on lumber and log sales as products are shipped, which is the point at which ownership and risk of loss transfers to the buyer of lumber products or logs.
 
The Company’s Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company’s ownership interest in the producing well. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance.
 
Allowance for Uncollectible Accounts
 
The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age and other specific information about customer accounts. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Regulatory Mechanisms
 
The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.
 
Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note C — Regulatory Matters for further discussion.
 
The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues.
 
In the Pipeline and Storage segment, the allowed rates that Supply Corporation bills its customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs in fixed monthly reservation charges. The allowed rates that Empire bills its customers are based on a modified fixed-variable rate design, which allows recovery of most fixed costs in fixed monthly reservation charges. To distinguish between the two rate designs, the modified fixed-variable rate design recovers return on equity and income taxes through variable charges whereas straight fixed-variable recovers all fixed costs, including return on equity and income taxes, through its monthly reservation charge. Because of the difference in rate design, changes in throughput due to weather variations do not have a significant impact on Supply Corporation’s revenues but may have a significant impact on Empire’s revenues.
 
Property, Plant and Equipment
 
The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service in the regulated businesses, as required by regulatory authorities.
 
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


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2008, 2007, and 2006, estimated future net cash flows were increased by $34.5 million, $2.2 million and $4.7 million, respectively. The Company’s capitalized costs exceeded the full cost ceiling for the Company’s Canadian properties at June 30, 2006 and September 30, 2006. As such, the Company recognized pre-tax impairments of $62.4 million at June 30, 2006 and $42.3 million at September 30, 2006. These impairment charges are included in loss from discontinued operations for 2006 due to the sale of SECI during 2007.
 
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
 
Depreciation, Depletion and Amortization
 
For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. For timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. For all other property, plant and equipment, depreciation, depletion and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment:
 
                 
    As of September 30  
    2008     2007  
    (Thousands)  
 
Utility
  $ 1,580,366     $ 1,539,808  
Pipeline and Storage
    996,743       976,316  
Exploration and Production
    1,800,422       1,577,745  
Energy Marketing
    1,232       1,199  
Timber
    120,021       119,237  
All Other and Corporate
    25,984       32,806  
                 
    $ 4,524,768     $ 4,247,111  
                 
 
Average depreciation, depletion and amortization rates are as follows:
 
                         
    Year Ended September 30  
    2008     2007     2006  
 
Utility
    2.6 %     2.8 %     2.8 %
Pipeline and Storage
    3.2 %     3.5 %     4.0 %
Exploration and Production, per Mcfe(1)
  $ 2.26     $ 1.94     $ 2.00  
Energy Marketing
    3.5 %     2.8 %     4.8 %
Timber
    4.1 %     4.0 %     5.6 %
All Other and Corporate
    5.0 %     4.6 %     4.1 %


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
(1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note O — Supplementary Information for Oil and Gas Producing Properties, depletion of oil and gas producing properties amounted to $2.23, $1.92 and $1.98 per Mcfe of production in 2008, 2007 and 2006, respectively. Depletion of oil and gas producing properties in the United States amounted to $2.23, $1.97 and $1.74 per Mcfe of production in 2008, 2007 and 2006, respectively. Depletion of oil and gas producing properties in Canada amounted $1.67 and $2.95 per Mcfe of production in 2007 and 2006, respectively.
 
Goodwill
 
The Company has recognized goodwill of $5.5 million as of September 30, 2008 and 2007 on its consolidated balance sheet related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with SFAS 142, which requires the Company to test goodwill for impairment annually. At September 30, 2008 and 2007, the fair value of Empire was greater than its book value. As such, the goodwill was considered not impaired.
 
Financial Instruments
 
Unrealized gains or losses from the Company’s investments in an equity mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note F — Financial Instruments for further discussion.
 
The Company 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 include price swap agreements and futures contracts. The Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases, the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled fair value of derivative financial instruments. Fair value represents the amount the Company would receive or pay to terminate these instruments.
 
For effective cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues, purchased gas expense or interest expense on the Consolidated Statements of Income. Any ineffectiveness associated with the cash flow hedges is recorded in the Consolidated Statements of Income. In December 2006, the Company repaid $22.8 million of Empire’s secured debt. The interest costs of this secured debt were hedged by an interest rate collar. Since the hedged transaction was settled and there will be no future cash flows associated with the secured debt, hedge accounting for the interest rate collar was discontinued and the unrealized gain of $1.9 million in accumulated other comprehensive income associated with the interest rate collar was reclassified to the Consolidated Statement of Income. The Company did not experience any material ineffectiveness with regard to its cash flow hedges during 2008 or 2006.
 
For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. The Company did not experience any material ineffectiveness with regard to its fair value hedges during 2008, 2007 or 2006.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Accumulated Other Comprehensive Income (Loss)
 
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
 
                 
    Year Ended September 30  
    2008     2007  
    (Thousands)  
 
Funded Status of the Pension and Other Post-Retirement Benefit Plans
  $ (19,741 )   $ (12,482 )(1)
Cumulative Foreign Currency Translation Adjustment
    (71 )     (83 )
Net Unrealized Gain (Loss) on Derivative Financial Instruments
    15,949       (3,886 )
Net Unrealized Gain on Securities Available for Sale
    6,826       10,248  
                 
Accumulated Other Comprehensive Income (Loss)
  $ 2,963     $ (6,203 )
                 
 
 
(1) In accordance with the transition recognition implementation provisions of SFAS 158, the adjustment to recognize the funded status of the pension and other post-retirement benefit plans are shown as an adjustment to the ending balance of accumulated other comprehensive income (loss). The adjustment is not shown as other comprehensive income (loss) in the Consolidated Statements of Comprehensive Income.
 
At September 30, 2008, it is estimated that of the $15.9 million net unrealized gain on derivative financial instruments shown in the table above, $13.1 million will be reclassified into the Consolidated Statement of Income during 2009. The remaining unrealized gain on derivative financial instruments of $2.8 million will be reclassified into the Consolidated Statement of Income in subsequent years. As disclosed in Note F — Financial Instruments, the Company’s derivative financial instruments extend out to 2012.
 
The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of an unrecognized transition obligation, prior service costs and accumulated losses. The total unrecognized transition obligation was $0.1 million at September 30, 2007 (nothing at September 30, 2008). The total amount for prior service costs was $0.4 million and $1.0 million at September 30, 2008 and September 30, 2007, respectively. The total amount for accumulated losses was $19.3 million and $11.4 million at September 30, 2008 and September 30, 2007, respectively.
 
Gas Stored Underground — Current
 
In the Utility segment, gas stored underground — current in the amount of $34.1 million is carried at lower of cost or market, on a LIFO method. Based upon the average price of spot market gas purchased in September 2008, including transportation costs, the current cost of replacing this inventory of gas stored underground — current exceeded the amount stated on a LIFO basis by approximately $195.4 million at September 30, 2008. All other gas stored underground — current, which is in the Energy Marketing segment, is carried at lower of cost or market on an average cost method.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Purchased Timber Rights
 
In the Timber segment, the Company purchases the right to harvest timber from land owned by other parties. These rights, which extend from several months to several years, are purchased to ensure an adequate supply of timber for the Company’s sawmill and kiln operations. The historical value of timber rights expected to be harvested during the following year are included in Materials and Supplies on the Consolidated Balance Sheets while the historical value of timber rights expected to be harvested beyond one year are included in Other Assets on the Consolidated Balance Sheets. The components of the Company’s purchased timber rights are as follows:
 
                 
    Year Ended September 30  
    2008     2007  
    (Thousands)  
 
Materials and Supplies
  $ 9,911     $ 8,925  
Other Assets
    7,383       5,641  
                 
    $ 17,294     $ 14,566  
                 
 
Unamortized Debt Expense
 
Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related debt. Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment.
 
Foreign Currency Translation
 
The functional currency for the Company’s foreign operations is the local currency of the country where the operations are located. Asset and liability accounts are translated at the rate of exchange on the balance sheet date. Revenues and expenses are translated at the average exchange rate during the period. Foreign currency translation adjustments are recorded as a component of accumulated other comprehensive income (loss). With the sale of SECI on August 31, 2007, the Company eliminated its major foreign operation. While the Company is in the process of winding up or selling certain power development projects in Europe, the investment in such projects is not significant and the Company does not expect to have any significant foreign currency translation adjustments in the future.
 
Income Taxes
 
The Company and its domestic subsidiaries file a consolidated federal income tax return. Investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction.
 
Consolidated Statements of Cash Flows
 
For purposes of the Consolidated Statements of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. At September 30, 2008, the Company accrued $16.8 million of capital expenditures related to the construction of the Empire Connector project. This amount has been excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represents a non-cash investing activity at that date.
 
Hedging Collateral Account
 
Cash held in margin accounts serves as collateral for open positions on exchange-traded futures contracts, exchange-traded options and over-the-counter swaps and collars.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 year ended September 30, 2008, 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.
 
Other Current Assets
 
Other Current Assets consist of prepayments in the amounts of $10.6 million and $14.1 million at September 30, 2008 and 2007, respectively, prepaid property and other taxes of $11.2 million and $14.1 million at September 30, 2008 and 2007, respectively, federal income taxes receivable in the amounts of $27.5 million and $8.7 million at September 30, 2008 and 2007, respectively, state income taxes receivable in the amounts of $5.0 million and zero at September 30, 2008 and 2007, respectively, and fair values of firm commitments in the amounts of $10.9 million and $8.2 million at September 30, 2008 and 2007, respectively.
 
Earnings Per Common Share
 
Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects 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 earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options and stock-settled SARs. The diluted weighted average shares outstanding shown on the Consolidated Statements 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 2008, there were 7,344 stock-settled SARs excluded as being antidilutive, and there were no stock options excluded as being antidilutive. For 2007, no stock options or stock-settled SARs were excluded as being antidilutive. For 2006, 119,241 stock options were excluded as being antidilutive. There were no stock-settled SARs excluded as being antidilutive for 2006.
 
Share Repurchases
 
The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is settled as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note E — Capitalization and Short-Term Borrowings for further discussion of the share repurchase program.
 
Stock-Based Compensation
 
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, stock-settled SARs, restricted stock, performance units or performance shares. Stock options and stock-settled SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no stock option or stock-settled SAR is exercisable less than one year or more than ten years


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
after the date of each grant. Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant.
 
Prior to October 1, 2005, the Company accounted for its stock-based compensation under the recognition and measurement principles of APB 25 and related interpretations. Under that method, no compensation expense was recognized for options granted under the Company’s stock option and stock award plans. The Company did record, in accordance with APB 25, compensation expense for the market value of restricted stock on the date of the award over the periods during which the vesting restrictions existed.
 
Effective October 1, 2005, the Company adopted SFAS 123R, which requires the measurement and recognition of compensation cost at fair value for all share-based payments, including stock options and stock-settled SARs. The Company has chosen to use the modified version of prospective application, as allowed by SFAS 123R. Using the modified prospective application, the Company recorded compensation cost for the portion of awards granted prior to October 1, 2005 for which the requisite service had not been rendered and recognized such compensation cost as the requisite service was rendered on or after October 1, 2005. Such compensation expense is based on the grant-date fair value of the awards as calculated for the Company’s disclosure using a Binomial option-pricing model under SFAS 123. Any new awards, modifications to awards, repurchases of awards, or cancellations of awards subsequent to September 30, 2005 will follow the provisions of SFAS 123R, with compensation expense being calculated using the Black-Scholes-Merton closed form model. The Company has chosen the Black-Scholes-Merton closed form model since it is easier to administer than the Binomial option-pricing model. Furthermore, since the Company does not have complex stock-based compensation awards, it does not believe that compensation expense would be materially different under either model. There were no stock options granted during the year ended September 30, 2008. There were 448,000 and 317,000 stock options granted during the years ended September 30, 2007 and 2006, respectively. The Company granted 321,000 performance based stock-settled SARs during the year ended September 30, 2008. There were no performance based stock-settled SARs granted during the year ended September 30, 2007. The Company granted 50,000 non-performance based stock-settled SARs during the year ended September 30, 2007. There were no non-performance based stock-settled SARs granted during the year ended September 30, 2008. There were no performance based or non-performance based stock-settled SARs granted during the year ended September 30, 2006. The accounting treatment for such performance based and non-performance based stock-settled SARs is the same under SFAS 123R as the accounting for stock options under SFAS 123R. The performance based stock-settled SARs granted for the year ended September 30, 2008 vest and become exercisable annually, in one-third increments, provided that a performance condition for diluted earnings per share is met for the prior fiscal year. The weighted average grant date fair value of the performance based stock-settled SARs granted during 2008 was estimated on the date of grant using the same accounting treatment that is applied for stock options under SFAS 123R, and assumes that the performance conditions specified will be achieved. If such conditions are not met, no compensation expense is recognized and any recognized compensation expense is reversed. The Company also granted 25,000, 25,000 and 16,000 restricted share awards (non-vested stock as defined by SFAS 123R) during the years ended September 30, 2008, 2007 and 2006, respectively. Stock-based compensation expense for the years ended September 30, 2008, 2007 and 2006 was approximately $2,332,000, $3,727,000, and $1,705,000, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statement of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2008, 2007 and 2006 was approximately $945,000, $1,488,000 and $653,000, respectively. There were no capitalized stock-based compensation costs during the years ended September 30, 2008 and 2007.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Stock Options
 
The total intrinsic value of stock options exercised during the years ended September 30, 2008, 2007 and 2006 totaled approximately $24.6 million, $38.7 million, and $30.9 million, respectively. For 2008, 2007 and 2006, the amount of cash received by the Company from the exercise of such stock options was approximately $18.5 million, $26.0 million, and $30.1 million, respectively.
 
The Company realizes tax benefits related to the exercise of stock options on a calendar year basis as opposed to a fiscal year basis. As such, for stock options exercised during the quarters ended December 31, 2007, 2006, and 2005, the Company realized a tax benefit of $4.4 million, $3.2 million, and $0.9 million, respectively. For stock options exercised during the period of January 1, 2008 through September 30, 2008, the Company will realize a tax benefit of approximately $4.3 million in the quarter ended December 31, 2008. For stock options exercised during the period of January 1, 2007 through September 30, 2007, the Company realized a tax benefit of approximately $12.0 million in the quarter ended December 31, 2007. For stock options exercised during the period of January 1, 2006 through September 30, 2006, the Company realized a tax benefit of approximately $11.4 million in the quarter ended December 31, 2006. The weighted average grant date fair value of options granted in 2007 and 2006 is $7.27 per share and $6.68 per share, respectively. For the years ended September 30, 2008, 2007 and 2006, 358,000, 327,501 and 89,665 stock options became fully vested, respectively. The total fair value of these stock options was approximately $2.6 million, $2.1 million and $0.4 million, respectively, for the years ended September 30, 2008, 2007 and 2006. As of September 30, 2008, unrecognized compensation expense related to stock options totaled approximately $0.3 million, which will be recognized over a weighted average period of 8.6 months. For a summary of transactions during 2008 involving option shares for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
 
The fair value of options at the date of grant was estimated using a Binomial option-pricing model for options granted prior to October 1, 2005 and the Black-Scholes-Merton closed form model for options granted after September 30, 2005. The following weighted average assumptions were used in estimating the fair value of options at the date of grant:
 
                         
    Year Ended September 30  
    2008     2007     2006  
 
Risk Free Interest Rate
    N/A       4.46 %     5.08 %
Expected Life (Years)
    N/A       7.0       7.0  
Expected Volatility
    N/A       17.73 %     17.71 %
Expected Dividend Yield (Quarterly)
    N/A       0.76 %     0.83 %
 
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the option. The expected life and expected volatility are based on historical experience.
 
For grants during the years ended September 30, 2007 and 2006, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
 
Non-Performance Based Stock-settled SARs
 
There were no non-performance based stock-settled SARs exercised during the years ended September 30, 2008, 2007 and 2006 as none of the non-performance based stock-settled SARs granted have vested. There were 50,000 non-performance based stock-settled SARs granted during 2007. The weighted average grant date fair value of non-performance based stock-settled SARs granted in 2007 is $7.81 per share. There were no non-performance based stock-settled SARs granted during 2008 or 2006. As of September 30, 2008, unrecognized compensation expense related to non-performance based stock-settled SARs totaled approximately $0.2 million, which will be recognized over a weighted average period of 10.2 months. For a summary of transactions during


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
2008 involving non-performance based stock-settled SARs for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
 
The fair value of non-performance based stock-settled SARs at the date of grant was estimated using the Black-Scholes-Merton closed form model. The following weighted average assumptions were used in estimating the fair value of options at the date of grant:
 
         
    Year Ended
 
    September 30,
 
    2007  
 
Risk Free Interest Rate
    4.53 %
Expected Life (Years)
    7.0  
Expected Volatility
    17.55 %
Expected Dividend Yield (Quarterly)
    0.73 %
 
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the non-performance based stock-settled SARs. The expected life and expected volatility are based on historical experience.
 
For grants during the year ended September 30, 2007, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
 
Performance Based Stock-settled SARs
 
There were no performance based stock-settled SARs exercised during the years ended September 30, 2008, 2007 and 2006 as none of the performance based stock-settled SARs granted have vested. There were 321,000 performance based stock-settled SARs granted during 2008. The weighted average grant date fair value of performance based stock-settled SARs granted in 2008 is $9.06 per share. There were no performance based stock-settled SARs granted during 2007 or 2006. For the years ended September 30, 2008, 2007 and 2006, there were no performance based stock-settled SARs that became fully vested. As of September 30, 2008, unrecognized compensation expense related to performance based stock-settled SARs totaled approximately $1.9 million, which will be recognized over a weighted average period of 1.1 years. For a summary of transactions during 2008 involving performance based stock-settled SARs for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
 
The fair value of performance based stock-settled SARs at the date of grant was estimated using the Black-Scholes-Merton closed form model. The following weighted average assumptions were used in estimating the fair value of options at the date of grant:
 
         
    Year Ended
 
    September 30,
 
    2008  
 
Risk Free Interest Rate
    3.78 %
Expected Life (Years)
    7.25  
Expected Volatility
    17.69 %
Expected Dividend Yield (Quarterly)
    0.64 %
 
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the performance based stock-settled SARs. The expected life and expected volatility are based on historical experience.
 
For grants during the year ended September 30, 2008, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Restricted Share Awards
 
The weighted average fair value of restricted share awards granted in 2008, 2007 and 2006 is $48.41 per share, $40.18 per share and $34.94 per share, respectively. As of September 30, 2008, unrecognized compensation expense related to restricted share awards totaled approximately $1.6 million, which will be recognized over a weighted average period of 2.5 years. For a summary of transactions during 2008 involving restricted share awards, refer to Note E — Capitalization and Short-Term Borrowings.
 
During 2006, a modification was made to a restricted share award involving one employee. The modification accelerated the vesting date of 4,000 shares from December 7, 2006 to July 1, 2006. The incremental compensation expense, totaling approximately $32,000, was included with the total stock-based compensation expense for the year ended September 30, 2006.
 
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, SFAS 157 is effective for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009. 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. The Company does not expect that SFAS 157 will have a significant impact on its consolidated financial statements.
 
In September 2006, the FASB also issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” (an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R). SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be adopted by the Company by the end of fiscal 2009. Currently, the Company measures its plan assets and benefit obligations using a June 30th measurement date. At September 30, 2007, in order to recognize the funded status of its pension and post-retirement benefit plans in accordance with SFAS 158, the Company recorded additional liabilities or reduced assets by a cumulative amount of $78.7 million ($71.1 million net of deferred tax benefits recognized for the portion recorded as an increase to Accumulated Other Comprehensive Loss). Of the $71.1 million recognized, $61.9 million was recorded as an increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments, $12.5 million (net of deferred tax benefits of $7.6 million) was recorded as an increase to Accumulated Other Comprehensive Loss, and $3.3 million was recorded as an increase to Other Regulatory Liabilities in the Company’s Utility segment. The Company has recorded amounts to Other Regulatory Assets or Other Regulatory Liabilities in the Utility and Pipeline and Storage segments in accordance with the provisions of SFAS 71. The Company, in those segments, has certain regulatory commission authorizations, which allow the Company to defer as a regulatory asset or liability the difference between pension and post-retirement benefit costs as calculated in accordance with SFAS 87 and SFAS 106 and what is collected in rates. Refer to Note G — Retirement Plan and Other Post-Retirement Benefits for further disclosures regarding the impact of SFAS 158 on the Company’s consolidated financial statements.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 at fair value that are not otherwise required to be measured at fair value under GAAP. A company that elects the fair value option for an eligible item will be required to recognize in current earnings any changes in that item’s fair value in reporting periods subsequent to the date of adoption. SFAS 159 is effective as of the Company’s first quarter of fiscal 2009. The Company does not plan to 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, “Business Combinations.” SFAS 141R will significantly change the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies, acquisition costs, in process research and development and restructuring costs. In addition, under SFAS 141R, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income tax expense. SFAS 141R is effective as of the Company’s first quarter of fiscal 2010.
 
In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB 51.” SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests (NCI) and classified as a component of equity. This new consolidation method will significantly change the accounting for transactions with minority interest holders. SFAS 160 is effective as of the Company’s first quarter of fiscal 2010. The Company currently does not have any NCI.
 
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.
 
Note B — Asset Retirement Obligations
 
The Company accounts for asset retirement obligations in accordance with the provisions of SFAS 143. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.
 
As previously disclosed, the Company follows the full cost method of accounting for its exploration and production costs. Upon the adoption of SFAS 143 on October 1, 2002, the Company recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and capitalized such costs in property, plant and equipment (i.e. the full cost pool). Prior to the adoption of SFAS 143, plugging and abandonment costs were accounted for solely through the Company’s units-of-production depletion calculation. An estimate of such costs was added to the depletion base, which also included capitalized costs in the full cost pool and estimated future expenditures to be incurred in developing proved reserves. With the adoption of SFAS 143, plugging and abandonment costs are already included in capitalized costs and the units-of-production depletion calculation has been modified to exclude from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
 
The full cost method of accounting provides a limit to the amount of costs that can be capitalized in the full cost pool. This limit is referred to as the full cost ceiling. Prior to the adoption of SFAS 143, in calculating the full


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
cost ceiling, the Company reduced the future net cash flows from proved oil and gas reserves by the estimated plugging and abandonment costs. Such future net cash flows would then be compared to capitalized costs in the full cost pool, with any excess capitalized costs being expensed. With the adoption of SFAS 143, since the full cost pool now includes an amount associated with plugging and abandoning the wells, the calculation of the full cost ceiling has been changed so that future net cash flows from proved oil and gas reserves are no longer reduced by the estimated plugging and abandonment costs.
 
On September 30, 2006, the Company adopted FIN 47, an interpretation of SFAS 143. FIN 47 provides clarification of the term “conditional asset retirement obligation” as used in SFAS 143, defined as a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Company. Under this standard, if the fair value of a conditional asset retirement obligation can be reasonably estimated, a company must record a liability and a corresponding asset for the conditional asset retirement obligation representing the present value of that obligation at the date the obligation was incurred. FIN 47 also serves to clarify when a company would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation.
 
Upon the adoption of FIN 47, the Company recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. The Company also identified asset retirement obligations for certain costs connected with the retirement of distribution mains and services pipeline systems in the Utility segment and with the transmission mains and other components in the pipeline systems in the Pipeline and Storage segment. These retirement costs within the distribution and transmission systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for the clean-up of PCB contamination associated with the removal of certain pipe.
 
As a result of the implementation of FIN 47 as of September 30, 2006, the Company recorded additional asset retirement obligations of $23.2 million and corresponding long-lived plant assets, net of accumulated depreciation, of $3.5 million. These assets will be depreciated over their respective remaining depreciable life. The remaining $19.7 million represents the cumulative accretion and depreciation of the asset retirement obligations that would have been recognized if this interpretation had been in effect at the inception of the obligations. Of this amount, the Company recorded an increase to regulatory assets of $9.0 million and a reduction to cost of removal regulatory liability of $10.7 million. The cost of removal regulatory liability represents amounts collected from customers through depreciation expense in the Company’s Utility and Pipeline and Storage segments. These removal costs are not a legal retirement obligation in accordance with SFAS 143. Rather, they represent a regulatory liability. However, SFAS 143 requires that such costs of removal be reclassified from accumulated depreciation to other regulatory liabilities. At September 30, 2008 and 2007, the costs of removal reclassified to other regulatory liabilities amounted to $103.1 million and $91.2 million, respectively.
 
A reconciliation of the Company’s asset retirement obligation calculated in accordance with SFAS 143 is shown below:
 
                         
    Year Ended September 30  
    2008     2007     2006  
          (Thousands)        
 
Balance at Beginning of Year
  $ 75,939     $ 77,392     $ 41,411  
Additions — Adoption of FIN 47
                23,234  
Liabilities Incurred and Revisions of Estimates
    18,739       (932 )     11,244  
Liabilities Settled
    (6,871 )     (6,108 )     (1,303 )
Accretion Expense
    5,440       5,394       2,671  
Exchange Rate Impact
          193       135  
                         
Balance at End of Year
  $ 93,247     $ 75,939     $ 77,392  
                         


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Note C — Regulatory Matters
 
Regulatory Assets and Liabilities
 
The Company has recorded the following regulatory assets and liabilities:
 
                 
    At September 30  
    2008     2007  
    (Thousands)  
 
Regulatory Assets(1):
               
Pension and Other Post-Retirement Benefit Costs(2) (Note G)
  $ 147,909     $ 98,787  
Recoverable Future Taxes (Note D)
    82,506       83,954  
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A)
    37,708       14,769  
Environmental Site Remediation Costs(2) (Note H)
    22,530       20,738  
Asset Retirement Obligations(2) (Note B)
    8,155       8,315  
Unamortized Debt Expense (Note A)
    7,524       8,470  
Recoverable Worker Compensation Expense(2)
    4,518       4,445  
Other(2)
    6,475       5,292  
                 
Total Regulatory Assets
    317,325       244,770  
                 
Regulatory Liabilities :
               
Cost of Removal Regulatory Liability (Note B)
    103,100       91,226  
Pension and Other Post-Retirement Benefit Costs(3) (Note G)
    42,994       21,676  
Tax Benefit on Medicare Part D Subsidy(3)
    23,502       19,147  
New York Rate Settlements(3)
    19,012       27,964  
Taxes Refundable to Customers (Note D)
    18,449       14,026  
Deferred Insurance Proceeds(3)
    3,933       7,422  
Amounts Payable to Customers (See Regulatory Mechanisms in Note A)
    2,753       10,409  
Other(3)
    2,492       450  
                 
Total Regulatory Liabilities
    216,235       192,320  
                 
Net Regulatory Position
  $ 101,090     $ 52,450  
                 
 
 
(1) The Company recovers the cost of its regulatory assets but, with the exception of Unrecovered Purchased Gas Costs, does not earn a return on them.
 
(2) Included in Other Regulatory Assets on the Consolidated Balance Sheets.
 
(3) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.
 
If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in income of the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
New York Rate Settlements
 
With respect to utility services provided in New York, the Company has entered into rate settlements approved by the NYPSC. The rate settlements have given rise to several significant liabilities, which are described as follows:
 
Gross Receipts Tax Over-Collections — In accordance with NYPSC policies, Distribution Corporation deferred the difference between the revenues it collects under a New York State gross receipts tax surcharge and its actual New York State income tax expense. Distribution Corporation’s cumulative gross receipts tax revenues exceeded its New York State income tax expense, resulting in a regulatory liability at September 30, 2008 and 2007 of $4.1 million and $6.7 million, respectively. Under the terms of its 2005 rate agreement, Distribution Corporation has been passing back that regulatory liability to rate payers since August 1, 2005. Further, the gross receipts tax surcharge that gave rise to the regulatory liability was eliminated from Distribution Corporation’s tariff (New York State income taxes are now recovered as a component of base rates).
 
Cost Mitigation Reserve (“CMR”) — The CMR is a regulatory liability that can be used to offset certain expense items specified in Distribution Corporation’s rate settlements. The source of the CMR was principally the accumulation of certain refunds from upstream pipeline companies. During 2005, under the terms of the 2005 rate agreement, Distribution Corporation transferred the remaining balance in a generic restructuring reserve (which had been established in a prior rate settlement) and the balances it had accumulated under various earnings sharing mechanisms to the CMR. The balance in the CMR at September 30, 2008 and 2007 amounted to $0.3 million and $7.4 million, respectively.
 
Other — The 2005 agreement also established a reserve to fund area development projects. The balance in the area development projects reserve at September 30, 2008 and 2007 amounted to $3.0 million and $3.6 million, respectively (Distribution Corporation established the reserve at September 30, 2005 by transferring $3.8 million from the CMR discussed above). Various other regulatory liabilities have also been created through the New York rate settlements and amounted to $11.6 million and $10.3 million at September 30, 2008 and 2007, respectively.
 
Tax Benefit on Medicare Part D Subsidy
 
The Company has established a regulatory liability for the tax benefit it will receive under the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act). The Act provides a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In the Company’s Utility and Pipeline and Storage segments, the ratepayer funds the Company’s post-retirement benefit plans. As such, any tax benefit received under the Act must be flowed-through to the ratepayer. Refer to Note G — Retirement Plan and Other Post-Retirement Benefits for further discussion of the Act and its impact on the Company.
 
Deferred Insurance Proceeds
 
The Company, in its Utility and Pipeline and Storage segments, has deferred environmental insurance settlement proceeds amounting to $3.9 million and $7.4 million at September 30, 2008 and 2007, respectively. Such proceeds have been deferred as a regulatory liability to be applied against any future environmental claims that may be incurred. The proceeds have been classified as a regulatory liability in recognition of the fact that ratepayers funded the premiums on the former insurance policies.
 
Recoverable Worker Compensation Expense
 
The Company has established a liability in its Utility segment in accordance with the provisions of SFAS 112 for future worker compensation liabilities. Such amounts have been deferred as a regulatory asset because the Company is allowed to recover worker compensation expense in rates.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note D — Income Taxes
 
The components of federal, state and foreign income taxes included in the Consolidated Statements of Income are as follows:
 
                         
    Year Ended September 30  
    2008     2007     2006  
          (Thousands)        
 
Current Income Taxes —
                       
Federal
  $ 75,079     $ 99,608     $ 65,593  
State
    20,257       21,700       13,511  
Foreign
    90       22       2,212  
Deferred Income Taxes —
                       
Federal
    56,668       39,340       19,111  
State
    15,828       10,751       9,024  
Foreign
          2,756       (33,365 )
                         
      167,922       174,177       76,086  
Deferred Investment Tax Credit
    (697 )     (697 )     (697 )
                         
Total Income Taxes
  $ 167,225     $ 173,480     $ 75,389  
                         
Presented as Follows:
                       
Other Income
  $ (697 )   $ (697 )   $ (697 )
Income Tax Expense — Continuing Operations
    167,922       131,813       108,245  
Discontinued Operations —
                       
Income From Operations
          2,792       (32,159 )
Gain on Disposal
          39,572        
                         
Total Income Taxes
  $ 167,225     $ 173,480     $ 75,389  
                         
 
The U.S. and foreign components of income (loss) before income taxes are as follows:
 
                         
    Year Ended September 30  
    2008     2007     2006  
          (Thousands)        
 
U.S. 
  $ 435,982     $ 496,074     $ 293,887  
Foreign
    (29 )     14,861       (80,407 )
                         
    $ 435,953     $ 510,935     $ 213,480  
                         


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:
 
                         
    Year Ended September 30  
    2008     2007     2006  
          (Thousands)        
 
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35%
  $ 152,584     $ 178,827     $ 74,718  
Increase in Taxes Resulting from:
                       
State Income Taxes
    23,455       21,093       14,648  
Foreign Tax Differential
    69       (20,980 )     (3,718 )
Reversal of Capital Loss Valuation Allowance
                (2,877 )
Miscellaneous
    (8,883 )     (5,460 )     (7,382 )
                         
Total Income Taxes
  $ 167,225     $ 173,480     $ 75,389  
                         
 
The foreign tax differential amount shown above for 2007 includes tax effects relating to the gain on disposition of a foreign subsidiary. Also, the foreign tax differential amount shown above for 2006 includes a $5.1 million deferred tax benefit relating to additional future tax deductions forecasted in Canada. The miscellaneous amount shown above for 2006 includes a net reversal of $3.2 million relating to a tax contingency reserve.
 
Significant components of the Company’s deferred tax liabilities and assets are as follows:
 
                 
    At September 30  
    2008     2007  
    (Thousands)  
 
Deferred Tax Liabilities:
               
Property, Plant and Equipment
  $ 673,313     $ 612,648  
Pension and Other Post-Retirement Benefit Costs — SFAS 158
    43,340       21,892  
Other
    55,391       39,724  
                 
Total Deferred Tax Liabilities
    772,044       674,264  
                 
Deferred Tax Assets:
               
Pension and Other Post-Retirement Benefit Costs — SFAS 158
    (43,340 )     (21,892 )
Other
    (92,461 )     (85,566 )
                 
Total Deferred Tax Assets
    (135,801 )     (107,458 )
                 
Total Net Deferred Income Taxes
  $ 636,243     $ 566,806  
                 
Presented as Follows:
               
Net Deferred Tax Liability/(Asset) — Current
  $ 1,871     $ (8,550 )
Net Deferred Tax Liability — Non-Current
    634,372       575,356  
                 
Total Net Deferred Income Taxes
  $ 636,243     $ 566,806  
                 
 
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $18.4 million and $14.0 million at September 30, 2008 and 2007, 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 $82.5 million and $84.0 million at September 30, 2008 and 2007, respectively.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Company adopted FIN 48 on October 1, 2007. As of the date of adoption, a cumulative effect adjustment was recorded that resulted in a decrease to retained earnings of $0.4 million. Upon adoption, the unrecognized tax benefits were $1.7 million, all of which would impact the effective tax rate (net of federal benefit) if recognized.
 
A tabular reconciliation of the change in unrecognized tax benefits for the twelve months ended September 30, 2008 is as follows:
 
         
    Amount  
    (thousands)  
 
Opening Balance of Unrecognized Tax Benefits — October 1, 2007
  $ 1,700  
Gross Increase — Tax Positions in Prior Periods
     
Gross Decrease — Tax Positions in Prior Periods
     
Gross Increase — Tax Positions in Current Periods
     
Gross Decrease — Tax Positions in Current Periods
     
Decrease in Unrecognized Tax Benefits Related to Tax Settlements
     
Reduction to Unrecognized Tax Benefits Due to Lapse of Statute of Limitations
     
         
Ending Balance of Unrecognized Tax Benefits — September 30, 2008
  $ 1,700  
         
 
Within the next twelve months, the Company believes it is reasonably possible that the total amount of unrecognized tax benefits may be eliminated. This potential decrease in the amount of unrecognized tax benefits is associated with the anticipated completion of state income tax audits for various prior years.
 
The Company recognizes estimated interest payable relating to income taxes in Other Interest Expense and estimated penalties relating to income taxes in Other Income. The Company has accrued interest of $0.5 million through September 30, 2008 and has not accrued any penalties.
 
The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 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.
 
For the major states in which the various subsidiary companies operate, the earliest tax year open for examination is as follows:
 
     
New York
  Fiscal 2002
Pennsylvania
  Fiscal 2003
California
  Fiscal 2004
Texas
  Fiscal 2004


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note E — Capitalization and Short-Term Borrowings
 
Summary of Changes in Common Stock Equity
 
                                         
                      Earnings
    Accumulated
 
                      Reinvested
    Other
 
                Paid
    in
    Comprehensive
 
    Common Stock     In
    the
    Income
 
    Shares     Amount     Capital     Business     (Loss)  
    (Thousands, except per share amounts)  
 
Balance at September 30, 2005
    84,357     $ 84,357     $ 529,834     $ 813,020     $ (197,628 )
Net Income Available for Common Stock
                            138,091          
Dividends Declared on Common Stock ($1.18 Per Share)
                            (98,829 )        
Other Comprehensive Income, Net of Tax
                                    228,044  
Share-Based Payment Expense(2)
                    1,705                  
Common Stock Issued Under Stock and Benefit Plans(1)
    1,572       1,572       28,564                  
Share Repurchases
    (2,526 )     (2,526 )     (16,373 )     (66,269 )        
                                         
Balance at September 30, 2006
    83,403       83,403       543,730       786,013       30,416  
                                         
Net Income Available for Common Stock
                            337,455          
Dividends Declared on Common Stock ($1.22 Per Share)
                            (101,496 )        
Other Comprehensive Loss, Net of Tax
                                    (24,137 )
Adjustment to Recognize the Funded Position of the Pension and Other Post-Retirement Benefit Plans
                                    (12,482 )
Share-Based Payment Expense(2)
                    3,727                  
Common Stock Issued Under Stock and Benefit Plans(1)
    1,367       1,367       30,193                  
Share Repurchases
    (1,309 )     (1,309 )     (8,565 )     (38,196 )        
                                         
Balance at September 30, 2007
    83,461       83,461       569,085       983,776       (6,203 )
                                         
Net Income Available for Common Stock
                            268,728          
Dividends Declared on Common Stock ($1.27 Per Share)
                            (103,523 )        
Cumulative Effect of the Adoption of FIN 48
                            (406 )        
Other Comprehensive Loss, Net of Tax
                                    9,166  
Share-Based Payment Expense(2)
                    2,332                  
Common Stock Issued Under Stock and Benefit Plans(1)
    854       854       33,335                  
Share Repurchases
    (5,194 )     (5,194 )     (37,036 )     (194,776 )        
                                         
Balance at September 30, 2008
    79,121     $ 79,121     $ 567,716     $ 953,799 (3)   $ 2,963  
                                         
 
 
(1) Paid in Capital includes tax benefits of $16.3 million, $13.7 million and $6.5 million for September 30, 2008, 2007 and 2006, respectively, associated with the exercise of stock options.
 
(2) As of October 1, 2005, Paid in Capital includes compensation costs associated with stock option, stock-settled SARs and/or restricted stock awards, in accordance with SFAS 123R. The expense is included within Net Income Available For Common Stock, net of tax benefits.
 
(3) The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2008, $808.8 million of accumulated earnings was free of such limitations.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Common Stock
 
The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent.
 
During 2008, the Company issued 890,944 original issue shares of common stock as a result of stock option exercises and 25,000 original issue shares for restricted stock awards (non-vested stock as defined in SFAS 123R). 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 2008, 72,205 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.
 
The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company’s Retainer Policy for Non-Employee Directors, as partial consideration for their services as directors. Under this program, the Company issued 9,600 original issue shares of common stock during 2008.
 
In December 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of eight million shares in the open market or through privately negotiated transactions. The Company completed the repurchase of the eight million shares during 2008 for a total program cost of $324.2 million (of which 4,165,122 shares were repurchased during the year ended September 30, 2008 for $191.0 million). In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares. Under this new authorization, the Company repurchased 1,028,981 shares for $46.0 million through September 17, 2008. The Company 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. All share repurchases mentioned above were funded with cash provided by operating activities and/or through the use of the Company’s lines of credit.
 
Shareholder Rights Plan
 
In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). The Plan has been amended five times since it was adopted and is now embodied in an Amended and Restated Rights Agreement effective July 11, 2008, which is an Exhibit to this Annual Report and Form 10-K.
 
The 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


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Distribution Date, each holder of a Right may exercise its right to receive a number of shares of common stock determined in accordance with a Plan formula that is based on the current market value of the Company’s common stock. Under certain circumstances, each holder of a Right may instead receive other property of the Company. 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 a number of shares of common stock determined in accordance with a Plan formula based on the current market value of the Company’s common stock, or other property of the Company. 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.
 
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.
 
Stock Option and Stock Award Plans
 
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, stock-settled SARs, restricted stock, performance units or performance shares. Stock options and stock-settled SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option or stock-settled SAR is exercisable less than one year or more than ten years after the date of each grant.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Transactions involving option shares for all plans are summarized as follows:
 
                                 
                Weighted
       
                Average
       
    Number of
          Remaining
    Aggregate
 
    Shares Subject
    Weighted Average
    Contractual
    Intrinsic
 
    to Option     Exercise Price     Life (Years)     Value  
                      (In thousands)  
 
Outstanding at September 30, 2007
    7,360,041     $ 25.89                  
Granted in 2008
        $                  
Exercised in 2008
    (890,944 )   $ 23.78                  
Forfeited in 2008
    (4,400 )   $ 27.97                  
                                 
Outstanding at September 30, 2008
    6,464,697     $ 26.17       3.11     $ 103,477  
                                 
Option shares exercisable at September 30, 2008
    6,337,697     $ 25.94       3.02     $ 102,909  
                                 
Option shares available for future grant at September 30, 2008(1)
    745,797                          
                                 
 
 
(1) Including shares available for stock-settled SARs and restricted stock grants.
 
Transactions involving non-performance based stock-settled SARs for all plans are summarized as follows:
 
                                 
                Weighted
       
                Average
       
    Number of
          Remaining
    Aggregate
 
    Shares Subject
    Weighted Average
    Contractual
    Intrinsic
 
    To Option     Exercise Price     Life (Years)     Value  
                      (In thousands)  
 
Outstanding at September 30, 2007
    50,000     $ 41.20                  
Granted in 2008
        $                  
Exercised in 2008
        $                  
Forfeited in 2008
        $                  
                                 
Outstanding at September 30, 2008
    50,000     $ 41.20       8.45     $ 49  
                                 
Stock-settled SARs exercisable at September 30, 2008
                    $  
                                 


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Transactions involving performance based stock-settled SARs for all plans are summarized as follows:
 
                                 
                Weighted
       
                Average
       
    Number of
          Remaining
    Aggregate
 
    Shares Subject
    Weighted Average
    Contractual
    Intrinsic
 
    To Option     Exercise Price     Life (Years)     Value  
                      (In thousands)  
 
Outstanding at September 30, 2007
        $                  
Granted in 2008
    321,000     $ 48.46                  
Exercised in 2008
        $                  
Forfeited in 2008
    (6,000 )   $ 58.99                  
                                 
Outstanding at September 30, 2008
    315,000     $ 48.26       9.42     $ (1,914 )
                                 
Stock-settled SARs exercisable at September 30, 2008
                    $  
                                 
 
Restricted Share Awards
 
Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective.
 
Transactions involving restricted shares for all plans are summarized as follows:
 
                 
    Number of
    Weighted Average
 
    Restricted
    Fair Value per
 
    Share Awards     Award  
 
Restricted Share Awards Outstanding at September 30, 2007
    36,328     $ 38.16  
Granted in 2008
    25,000     $ 48.41  
Vested in 2008
    (2,500 )   $ 34.94  
Forfeited in 2008
        $  
                 
Restricted Share Awards Outstanding at September 30, 2008
    58,828     $ 42.65  
                 
 
Vesting restrictions for the outstanding shares of non-vested restricted stock at September 30, 2008 will lapse as follows: 2009 — 2,500 shares; 2010 — 28,828 shares; 2011 — 2,500 shares; 2012 — 5,000 shares; 2013 — 5,000 shares; 2014 — 5,000 shares; 2015 — 5,000 shares; and 2016 — 5,000 shares.
 
Redeemable Preferred Stock
 
As of September 30, 2007, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Long-Term Debt
 
The outstanding long-term debt is as follows:
 
                 
    At September 30  
    2008     2007  
    (Thousands)  
 
Medium-Term Notes(1):
               
6.0% to 7.50% due March 2009 to June 2025
  $ 549,000     $ 749,000  
Notes(1):
               
5.25% to 6.5% due March 2013 to September 2022(2)
    550,000       250,000  
                 
      1,099,000       999,000  
                 
Other Notes:
               
Unsecured
          24  
                 
Total Long-Term Debt
    1,099,000       999,024  
Less Current Portion
    100,000       200,024  
                 
    $ 999,000     $ 799,000  
                 
 
 
(1) The medium-term notes and notes are unsecured.
 
(2) 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 is required to either offer to exchange the notes for substantially similar notes registered under the Securities Act of 1933 or, in certain circumstances, register the resale of the notes. The Company used $200.0 million of the proceeds from the sale of the notes to refund $200.0 million of 6.303% medium-term notes that subsequently matured on May 27, 2008.
 
As of September 30, 2008, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $100.0 million in 2009, zero in 2010, $200.0 million in 2011, $150.0 million in 2012, $250.0 million in 2013, and $399.0 million thereafter.
 
Short-Term Borrowings
 
The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. As for the former, 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 uncommitted 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 that extends through September 30, 2010.
 
At September 30, 2008 and 2007, the Company had no outstanding short-term notes payable to banks or commercial paper.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Debt Restrictions
 
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 September 30, 2008, the Company’s debt to capitalization ratio (as calculated under the facility) was .41. The constraints specified in the committed credit facility would permit an additional $1.88 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 September 30, 2008, the Company would have been permitted to issue up to a maximum of $1.3 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 1974 indenture pursuant to which $199.0 million (or 18%) of the Company’s long-term debt (as of September 30, 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 or 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 September 30, 2008, the Company had no debt outstanding under the committed credit facility.
 
Note F — Financial Instruments
 
Fair Values
 
The fair market value of the Company’s long-term debt is estimated based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
 
                                 
    At September 30  
    2008 Carrying
    2008 Fair
    2007 Carrying
    2007 Fair
 
    Amount     Value     Amount     Value  
    (Thousands)  
 
Long-Term Debt
  $ 1,099,000     $ 1,027,098     $ 999,024     $ 1,024,417  
                                 
 
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay.
 
Temporary cash investments, notes payable to banks and commercial paper are stated at cost, which approximates their fair value due to the short-term maturities of those financial instruments. Investments in life


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
 
Other Investments
 
Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The values of the insurance contracts amounted to $53.6 million and $54.7 million at September 30, 2008 and 2007, respectively. The fair value of the equity mutual fund was $12.4 million and $14.7 million at September 30, 2008 and 2007, respectively. The gross unrealized loss on this equity mutual fund was $(1.0) million at September 30, 2008. The equity mutual fund was in a gross unrealized gain position of $2.2 million at September 30, 2007. The fair value of the stock of an insurance company was $14.5 million and $16.3 million at September 30, 2008 and 2007, respectively. The gross unrealized gain on this stock was $12.1 million and $13.8 million at September 30, 2008 and 2007, respectively. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
 
Derivative Financial Instruments
 
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with the fluctuations in the price of natural gas and crude oil. These instruments include price swap agreements, no cost collars and futures contracts.
 
Under the price swap agreements, the Company receives monthly payments from (or makes payments to) other parties based upon the difference between a fixed price and a variable price as specified by the agreement. The variable price is either a crude oil or natural gas price quoted on the NYMEX or a quoted natural gas price in various national natural gas publications. The majority of these derivative financial instruments are accounted for as cash flow hedges and are used to lock in a price for the anticipated sale of natural gas and crude oil production in the Exploration and Production segment and the All Other category. The Energy Marketing segment accounts for these derivative financial instruments as fair value hedges and uses them to hedge against falling prices, a risk to which they are exposed on their fixed price gas purchase commitments. The Energy Marketing segment also uses these derivative financial instruments to hedge against rising prices, a risk to which they are exposed on their fixed price sales commitments. At September 30, 2008, the Company had natural gas price swap agreements covering a notional amount of 15.1 Bcf extending through 2011 at a weighted average fixed rate of $9.69 per Mcf. Of this amount, 0.9 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $9.64 per Mcf. The remaining 14.2 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $9.69 per Mcf. At September 30, 2008, the Company would have received a net $20.3 million to terminate the price swap agreements. The Company also had crude oil price swap agreements covering a notional amount of 1,920,000 bbls extending through 2011 at a weighted average fixed rate of $90.50 per bbl. At September 30, 2008, the Company would have had to pay a net $0.8 million to terminate the price swap agreements. The Energy Marketing segment also used natural gas swaps to hedge basis risk on their fixed price purchase commitments. At September 30, 2008, the Company had natural gas swap agreements covering 1.4 Bcf at a weighted average fixed rate of $0.47 per Mcf. These are treated as fair value hedges and the Company would have had to pay $0.2 million at September 30, 2008 to terminate the agreements.
 
At September 30, 2008, the Company had long (purchased) futures contracts covering 9.1 Bcf of gas extending through 2012 at a weighted average contract price of $9.24 per Mcf. They are accounted for as fair value hedges and are used by the Company’s Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed due to the fixed price gas sales commitments that it enters into with residential, commercial and industrial customers. The Company would have had to pay $9.9 million to terminate these futures contracts at September 30, 2008.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
At September 30, 2008, the Company had short (sold) futures contracts covering 6.7 Bcf of gas extending through 2010 at a weighted average contract price of $11.02 per Mcf. Of this amount, 3.5 Bcf is accounted for as cash flow hedges as these contracts relate to the anticipated sale of natural gas by the Energy Marketing segment. The remaining 3.2 Bcf is accounted for as fair value hedges used to hedge against falling prices on their fixed price gas purchasing commitments and hedge against decreases in natural gas prices associated with the eventual sale of gas in storage. The Company would have received $18.6 million to terminate these futures contracts at September 30, 2008.
 
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on an ongoing basis monitors counterparty credit exposure. Management has obtained guarantees from many of the parent companies of the respective counterparties to its derivative financial instruments. At September 30, 2008, the Company had eleven counterparties for its over the counter derivative financial instruments and no individual counterparty represented greater than 42% of total credit risk (measured as volumes hedged by an individual counterparty as a percentage of the Company’s total over the counter volumes hedged). The Company recorded a $0.6 million reduction to the fair market value of its derivative contracts that are in a gain position based on its assessment of counterparty credit risk. This credit reserve was determined by applying default probabilities to the anticipated cash flows that the Company is expecting from its counterparties.
 
Note G — Retirement Plan and Other Post-Retirement Benefits
 
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan) that covers approximately 65% of the employees of the Company. The Retirement Plan covers certain non-collectively bargained employees hired before July 1, 2003 and certain collectively bargained employees hired before November 1, 2003. Employees hired after June 30, 2003 are eligible for a Retirement Savings Account benefit provided under the Company’s defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account benefit have been $0.6 million through September 30, 2008 (with $0.2 million, $0.2 million and $0.1 million of costs occurring in 2008, 2007 and 2006, respectively). Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans were $4.0 million, $4.1 million, and $4.1 million for the years ended September 30, 2008, 2007 and 2006, respectively.
 
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003.
 
The Company’s policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations. Retirement Plan, VEBA trust and 401(h) account assets primarily consist of equity and fixed income investments or units in commingled funds or money market funds.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The expected return on plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is equal to market value as of the measurement date.
 
Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is June 30, 2008, 2007 and 2006, respectively.
 
                                                 
    Retirement Plan     Other Post-Retirement Benefits  
    Year Ended September 30     Year Ended September 30  
    2008     2007     2006     2008     2007     2006  
    (Thousands)  
 
Change in Benefit Obligation
                                               
Benefit Obligation at Beginning of Period
  $ 742,519     $ 732,207     $ 825,204     $ 444,545     $ 445,931     $ 546,273  
Service Cost
    12,597       12,898       16,416       5,104       5,614       8,029  
Interest Cost
    44,949       44,350       40,196       27,081       27,198       26,804  
Plan Participants’ Contributions
                      1,990       1,566       1,559  
Retiree Drug Subsidy Receipts
                      1,532       1,325        
Amendments(1)
                      (31,874 )            
Actuarial (Gain) Loss
    (34,189 )     (2,986 )     (108,112 )     (14,390 )     (14,450 )     (115,052 )
Benefits Paid
    (46,817 )     (43,950 )     (41,497 )     (22,443 )     (22,639 )     (21,682 )
                                                 
Benefit Obligation at End of Period
  $ 719,059     $ 742,519     $ 732,207     $ 411,545     $ 444,545     $ 445,931  
                                                 
Change in Plan Assets
                                               
Fair Value of Assets at Beginning of Period
  $ 765,144     $ 664,521     $ 616,462     $ 412,371     $ 325,624     $ 271,636  
Actual Return on Plan Assets
    (39,206 )     119,662       68,649       (43,478 )     65,552       34,785  
Employer Contributions
    3,817       16,488       20,907       29,200       42,268       39,326  
Employer Contributions During Period from Measurement Date to Fiscal Year End
    12,151       8,423                          
Plan Participants’ Contributions
                      1,990       1,566       1,559  
Benefits Paid
    (46,817 )     (43,950 )     (41,497 )     (22,443 )     (22,639 )     (21,682 )
                                                 
Fair Value of Assets at End of Period
  $ 695,089     $ 765,144     $ 664,521     $ 377,640     $ 412,371     $ 325,624  
                                                 
Reconciliation of Funded Status
                                               
Funded Status
  $ (23,970 )   $ 22,625     $ (67,686 )   $ (33,905 )   $ (32,174 )   $ (120,307 )
Unrecognized Net Actuarial Loss
                107,626                   54,487  
Unrecognized Transition Obligation
                                  49,890  
Unrecognized Prior Service Cost
                7,185                   12  
                                                 
Net Amount Recognized at End of Period
  $ (23,970 )   $ 22,625     $ 47,125     $ (33,905 )   $ (32,174 )   $ (15,918 )
                                                 


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    Retirement Plan     Other Post-Retirement Benefits  
    Year Ended September 30     Year Ended September 30  
    2008     2007     2006     2008     2007     2006  
    (Thousands)  
 
Amounts Recognized in the Balance Sheets Consist of:
                                               
Accrued Benefit Liability
  $ (23,970 )   $     $     $ (54,939 )   $ (70,555 )   $ (32,918 )
Prepaid Benefit Cost
          22,625       47,125       21,034       38,381       17,000  
Intangible Assets
                                   
Accumulated Other Comprehensive Loss from Additional Minimum Pension Liability Adjustment (Pre-Tax)
                                   
                                                 
Net Amount Recognized at End of Period
  $ (23,970 )   $ 22,625     $ 47,125     $ (33,905 )   $ (32,174 )   $ (15,918 )
                                                 
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
                                               
Discount Rate
    6.75 %     6.25 %     6.25 %     6.75 %     6.25 %     6.25 %
Expected Return on Plan Assets
    8.25 %     8.25 %     8.25 %     8.25 %     8.25 %     8.25 %
Rate of Compensation Increase
    5.00 %     5.00 %     5.00 %     5.00 %     5.00 %     5.00 %
Components of Net Periodic Benefit Cost
                                               
Service Cost
  $ 12,598     $ 12,898     $ 16,416     $ 5,104     $ 5,614     $ 8,029  
Interest Cost
    44,949       44,350       40,196       27,081       27,198       26,804  
Expected Return on Plan Assets
    (55,000 )     (51,235 )     (49,943 )     (33,715 )     (26,960 )     (22,302 )
Amortization of Prior Service Cost
    808       882       957       4       4       4  
Amortization of Transition Amount
                      7,127       7,127       7,127  
Recognition of Actuarial Loss(2)
    11,063       13,528       23,108       2,927       8,214       23,402  
Net Amortization and Deferral for Regulatory Purposes
    6,008       1,211       (6,409 )     22,264       16,220       (11,084 )
                                                 
Net Periodic Benefit Cost
  $ 20,426     $ 21,634     $ 24,325     $ 30,792     $ 37,417     $ 31,980  
                                                 
Other Comprehensive (Income) Loss (Pre-Tax) Attributable to Change In Additional Minimum Liability Recognition
  $     $     $ (165,914 )   $     $     $  
                                                 
Accumulated Other Comprehensive Loss (Pre-Tax) Attributable to Adoption of SFAS 158
    NA     $ 11,256       NA       NA     $ 778       NA  
                                                 
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30
                                               
Discount Rate
    6.25 %     6.25 %     5.00 %     6.25 %     6.25 %     5.00 %
Expected Return on Plan Assets
    8.25 %     8.25 %     8.25 %     8.25 %     8.25 %     8.25 %
Rate of Compensation Increase
    5.00 %     5.00 %     5.00 %     5.00 %     5.00 %     5.00 %

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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
(1) In Fiscal 2008, the Company passed an amendment, for most of the subsidiaries, which increased the participant contributions for active employees at the time of the amendment. This decreased the benefit obligation.
 
(2) Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.
 
The Net Periodic Benefit Cost in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under SFAS 87 and SFAS 106 as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.
 
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 Company’s fiscal year, with limited exceptions. Under SFAS 158, certain previously unrecognized actuarial gains and losses, previously unrecognized prior service costs, and a previously unrecognized transition obligation are required to be recognized. These amounts were not required to be recorded on the Company’s Consolidated Balance Sheet before the adoption of SFAS 158, but were instead amortized over a period of time. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 as of September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be adopted by the Company by the end of fiscal 2009. Currently, the Company measures its plan assets and benefit obligations using a June 30th measurement date. The incremental effects of adopting the provisions of SFAS 158 on the Company’s Consolidated Balance Sheet at September 30, 2007 are presented in the table below:
 
                         
    Before
    Consolidated
    After
 
    Application of
    SFAS 158
    Application of
 
    SFAS 158(1)     Impact     SFAS 158  
    (Thousands)  
 
Qualified Retirement Plan
                       
Reduction in Prepaid Pension and Other Post-Retirement Benefit Costs
  $ 51,612     $ (28,987 )   $ 22,625  
Increase in Other Regulatory Assets Related to SFAS 158
  $     $ 17,731     $ 17,731  
Reduction in Accumulated Other Comprehensive Income
  $     $ 7,008     $ 7,008  
Reduction in Deferred Income Taxes (under Deferred Credits)
  $     $ 4,248     $ 4,248  


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
    Before
    Consolidated
    After
 
    Application of
    SFAS 158
    Application of
 
    SFAS 158(1)     Impact     SFAS 158  
    (Thousands)  
 
Other Post-Retirement Benefits
                       
Increase in Prepaid Pension and Other Post-Retirement Benefit Costs
  $ 26,067     $ 12,314     $ 38,381  
Increase in Other Regulatory Assets Related to SFAS 158
  $     $ 38,472     $ 38,472  
Increase in Other Regulatory Liabilities Related to SFAS 158
  $     $ (3,247 )   $ (3,247 )
Reduction in Accumulated Other Comprehensive Income
  $     $ 484     $ 484  
Reduction in Deferred Income Taxes (under Deferred Credits)
  $     $ 294     $ 294  
Increase in Other Post-Retirement Liabilities
  $ (22,238 )   $ (48,317 )   $ (70,555 )
Non-Qualified Benefit Plan
                       
Increase in Other Regulatory Assets Related to SFAS 158
  $     $ 5,704     $ 5,704  
Reduction in Accumulated Other Comprehensive Income
  $     $ 4,990     $ 4,990  
Reduction in Deferred Income Taxes (under Deferred Credits)
  $     $ 3,027     $ 3,027  
Increase in Other Deferred Credits
  $ (30,115 )   $ (13,721 )   $ (43,836 )
Total Consolidated
                       
Reduction in Prepaid Pension and Other Post-Retirement Benefit Costs
  $ 77,679     $ (16,673 )   $ 61,006  
Increase in Other Regulatory Assets Related to SFAS 158
  $     $ 61,907     $ 61,907  
Increase in Other Regulatory Liabilities Related to SFAS 158
  $     $ (3,247 )   $ (3,247 )
Reduction in Accumulated Other Comprehensive Income
  $     $ 12,482     $ 12,482  
Reduction in Deferred Income Taxes (under Deferred Credits)
  $     $ 7,569     $ 7,569  
Increase in Other Post-Retirement Liabilities
  $ (22,238 )   $ (48,317 )   $ (70,555 )
Increase in Other Deferred Credits
  $ (30,115 )   $ (13,721 )   $ (43,836 )
 
 
(1) Amounts represent balances before applying the effects of the adoption of SFAS 158, but after giving effect to any necessary adjustments as a result of recognizing an additional minimum pension liability. At September 30, 2007, there was no additional minimum pension liability adjustment since the fair value of the plan assets exceeded the accumulated benefit obligation.
 
In order to adjust the funded status of its pension and other post-retirement benefit plans at September 30, 2008, the Company recorded a $57.2 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $7.3 million (net of deferred tax benefits of $4.4 million) increase to Accumulated Other Comprehensive Loss.

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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
The amounts recognized in accumulated other comprehensive loss, regulatory assets, and regulatory liabilities in fiscal 2008, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2009 are presented in the table below:
 
                         
          Other
       
    Retirement
    Post-Retirement
    Non-Qualified
 
    Plan     Benefits     Benefit Plan  
    (Thousands)  
 
Amounts Recognized In Accumulated Other Comprehensive Loss, Regulatory Assets and Regulatory Liabilities(1)
                       
Net Actuarial Gain/(Loss)
  $ (71,637 )   $ (53,108 )   $ (13,530 )
Transition Obligation
          (11,326 )      
Prior Service (Cost) Credit
    (5,495 )     7,561       (11 )
                         
Net Amount Recognized
  $ (77,132 )   $ (56,873 )   $ (13,541 )
                         
Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1)
                       
Net Actuarial Gain/(Loss)
  $ (5,676 )   $ (9,271 )   $ (1,322 )
Transition Obligation
          (2,265 )      
Prior Service (Cost) Credit
    (731 )     1,074        
                         
Net Amount Expected to be Recognized
  $ (6,407 )   $ (10,462 )   $ (1,322 )
                         
 
 
(1) Amounts presented are shown before recognizing deferred taxes.
 
In accordance with the provisions of SFAS 87, the Company recorded an additional minimum pension liability at September 30, 2005 representing the excess of the accumulated benefit obligation over the fair value of plan assets plus accrued amounts previously recorded. An intangible asset offset the additional liability to the extent of previously Unrecognized Prior Service Cost. The amount in excess of Unrecognized Prior Service Cost was recorded net of the related tax benefit as accumulated other comprehensive loss. At September 30, 2006, the Company reversed the additional minimum pension liability, intangible asset and accumulated other comprehensive loss recorded in prior years since the fair value of the plan assets exceeded the accumulated benefit obligation at September 30, 2006. The pre-tax amounts of the change in accumulated other comprehensive (income) loss related to the additional minimum pension liability adjustment at September 30, 2006 are shown in the table above. At September 30, 2007, prior to recognizing the impact of adopting SFAS 158, there was no additional minimum pension liability adjustment recorded since the fair value of the plan assets exceeded the accumulated benefit obligation. The projected benefit obligation, accumulated benefit obligation and fair value of assets for the Retirement Plan were as follows:
 
                         
    2008     2007     2006  
    (Thousands)  
 
Projected Benefit Obligation
  $ 719,059     $ 742,519     $ 732,207  
Accumulated Benefit Obligation
  $ 659,004     $ 672,340     $ 660,026  
Fair Value of Plan Assets
  $ 695,089     $ 765,144     $ 664,520  
 
The effect of the discount rate change for the Retirement Plan in 2008 was to decrease the projected benefit obligation of the Retirement Plan by $38.6 million. In 2008, other actuarial experience increased the projected benefit obligation for the Retirement Plan by $4.4 million. There was no change to the discount rate used to estimate the projected benefit obligation for the Retirement Plan during 2007. The effect of the discount rate change for the Retirement Plan in 2006 was to decrease the projected benefit obligation of the Retirement Plan by $113.1 million.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Company made cash contributions totaling $16.0 million to the Retirement Plan during the year ended September 30, 2008. The Company expects that the annual contribution to the Retirement Plan in 2009 will be in the range of $15.0 million to $20.0 million. 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 2009 in order to be in compliance with the Pension Protection Act of 2006. The following benefit payments, which reflect expected future service, are expected to be paid during the next five years and the five years thereafter: $50.5 million in 2009; $51.0 million in 2010; $51.4 million in 2011; $51.9 million in 2012; $52.9 million in 2013; and $286.7 million in the five years thereafter.
 
In addition to the Retirement Plan discussed above, the Company also has a Non Qualified benefit plan that covers a group of management employees designated by the Chief Executive Officer of the Company. This plan provides for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit cost associated with this plan was $5.0 million, $5.5 million and $5.4 million in 2008, 2007 and 2006, respectively. At September 30, 2008, an $8.0 million (pre-tax) loss was included in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet. This was first recognized in 2007 upon adoption of SFAS 158. There were no amounts recognized in other comprehensive income (loss) attributable to the recognition of an additional minimum liability for 2006. The accumulated benefit obligation for this plan was $31.8 million and $28.8 million at September 30, 2008 and 2007, respectively. The projected benefit obligation for the plan was $47.5 million and $43.8 million at September 30, 2008 and 2007, respectively. The actuarial valuations for this plan were determined based on a discount rate of 6.75%, 6.25% and 6.25% as of September 30, 2008, 2007 and 2006, respectively; a rate of compensation increase of 10.0% as of September 30, 2008, 2007 and 2006; and an expected long-term rate of return on plan assets of 8.25% at September 30, 2008, 2007 and 2006.
 
The effect of the discount rate change in 2008 was to decrease the other post-retirement benefit obligation by $26.3 million. Effective July 1, 2008, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $20.0 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2008 by $8.1 million.
 
There was no change to the discount rate used to estimate the other post-retirement benefit obligation during 2007. Effective July 1, 2007, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $8.6 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2007 by $23.0 million.
 
The effect of the discount rate change in 2006 was to decrease the other post-retirement benefit obligation by $77.5 million. Effective July 1, 2006, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to decrease the other post-retirement benefit obligation by $1.7 million. A change in the disability assumption decreased the other post-retirement benefit obligation by $1.4 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2006 by $34.4 million.
 
On December 8, 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. This Act introduced a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In accordance with FASB Staff Position FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, since the Company is assumed to continue to provide a prescription drug benefit to retirees in the point of service and indemnity plans that is at least actuarially equivalent to Medicare Part D, the impact of the Act was reflected as of December 8, 2003.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The estimated gross benefit payments and gross amount of subsidy receipts are as follows:
 
                 
    Benefit Payments     Subsidy Receipts  
 
2009
  $ 26,210,000     $ (1,714,000 )
2010
  $ 28,248,000     $ (1,942,000 )
2011
  $ 30,122,000     $ (2,167,000 )
2012
  $ 31,484,000     $ (2,437,000 )
2013
  $ 32,687,000     $ (2,719,000 )
2014 through 2018
  $ 181,354,000     $ (17,304,000 )
 
                         
    2008     2007     2006  
 
Rate of Increase for Pre Age 65 Participants
    9.0 %(1)     8.0 %(2)     9.0 %(2)
Rate of Increase for Post Age 65 Participants
    7.0 %(1)     6.67 %(2)     7.0 %(2)
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits
    10.0 %(1)     10.0 %(2)     11.0 %(2)
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement
    7.0 %(1)     7.0 %(3)     5.25 %(4)
 
 
(1) It was assumed that this rate would gradually decline to 5.0% by 2018.
 
(2) It was assumed that this rate would gradually decline to 5.0% by 2014.
 
(3) It was assumed that this rate would gradually decline to 5.0% by 2016.
 
(4) It was assumed that this rate would gradually decline to 5.0% by 2017.
 
The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2008 would increase by $45.1 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2008 by $4.7 million. If the health care cost trend rates were decreased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2008 would decrease by $38.4 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2007 by $3.9 million.
 
The Company made cash contributions totaling $29.1 million to the VEBA trusts and 401(h) accounts during the year ended September 30, 2008. In addition, the Company made direct payments of $0.1 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2008. The Company expects that the annual contribution to the VEBA trusts and 401(h) accounts in 2009 will be in the range of $25.0 million to $30.0 million.
 
The Company’s Retirement Plan weighted average asset allocations (excluding the 401(h) accounts) at September 30, 2008, 2007 and 2006 by asset category are as follows:
 
                                 
          Percentage of Plan
 
    Target Allocation
    Assets at September 30  
Asset Category
  2009     2008     2007     2006  
 
Equity Securities
    60-75 %     67 %     70 %     67 %
Fixed Income Securities
    20-35 %     29 %     24 %     26 %
Other
    0-15 %     4 %     6 %     7 %
                                 
Total
            100 %     100 %     100 %
                                 


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Company’s weighted average asset allocations for its VEBA trusts and 401(h) accounts at September 30, 2008, 2007 and 2006 by asset category are as follows:
 
                                 
          Percentage of Plan
 
    Target Allocation
    Assets at September 30  
Asset Category
  2009     2008     2007     2006  
 
Equity Securities
    85-100 %     93 %     95 %     95 %
Fixed Income Securities
    0-15 %     2 %     1 %     1 %
Other
    0-15 %     5 %     4 %     4 %
                                 
Total
            100 %     100 %     100 %
                                 
 
The Company’s assumption regarding the expected long-term rate of return on plan assets is 8.25%. The return assumption reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets.
 
The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition.
 
Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis.
 
The discount rate which is used to present value the future benefit payment obligations of the Retirement Plan, the Non-Qualified benefit plan, and the Company’s other post-retirement benefits is 6.75% as of September 30, 2008. The Company utilizes a yield curve model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year’s anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments.
 
Note H — 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. At September 30, 2008, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $19.4 million to $23.6 million. The minimum estimated liability of $19.4 million has been recorded on the Consolidated Balance Sheet at September 30, 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 (refer to Note C — Regulatory Matters for further discussion of the insurance proceeds). Other than as discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
(i)  Former Manufactured Gas Plant Sites
 
The Company has incurred investigation and/or clean-up costs at several former manufactured gas plant sites in New York and Pennsylvania. The Company continues to be responsible for future ongoing monitoring and long-term maintenance at two sites.
 
With respect to another former manufactured gas plant site, the Company received, in 1998 and again in October 1999, notice that the NYDEC believes the Company is responsible for contamination discovered at the site located in New York for which the Company had not been named as a PRP. In February 2007, the NYDEC identified the Company as a PRP for the site and issued a proposed remedial action plan. The NYDEC estimated clean-up costs under its proposed remedy to be $8.9 million if implemented. Although the Company commented to the NYDEC that the proposed remedial action plan contained a number of material errors, omissions and procedural defects, the NYDEC, in a March 2007 Record of Decision, selected the remedy it had previously proposed. In July 2007, the Company appealed the NYDEC’s Record of Decision to the New York State Supreme Court, Albany County. The Court dismissed the appeal in January 2008. The Company filed a notice of appeal in February 2008. In July 2008, the Company withdrew its appeal and, without admitting liability or fault, agreed to the terms of an Order on Consent issued by the NYDEC. Pursuant to the order, the Company will remediate the site consistent with the remedy selected in the NYDEC’s Record of Decision. The Company reimbursed the NYDEC in the amount of approximately $1.5 million for costs incurred in connection with the site from 1998 through May 30, 2007. The Company acknowledged that additional charges related to the site will be billed to the Company at a later date, including costs incurred by the NYDEC after May 30, 2007 and any costs incurred by the New York Department of Health. The Company has not received and does not expect to receive any estimates of such additional costs. The Company has submitted a Remedial Design/Remedial Action work plan to the NYDEC in accordance with the Order on Consent and has increased its recorded estimated minimum liability for this site to $16.5 million.
 
(ii)  Other
 
In June 2007, the NYDEC notified the Company, as well as a number of other companies, of their potential liability with respect to a remedial action at a waste disposal site in New York. The notification identified the Company as one of approximately 500 other companies considered to be PRPs related to this site and requested that the remedy the NYDEC proposed in a Record of Decision issued in March 2006 be performed. The estimated clean-up costs under the remedy selected by the NYDEC are estimated to be approximately $13.0 million if implemented. The Company participates in an organized group with other PRPs who are addressing this site.
 
Other
 
The Company, in its Utility segment, Energy Marketing segment, and All Other category, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Substantially all of these contracts expire within the next five years. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $793.2 million in 2009, $168.0 million in 2010, $55.6 million in 2011, $47.0 million in 2012, $21.6 million in 2013, and $100.7 million thereafter. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.
 
The Company has entered into leases for the use of buildings, vehicles, construction tools, meters, computer equipment and other items. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $6.0 million in 2009, $4.6 million in 2010, $3.6 million in 2011, $3.2 million in 2012, $2.5 million in 2013, and $12.4 million thereafter.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Company has entered into several contractual commitments associated with the construction of the Empire Connector project, including the pipeline construction itself and construction of a compressor station, as well as other contractual commitments for engineering and consulting services. The Empire Connector is scheduled to go in service by December 2008. As of September 30, 2008, the future contractual commitments related to the construction of the Empire Connector during 2009 is $13.5 million.
 
The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note C — Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business. These other litigation and regulatory 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 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.
 
Note I — Discontinued Operations
 
On August 31, 2007, the Company, in its Exploration and Production segment, completed the sale of SECI, Seneca’s wholly owned subsidiary that operated in Canada. The Company received approximately $232.1 million of proceeds from the sale, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. The sale resulted in the recognition of a gain of approximately $120.3 million, net of tax, during the fourth quarter of 2007. SECI is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in the provinces of Alberta, Saskatchewan and British Columbia in Canada. The decision to sell was based on lower than expected returns from the Canadian oil and gas properties combined with difficulty in finding significant new reserves. Seneca will continue its exploration and development activities in Appalachia, the Gulf of Mexico, and California. As a result of the decision to sell SECI, the Company began presenting all SECI operations as discontinued operations during the fourth quarter of 2007.
 
The following is selected financial information of the discontinued operations for SECI:
 
                 
    Year Ended September 30  
    2007     2006  
    (Thousands)  
 
Operating Revenues
  $ 50,495     $ 71,984  
Operating Expenses
    33,306       151,532  
                 
Operating Income (Loss)
    17,189       (79,548 )
Interest Income
    1,082       866  
                 
Income (Loss) before Income Taxes
    18,271       (78,682 )
Income Tax Expense (Benefit)
    2,792       (32,159 )
                 
Income (Loss) from Discontinued Operations
    15,479       (46,523 )
Gain on Disposal, Net of Taxes of $39,572
    120,301        
                 
Income (Loss) from Discontinued Operations
  $ 135,780     $ (46,523 )
                 


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note J — Business Segment Information
 
The Company reports financial results for five business segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing, and Timber. The breakdown of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
 
The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.
 
The Pipeline and Storage segment operations are regulated. The FERC regulates the operations of Supply Corporation and the NYPSC regulates the operations of Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR) and pipeline companies in the northeastern United States markets. Empire transports natural gas from the United States/Canadian border near Buffalo, New York into Central New York just north of Syracuse, New York. Empire is constructing the Empire Connector project, which consists of a compressor station and a pipeline extension from near Rochester, New York to an interconnection near Corning, New York with the unaffiliated Millennium Pipeline. The Empire Connector is anticipated to be ready to commence service in early December 2008, on or before the in-service date of the Millennium Pipeline. Empire transports gas to major industrial companies, utilities (including Distribution Corporation) and power producers.
 
The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, and in the Gulf Coast region of Texas, Louisiana and Alabama. Seneca’s production is, for the most part, sold to purchasers located in the vicinity of its wells. As disclosed in Note I — Discontinued Operations, on August 31, 2007, Seneca completed the sale of SECI, its wholly owned subsidiary operating in Canada, for a gain of approximately $120.3 million, net of tax, during the fourth quarter of 2007. As a result of the sale, SECI’s operations have been reported as discontinued operations.
 
The Energy Marketing segment is comprised of NFR’s operations. NFR markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
 
The Timber segment’s operations are carried out by the Northeast division of Seneca and by Highland. This segment has timber holdings (primarily high quality hardwoods) in the northeastern United States and sawmills and kilns in Pennsylvania.
 
The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. The accounting policies of the segments are the same as those described in Note A — Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. 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.
 


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                                         
    Year Ended September 30, 2008  
                                              Corporate
       
          Pipeline
    Exploration
                Total
          and
       
          and
    and
    Energy
          Reported
    All
    Intersegment
    Total
 
    Utility     Storage     Production     Marketing     Timber     Segments     Other     Eliminations     Consolidated  
    (Thousands)  
 
Revenue from External Customers
  $ 1,194,657     $ 135,052     $ 466,760     $ 549,932     $ 49,516     $ 2,395,917     $ 3,749     $ 695     $ 2,400,361  
Intersegment Revenues
  $ 15,612     $ 81,504     $     $ 1,300     $     $ 98,416     $ 14,115     $ (112,531 )   $  
Interest Income
  $ 1,836     $ 843     $ 10,921     $ 323     $ 1,053     $ 14,976     $ 179     $ (4,340 )   $ 10,815  
Interest Expense
  $ 27,683     $ 13,783     $ 41,645     $ 175     $ 3,142     $ 86,428     $ 640     $ (13,099 )   $ 73,969  
Depreciation, Depletion and Amortization
  $ 39,113     $ 32,871     $ 92,221     $ 42     $ 4,904     $ 169,151     $ 783     $ 689     $ 170,623  
Income Tax Expense
  $ 36,303     $ 34,008     $ 92,686     $ 3,180     $ (378 )   $ 165,799     $ 2,564     $ (441 )   $ 167,922  
Income from Unconsolidated Subsidiaries
  $     $     $     $     $     $     $ 6,303     $     $ 6,303  
Segment Profit: Net Income (Loss)
  $ 61,472     $ 54,148     $ 146,612     $ 5,889     $ 107     $ 268,228     $ 5,672     $ (5,172 )   $ 268,728  
Expenditures for Additions to Long-Lived Assets
  $ 57,457     $ 165,520     $ 192,187     $ 39     $ 1,354     $ 416,557     $ 131     $ (2,186 )   $ 414,502  
 
                                                                         
    At September 30, 2008  
    (Thousands)  
 
                                                                         
Segment Assets
  $ 1,643,665     $ 948,984     $ 1,416,120     $ 89,527     $ 149,896     $ 4,248,192     $ 67,978     $ (185,983 )   $ 4,130,187  
 
                                                                         
    Year Ended September 30, 2007  
                                              Corporate
       
          Pipeline
    Exploration
                Total
          and
       
          and
    and
    Energy
          Reported
    All
    Intersegment
    Total
 
    Utility     Storage     Production     Marketing     Timber     Segments     Other     Eliminations     Consolidated  
    (Thousands)  
 
Revenue from External Customers
  $ 1,106,453     $ 130,410     $ 324,037     $ 413,612     $ 58,897     $ 2,033,409     $ 5,385     $ 772     $ 2,039,566  
Intersegment Revenues
  $ 14,271     $ 81,556     $     $     $     $ 95,827     $ 8,726     $ (104,553 )   $  
Interest Income
  $ (2,345 )   $ 357     $ 9,905     $ 682     $ 1,249     $ 9,848     $ 16     $ (8,314 )   $ 1,550  
Interest Expense
  $ 28,190     $ 9,623     $ 51,743     $ 263     $ 3,265     $ 93,084     $ 2,687     $ (21,296 )   $ 74,475  
Depreciation, Depletion and Amortization
  $ 40,541     $ 32,985     $ 78,174     $ 33     $ 4,709     $ 156,442     $ 785     $ 692     $ 157,919  
Income Tax Expense
  $ 31,642     $ 35,740     $ 52,421     $ 5,654     $ 2,818     $ 128,275     $ 1,647     $ 1,891     $ 131,813  
Income from Unconsolidated Subsidiaries
  $     $     $     $     $     $     $ 4,979     $     $ 4,979  
Segment Profit: Income from Continuing Operations
  $ 50,886     $ 56,386     $ 74,889     $ 7,663     $ 3,728     $ 193,552     $ 2,564     $ 5,559     $ 201,675  
Expenditures for Additions to Long-Lived Assets from Continuing Operations
  $ 54,185     $ 43,226     $ 146,687     $ 76     $ 3,657     $ 247,831     $ 87     $ (319 )   $ 247,599  
 
                                                                         
    At September 30, 2007  
    (Thousands)  
 
                                                                         
Segment Assets
  $ 1,565,593     $ 810,957     $ 1,326,073     $ 59,802     $ 165,224     $ 3,927,649     $ 66,531     $ (105,768 )   $ 3,888,412  
 
                                                                         
    Year Ended September 30, 2006  
                                              Corporate
       
          Pipeline
    Exploration
                Total
          and
       
          and
    and
    Energy
          Reported
    All
    Intersegment
    Total
 
    Utility     Storage     Production     Marketing     Timber     Segments     Other     Eliminations     Consolidated  
    (Thousands)  
 
Revenue from External Customers
  $ 1,265,695     $ 132,921     $ 274,896     $ 497,069     $ 65,024     $ 2,235,605     $ 3,304     $ 766     $ 2,239,675  
Intersegment Revenues
  $ 15,068     $ 81,431     $     $     $ 5     $ 96,504     $ 9,444     $ (105,948 )   $  
Interest Income
  $ 4,889     $ 454     $ 7,816     $ 445     $ 747     $ 14,351     $ 22     $ (4,964 )   $ 9,409  
Interest Expense
  $ 26,174     $ 6,620     $ 50,457     $ 227     $ 3,095     $ 86,573     $ 2,555     $ (10,547 )   $ 78,581  
Depreciation, Depletion and Amortization
  $ 40,172     $ 36,876     $ 67,122     $ 53     $ 6,495     $ 150,718     $ 789     $ 492     $ 151,999  
Income Tax Expense
  $ 35,699     $ 33,896     $ 29,351     $ 3,748     $ 3,277     $ 105,971     $ 969     $ 1,305     $ 108,245  
Income from Unconsolidated Subsidiaries
  $     $     $     $     $     $     $ 3,583     $     $ 3,583  
Segment Profit: Income (Loss) from Continuing Operations
  $ 49,815     $ 55,633     $ 67,494     $ 5,798     $ 5,704     $ 184,444     $ 359     $ (189 )   $ 184,614  
Expenditures for Additions to Long-Lived Assets from Continuing Operations
  $ 54,414     $ 26,023     $ 166,535     $ 16     $ 2,323     $ 249,311     $ 85     $ 2,995     $ 252,391  
 
                                                                         
    At September 30, 2006  
    (Thousands)  
 
                                                                         
Segment Assets
  $ 1,498,442     $ 767,889     $ 1,209,969 (1)   $ 81,374     $ 159,421     $ 3,717,095     $ 64,287     $ (17,634 )   $ 3,763,748  

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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
(1) Amount includes $134,930 of assets of SECI, which has been classified as discontinued operations as of September 30, 2007. (See Note I — Discontinued Operations).
 
                         
    For The Year Ended September 30  
Geographic Information
  2008     2007     2006  
    (Thousands)  
 
Revenues from External Customers(1):
                       
United States
  $ 2,400,361     $ 2,039,566     $ 2,239,675  
                         
 
                         
    At September 30  
    2008     2007     2006  
    (Thousands)  
 
Long-Lived Assets:
                       
United States
  $ 3,630,709     $ 3,334,274     $ 3,181,769  
Assets of Discontinued Operations
                97,234  
                         
    $ 3,630,709     $ 3,334,274     $ 3,279,003  
                         
 
 
(1) Revenue is based upon the country in which the sale originates. This table excludes revenues from Canadian discontinued operations of $50,495 and $71,984 for September 30, 2007 and 2006, respectively.
 
Note K — Investments in Unconsolidated Subsidiaries
 
The Company’s unconsolidated subsidiaries consist of equity method investments in Seneca Energy, Model City and ESNE. The Company has 50% interests in each of these entities. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. ESNE sells its electricity into the New York power grid.
 
A summary of the Company’s investments in unconsolidated subsidiaries at September 30, 2008 and 2007 is as follows:
 
                 
    At September 30  
    2008     2007  
    (Thousands)  
 
ESNE
  $ 3,958     $ 4,652  
Seneca Energy
    10,589       12,033  
Model City
    1,732       1,571  
                 
    $ 16,279     $ 18,256  
                 


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note L — Intangible Assets
 
As a result of the Empire and Toro acquisitions, the Company acquired certain intangible assets during 2003. In the case of the Empire acquisition, the intangible assets represent the fair value of various long-term transportation contracts with Empire’s customers. In the case of the Toro acquisition, the intangible assets represent the fair value of various long-term gas purchase contracts with the various landfills. These intangible assets are being amortized over the lives of the transportation and gas purchase contracts with no residual value at the end of the amortization period. The weighted-average amortization period for the gross carrying amount of the transportation contracts is 8 years. The weighted-average amortization period for the gross carrying amount of the gas purchase contracts is 20 years. Details of these intangible assets are as follows (in thousands):
 
                                 
                      At September 30,
 
    At September 30, 2008     2007  
    Gross Carrying
    Accumulated
    Net Carrying
    Net Carrying
 
    Amount     Amortization     Amount     Amount  
 
Intangible Assets Subject to Amortization:
                               
Long-Term Transportation Contracts
  $ 8,580     $ (6,058 )   $ 2,522     $ 3,591  
Long-Term Gas Purchase Contracts
    31,864       (8,212 )     23,652       25,245  
                                 
    $ 40,444     $ (14,270 )   $ 26,174     $ 28,836  
                                 
Aggregate Amortization Expense:
                               
For the Year Ended September 30, 2008
  $ 2,662                          
For the Year Ended September 30, 2007
  $ 2,662                          
For the Year Ended September 30, 2006
  $ 2,662                          
 
The gross carrying amount of intangible assets subject to amortization at September 30, 2008 remained unchanged from September 30, 2007. The only activity with regard to intangible assets subject to amortization was amortization expense as shown on the table above. Amortization expense for the long-term transportation contracts is estimated to be $0.5 million in 2009, and $0.4 million in 2010, 2011, 2012 and 2013. Amortization expense for the long-term gas purchase contracts is estimated to be $1.6 million annually for 2009, 2010, 2011, 2012 and 2013.
 
Note M — Quarterly Financial Data (unaudited)
 
In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statements of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis.
 


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                                         
                            Net
                         
                            Income
                         
                Income
    Income
    Available
    Earnings from
             
                from
    from
    for
    Continuing Operations per
             
Quarter
  Operating
    Operating
    Continuing
    Discontinued
    Common
    Common Share     Earnings per Common Share  
Ended
  Revenues     Income     Operations     Operations     Stock     Basic     Diluted     Basic     Diluted  
    (Thousands, except per common share amounts)  
 
2008
                                                                       
9/30/2008
  $ 397,858     $ 79,149     $ 43,266     $     $ 43,266     $ 0.54     $ 0.52     $ 0.54     $ 0.52  
6/30/2008
  $ 548,382     $ 110,947     $ 59,855     $     $ 59,855     $ 0.74     $ 0.72     $ 0.74     $ 0.72  
3/31/2008
  $ 885,853     $ 170,020     $ 95,003 (1)   $     $ 95,003 (1)   $ 1.14     $ 1.11     $ 1.14     $ 1.11  
12/31/2007
  $ 568,268     $ 126,009     $ 70,604     $     $ 70,604     $ 0.84     $ 0.82     $ 0.84     $ 0.82  
2007
                                                                       
9/30/2007
  $ 302,030     $ 73,504     $ 34,295     $ 123,395 (2)   $ 157,690 (2)   $ 0.41     $ 0.40     $ 1.89     $ 1.84  
6/30/2007
  $ 448,779     $ 83,933     $ 41,212 (3)   $ 5,586     $ 46,798 (3)   $ 0.49     $ 0.48     $ 0.56     $ 0.55  
3/31/2007
  $ 798,100     $ 142,404     $ 75,480 (4)   $ 2,967     $ 78,447 (4)   $ 0.91     $ 0.89     $ 0.95     $ 0.92  
12/31/2006
  $ 490,657     $ 96,657     $ 50,688 (5)   $ 3,832     $ 54,520 (5)   $ 0.61     $ 0.60     $ 0.66     $ 0.64  
 
 
(1) Includes a $0.6 million gain on sale of turbine.
 
(2) Includes a $120.3 million gain on the sale of SECI.
 
(3) Includes $4.8 million of income associated with the reversal of reserve for preliminary project costs associated with the Empire Connector project.
 
(4) Includes $2.3 million of income associated with the reversal of a purchased gas expense accrual related to the resolution of a contingency.
 
(5) Includes a $1.9 million positive earnings impact associated with the discontinuance of hedge accounting on an interest rate collar.
 
Note N — Market for Common Stock and Related Shareholder Matters (unaudited)
 
At September 30, 2008, there were 16,544 registered shareholders of Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note E — Capitalization and Short-Term Borrowings. The quarterly price ranges (based on intra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 2008 and 2007, are shown below:
 
                         
    Price Range        
Quarter Ended
  High     Low     Dividends Declared  
 
2008
                       
9/30/2008
  $ 60.36     $ 39.16     $ .325  
6/30/2008
  $ 63.71     $ 47.00     $ .325  
3/31/2008
  $ 48.78     $ 38.04     $ .31  
12/31/2007
  $ 50.29     $ 45.20     $ .31  
2007
                       
9/30/2007
  $ 47.00     $ 40.95     $ .31  
6/30/2007
  $ 47.87     $ 42.75     $ .31  
3/31/2007
  $ 43.79     $ 36.94     $ .30  
12/31/2006
  $ 40.21     $ 35.02     $ .30  
 

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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note O — Supplementary Information for Oil and Gas Producing Activities (unaudited)
 
The following supplementary information is presented in accordance with SFAS 69, “Disclosures about Oil and Gas Producing Activities,” and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars.
 
Capitalized Costs Relating to Oil and Gas Producing Activities
 
                 
    At September 30  
    2008     2007  
    (Thousands)  
 
Proved Properties(1)
  $ 1,783,276     $ 1,583,956  
Unproved Properties
    23,285       20,005  
                 
      1,806,561       1,603,961  
Less — Accumulated Depreciation, Depletion and Amortization
    718,166       627,073  
                 
    $ 1,088,395     $ 976,888  
                 
 
 
(1) Includes asset retirement costs of $60.9 million and $40.9 million at September 30, 2008 and 2007, respectively.
 
Costs related to unproved properties 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. Following is a summary of costs excluded from amortization at September 30, 2008:
 
                                         
    Total
                         
    as of
                         
    September 30,
    Year Costs Incurred  
    2008     2008     2007     2006     Prior  
    (Thousands)  
 
Acquisition Costs
  $ 23,285     $ 7,914     $ 2,433     $ 11,918     $ 1,020  


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands)  
 
United States
                       
Property Acquisition Costs:
                       
Proved
  $ 16,474     $ 2,621     $ 5,339  
Unproved
    8,449       3,210       8,844  
Exploration Costs
    56,274       26,891       64,087  
Development Costs
    106,975       113,206       87,738  
Asset Retirement Costs
    20,048       2,139       10,965  
                         
      208,220       148,067       176,973  
                         
Canada — Discontinued Operations
                       
Property Acquisition Costs:
                       
Proved
          (1,404 )     (427 )
Unproved
          (1,142 )     6,492  
Exploration Costs
          20,134       20,778  
Development Costs
          11,414       14,385  
Asset Retirement Costs
          167       279  
                         
            29,169       41,507  
                         
Total
                       
Property Acquisition Costs:
                       
Proved
    16,474       1,217       4,912  
Unproved
    8,449       2,068       15,336  
Exploration Costs
    56,274       47,025       84,865  
Development Costs
    106,975       124,620       102,123  
Asset Retirement Costs
    20,048       2,306       11,244  
                         
    $ 208,220     $ 177,236     $ 218,480  
                         
 
For the years ended September 30, 2008, 2007 and 2006, the Company spent $25.4 million, $30.3 million and $55.6 million, respectively, developing proved undeveloped reserves.


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Results of Operations for Producing Activities
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands, except per Mcfe amounts)  
 
United States
                       
Operating Revenues:
                       
Natural Gas (includes revenues from sales to affiliates of $443, $325 and $106, respectively)
  $ 216,623     $ 135,399     $ 152,451  
Oil, Condensate and Other Liquids
    305,887       189,539       195,050  
                         
Total Operating Revenues(1)
    522,510       324,938       347,501  
Production/Lifting Costs
    66,685       48,410       41,354  
Accretion Expense
    4,056       3,704       2,412  
Depreciation, Depletion and Amortization ($2.23, $1.97 and $1.74 per Mcfe of production)
    91,093       77,452       66,488  
Income Tax Expense
    144,922       78,928       88,104  
                         
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)
    215,754       116,444       149,143  
                         
Canada — Discontinued Operations
                       
Operating Revenues:
                       
Natural Gas
          39,114       54,819  
Oil, Condensate and Other Liquids
          10,313       13,985  
                         
Total Operating Revenues(1)
          49,427       68,804  
Production/Lifting Costs
          14,846       14,628  
Accretion Expense
          249       258  
Depreciation, Depletion and Amortization ($0, $1.67 and $2.95 per Mcfe of production)
          12,787       27,439  
Impairment of Oil and Gas Producing Properties(2)
                104,739  
Income Tax Expense (Benefit)
          3,703       (31,987 )
                         
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)
          17,842       (46,273 )
                         


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands, except per Mcfe amounts)  
 
Total
                       
Operating Revenues:
                       
Natural Gas (includes revenues from sales to affiliates of $443, $325 and $106, respectively)
    216,623       174,513       207,270  
Oil, Condensate and Other Liquids
    305,887       199,852       209,035  
                         
Total Operating Revenues(1)
    522,510       374,365       416,305  
Production/Lifting Costs
    66,685       63,256       55,982  
Accretion Expense
    4,056       3,953       2,670  
Depreciation, Depletion and Amortization ($2.23, $1.92 and $1.98 per Mcfe of production)
    91,093       90,239       93,927  
Impairment of Oil and Gas Producing Properties(2)
                104,739  
Income Tax Expense
    144,922       82,631       56,117  
                         
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)
  $ 215,754     $ 134,286     $ 102,870  
                         
 
 
(1) Exclusive of hedging gains and losses. See further discussion in Note F — Financial Instruments.
 
(2) See discussion of impairment in Note A — Summary of Significant Accounting Policies.

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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Reserve Quantity Information
 
The Company’s proved oil and gas reserves are located in the United States. The estimated quantities of proved reserves disclosed in the table below are based upon estimates by qualified Company geologists and engineers and are audited by independent petroleum engineers. Such estimates are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
 
                                                 
    Gas MMcf  
    U. S.              
    Gulf
    West
                Canada
       
    Coast
    Coast
    Appalachian
    Total
    (Discontinued
    Total
 
    Region     Region     Region     U.S.     Operations)     Company  
 
Proved Developed and Undeveloped Reserves:
                                               
September 30, 2005
    38,470       70,459       83,125       192,054       46,086       238,140  
Extensions and Discoveries
    11,763       1,815       11,132       24,710       6,229       30,939  
Revisions of Previous Estimates
    679       5,757       (7,776 )     (1,340 )     (11,096 )     (12,436 )
Production
    (9,110 )     (3,880 )     (5,108 )     (18,098 )     (7,673 )     (25,771 )
Purchases of Minerals in Place
          1,715             1,715             1,715  
Sales of Minerals in Place
                            (12 )     (12 )
                                                 
September 30, 2006
    41,802       75,866       81,373       199,041       33,534       232,575  
Extensions and Discoveries
    3,577             29,676       33,253       1,333       34,586  
Revisions of Previous Estimates
    (9,851 )     1,238       1,618       (6,995 )     11,634       4,639  
Production
    (10,356 )     (3,929 )     (5,555 )     (19,840 )     (6,426 )     (26,266 )
Sales of Minerals in Place
    (36 )           (34 )     (70 )     (40,075 )     (40,145 )
                                                 
September 30, 2007
    25,136       73,175       107,078       205,389             205,389  
Extensions and Discoveries
    8,759             31,322       40,081             40,081  
Revisions of Previous Estimates
    2,156       566       (3,460 )     (738 )           (738 )
Production
    (11,033 )     (4,039 )     (7,269 )     (22,341 )           (22,341 )
Purchases of Minerals in Place
          4,539       727       5,266             5,266  
Sales of Minerals in Place
    (377 )     (1,381 )           (1,758 )           (1,758 )
                                                 
September 30, 2008
    24,641       72,860       128,398       225,899             225,899  
                                                 
Proved Developed Reserves:
                                               
September 30, 2005
    23,108       58,692       83,125       164,925       43,980       208,905  
September 30, 2006
    32,345       64,196       81,373       177,914       33,534       211,448  
September 30, 2007
    25,136       66,017       96,674       187,827             187,827  
September 30, 2008
    18,242       68,453       115,824       202,519             202,519  
 


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    Oil Mbbl  
    U. S.              
    Gulf
    West
                Canada
       
    Coast
    Coast
    Appalachian
    Total
    (Discontinued
    Total
 
    Region     Region     Region     U.S.     Operations)     Company  
 
Proved Developed and Undeveloped Reserves:
                                               
September 30, 2005
    1,295       57,085       177       58,557       1,700       60,257  
Extensions and Discoveries
    39       172       108       319       128       447  
Revisions of Previous Estimates
    595       (80 )     57       572       101       673  
Production
    (685 )     (2,582 )     (69 )     (3,336 )     (272 )     (3,608 )
Purchases of Minerals in Place
          274             274             274  
Sales of Minerals in Place
                            (25 )     (25 )
                                                 
September 30, 2006
    1,244       54,869       273       56,386       1,632       58,018  
Extensions and Discoveries
    63             281       344       108       452  
Revisions of Previous Estimates
    851       (6,822 )     84       (5,887 )     (76 )     (5,963 )
Production
    (717 )     (2,403 )     (124 )     (3,244 )     (206 )     (3,450 )
Sales of Minerals in Place
    (6 )           (7 )     (13 )     (1,458 )     (1,471 )
                                                 
September 30, 2007
    1,435       45,644       507       47,586             47,586  
Extensions and Discoveries
    298       471       58       827             827  
Revisions of Previous Estimates
    203       (34 )     (64 )     105             105  
Production
    (505 )     (2,460 )     (105 )     (3,070 )           (3,070 )
Purchases of Minerals in Place
          2,084             2,084             2,084  
Sales of Minerals in Place
    (73 )     (1,261 )           (1,334 )           (1,334 )
                                                 
September 30, 2008
    1,358       44,444       396       46,198             46,198  
                                                 
Proved Developed Reserves:
                                               
September 30, 2005
    1,229       41,701       177       43,107       1,700       44,807  
September 30, 2006
    1,217       42,522       273       44,012       1,632       45,644  
September 30, 2007
    1,435       36,509       483       38,427             38,427  
September 30, 2008
    1,313       37,224       357       38,894             38,894  
 
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, it is based on year-end prices and costs adjusted only for existing contractual changes, and it assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.
 
The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
 

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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands)  
 
United States
                       
Future Cash Inflows
  $ 5,845,214     $ 4,879,496     $ 3,911,059  
Less:
                       
Future Production Costs
    1,231,705       872,536       758,258  
Future Development Costs
    265,515       229,987       205,497  
Future Income Tax Expense at Applicable Statutory Rate
    1,645,351       1,423,707       1,019,307  
                         
Future Net Cash Flows
    2,702,643       2,353,266       1,927,997  
Less:
                       
10% Annual Discount for Estimated Timing of Cash Flows
    1,434,799       1,292,804       1,066,338  
                         
Standardized Measure of Discounted Future Net Cash Flows
    1,267,844       1,060,462       861,659  
                         
Canada — Discontinued Operations
                       
Future Cash Inflows
                197,227  
Less:
                       
Future Production Costs
                92,234  
Future Development Costs
                11,520  
Future Income Tax Expense at Applicable Statutory Rate
                (151 )
                         
Future Net Cash Flows
                93,624  
Less:
                       
10% Annual Discount for Estimated Timing of Cash Flows
                19,375  
                         
Standardized Measure of Discounted Future Net Cash Flows
                74,249  
                         
Total
                       
Future Cash Inflows
    5,845,214       4,879,496       4,108,286  
Less:
                       
Future Production Costs
    1,231,705       872,536       850,492  
Future Development Costs
    265,515       229,987       217,017  
Future Income Tax Expense at Applicable Statutory Rate
    1,645,351       1,423,707       1,019,156  
                         
Future Net Cash Flows
    2,702,643       2,353,266       2,021,621  
Less:
                       
10% Annual Discount for Estimated Timing of Cash Flows
    1,434,799       1,292,804       1,085,713  
                         
Standardized Measure of Discounted Future Net Cash Flows
  $ 1,267,844     $ 1,060,462     $ 935,908  
                         

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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands)  
 
United States
                       
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year
  $ 1,060,462     $ 861,659     $ 1,491,532  
Sales, Net of Production Costs
    (455,825 )     (276,529 )     (306,147 )
Net Changes in Prices, Net of Production Costs
    509,705       539,895       (941,545 )
Purchases of Minerals in Place
    67,768             7,607  
Sales of Minerals in Place
    (31,642 )     484        
Extensions and Discoveries
    143,394       98,751       66,975  
Changes in Estimated Future Development Costs
    (100,684 )     (83,199 )     (83,750 )
Previously Estimated Development Costs Incurred
    65,156       58,710       67,048  
Net Change in Income Taxes at Applicable Statutory Rate
    (119,585 )     (174,920 )     404,176  
Revisions of Previous Quantity Estimates
    (3,936 )     (140,203 )     4,850  
Accretion of Discount and Other
    133,031       175,814       150,913  
                         
Standardized Measure of Discounted Future Net Cash Flows at End of Year
    1,267,844       1,060,462       861,659  
                         
Canada — Discontinued Operations
                       
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year
          74,249       206,643  
Sales, Net of Production Costs
          (34,581 )     (54,176 )
Net Changes in Prices, Net of Production Costs
          35,628       (180,216 )
Sales of Minerals in Place
          (151,236 )     (238 )
Extensions and Discoveries
          6,908       10,369  
Changes in Estimated Future Development Costs
          5,722       (3,282 )
Previously Estimated Development Costs Incurred
          5,798       4,450  
Net Change in Income Taxes at Applicable Statutory Rate
          (10,075 )     82,966  
Revisions of Previous Quantity Estimates
          34,998       (15,478 )
Accretion of Discount and Other
          32,589       23,211  
                         
Standardized Measure of Discounted Future Net Cash Flows at End of Year
                74,249  
                         


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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
    Year Ended September 30  
    2008     2007     2006  
    (Thousands)  
 
Total
                       
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year
    1,060,462       935,908       1,698,175  
Sales, Net of Production Costs
    (455,825 )     (311,110 )     (360,323 )
Net Changes in Prices, Net of Production Costs
    509,705       575,523       (1,121,761 )
Purchases of Minerals in Place
    67,768             7,607  
Sales of Minerals in Place
    (31,642 )     (150,752 )     (238 )
Extensions and Discoveries
    143,394       105,659       77,344  
Changes in Estimated Future Development Costs
    (100,684 )     (77,477 )     (87,032 )
Previously Estimated Development Costs Incurred
    65,156       64,508       71,498  
Net Change in Income Taxes at Applicable Statutory Rate
    (119,585 )     (184,995 )     487,142  
Revisions of Previous Quantity Estimates
    (3,936 )     (105,205 )     (10,628 )
Accretion of Discount and Other
    133,031       208,403       174,124  
                         
Standardized Measure of Discounted Future Net Cash Flows at End of Year
  $ 1,267,844     $ 1,060,462     $ 935,908  
                         
 
Schedule II — Valuation and Qualifying Accounts
 
                                         
          Additions
                   
    Balance
    Charged
    Additions
          Balance
 
    at
    to
    Charged
          at
 
    Beginning
    Costs
    to
          End
 
    of
    and
    Other
          of
 
Description
  Period     Expenses     Accounts(1)     Deductions(2)     Period  
    (Thousands)  
 
Year Ended September 30, 2008
                                       
Allowance for Uncollectible Accounts
  $ 28,654     $ 27,274     $ 2,734     $ 25,545     $ 33,117  
                                         
Year Ended September 30, 2007
                                       
Allowance for Uncollectible Accounts
  $ 31,427     $ 27,652     $ 1,414     $ 31,839     $ 28,654  
                                         
Year Ended September 30, 2006
                                       
Allowance for Uncollectible Accounts
  $ 26,940     $ 29,088     $ 907     $ 25,508     $ 31,427  
Deferred Tax Valuation Allowance
  $ 2,877     $ (2,877 )   $     $     $  
                                         
 
 
(1) Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate agreement.
 
(2) Amounts represent net accounts receivable written-off.

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Item 9    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
None
 
Item 9A    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 September 30, 2008.
 
Management’s Report on Internal Control over Financial Reporting
 
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
 
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2008. In making this assessment, management used the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of September 30, 2008.
 
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this Annual Report on Form 10-K, has issued a report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2008. The report appears in Part II, Item 8 of this Annual Report on Form 10-K.
 
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 September 30, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
 
Item 9B    Other Information
 
None
 
PART III
 
Item 10    Directors, Executive Officers and Corporate Governance
 
The information required by this item concerning the directors of the Company and corporate governance is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its 2009


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Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008. The information concerning directors is set forth in the definitive Proxy Statement under the headings entitled “Nominees for Election as Directors for Three-Year Terms to Expire in 2012,” “Directors Whose Terms Expire in 2011,” “Directors Whose Terms Expire in 2010,” and “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated herein by reference. The information concerning corporate governance is set forth in the definitive Proxy Statement under the heading entitled “Meetings of the Board of Directors and Standing Committees” and is incorporated herein by reference. Information concerning the Company’s executive officers can be found in Part I, Item 1, of this report.
 
The Company has adopted a Code of Business Conduct and Ethics that applies to the Company’s directors, officers and employees and has posted such Code of Business Conduct and Ethics on the Company’s website, www.nationalfuelgas.com, together with certain other corporate governance documents. Copies of the Company’s Code of Business Conduct and Ethics, charters of important committees, and Corporate Governance Guidelines will be made available free of charge upon written request to Investor Relations, National Fuel Gas Company, 6363 Main Street, Williamsville, New York 14221.
 
The Company intends to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or a waiver from, a provision of its code of ethics that applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, and that relates to any element of the code of ethics definition enumerated in paragraph (b) of Item 406 of the SEC’s Regulation S-K, by posting such information on its website, www.nationalfuelgas.com.
 
Item 11    Executive Compensation
 
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its 2009 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008. The information concerning executive compensation is set forth in the definitive Proxy Statement under the headings “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and, excepting the “Report of the Compensation Committee,” is incorporated herein by reference.
 
Item 12    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
Equity Compensation Plan Information
 
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its 2009 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008. The equity compensation plan information is set forth in the definitive Proxy Statement under the heading “Equity Compensation Plan Information” and is incorporated herein by reference.
 
Security Ownership and Changes in Control
 
(a)   Security Ownership of Certain Beneficial Owners
 
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its 2009 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008. The information concerning security ownership of certain beneficial owners is set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
 
(b)   Security Ownership of Management
 
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its 2009 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008. The information concerning security ownership of


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management is set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
 
(c)   Changes in Control
 
None
 
Item 13    Certain Relationships and Related Transactions, and Director Independence
 
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its 2009 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008. The information regarding certain relationships and related transactions is set forth in the definitive Proxy Statement under the headings “Compensation Committee Interlocks and Insider Participation” and “Related Person Transactions” and is incorporated herein by reference. The information regarding director independence is set forth in the definitive Proxy Statement under the heading “Director Independence” and is incorporated herein by reference.
 
Item 14    Principal Accountant Fees and Services
 
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its 2009 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008. The information concerning principal accountant fees and services is set forth in the definitive Proxy Statement under the heading “Audit Fees” and is incorporated herein by reference.
 
PART IV
 
Item 15    Exhibits and Financial Statement Schedules
 
(a)1.  Financial Statements
 
Financial statements filed as part of this report are listed in the index included in Item 8 of this Form 10-K, and reference is made thereto.
 
(a)2.  Financial Statement Schedules
 
Financial statement schedules filed as part of this report are listed in the index included in Item 8 of this Form 10-K, and reference is made thereto.
 
(a)3.  Exhibits
 
         
Exhibit
  Description of
Number
 
Exhibits
 
  3(i)     Articles of Incorporation:
      Restated Certificate of Incorporation of National Fuel Gas Company dated September 21, 1998 (Exhibit 3.1, Form 10-K for fiscal year ended September 30, 1998 in File No. 1-3880)
      Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 3(ii), Form 8-K dated March 14, 2005 in File No. 1-3880)
  3(ii)     By-Laws:
      National Fuel Gas Company By-Laws as amended June 11, 2008 (Exhibit 3.1, Form 8-K dated June 16, 2008 in File No. 1-3880)
  4     Instruments Defining the Rights of Security Holders, Including Indentures:
      Indenture, dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 2(b) in File No. 2-51796)


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Exhibit
  Description of
Number
 
Exhibits
 
      Third Supplemental Indenture, dated as of December 1, 1982, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(4) in File No. 33-49401)
      Eleventh Supplemental Indenture, dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b), Form 8-K dated February 14, 1992 in File No. 1-3880)
      Twelfth Supplemental Indenture, dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c), Form 8-K dated June 18, 1992 in File No. 1-3880)
      Thirteenth Supplemental Indenture, dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(14) in File No. 33-49401)
      Fourteenth Supplemental Indenture, dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880)
      Fifteenth Supplemental Indenture, dated as of September 1, 1996, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
      Indenture dated as of October 1, 1999, between the Company and The Bank of New York (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
      Officers Certificate Establishing Medium-Term Notes, dated October 14, 1999 (Exhibit 4.2, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
      Officers Certificate establishing 5.25% Notes due 2013, dated February 18, 2003 (Exhibit 4, Form 10-Q for the quarterly period ended March 31, 2003 in File No. 1-3880)
      Officer’s Certificate establishing 6.50% Notes due 2018, dated April 11, 2008 (Exhibit 4.1, Form 10-Q for the quarterly period ended June 30, 2008 in File No. 1-3880)
      Amended and Restated Rights Agreement, dated as of July 11, 2008, between the Company and The Bank of New York, as rights agent (Exhibit 4.1, Form 8-K dated July 15, 2008 in File No. 1-3880)
  10     Material Contracts:
      Credit Agreement, dated as of August 19, 2005, among the Company, the Lenders Party Thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
      Form of Indemnification Agreement, dated September 2006, between the Company and each Director (Exhibit 10.1, Form 8-K dated September 18, 2006 in File No. 1-3880)
      Settlement Agreement dated January 24, 2008 among the Company, New Mountain Vantage GP, L.L.C. (“Vantage”) and certain of Vantage’s affiliates (Exhibit 10.1, Form 8-K dated January 24, 2008 in File No. 1-3880)
      Director Services Agreement, dated as of June 1, 2008, between the Company and Philip C. Ackerman (Exhibit 99, Form 8-K dated June 16, 2008 in File No. 1-3880)
      Resolutions adopted by the National Fuel Gas Company Board of Directors on February 21, 2008 regarding director stock ownership guidelines (Exhibit 10.5, Form 10-Q for the quarterly period ended March 31, 2008 in File No. 1-3880)
  10 .1   Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, a subsidiary of the Company and each of Karen M. Camiolo, Carl M. Carlotti, Anna Marie Cellino, Paula M. Ciprich, Donna L. DeCarolis, John R. Pustulka, James D. Ramsdell, David F. Smith and Ronald J. Tanski
  10 .2   Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, Seneca Resources Corporation and Matthew D. Cabell
      Letter Agreement between the Company and Matthew D. Cabell, dated November 17, 2006 (Exhibit 10.1, Form 10-Q for the quarterly period ended December 31, 2006 in File No. 1-3880)

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Exhibit
  Description of
Number
 
Exhibits
 
      National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993 (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880)
      Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 (Exhibit 10.8, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880)
      Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 11, 1996 (Exhibit 10.8, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
      Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 18, 1996 (Exhibit 10, Form 10-Q for the quarterly period ended December 31, 1996 in File No. 1-3880)
      National Fuel Gas Company 1993 Award and Option Plan, amended through June 14, 2001 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 2001 in File No. 1-3880)
      National Fuel Gas Company 1993 Award and Option Plan, amended through September 8, 2005 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
      Administrative Rules with Respect to At Risk Awards under the 1993 Award and Option Plan (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
      National Fuel Gas Company 1997 Award and Option Plan, as amended and restated as of July 23, 2007 (Exhibit 10.4, Form 10-Q for the quarterly period ended March 31, 2008 in File No. 1-3880)
      Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1, Form 8-K dated March 28, 2005 in File No. 1-3880)
      Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1, Form 8-K dated May 16, 2006 in File No. 1-3880)
      Form of Restricted Stock Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2, Form 10-Q for the quarterly period ended December 31, 2006 in File No. 1-3880)
      Form of Stock Option Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.3, Form 10-Q for the quarterly period ended December 31, 2006 in File No. 1-3880)
      Form of Stock Appreciation Right Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2, Form 10-Q for the quarterly period ended March 31, 2008 in File No. 1-3880)
      Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan amended and restated as of September 8, 2005 (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
  10 .3   Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program
      Description of performance goals for certain executive officers under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10.8, Form 10-Q for the quarterly period ended December 31, 2006 in File No. 1-3880)
      Description of performance goals for certain executive officers under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10.1, Form 10-Q for the quarterly period ended December 31, 2007 in File No. 1-3880)
  10 .4   National Fuel Gas Company Executive Annual Cash Incentive Program
      Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated effective February 20, 2008 (Exhibit 10.3, Form 10-Q for the quarterly period ended March 31, 2008 in File No. 1-3880)
      National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880)
      Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880)
      Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)

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Exhibit
  Description of
Number
 
Exhibits
 
      National Fuel Gas Company Deferred Compensation Plan, as amended and restated through March 20, 1997 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
      Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 16, 1997 (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
      Amendment No. 2 to the National Fuel Gas Company Deferred Compensation Plan, dated March 13, 1998 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1998 in File No. 1-3880)
      Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated February 18, 1999 (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 1999 in File No. 1-3880)
      Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 15, 2001 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 2001 in File No. 1-3880)
      Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated October 21, 2005 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
      Form of Letter Regarding Deferred Compensation Plan and Internal Revenue Code Section 409A, dated July 12, 2005 (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
      National Fuel Gas Company Tophat Plan, effective March 20, 1997 (Exhibit 10, Form 10-Q for the quarterly period ended June 30, 1997 in File No. 1-3880)
      Amendment No. 1 to National Fuel Gas Company Tophat Plan, dated April 6, 1998 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1998 in File No. 1-3880)
      Amendment No. 2 to National Fuel Gas Company Tophat Plan, dated December 10, 1998 (Exhibit 10.1, Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880)
      Form of Letter Regarding Tophat Plan and Internal Revenue Code Section 409A, dated July 12, 2005 (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
      National Fuel Gas Company Tophat Plan, Amended and Restated December 7, 2005 (Exhibit 10.1, Form 10-Q for the quarterly period ended December 31, 2005 in File No. 1-3880)
      National Fuel Gas Company Tophat Plan, as amended September 20, 2007 (Exhibit 10.3, Form 10-K for the fiscal year ended September 30, 2007 in File No. 1-3880)
      Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 17, 1997 between the Company and Philip C. Ackerman (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
      Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Philip C. Ackerman, dated March 23, 1999 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
      Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and David F. Smith (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
      Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
      National Fuel Gas Company Parameters for Executive Life Insurance Plan (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 2004 in File No. 1-3880)
      National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880)
      Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated September 18, 1997 (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
      Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated December 10, 1998 (Exhibit 10.2, Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880)

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Exhibit
  Description of
Number
 
Exhibits
 
      Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16, 1999 (Exhibit 10.15, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
      Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 5, 2001 (Exhibit 10.4, Form 10-K/A for fiscal year ended September 30, 2001, in File No. 1-3880)
      National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of January 1, 2007 (Exhibit 10.5, Form 10-Q for the quarterly period ended December 31, 2006 in File No. 1-3880)
      National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 20, 2007 (Exhibit 10.4, Form 10-K for the fiscal year ended September 30, 2007 in File No. 1-3880)
  10 .5   National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 24, 2008
      National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
      National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement (I), dated September 1, 2003 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 2004 in File No. 1-3880)
      National Fuel Gas Company Performance Incentive Program (Exhibit 10.1, Form 8-K dated June 3, 2005 in File No. 1-3880)
      Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
      Amended and Restated Retirement Benefit Agreement for David F. Smith, dated September 20, 2007, among the Company, National Fuel Gas Supply Corporation and David F. Smith (Exhibit 10.5, Form 10-K for the fiscal year ended September 30, 2007 in File No. 1-3880)
      Description of assignment of interests in certain life insurance policies (Exhibit 10.1, Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880)
      Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.7, Form 10-Q for the quarterly period ended December 31, 2006 in File No. 1-3880)
      Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 2008 in File No. 1-3880)
      Description of agreement between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.3, Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880)
      Agreement, dated September 24, 2006, between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.1, Form 10-K for the fiscal year ended September 30, 2006 in File No. 1-3880)
  12     Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 2004 through 2008
  21     Subsidiaries of the Registrant
  23     Consents of Experts:
  23 .1   Consent of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation
  23 .2   Consent of Independent Registered Public Accounting Firm
  31     Rule 13a-14(a)/15d-14(a) Certifications:
  31 .1   Written statements of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act

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Table of Contents

         
Exhibit
  Description of
Number
 
Exhibits
 
  31 .2   Written statements of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act
  32     Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
  99     Additional Exhibits:
  99 .1   Report of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation
  99 .2   Company Maps
      Incorporated herein by reference as indicated.
        All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report on Form 10-K
  ••     In accordance with Item 601(b)(32)(ii) of Regulation S-K and SEC Release Nos. 33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference

123


Table of Contents

 
Signatures
 
Pursuant to the requirements of Section 13 or 15(d) 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)
 
  By 
/s/  D. F. Smith
D. F. Smith
President and Chief Executive Officer
 
Date: November 26, 2008
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
             
Signature
 
Title
   
 
         
/s/  P. C. Ackerman

P. C. Ackerman
  Chairman of the Board and Director   Date: November 26, 2008
         
/s/  R. T. Brady

R. T. Brady
  Director   Date: November 26, 2008
         
/s/  R. D. Cash

R. D. Cash
  Director   Date: November 26, 2008
         
/s/  S. E. Ewing

S. E. Ewing
  Director   Date: November 26, 2008
         
/s/  R. E. Kidder

R. E. Kidder
  Director   Date: November 26, 2008
         
/s/  C. G. Matthews

C. G. Matthews
  Director   Date: November 26, 2008
         
/s/  G. L. Mazanec

G. L. Mazanec
  Director   Date: November 26, 2008
         
/s/  R. G. Reiten

R. G. Reiten
  Director   Date: November 26, 2008
         
/s/  F. V. Salerno

F. V. Salerno
  Director   Date: November 26, 2008
         
/s/  D. F. Smith

D. F. Smith
  President, Chief Executive
Officer and Director
  Date: November 26, 2008


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Table of Contents

             
Signature
 
Title
   
 
         
/s/  R. J. Tanski

R. J. Tanski
  Treasurer and Principal
Financial Officer
  Date: November 26, 2008
         
/s/  K. M. Camiolo

K. M. Camiolo
  Controller and Principal
Accounting Officer
  Date: November 26, 2008


125

Exhibit 10.1
FORM ECNA
AMENDED AND RESTATED
EMPLOYMENT CONTINUATION AND
NONCOMPETITION AGREEMENT
          THIS AGREEMENT between [subsidiary corporation], a [state] corporation (the “Company”), NATIONAL FUEL GAS COMPANY, a New Jersey corporation (“National”), and                      (the “Executive”), dated as of the       day of                      ,       , and amended and restated as of the       day of                      ,       .
W I T N E S S E T H :
          WHEREAS, the Company and National wish to attract and retain well-qualified executive and key personnel and to assure continuity of management, which will be essential to its ability to evaluate and respond to any actual or threatened Change in Control (as defined below) in the best interests of shareholders;
          WHEREAS, the Executive is a valuable employee of the Company, an integral part of its management team and a key participant in the decision making process relative to short-term and long-term planning and policy for the Company;
          WHEREAS, the Company and National understand that any actual or threatened Change in Control will present significant concerns for the Executive with respect to his financial and job security;
          WHEREAS, the Company and National wish to encourage the Executive to continue his career and services with the Company for the period during and after an actual or threatened Change in Control and to assure to the Company the Executive’s services during the period in which such a Change in Control is threatened, and to provide the Executive certain financial assurances to enable the Executive to perform the responsibilities of his position without undue distraction and to exercise his judgment without bias due to his personal circumstances; and
          WHEREAS, the Board of Directors of National has determined that it would be in the best interests of National and its shareholders to assure continuity in the management of National in the event of a Change in Control by entering into an employment continuation and noncompete agreement with Executive;
          WHEREAS, to achieve these objectives, the Company, National and the Executive desire to enter into an agreement providing the Company and the Executive with certain rights and obligations upon the occurrence of a Change in Control or Potential Change in Control (as defined in Section 2).

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          NOW, THEREFORE, in consideration of the premises and mutual covenants herein contained, it is hereby agreed by and between the Company, National and the Executive as follows:
          1. Operation of Agreement. (a) Effective Date. The effective date of this Agreement shall be the date on which a Change in Control occurs (the “Effective Date”), provided that, except as provided in Section 1(b), if the Executive is not employed by the Company, National or any of their subsidiaries on the Effective Date, this Agreement shall be void and without effect.
          (b) Termination of Employment Following a Potential Change in Control. Notwithstanding Section 1(a), if (i) the Executive’s employment is terminated by the Company Without Cause (as defined in Section 6(c)) after the occurrence of a Potential Change in Control and prior to the occurrence of a Change in Control and (ii) a Change in Control, which also constitutes a “change in control event” for purposes of Section 409A of the Code, occurs within two years of such termination, the Executive shall be deemed, solely for purposes of determining his rights under this Agreement, to have remained employed until the date such Change in Control occurs and to have been terminated by the Company without Cause immediately after the Change in Control. For this purpose, a Change in Control shall also be a change of control event for purposes of Section 409A of the Code if it is a change in the ownership or effective control of the Company, or a change in the ownership of a substantial portion of the assets of the Company, as such terms are defined in Treas. Reg. § 1.409A-3(i)(5) (or any successor provision).
          2. Definitions. (a) Change in Control. For the purposes of this Agreement, a “Change in Control” shall be deemed to have occurred if any of the following have occurred:
          (i) either (a) the Company or National shall receive a report on Schedule 13D, or an amendment to such a report, filed with the Securities and Exchange Commission pursuant to Section 13(d) of the Securities Exchange Act of 1934 (the “1934 Act”) disclosing that any person (as such term is used in Section 13(d) of the 1934 Act) (“Person”), is the beneficial owner, directly or indirectly, of twenty (20) percent or more of the outstanding stock of National or (b) the Company or National has actual knowledge of facts which would require any Person to file such a report on Schedule 13D, or to make an amendment to such a report, with the SEC (or would be required to file such a report or amendment upon the lapse of the applicable period of time specified in Section 13(d) of the 1934 Act) disclosing that such Person is the beneficial owner, directly or indirectly, of twenty (20) percent or more of the outstanding stock of National;
          (ii) purchase by any Person, other than National or a wholly-owned subsidiary of National or an employee benefit plan sponsored or maintained by National or a wholly-owned subsidiary of National, of shares pursuant to a tender or exchange offer to acquire any stock of

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National (or securities convertible into stock) for cash, securities or any other consideration provided that, after consummation of the offer, such Person is the beneficial owner (as defined in Rule 13d-3 under the 1934 Act), directly or indirectly, of twenty (20) percent or more of the outstanding stock of National (calculated as provided in paragraph (d) of Rule 13d-3 under the 1934 Act in the case of rights to acquire stock);
          (iii) approval by the shareholders of National of (a) any consolidation or merger of National in which National is not the continuing or surviving corporation or pursuant to which shares of stock of National would be converted into cash, securities or other property, other than a consolidation or merger of National in which holders of its stock immediately prior to the consolidation or merger have substantially the same proportionate ownership of common stock of the surviving corporation immediately after the consolidation or merger as immediately before, or (b) any consolidation or merger in which National is the continuing or surviving corporation but in which the common shareholders of National immediately prior to the consolidation or merger do not hold at least a majority of the outstanding common stock of the continuing or surviving corporation (except where such holders of common stock hold at least a majority of the common stock of the corporation which owns all of the common stock of National), or (c) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all the assets of National; or
          (iv) a change in the majority of the members of the Board of Directors of National (the “Board”) within a 24-month period unless the election or nomination for election by National’s shareholders of each new director was approved by the vote of at least two-thirds of the directors then still in office who were in office at the beginning of the 24-month period.
          (b) Potential Change in Control. For the purposes of this Agreement, a Potential Change in Control shall be deemed to have occurred if:
          (i) a Person commences a tender offer (with adequate financing) for securities representing at least twenty (20) percent of the outstanding stock of National (calculated as provided in paragraph (d) of Rule 13d-3 under the 1934 Act in the case of rights to acquire stock);
          (ii) National enters into an agreement the consummation of which would constitute a Change in Control;
          (iii) proxies for the election of directors of National are solicited by anyone other than National; or
          (iv) any other event occurs which is deemed to be a Potential Change in Control by the Board.

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          3. Employment Period. Subject to Section 6 of this Agreement, the Company agrees to continue the Executive in its employ, and the Executive agrees to remain in the employ of the Company, for the period (the “Employment Period”) commencing on the Effective Date and ending on the earlier to occur of (i) the third anniversary of the Effective Date and (ii) the date on which the Executive attains age 65.
          4. Position and Duties. During the Employment Period, the Executive’s position (including titles), authority and responsibilities shall be at least commensurate with those held, exercised and assigned immediately prior to the Effective Date. It is understood that, for purposes of this Agreement, such position, authority and responsibilities shall not be regarded as not commensurate merely by virtue of the fact that a successor shall have acquired all or substantially all of the business and/or assets of the Company as contemplated by Section 12(b) of this Agreement. The Executive’s services shall be performed in the United States and within 30 miles of the location where the Executive was employed immediately preceding the Effective Date.
          5. Compensation. (a) Base Salary. During the Employment Period, the Executive shall receive a base salary at a monthly rate at least equal to the monthly salary paid to the Executive by the Company and any of its affiliated companies immediately prior to the Effective Date. The base salary shall be reviewed at least once each year after the Effective Date, and shall be increased annually at a rate at least equal to the greater of (i) the average percentage increase for the same period in the compensation of salaried employees of National and its subsidiaries who are not executives and (ii) the percentage increase in the national Consumer Price Index for the last completed calendar year. The Executive’s base salary, as it shall be increased from time to time, shall hereafter be referred to as “Base Salary”. Neither the Base Salary nor any increase in Base Salary after the Effective Date shall serve to limit or reduce any other obligation of the Company hereunder.
          (b) Annual Bonus. During the Employment Period, in addition to the Base Salary, for each fiscal year of the Company ending during the Employment Period, the Executive shall be afforded the opportunity to receive an annual bonus on terms and conditions no less favorable to the Executive (taking into account reasonable changes in the Company’s goals and objectives) than the annual bonus opportunity that had been made available to the Executive for the fiscal year ended immediately prior to the Effective Date (the “Annual Bonus Opportunity”). Any amount payable in respect of the Annual Bonus Opportunity shall be paid as soon as practicable following the year for which the amount (or prorated portion) is earned or awarded, unless electively deferred by the Executive pursuant to any deferral programs or arrangements that the Company may make available to the Executive.
          (c) Long-term Incentive Compensation Programs. During the Employment Period, the Executive shall participate in all long-term incentive compensation programs for key executives at a level that is

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commensurate with the Executive’s participation in such plans immediately prior to the Effective Date, or, if more favorable to the Executive, at the level made available to the Executive or other similarly situated officers at any time thereafter.
          (d) Benefit Plans. During the Employment Period, the Executive (and, to the extent applicable, his dependents) shall be entitled to participate in or be covered under all pension, retirement, deferred compensation, savings, medical, dental, health, disability, group life, accidental death and travel accident insurance plans and programs of the Company and its affiliated companies at a level that is commensurate with the Executive’s participation in such plans immediately prior to the Effective Date, or, if more favorable to the Executive, at the level made available to the Executive or other similarly situated officers at any time thereafter.
          (e) Expenses. During the Employment Period, the Executive shall be entitled to receive prompt reimbursement for all reasonable expenses incurred by the Executive in accordance with the policies and procedures of the Company as in effect immediately prior to the Effective Date. Notwithstanding the foregoing, the Company may apply the policies and procedures in effect after the Effective Date to the Executive, if such policies and procedures are not less favorable to the Executive than those in effect immediately prior to the Effective Date.
          (f) Vacation and Fringe Benefits. During the Employment Period, the Executive shall be entitled to paid vacation and fringe benefits at a level that is commensurate with the paid vacation and fringe benefits available to the Executive immediately prior to the Effective Date, or, if more favorable to the Executive, at the level made available from time to time to the Executive or other similarly situated officers at any time thereafter.
          (g) Indemnification. During and after the Employment Period, National and the Company shall indemnify the Executive and hold the Executive harmless from and against any claim, loss or cause of action arising from or out of the Executive’s performance as an officer, director or employee of National or the Company or any of their subsidiaries or in any other capacity, including any fiduciary capacity, in which the Executive serves at the request of National or the Company to the maximum extent permitted by applicable law and the Company’s Certificate of Incorporation and By-Laws (the “Governing Documents”), provided that in no event shall the protection afforded to the Executive hereunder be less than that afforded under the Governing Documents as in effect immediately prior to the Effective Date.
          6. Termination. (a) Death, Disability or Retirement. Subject to the provisions of Section 1 hereof, this Agreement shall terminate automatically upon the Executive’s death, termination due to “Disability” (as defined below) or voluntary retirement under any of the Company’s retirement plans as in effect from time to time. For purposes of this Agreement, Disability shall mean the Executive’s

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inability to perform the duties of his position, as determined in accordance with the policies and procedures applicable with respect to the Company’s long-term disability plan, as in effect immediately prior to the Effective Date.
          (b) Voluntary Termination. Notwithstanding anything in this Agreement to the contrary, following a Change in Control the Executive may, upon not less than 30 days’ written notice to the Company, voluntarily terminate employment for any reason (including early retirement under the terms of any of the Company’s retirement plans as in effect from time to time), provided that any termination by the Executive pursuant to Section 6(d) on account of Good Reason (as defined therein) shall not be treated as a voluntary termination under this Section 6(b).
          (c) Cause. The Company may terminate the Executive’s employment for Cause. For purposes of this Agreement, “Cause” means the Executive’s gross misconduct, fraud or dishonesty, which has resulted or is likely to result in material economic damage to the Company or National, as determined in good faith by a vote of at least two-thirds of the non-employee directors of National at a meeting of the Board at which the Executive is provided an opportunity to be heard (with representation by counsel of his choosing, should he so desire).
          (d) Good Reason. Following the occurrence of a Change in Control, the Executive may terminate his employment for Good Reason. For purposes of this Agreement, “Good Reason” means the occurrence of any of the following, without the express written consent of the Executive, after the occurrence of a Change in Control:
(i) a material diminution in (A) the Executive’s authority, duties, or responsibilities, (B) the Executive’s base compensation or (C) the budget over which the Executive retains authority;
(ii) a material diminution in the authority, duties, or responsibilities of the supervisor to whom the Executive is required to report, including a requirement that the Executive report to a corporate officer or employee instead of reporting directly to the board of directors of a corporation; or
(iii) the Company’s requiring the Executive to be based at any office or location outside of the United States and/or more than 30 miles from that location at which he performed his services specified under the provisions of Section 4 immediately prior to the Change in Control, except for travel reasonably required in the performance of the Executive’s responsibilities; or
(iv) any other action or inaction that constitutes a material breach by the Company of this Agreement;
provided, however, that to constitute Good Reason the Company shall have a period of 30 days to cure any acts which would

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otherwise give Executive the right to terminate his employment for Good Reason. Such 30-day period shall commence as of the date of receipt by the Company of the Notice of Termination.
In no event shall the mere occurrence of a Change in Control, absent any further impact on the Executive, be deemed to constitute Good Reason. In the event that the Executive shall in good faith give a Notice of Termination for Good Reason and it shall thereafter be determined that Good Reason did not exist, the Executive shall, unless the Company and the Executive shall otherwise mutually agree, return to employment with the Company within 5 business days of such decision, without any impairment or other limitation of his rights hereunder, except that he shall not be paid his base salary for any period he did not perform services and his annual bonus opportunity for such year may be reduced to reflect his period of absence.
          (e) Notice of Termination. Any termination by the Company for Cause or by the Executive for Good Reason shall be communicated by Notice of Termination given in accordance with Section 13(e). For purposes of this Agreement, a “Notice of Termination” means a written notice given, in the case of a termination for Cause, within 30 business days of the Company’s having actual knowledge of the events giving rise to such termination, and in the case of a termination for Good Reason, within 90 days of the Executive’s having actual knowledge of the events giving rise to such termination, and which (i) indicates the specific termination provision in this Agreement relied upon, (ii) sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Executive’s employment under the provision so indicated, and (iii) specifies the date the Executive’s employment shall terminate (which date shall be not less than 30 nor more than 60 days after the giving of such notice). The failure by the Executive to set forth in the Notice of Termination any fact or circumstance which contributes to a showing of Good Reason shall not waive any right of the Executive hereunder or preclude the Executive from asserting such fact or circumstance in enforcing his rights hereunder.
          (f) Date of Termination. For the purpose of this Agreement, the term “Date of Termination” means (i) in the case of a termination for which a Notice of Termination is required, the date of receipt of such Notice of Termination or, if later, the date specified therein, as the case may be, and (ii) in all other cases, the actual date on which the Executive’s employment terminates during the Employment Period. For the avoidance of doubt, if the Executive ceases to be an employee but continues to provide services to the Company or any of its affiliates following his Date of Termination, or is reasonably expected (at such Date of Termination) to provide such services within 12 months of such Date of Termination, the term Date of Termination (or termination of employment or any other similar terms used in this Agreement) shall be deemed to refer to the date at which the Executive incurs a “separation from service” from the Company within the meaning of Section 409A of the Code and the regulations promulgated thereunder. This means that rather than being entitled to receive any payments or benefits

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hereunder upon, or at a specified time following, the Date of Termination (or termination of employment or any other similar terms used in the Agreement), such a continuing Executive shall be entitled to receive such payments or benefits upon, or at a specified time following, such a separation from service.
          7. Obligations of the Company upon Termination. (a) Death or Disability. If the Executive’s employment is terminated during the Employment Period by reason of the Executive’s death or Disability, this Agreement shall terminate without further obligations to the Executive or the Executive’s legal representatives under this Agreement other than those obligations accrued hereunder at the Date of Termination, and the Company shall pay to the Executive (or his beneficiary or estate) (i) the Executive’s full Base Salary through the Date of Termination (the “Earned Salary”), (ii) any vested amounts or benefits owing to the Executive under the Company’s otherwise applicable employee benefit plans and programs, including any compensation previously deferred by the Executive (together with any accrued earnings thereon) and not yet paid by the Company and any amounts payable pursuant any individual agreement with Executive (the “Accrued Obligations”), and (iii) any other benefits payable due to the Executive’s death or Disability under the Company’s plans, policies or programs (the “Additional Benefits”).
          Any Earned Salary shall be paid in cash in a single lump sum as soon as practicable, but in no event more than 15 days (or at such earlier date required by law), following the Date of Termination. Accrued Obligations and Additional Benefits shall be paid in accordance with the terms of the applicable plan, program or arrangement.
          (b) Cause and Voluntary Termination. If, during the Employment Period, the Executive’s employment shall be terminated for Cause or voluntarily terminated by the Executive (other than on account of Good Reason following a Change in Control), the Company shall pay the Executive (i) the Earned Salary in cash in a single lump sum as soon as practicable, but in no event more than 10 days, following the Date of Termination, and (ii) the Accrued Obligations in accordance with the terms of the applicable plan, program or arrangement.
          (c) Termination by the Company other than for Cause and Termination by the Executive for Good Reason. Subject to Section 7(f) below, if, during the Employment Period, the Company terminates the Executive’s employment other than for Cause, or the Executive terminates his employment for Good Reason, the Company shall pay to the Executive the following amounts:
     (i) Severance Benefits. The Executive shall be paid the following:
(A) the Executive’s Earned Salary;
(B) a cash amount (the “Severance Amount”) equal to

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(1) 1.99; times
(2) the sum of
(i) the Executive’s annual Base Salary; and
(ii) the average of the annual at risk compensation incentive program bonuses or other bonuses (excluding sign-on bonuses) payable to the Executive (including, for the purposes of this calculation, any amount of such bonuses paid in the form of restricted stock (in lieu of cash), to be valued at the date of grant) for the two fiscal years of the Company ending immediately prior to the Effective Date (the “Average Bonus”); and
          (C) the Accrued Obligations.
The Earned Salary and Severance Amount shall be paid in cash in a single lump sum as soon as practicable, but in no event more than 10 days (or at such earlier date required by law), following the Date of Termination; provided however that if the date payment would otherwise be due hereunder is after September 30, payment of the Severance Amount shall be paid on the first business day in the following January. Accrued Obligations shall be paid in accordance with the terms of the applicable plan, program or arrangement.
          (ii) Continuation of Welfare Benefits. If, during the Employment Period, the Company terminates the Executive’s employment other than for Cause, or following a Change in Control the Executive terminates his employment for Good Reason, the Executive (and, to the extent applicable, his dependents) shall be entitled, after the Date of Termination until the earlier of (1) the eighteen month anniversary of the Date of Termination (the “End Date”) and (2) the date the Executive becomes eligible for comparable benefits under a similar plan, policy or program of a subsequent employer, to continue participation in all of the Company’s employee and executive welfare and fringe benefit plans, excluding further vacation pay (the “Benefit Plans”). To the extent any such benefits cannot be provided under the terms of the applicable plan, policy or program, the Company shall provide a comparable benefit under another plan or from the Company’s general assets. The Executive’s participation in the Benefit Plans will be on the same terms and conditions that would have applied had the Executive continued to be employed by the Company through the End Date.
          (iii) Qualification for Early Retirement. If the Executive is at least age 52 at his Date of Termination, the Executive shall be deemed to have earned, and to have become vested in, the retirement benefits (including, without limitation, any early retirement subsidy or supplement, retiree life coverage or retiree medical benefits) that would have been payable or made available to the Executive under any employee benefit plan sponsored or maintained by the Company or any of its subsidiaries for which the Executive was eligible at the Date of Termination had he continued in service for three additional years

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after the Date of Termination. The purpose and intent of this provision is to provide the Executive with vesting and to bridge any gap of three or fewer years of service to qualify for any additional benefits available for an early retiree (such as the benefits under the Executive Retirement Plan (“ERP”) or the benefits available under the Retirement Plan (“RP”) including the so-called Rule of 90), and not to increase the service taken into account for purpose of determining the amount of benefits payable to the Executive beyond his actual period of service through the Date of Termination.
          The operation of this provision is illustrated by the following examples:
          Example 1: Assume that, at the Executive’s Date of Termination, the Executive is exactly 53 years old, and has exactly 4 years of service for purposes of the ERP. Assume further that the relevant RP and ERP provisions have not changed since the date of the execution of this Agreement. The Executive would receive a benefit (in the form of a single life annuity) under the RP and ERP in the aggregate in the form of a benefit beginning at age 56, equal to 4/5 times what he would otherwise have received under a combination of those plans beginning at age 56. (Or, he could elect commencement of benefits at age 55 in reduced amounts per the terms of the relevant plans.) Five is used in the denominator because the current ERP vesting policy is attainment of age 55 and at least 5 years of service.
          Example 2: The assumptions are the same as in example 1, except that the Executive has exactly 32 years of service (instead of 4). By reason of the additional credit provided under this Agreement, the Executive would receive a benefit calculated as though payable under the RP (in the form of a single life annuity), under the RP’s “Rule of 90,” that would begin at age 55-1/2 and would equal [(53 + 32)/90] times what he would otherwise have received under the RP under the Rule of 90 beginning at age 55-1/2 (the earliest date at which he otherwise could have retired and commenced receiving benefits determined under the Rule of 90).
          In both examples, (i) any portion of the incremental benefit that could not be paid under the RP will be paid from the ERP or the Company’s general assets, (ii) final average salaries would be determined under those plans as of the Executive’s Date of Termination and (iii) the Executive would be entitled to elect forms of benefit other than the single life annuity.
          Other fact patterns, and examples respecting other post-retirement benefits, would use similar principles, but might use different math. For example, the current provisions concerning an executive’s vesting in early retirement benefits under the RP, and concerning retiree medical benefit vesting, have years of service requirements in excess of five years.
          (d) Discharge of the Company’s Obligations. Except as expressly provided in the last sentence of this Section 7(d), the

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amounts payable to the Executive pursuant to this Section 7 (whether or not reduced pursuant to Section 7(e)) following termination of his employment shall be in full and complete satisfaction of the Executive’s rights under this Agreement and any other claims he may have in respect of his employment by the Company or any of its subsidiaries. Such amounts shall constitute liquidated damages with respect to any and all such rights and claims and, upon the Executive’s receipt of such amounts, the Company shall be released and discharged from any and all liability to the Executive in connection with this Agreement or otherwise in connection with the Executive’s employment with the Company and its subsidiaries. Nothing in this Section 7(d) shall be construed to release the Company from its commitment to indemnify the Executive and hold the Executive harmless from and against any claim, loss or cause of action arising from or out
of the Executive’s performance as an officer, director or employee of the Company or any of its subsidiaries or in any other capacity, including any fiduciary capacity, in which the Executive served at the request of the Company to the maximum extent permitted by applicable law and the Governing Documents.
          (e) Limit on Payments by the Company.
     (i) Application of Section 7(e). In the event that any amount or benefit paid or distributed to the Executive pursuant to this Agreement, taken together with any amounts or benefits otherwise paid or distributed to the Executive by the Company or any affiliated company (collectively, the “Covered Payments”), would be an “excess parachute payment” as defined in Section 280G of the Code and would thereby subject the Executive to the tax (the “Excise Tax”) imposed under Section 4999 of the Code (or any similar tax that may hereafter be imposed), the provisions of this Section 7(e) shall apply to determine the amounts payable to the Executive pursuant to this Agreement.
     (ii) Calculation of Benefits. Immediately following delivery of any Notice of Termination, the Company shall notify the Executive of the aggregate present value of all termination benefits to which he would be entitled under this Agreement and any other plan, program or arrangement as of the projected Date of Termination, together with the projected maximum payments, determined as of such projected Date of Termination that could be paid without the Executive being subject to the Excise Tax.
     (iii) Imposition of Payment Cap. If
     (x) the aggregate value of all compensation payments or benefits to be paid or provided to the Executive under this Agreement and any other plan, agreement or arrangement with the Company exceeds the amount which can be paid to the Executive without the Executive incurring an Excise Tax, and

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     (y) the net-after tax amount (taking into account all applicable taxes payable by the Executive, including any Excise Tax) that the Executive would receive if the limitation contained in this Section 7(e)(iii) were not imposed does not exceed the net-after tax benefit the Executive would receive if such limitation were imposed by more than $25,000, then the amounts payable to the Executive under this Section 7 shall be reduced (but not below zero) to the maximum amount which may be paid hereunder without the Executive becoming subject to such an Excise Tax (such reduced payments to be referred to as the “Payment Cap”). In the event that the Executive receives reduced payments and benefits hereunder, such payments and benefits shall be reduced in connection with the application of the Payment Cap in the following manner: first the Executive’s Severance Amount shall be reduced, followed by, to the extent necessary and in order, the continuation of welfare benefits, any early retirement benefits the Executive becomes vested in under the Agreement, the Average Bonus and finally the Accrued Obligations.
     (iv) Application of Section 280G. For purposes of determining whether any of the Covered Payments will be subject to the Excise Tax and the amount of such Excise Tax,
     (A) such Covered Payments will be treated as “parachute payments” within the meaning of Section 280G of the Code, and all “parachute payments” in excess of the “base amount” (as defined under Section 280G(b)(3) of the Code) shall be treated as subject to the Excise Tax, unless, and except to the extent that, in the good faith judgment of the Company’s independent certified public accountants appointed prior to the Effective Date or tax counsel selected by such Accountants (the “Accountants”), the Company as a reasonable basis to conclude that such Covered Payments (in whole or in part) either do not constitute “parachute payments” or represent reasonable compensation for personal services actually rendered (within the meaning of Section 280G(b)(4)(B) of the Code) in excess of the portion of the “base amount” allocable to such Covered Payments, or such “parachute payments” are otherwise not subject to such Excise Tax, and
     (B) the value of any noncash benefits or any deferred payment or benefit shall be determined by the Accountants in accordance with the principles of Section 280G of the Code.
     (v) Applicable Tax Rates. For purposes of determining whether the Executive would receive a greater net after-tax benefit were the amounts payable under this Agreement reduced in accordance with Paragraph 7(e)(iii), the Executive shall be deemed to pay:

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(A) Federal income taxes at the highest applicable marginal rate of Federal income taxation for the calendar year in which the first amounts are to be paid hereunder, and
(B) any applicable state and local income taxes at the highest applicable marginal rate of taxation for such calendar year, net of the maximum reduction in Federal incomes taxes which could be obtained from the deduction of such state or local taxes if paid in such year;
provided, however, that the Executive may request that such determination be made based on his individual tax circumstances, which shall govern such determination so long as the Executive provides to the Accountants such information and documents as the Accountants shall reasonably request to determine such individual circumstances.
          (vi) Adjustments in Respect of the Payment Cap. If the Executive receives reduced payments and benefits under this Section 7(e) (or this Section 7(e) is determined not to be applicable to the Executive because the Accountants conclude that the Executive is not subject to any Excise Tax) and it is established pursuant to a final determination of a court or an Internal Revenue Service proceeding (a “Final Determination”) that, notwithstanding the good faith of the Executive and the Company in applying the terms of this Agreement, the aggregate “parachute payments” within the meaning of Section 280G of the Code paid to the Executive or for his benefit are in an amount that would result in the Executive being subject an Excise Tax, then the amount equal to such excess parachute payments shall be deemed for all purposes to be a loan to the Executive made on the date of receipt of such excess payments, which the Executive shall have an obligation to repay to the Company on demand, together with interest on such amount at the applicable Federal rate (as defined in Section 1274(d) of the Code) from the date of the payment hereunder to the date of repayment by the Executive. If this Section 7(e) is not applied to reduce the Executive’s entitlement under this Section 7 because the Accountants determine that the Executive would not receive a greater net-after tax benefit by applying this Section 7(e) and it is established pursuant to a Final Determination that, notwithstanding the good faith of the Executive and the Company in applying the terms of this Agreement, the Executive would have received a greater net after tax benefit by subjecting his payments and benefits hereunder to the Payment Cap, then the aggregate “parachute payments” paid to the Executive or for his benefit in excess of the Payment Cap shall be deemed for all purposes a loan to the Executive made on the date of receipt of such excess payments, which the Executive shall have an obligation to repay to the Company on demand, together with interest on such amount at the applicable Federal rate (as defined in Section 1274(d) of the Code) from the date of the payment hereunder to the date of repayment by the Executive. If the Executive receives reduced payments and benefits by reason of this Section 7(e) and it is established pursuant to a Final Determination that the Executive could have received a greater amount without exceeding the Payment Cap, then the Company shall promptly

13


 

thereafter pay the Executive the aggregate additional amount which could have been paid without exceeding the Payment Cap, together with interest on such amount at the applicable Federal rate (as defined in Section 1274(d) of the Code) from the original payment due date to the date of actual payment by the Company.
          (f) If Termination of Employment Occurs After the Executive Has Reached Age 62. Notwithstanding anything else to the contrary contained in this Section 7, if the Executive’s employment with the Company terminates at any time during the 3 year period ending on the first day of the month following the Executive’s sixty-fifth birthday (the “Normal Retirement Date”), and the Executive would be entitled to receive severance benefits under paragraphs 7(c), then (i) the multiplier in paragraph 7(c)(i)(B) shall not be 1.99, but shall be a number equal to 1.99 times (x/1095), where x equals the number of days remaining until the Executive’s Normal Retirement Date, and (ii) the End Date described in Section 7(c)(ii) shall not be the third anniversary of the Date of Termination, but shall be the Executive’s Normal Retirement Date.
          8. Non-exclusivity of Rights. Except as expressly provided herein, nothing in this Agreement shall prevent or limit the Executive’s continuing or future participation in any benefit, bonus, incentive or other plan or program provided by the Company or any of its affiliated companies and for which the Executive may qualify, nor shall anything herein limit or otherwise prejudice such rights as the Executive may have under any other agreements with the Company or any of its affiliated companies, including employment agreements or stock option agreements. Amounts which are vested benefits or which the Executive is otherwise entitled to receive under any plan or program of the Company or any of its affiliated companies at or subsequent to the Date of Termination shall be payable in accordance with such plan or program.
          9. No Offset. The Company’s obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any circumstances, including, without limitation, any set-off, counterclaim, recoupment, defense or other right which the Company may have against the Executive or others whether by reason of the subsequent employment of the Executive or otherwise.
          10. Non-Competition and Non-Solicitation. (a) Noncompete. Unless the Executive otherwise elects by written notice to the Company prior to his Date of Termination (or in the case of a Company initiated termination, within 5 business days of receipt of a Notice of Termination, if such period extends beyond the Date of Termination) not to be bound by the provisions of this Section 10(a), during the one year period following the Executive’s Date of Termination for any reason (the “Restriction Period”), Executive shall not, directly or indirectly, engage in, become employed by, serve as an agent or consultant to, or become a partner, principal or stockholder (other than a holder of less than 1% of the outstanding voting shares of any

14


 

publicly held company) of any business or entity that is engaged in any activity which is competitive with the business of the Company, National and their respective subsidiaries or affiliates in any geographic area in which the Company, National and/or any of their respective subsidiaries or affiliates is engaged in such competitive business.
          (b) Non-Solicitation of Employees. Regardless of whether the Executive has elected to be bound by Section 10(a), during the Restriction Period, the Executive shall not, directly or indirectly, for his own account or for the account of any other person or entity with which he is or shall become associated in any capacity, solicit for employment, employ or otherwise interfere with the relationship of Employer with any person who at any time during the six months preceding such solicitation, employment or interference is or was employed by or otherwise engaged to perform services for Employer other than any such solicitation or employment during the Executive’s employment with Employer on behalf of Employer.
          (c) Confidential Information. Regardless of whether the Executive has elected to be bound by Section 10(a), the Executive shall hold in a fiduciary capacity for the benefit of National and the Company all secret or confidential information, knowledge or data relating to National, the Company or any of their affiliated companies, and their respective businesses, (i) obtained by the Executive during his employment by the Company or any of its affiliated companies and (ii) not otherwise public knowledge (other than by reason of an unauthorized act by the Executive). After termination of the Executive’s employment with the Company, the Executive shall not, without the prior written consent of the Company, unless compelled pursuant to an order of a court or other body having jurisdiction over such matter, communicate or divulge any such information, knowledge or data to anyone other than the Company and those designated by it.
          (d) Non-disparagement. Regardless of whether the Executive has elected to be bound by Section 10(a), the Executive shall not publicly or privately disparage National or the Company, or any of their subsidiaries or affiliates, including any aspect of their respective business, products, employees, management or Board of Directors, in any manner which could adversely effect the business of National, the Company or such subsidiaries or affiliates. Furthermore, the Executive shall not, directly or indirectly, take any action or fail to take any action with the purpose of interfering with, damaging or disrupting the assets or business operations or affairs of National or the Company or any of their respective subsidiaries or affiliates.
          National and the Company shall not publicly or privately disparage the Executive, either personally or professionally. Nothing in this paragraph shall be construed to prevent any officer of National or the Company from discussing the Executive’s performance internally in the ordinary course of business.

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          (e) Company Property. Except as expressly provided herein, promptly following the Executive’s termination of employment, the Executive shall return to the Company all property of National and the Company and all copies thereof in the Executive’s possession or under his control.
          (f) Additional Payment. Unless the Executive has elected not to be bound by Section 10(a), the Company shall make an additional lump sum payment to the Executive within 30 days following the Executive’s Date of Termination equal to one times the sum of (i) the Executive’s annual Base Salary and (ii) the Executive’s Average Bonus as compensation for the covenant contained in Section 10(a).
          11. Injunctive Relief and Other Remedies with Respect to Covenants. The Executive acknowledges and agrees that the covenants and obligations of the Executive set forth in Section 10 relate to special, unique and extraordinary matters and that a violation of any of the terms of such covenants and obligations will cause the Company irreparable injury for which adequate remedies are not available at law. Therefore, the Executive agrees that the Company shall be entitled to an injunction, restraining order or such other equitable relief (without the requirement to post bond) restraining the Executive from committing any violation of the covenants and obligations contained in Section 10 These remedies are cumulative and are in addition to any other rights and remedies the Company may have at law or in equity. In no event shall an asserted violation of the provisions of Section 10 constitute a basis for deferring or withholding any amounts otherwise payable to the Executive under this Agreement.
          12. Successors. (a) This Agreement is personal to the Executive and, without the prior written consent of the Company, shall not be assignable by the Executive otherwise than by will or the laws of descent and distribution. This Agreement shall inure to the benefit of and be enforceable by the Executive’s legal representatives.
          (b) This Agreement shall inure to the benefit of and be binding upon the Company and its successors. The Company shall require any successor to all or substantially all of the business and/or assets of the Company, whether direct or indirect, by purchase, merger, consolidation, acquisition of stock, or otherwise, by an agreement in form and substance satisfactory to the Executive, expressly to assume and agree to perform this Agreement in the same manner and to the same extent as the Company would be required to perform if no such succession had taken place.
          (c) In the event the Executive ceases to be employed by the Company as a result of the transfer of the Executive’s employment to National or to another wholly owned subsidiary of National, for purposes of this Agreement, National or such other subsidiary, as the case may be, will automatically be deemed to be the Company from and after the date of such transfer and shall have the same rights, duties and obligations hereunder as the Company had immediately prior to such transfer.

16


 

          13. Miscellaneous. (a) Applicable Law. This Agreement shall be governed by and construed in accordance with the laws of the State of New York, applied without reference to principles of conflict of laws.
          (b) Arbitration. Except to the extent provided in Section 11, in the event that any dispute, controversy or claim arises between the Company or National and the Executive with respect to the subject matter of this Agreement and the enforcement of rights hereunder, such dispute, controversy or claim shall be resolved by binding arbitration before a panel of three arbitrators selected in accordance with the American Arbitration Association (the “AAA”). The arbitration shall be conducted in accordance with the Expedited Employment Arbitration Rules of the American Arbitration Association then in effect at the time of the arbitration (or such other rules as the parties may agree to in writing), and otherwise in accordance with principles which would be applied by a court of law or equity. The determination reached in such arbitration shall be final and binding on both parties without any right of appeal or further dispute. Execution of the determination by such arbitration panel may be sought in any court of competent jurisdiction. The arbitrators shall not be bound by judicial formalities and may abstain from following the strict rules of evidence and shall interpret this Agreement as an honorable engagement and not merely as a legal obligation. Unless otherwise agreed by the parties, any such arbitration shall take place in a location selected by the Company which is a convenient forum for such arbitration (taking into account the availability of a sufficient pool of experienced arbitrators) and not more than 100 miles from the Executive’s principal place of employment at the Effective Date (or at such other location as may be agreed upon by the parties), and shall be conducted in accordance with the Rules of the AAA. In the event of the occurrence of any proceeding (including the appeal of an arbitration decision) between the Company or National and the Executive with respect to the subject matter of this Agreement and the enforcement of rights hereunder, the Company or National shall reimburse the Executive for all reasonable costs and expenses relating to such proceeding, including reasonable attorneys’ fees and expenses, regardless of the final outcome, unless the arbitration panel determines that recovery by the Executive of all or a part of such fees, costs and expenses would be unjust. In no event shall the Executive reimburse the Company for any of the costs and expenses relating to such litigation or other proceeding.
          (c) Amendments. This Agreement may not be amended or modified otherwise than by a written agreement executed by the parties hereto or their respective successors and legal representatives.
          (d) Entire Agreement. This Agreement constitutes the entire agreement between the parties hereto with respect to the matters referred to herein, provided, however, that this Agreement is not intended to impair any rights of the Executive under any prior written agreement, any employee benefit plan of the Company or a Subsidiary or

17


 

any written policy, program or procedure of the Company or a Subsidiary unless and to the extent specifically provided herein. No other agreement relating to the terms of the Executive’s employment by the Company, oral or otherwise, shall be binding between the parties unless it is in writing and signed by the party against whom enforcement is sought. There are no promises, representations, inducements or statements between the parties other than those that are expressly contained herein. The Executive acknowledges that he is entering into this Agreement of his own free will and accord, and with no duress, that he has read this Agreement and that he understands it and its legal consequences.
          (e) Notices. All notices and other communications hereunder shall be in writing and shall be given by hand-delivery to the other party or by registered or certified mail, return receipt requested, postage prepaid, addressed as follows:
          If to the Executive:
at the home address of the Executive noted on the records of the Company
          If to the Company:
[subsidiary corporation]
6363 Main Street
Williamsville, NY 14221
Attention: Corporate Secretary
          If to National:
National Fuel Gas Company
6363 Main Street
Williamsville, NY 14221
Attention: Corporate Secretary
or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notice and communications shall be effective when actually received by the addressee.
          (f) Source of Payments. All payments to be made hereunder shall be paid in cash from the general funds of the Company; provided, however, that such payments shall be reduced by the amount of any payments made to the Executive or his dependents, beneficiaries or estate from any trust or special or separate fund established by the Company or National to assure such payments. To the extent that the Company does not pay any such amount when due, National shall, or shall cause the Company, to make such payment. The Company or National shall not be required to establish a special or separate fund or other segregation of assets to assure such payments, and, if the Company or National shall make any investments to aid it in meeting its obligations hereunder, the Executive shall have no right, title or interest whatever in or to any such investments except as may otherwise be expressly provided in a separate written instrument relating to

18


 

such investments. Nothing contained in this Agreement, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind or a fiduciary relationship, between the Company or National and the Executive or any other person. To the extent that any person acquires a right to receive payments from the Company or National such right shall be no greater than the right of an unsecured creditor of the Company or National.
          (g) Tax Withholding;409A. The Company shall withhold from any amounts payable under this Agreement such Federal, state or local taxes as shall be required to be withheld pursuant to any applicable law or regulation. To the extent that any payments hereunder are subject to the provisions of Section 409A of the Code, the Company intends that the amounts payable under this Agreement shall be administered in compliance with the requirements of that Section.
          (h) Severability; Reformation. In the event that one or more of the provisions of this Agreement shall become invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby. In the event that any of the provisions of any of Section 10 are not enforceable in accordance with its terms, the Executive and the Company agree that such Section shall be reformed to make such Section enforceable in a manner which provides the Company the maximum rights permitted at law.
          (i) Waiver. Waiver by any party hereto of any breach or default by the other party of any of the terms of this Agreement shall not operate as a waiver of any other breach or default, whether similar to or different from the breach or default waived. No waiver of any provision of this Agreement shall be implied from any course of dealing between the parties hereto or from any failure by either party hereto to assert its or the Executive’s rights hereunder on any occasion or series of occasions.
          (j) Counterparts. This Agreement may be executed in counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument.
          (k) Captions. The captions of this Agreement are not part of the provisions hereof and shall have no force or effect.

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          IN WITNESS WHEREOF, the Executive has hereunto set his hand and the Company has caused this Agreement to be executed in its name on its behalf, and its corporate seal to be hereunto affixed and attested by its Secretary, all as of the day and year first above written.
             
 
      [SUBSIDIARY CORPORATION]    
 
           
Attest: /s/
      By:    
 
Secretary
     
 
Title:
   
 
           
 
      NATIONAL FUEL GAS COMPANY    
 
           
Attest: /s/
      By:    
 
Secretary
     
 
Title:
   
 
           
 
      EXECUTIVE:    
 
           
 
     
 
   

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NATIONAL FUEL GAS COMPANY
AMENDED AND RESTATED
EMPLOYMENT CONTINUATION
AND
NONCOMPETITION AGREEMENT
TABLE OF CONTENTS
Page
         
1. Operation of Agreement
    2  
a. Effective Date
    2  
b. Termination of Employment Following a Potential Change in Control
    2  
 
       
2. Definitions
    2  
a. Change in Control
    2  
b. Potential Change in Control
    3  
 
       
3. Employment Period
    4  
 
       
4. Position and Duties
    4  
 
       
5. Compensation
    4  
a. Base Salary
    4  
b. Annual Bonus
    4  
c. Long-term Incentive Compensation Programs
    4  
d. Benefit Plans
    5  
e. Expenses
    5  
f. Vacation and Fringe Benefits
    5  
g. Indemnification
    5  
 
       
6. Termination
    5  
a. Death, Disability or Retirement
    5  
b. Voluntary Termination
    6  
c. Cause
    6  
d. Good Reason
    6  
e. Notice of Termination
    7  
f. Date of Termination
    7  
 
       
7. Obligations of the Company upon Termination
    8  
a. Death or Disability
    8  
b. Cause and Voluntary Termination
    8  
c. Termination by the Company other than for Cause and Termination by the Executive for Good Reason
    8  
i. Severance Benefits
    8  
ii. Continuation of Welfare Benefits
    9  

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Page
         
iii. Qualification for Early Retirement
    9  
d. Discharge of the Company’s Obligations
    10  
e. Limit on Payments by the Company
    11  
i. Application of Section 7(e)
    11  
ii. Calculation of Benefits
    11  
iii. Imposition of Payment Cap
    11  
iv. Application of Section 280G
    12  
v. Applicable Tax Rates
    12  
vi. Adjustments in Respect of the Payment Cap
    13  
f. If Termination of Employment Occurs After the Executive Has Reached Age 62
    14  
 
       
8. Non-exclusivity of Rights
    14  
 
       
9. No Offset
    14  
 
       
10. Non-Competition and Non-Solicitation
    14  
a. Noncompete
    14  
b. Non-Solicitation of Employees
    15  
c. Confidential Information
    15  
d. Non-disparagement
    15  
e. Company Property
    16  
f. Additional Payment
    16  
 
       
11. Injunctive Relief and Other Remedies with Respect to Covenants
    16  
 
       
12. Successors
    16  
 
       
13. Miscellaneous
    17  
a. Applicable Law
    17  
b. Arbitration
    17  
c. Amendments
    17  
d. Entire Agreement
    17  
e. Notices
    18  
f. Source of Payments
    18  
g. Tax Withholding
    19  
h. Severability; Reformation
    19  
i. Waiver
    19  
j. Counterparts
    19  
k. Captions
    19  
 
       
Signature Page
    20  

22

Exhibit 10.2
FORM ECNA — CABELL
AMENDED AND RESTATED
EMPLOYMENT CONTINUATION AND
NONCOMPETITION AGREEMENT
          THIS AGREEMENT among SENECA RESOURCES CORPORATION, a Pennsylvania corporation (the “Company”), NATIONAL FUEL GAS COMPANY, a New Jersey corporation (“National”), and Matthew D. Cabell (the “Executive”), dated as of the 11th day of December, 2006, and amended and restated as of the 20th day of September, 2007, and further amended and restated as of the 24th day of September, 2008.
W I T N E S S E T H :
          WHEREAS, the Company and National wish to attract and retain well-qualified executive and key personnel and to assure continuity of management, which will be essential to its ability to evaluate and respond to any actual or threatened Change in Control (as defined below) in the best interests of shareholders;
          WHEREAS, the Executive is a valuable employee of the Company, an integral part of its management team and a key participant in the decision making process relative to short-term and long-term planning and policy for the Company;
          WHEREAS, the Company and National understand that any actual or threatened Change in Control will present significant concerns for the Executive with respect to his financial and job security;
          WHEREAS, the Company and National wish to encourage the Executive to continue his career and services with the Company for the period during and after an actual or threatened Change in Control and to assure to the Company the Executive’s services during the period in which such a Change in Control is threatened, and to provide the Executive certain financial assurances to enable the Executive to perform the responsibilities of his position without undue distraction and to exercise his judgment without bias due to his personal circumstances; and
          WHEREAS, the Board of Directors of National has determined that it would be in the best interests of National and its shareholders to assure continuity in the management of National in the event of a Change in Control by entering into an employment continuation and noncompete agreement with Executive;
          WHEREAS, to achieve these objectives, the Company, National and the Executive entered into an agreement providing the Company and the Executive with certain rights and obligations upon the occurrence of a Change in Control or Potential Change in Control (as defined in Section 2);

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          WHEREAS, the parties have determined to amend and restate this Agreement to assure that its terms comply with the applicable requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”).
          NOW, THEREFORE, in consideration of the premises and mutual covenants herein contained, it is hereby agreed by and between the Company, National and the Executive as follows:
          1. Operation of Agreement. (a) Effective Date. The effective date of this Agreement shall be the date on which a Change in Control occurs (the “Effective Date”), provided that, except as provided in Section 1(b), if the Executive is not employed by the Company, National or any of their subsidiaries on the Effective Date, this Agreement shall be void and without effect.
          (b) Termination of Employment Following a Potential Change in Control. Notwithstanding Section 1(a), if (i) the Executive’s employment is terminated by the Company Without Cause (as defined in Section 6(c)) after the occurrence of a Potential Change in Control and prior to the occurrence of a Change in Control and (ii) a Change in Control, which also constitutes a “change in control event” for purposes of Section 409A of the Code, occurs within two years of such termination, the Executive shall be deemed, solely for purposes of determining his rights under this Agreement, to have remained employed until the date such Change in Control occurs and to have been terminated by the Company without Cause immediately after the Change in Control. For this purpose, a Change in Control shall also be a change of control event for purposes of Section 409A of the Code if it is a change in the ownership or effective control of the Company, or a change in the ownership of a substantial portion of the assets of the Company, as such terms are defined in Treas. Reg. § 1.409A-3(i)(5) (or any successor provision).
          2. Definitions. (a) Change in Control. For the purposes of this Agreement, a “Change in Control” shall be deemed to have occurred if any of the following have occurred:
(i) either (a) the Company or National shall receive a report on Schedule 13D, or an amendment to such a report, filed with the Securities and Exchange Commission pursuant to Section 13(d) of the Securities Exchange Act of 1934 (the “1934 Act”) disclosing that any person (as such term is used in Section 13(d) of the 1934 Act) (“Person”), is the beneficial owner, directly or indirectly, of twenty (20) percent or more of the outstanding stock of National or (b) the Company or National has actual knowledge of facts which would require any Person to file such a report on Schedule 13D, or to make an amendment to such a report, with the SEC (or would be required to file such a report or amendment upon the lapse of the applicable period of time specified in Section 13(d) of the 1934 Act) disclosing that such Person is the beneficial owner, directly or indirectly, of twenty (20) percent or more of the outstanding stock of National;

2


 

(ii) purchase by any Person, other than National or a wholly-owned subsidiary of National or an employee benefit plan sponsored or maintained by National or a wholly-owned subsidiary of National, of shares pursuant to a tender or exchange offer to acquire any stock of National (or securities convertible into stock) for cash, securities or any other consideration provided that, after consummation of the offer, such Person is the beneficial owner (as defined in Rule 13d-3 under the 1934 Act), directly or indirectly, of twenty (20) percent or more of the outstanding stock of National (calculated as provided in paragraph (d) of Rule 13d-3 under the 1934 Act in the case of rights to acquire stock);
(iii) approval by the shareholders of National of (a) any consolidation or merger of National in which National is not the continuing or surviving corporation or pursuant to which shares of stock of National would be converted into cash, securities or other property, other than a consolidation or merger of National in which holders of its stock immediately prior to the consolidation or merger have substantially the same proportionate ownership of common stock of the surviving corporation immediately after the consolidation or merger as immediately before, or (b) any consolidation or merger in which National is the continuing or surviving corporation but in which the common shareholders of National immediately prior to the consolidation or merger do not hold at least a majority of the outstanding common stock of the continuing or surviving corporation (except where such holders of common stock hold at least a majority of the common stock of the corporation which owns all of the common stock of National), or (c) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all the assets of National;
(iv) a change in the majority of the members of the Board of Directors of National (the “Board”) within a 24-month period unless the election or nomination for election by National’s shareholders of each new director was approved by the vote of at least two-thirds of the directors then still in office who were in office at the beginning of the 24-month period;
(v) National shall cease to own, directly or indirectly, through one or more subsidiaries, securities of the Company that provide it with more than 50% of the voting power of all outstanding classes of the Company’s securities entitled to vote in the election of directors, and more than 50% of the value of all classes of the Company’s outstanding equity securities.
          (b) Potential Change in Control. For the purposes of this Agreement, a Potential Change in Control shall be deemed to have occurred if:

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(i) a Person commences a tender offer (with adequate financing) for securities representing at least twenty (20) percent of the outstanding stock of National (calculated as provided in paragraph (d) of Rule 13d-3 under the 1934 Act in the case of rights to acquire stock);
(ii) National enters into an agreement the consummation of which would constitute a Change in Control;
(iii) proxies for the election of directors of National are solicited by anyone other than National; or
(iv) any other event occurs which is deemed to be a Potential Change in Control by the Board.
          3. Employment Period. Subject to Section 6 of this Agreement, the Company agrees to continue the Executive in its employ, and the Executive agrees to remain in the employ of the Company, for the period (the “Employment Period”) commencing on the Effective Date and ending on the earlier to occur of (i) the third anniversary of the Effective Date and (ii) the date on which the Executive attains age 65.
          4. Position and Duties. During the Employment Period, the Executive’s position (including titles), authority and responsibilities shall be at least commensurate with those held, exercised and assigned immediately prior to the Effective Date. It is understood that, for purposes of this Agreement, such position, authority and responsibilities shall not be regarded as not commensurate merely by virtue of the fact that a successor shall have acquired all or substantially all of the business and/or assets of the Company as contemplated by Section 12(b) of this Agreement. The Executive’s services shall be performed in the United States and within 30 miles of the location where the Executive was employed immediately preceding the Effective Date.
          5. Compensation. (a) Base Salary. During the Employment Period, the Executive shall receive a base salary at a monthly rate at least equal to the monthly salary paid to the Executive by the Company and any of its affiliated companies immediately prior to the Effective Date. The base salary shall be reviewed at least once each year after the Effective Date, and shall be increased annually at a rate at least equal to the greater of (i) the average percentage increase for the same period in the compensation of salaried employees of National and its subsidiaries who are not executives and (ii) the percentage increase in the national Consumer Price Index for the last completed calendar year. The Executive’s base salary, as it shall be increased from time to time, shall hereafter be referred to as “Base Salary”. Neither the Base Salary nor any increase in Base Salary after the Effective Date shall serve to limit or reduce any other obligation of the Company hereunder.
          (b) Annual Bonus. During the Employment Period, in addition to the Base Salary, for each fiscal year of the Company ending during the

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Employment Period, the Executive shall be afforded the opportunity to receive an annual bonus on terms and conditions no less favorable to the Executive (taking into account reasonable changes in the Company’s goals and objectives) than the annual bonus opportunity that had been made available to the Executive for the fiscal year ended immediately prior to the Effective Date (the “Annual Bonus Opportunity”). Any amount payable in respect of the Annual Bonus Opportunity shall be paid as soon as practicable following the year for which the amount (or prorated portion) is earned or awarded, unless electively deferred by the Executive pursuant to any deferral programs or arrangements that the Company may make available to the Executive.
          (c) Long-term Incentive Compensation Programs. During the Employment Period, the Executive shall participate in all long-term incentive compensation programs for key executives at a level that is commensurate with the Executive’s participation in such plans immediately prior to the Effective Date, or, if more favorable to the Executive, at the level made available to the Executive or other similarly situated officers at any time thereafter.
          (d) Benefit Plans. During the Employment Period, the Executive (and, to the extent applicable, his dependents) shall be entitled to participate in or be covered under all retirement, deferred compensation, savings, medical, dental, health, disability, group life, accidental death and travel accident insurance plans and programs of the Company and its affiliated companies at a level that is commensurate with the Executive’s participation in such plans immediately prior to the Effective Date, or, if more favorable to the Executive, at the level made available to the Executive or other similarly situated officers at any time thereafter.
          (e) Expenses. During the Employment Period, the Executive shall be entitled to receive prompt reimbursement for all reasonable expenses incurred by the Executive in accordance with the policies and procedures of the Company as in effect immediately prior to the Effective Date. Notwithstanding the foregoing, the Company may apply the policies and procedures in effect after the Effective Date to the Executive, if such policies and procedures are not less favorable to the Executive than those in effect immediately prior to the Effective Date.
          (f) Vacation and Fringe Benefits. During the Employment Period, the Executive shall be entitled to paid vacation and fringe benefits at a level that is commensurate with the paid vacation and fringe benefits available to the Executive immediately prior to the Effective Date, or, if more favorable to the Executive, at the level made available from time to time to the Executive or other similarly situated officers at any time thereafter.
          (g) Indemnification. During and after the Employment Period, National and the Company shall indemnify the Executive and hold the Executive harmless from and against any claim, loss or cause of action arising from or out of the Executive’s performance as an

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officer, director or employee of National or the Company or any of their subsidiaries or in any other capacity, including any fiduciary capacity, in which the Executive serves at the request of National or the Company to the maximum extent permitted by applicable law and the Company’s Certificate of Incorporation and By-Laws (the “Governing Documents”), provided that in no event shall the protection afforded to the Executive hereunder be less than that afforded under the Governing Documents as in effect immediately prior to the Effective Date.
          6. Termination. (a) Death, Disability or Retirement. Subject to the provisions of Section 1 hereof, this Agreement shall terminate automatically upon the Executive’s death, termination due to “Disability” (as defined below) or voluntary retirement under any of the Company’s retirement plans as in effect from time to time. For purposes of this Agreement, Disability shall mean the Executive’s inability to perform the duties of his position, as determined in accordance with the policies and procedures applicable with respect to the Company’s long-term disability plan, as in effect immediately prior to the Effective Date.
          (b) Voluntary Termination. Notwithstanding anything in this Agreement to the contrary, following a Change in Control the Executive may, upon not less than 30 days’ written notice to the Company, voluntarily terminate employment for any reason, provided that any termination by the Executive pursuant to Section 6(d) on account of Good Reason (as defined therein) shall not be treated as a voluntary termination under this Section 6(b).
          (c) Cause. The Company may terminate the Executive’s employment for Cause. For purposes of this Agreement, “Cause” means the Executive’s gross misconduct, fraud or dishonesty, which has resulted or is likely to result in material economic damage to the Company or National, as determined in good faith by a vote of at least two-thirds of the non-employee directors of National at a meeting of the Board at which the Executive is provided an opportunity to be heard (with representation by counsel of his choosing, should he so desire).
          (d) Good Reason. Following the occurrence of a Change in Control, the Executive may terminate his employment for Good Reason. For purposes of this Agreement, “Good Reason” means the occurrence of any of the following, without the express written consent of the Executive, after the occurrence of a Change in Control:
(i) a material diminution in (A) the Executive’s authority, duties, or responsibilities, (B) the Executive’s base compensation or (C) the budget over which the Executive retains authority;
(ii) a material diminution in the authority, duties, or responsibilities of the supervisor to whom the Executive is required to report, including a requirement that the Executive report to a corporate officer or employee instead of reporting directly to the board of directors of a corporation; or

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(iii) the Company’s requiring the Executive to be based at any office or location outside of the United States and/or more than 30 miles from that location at which he performed his services specified under the provisions of Section 4 immediately prior to the Change in Control, except for travel reasonably required in the performance of the Executive’s responsibilities; or
(iv) any other action or inaction that constitutes a material breach by the Company of this Agreement;
provided, however, that to constitute Good Reason the Company shall have a period of 30 days to cure any acts which would otherwise give Executive the right to terminate his employment for Good Reason. Such 30-day period shall commence as of the date of receipt by the Company of the Notice of Termination.
In no event shall the mere occurrence of a Change in Control, absent any further impact on the Executive, be deemed to constitute Good Reason. In the event that the Executive shall in good faith give a Notice of Termination for Good Reason and it shall thereafter be determined that Good Reason did not exist, the Executive shall, unless the Company and the Executive shall otherwise mutually agree, return to employment with the Company within 5 business days of such decision, without any impairment or other limitation of his rights hereunder, except that he shall not be paid his base salary for any period he did not perform services and his annual bonus opportunity for such year may be reduced to reflect his period of absence.
          (e) Notice of Termination. Any termination by the Company for Cause or by the Executive for Good Reason shall be communicated by Notice of Termination given in accordance with Section 13(e). For purposes of this Agreement, a “Notice of Termination” means a written notice given, in the case of a termination for Cause, within 30 business days of the Company’s having actual knowledge of the events giving rise to such termination, and in the case of a termination for Good Reason, within 90 days of the Executive’s having actual knowledge of the events giving rise to such termination, and which (i) indicates the specific termination provision in this Agreement relied upon, (ii) sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Executive’s employment under the provision so indicated, and (iii) specifies the date the Executive’s employment shall terminate (which date shall be not less than 30 nor more than 60 days after the giving of such notice). The failure by the Executive to set forth in the Notice of Termination any fact or circumstance which contributes to a showing of Good Reason shall not waive any right of the Executive hereunder or preclude the Executive from asserting such fact or circumstance in enforcing his rights hereunder.
          (f) Date of Termination. For the purpose of this Agreement, the term “Date of Termination” means (i) in the case of a termination for which a Notice of Termination is required, the date of receipt of

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such Notice of Termination or, if later, the date specified therein, as the case may be, and (ii) in all other cases, the actual date on which the Executive’s employment terminates during the Employment Period. For the avoidance of doubt, if the Executive ceases to be an employee but continues to provide services to the Company or any of its affiliates following his Date of Termination, or is reasonably expected (at such Date of Termination) to provide such services within 12 months of such Date of Termination, the term Date of Termination (or termination of employment or any other similar terms used in this Agreement) shall be deemed to refer to the date at which the Executive incurs a “separation from service” from the Company within the meaning of Section 409A of the Code and the regulations promulgated thereunder. This means that rather than being entitled to receive any payments or benefits hereunder upon, or at a specified time following, the Date of Termination (or termination of employment or any other similar terms used in the Agreement), such a continuing Executive shall be entitled to receive such payments or benefits upon, or at a specified time following, such a separation from service.
          7. Obligations of the Company upon Termination. (a) Death or Disability. If the Executive’s employment is terminated during the Employment Period by reason of the Executive’s death or Disability, this Agreement shall terminate without further obligations to the Executive or the Executive’s legal representatives under this Agreement other than those obligations accrued hereunder at the Date of Termination, and the Company shall pay to the Executive (or his beneficiary or estate) (i) the Executive’s full Base Salary through the Date of Termination (the “Earned Salary”), (ii) any vested amounts or benefits owing to the Executive under the Company’s otherwise applicable employee benefit plans and programs, including any compensation previously deferred by the Executive (together with any accrued earnings thereon) and not yet paid by the Company and any amounts payable pursuant to any individual agreement with Executive (the “Accrued Obligations”), and (iii) any other benefits payable due to the Executive’s death or Disability under the Company’s plans, policies or programs (the “Additional Benefits”).
          Any Earned Salary shall be paid in cash in a single lump sum as soon as practicable, but in no event more than 15 days (or at such earlier date required by law), following the Date of Termination. Accrued Obligations and Additional Benefits shall be paid in accordance with the terms of the applicable plan, program or arrangement.
          (b) Cause and Voluntary Termination. If, during the Employment Period, the Executive’s employment shall be terminated for Cause or voluntarily terminated by the Executive (other than on account of Good Reason following a Change in Control), the Company shall pay the Executive (i) the Earned Salary in cash in a single lump sum as soon as practicable, but in no event more than 10 days, following the Date of Termination, and (ii) the Accrued Obligations in accordance with the terms of the applicable plan, program or arrangement.

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          (c) Termination by the Company other than for Cause and Termination by the Executive for Good Reason. Subject to Section 7(f) below, if, during the Employment Period, the Company terminates the Executive’s employment other than for Cause, or the Executive terminates his employment for Good Reason, the Company shall pay to the Executive the following amounts:
(i) Severance Benefits. The Executive shall be paid the following:
(A) the Executive’s Earned Salary;
(B) a cash amount (the “Severance Amount”) equal to
(1) 1.99; times
(2) the sum of
(i) the Executive’s annual Base Salary; and
(ii) the average of the annual at risk compensation incentive program bonuses or other bonuses (excluding sign-on bonuses) payable to the Executive (including, for the purposes of this calculation, any amount of such bonuses paid in the form of restricted stock (in lieu of cash), to be valued at the date of grant) for the two fiscal years of the Company ending immediately prior to the Effective Date (the “Average Bonus”); and
          (C) the Accrued Obligations.
Except as otherwise expressly provided in the next sentence, the Earned Salary and Severance Amount shall be paid in cash in a single lump sum as soon as practicable, but in no event more than 10 days (or at such earlier date required by law), following the Date of Termination; provided however that if the date payment would otherwise be due hereunder is after September 30, payment of the Severance Amount shall be paid on the first business day in the following January. Accrued Obligations shall be paid in accordance with the terms of the applicable plan, program or arrangement.
(ii) Continuation of Medical Benefits. The Executive (and, to the extent applicable, his dependents) shall be entitled, after the Date of Termination until the earlier of (1) the eighteen month anniversary of the Date of Termination (the “Medical End Date”) and (2) the date the Executive becomes eligible for comparable benefits under a similar plan, policy or program of a subsequent employer, to continue participation in all of the Company’s medical, dental and health benefit plans (“Medical Plans”). To the extent any such benefits cannot be provided under the terms of the applicable plan, policy or program, the Company shall provide a comparable benefit under another plan or from the Company’s general assets. The Executive’s participation in the Medical Plans will be on the same

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terms and conditions that would have applied had the Executive continued to be employed by the Company through the Medical End Date.
(iii) Continuation of Other Welfare Benefits. The Executive (and, to the extent applicable, his dependents) shall be entitled, after the Date of Termination until the earlier of (1) the end of the second calendar year following the Date of Termination (the “Benefits End Date”) and (2) the date the Executive becomes eligible for comparable benefits under a similar plan, policy or program of a subsequent employer, to continue participation in all employee and executive welfare and fringe benefit plans, excluding the Medical Plans, any severance plans and further vacation pay (the “Benefit Plans”). To the extent any such benefit or perquisite cannot be provided under the terms of the applicable plan, policy or program, the Company shall provide a comparable benefit under another plan or from the Company’s general assets. The Executive’s participation in the Benefit Plans will be on the same terms and conditions that would have applied had the Executive continued to be employed by the Company through the Benefits End Date.
     (iv) Vesting of Retirement Benefit Account. To the extent that, at the Date of Termination, the Executive is not fully vested in any amounts credited to his retirement accounts under the Company’s retirement plans (whether qualified or non-qualified) in which the Executive was participating immediately prior to the Change of Control, then in addition to any benefit otherwise payable to Executive under such plans, the Company shall make a single lump sum payment to the Executive, within 10 days of the Date of Termination, equal to the present value of the Executive’s unvested accrued benefit under such retirement plans. Such lump sum value shall be determined in accordance with the provisions of the applicable plans.
          (d) Discharge of the Company’s Obligations. Except as expressly provided in the last sentence of this Section 7(d), the amounts payable to the Executive pursuant to this Section 7 (whether or not reduced pursuant to Section 7(e)) following termination of his employment shall be in full and complete satisfaction of the Executive’s rights under this Agreement and any other claims he may have in respect of his employment by the Company or any of its subsidiaries. Such amounts shall constitute liquidated damages with respect to any and all such rights and claims and, upon the Executive’s receipt of such amounts, the Company shall be released and discharged from any and all liability to the Executive in connection with this Agreement or otherwise in connection with the Executive’s employment with the Company and its subsidiaries. Nothing in this Section 7(d) shall be construed to release the Company from its commitment to indemnify the Executive and hold the Executive harmless from and against any claim, loss or cause of action arising from or out of the Executive’s performance as an officer, director or employee of the Company or any of its subsidiaries or in any other capacity, including any fiduciary capacity, in which

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the Executive served at the request of the Company to the maximum extent permitted by applicable law and the Governing Documents.
     (e) Limit on Payments by the Company.
(i) Application of Section 7(e). In the event that any amount or benefit paid or distributed to the Executive pursuant to this Agreement, taken together with any amounts or benefits otherwise paid or distributed to the Executive by the Company or any affiliated company (collectively, the “Covered Payments”), would be an “excess parachute payment” as defined in Section 280G of the Code and would thereby subject the Executive to the tax (the “Excise Tax”) imposed under Section 4999 of the Code (or any similar tax that may hereafter be imposed), the provisions of this Section 7(e) shall apply to determine the amounts payable to the Executive pursuant to this Agreement.
(ii) Calculation of Benefits. Immediately following delivery of any Notice of Termination, the Company shall notify the Executive of the aggregate present value of all termination benefits to which he would be entitled under this Agreement and any other plan, program or arrangement as of the projected Date of Termination, together with the projected maximum payments, determined as of such projected Date of Termination that could be paid without the Executive being subject to the Excise Tax.
(iii) Imposition of Payment Cap. If
     (x) the aggregate value of all compensation payments or benefits to be paid or provided to the Executive under this Agreement and any other plan, agreement or arrangement with the Company exceeds the amount which can be paid to the Executive without the Executive incurring an Excise Tax, and
     (y) the net-after tax amount (taking into account all applicable taxes payable by the Executive, including any Excise Tax) that the Executive would receive if the limitation contained in this Section 7(e)(iii) were not imposed does not exceed the net-after tax benefit the Executive would receive if such limitation were imposed by more than $25,000, then the amounts payable to the Executive under this Section 7 shall be reduced (but not below zero) to the maximum amount which may be paid hereunder without the Executive becoming subject to such an Excise Tax (such reduced payments to be referred to as the “Payment Cap”). In the event that the Executive receives reduced payments and benefits hereunder, such payments and benefits shall be reduced in connection with the application of the Payment Cap in the following manner: first the Executive’s Severance Amount shall be reduced, followed by, to the extent necessary and in order, the continuation of welfare benefits, any early retirement

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benefits the Executive becomes vested in under the Agreement, the Average Bonus and finally the Accrued Obligations.
(iv) Application of Section 280G. For purposes of determining whether any of the Covered Payments will be subject to the Excise Tax and the amount of such Excise Tax,
     (A) such Covered Payments will be treated as “parachute payments” within the meaning of Section 280G of the Code, and all “parachute payments” in excess of the “base amount” (as defined under Section 280G(b)(3) of the Code) shall be treated as subject to the Excise Tax, unless, and except to the extent that, in the good faith judgment of the Company’s independent certified public accountants appointed prior to the Effective Date or tax counsel selected by such Accountants (the “Accountants”), the Company as a reasonable basis to conclude that such Covered Payments (in whole or in part) either do not constitute “parachute payments” or represent reasonable compensation for personal services actually rendered (within the meaning of Section 280G(b)(4)(B) of the Code) in excess of the portion of the “base amount” allocable to such Covered Payments, or such “parachute payments” are otherwise not subject to such Excise Tax, and
     (B) the value of any noncash benefits or any deferred payment or benefit shall be determined by the Accountants in accordance with the principles of Section 280G of the Code.
(v) Applicable Tax Rates. For purposes of determining whether the Executive would receive a greater net after-tax benefit were the amounts payable under this Agreement reduced in accordance with Paragraph 7(e)(iii), the Executive shall be deemed to pay:
(A) Federal income taxes at the highest applicable marginal rate of Federal income taxation for the calendar year in which the first amounts are to be paid hereunder, and
(B) any applicable state and local income taxes at the highest applicable marginal rate of taxation for such calendar year, net of the maximum reduction in Federal incomes taxes which could be obtained from the deduction of such state or local taxes if paid in such year;
provided, however, that the Executive may request that such determination be made based on his individual tax circumstances, which shall govern such determination so long as the Executive provides to the Accountants such information and documents as the Accountants shall reasonably request to determine such individual circumstances.

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(vi) Adjustments in Respect of the Payment Cap. If the Executive receives reduced payments and benefits under this Section 7(e) (or this Section 7(e) is determined not to be applicable to the Executive because the Accountants conclude that the Executive is not subject to any Excise Tax) and it is established pursuant to a final determination of a court or an Internal Revenue Service proceeding (a “Final Determination”) that, notwithstanding the good faith of the Executive and the Company in applying the terms of this Agreement, the aggregate “parachute payments” within the meaning of Section 280G of the Code paid to the Executive or for his benefit are in an amount that would result in the Executive being subject an Excise Tax, then the amount equal to such excess parachute payments shall be deemed for all purposes to be a loan to the Executive made on the date of receipt of such excess payments, which the Executive shall have an obligation to repay to the Company on demand, together with interest on such amount at the applicable Federal rate (as defined in Section 1274(d) of the Code) from the date of the payment hereunder to the date of repayment by the Executive. If this Section 7(e) is not applied to reduce the Executive’s entitlement under this Section 7 because the Accountants determine that the Executive would not receive a greater net-after tax benefit by applying this Section 7(e) and it is established pursuant to a Final Determination that, notwithstanding the good faith of the Executive and the Company in applying the terms of this Agreement, the Executive would have received a greater net after tax benefit by subjecting his payments and benefits hereunder to the Payment Cap, then the aggregate “parachute payments” paid to the Executive or for his benefit in excess of the Payment Cap shall be deemed for all purposes a loan to the Executive made on the date of receipt of such excess payments, which the Executive shall have an obligation to repay to the Company on demand, together with interest on such amount at the applicable Federal rate (as defined in Section 1274(d) of the Code) from the date of the payment hereunder to the date of repayment by the Executive. If the Executive receives reduced payments and benefits by reason of this Section 7(e) and it is established pursuant to a Final Determination that the Executive could have received a greater amount without exceeding the Payment Cap, then the Company shall promptly thereafter pay the Executive the aggregate additional amount which could have been paid without exceeding the Payment Cap, together with interest on such amount at the applicable Federal rate (as defined in Section 1274(d) of the Code) from the original payment due date to the date of actual payment by the Company.
          (f) If Termination of Employment Occurs After the Executive Has Reached Age 62. Notwithstanding anything else to the contrary contained in this Section 7, if the Executive’s employment with the Company terminates at any time during the 3 year period ending on the first day of the month following the Executive’s sixty-fifth birthday (the “Normal Retirement Date”), and the Executive would be entitled to receive severance benefits under paragraphs 7(c), then (i) the

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multiplier in paragraph 7(c)(i)(B) shall not be 1.99, but shall be a number equal to 1.99 times (x/1095), where x equals the number of days remaining until the Executive’s Normal Retirement Date, and (ii) if the Executive’s Normal Retirement Date shall occur earlier than either the Medical End Date or the Benefits End Date described in Section 7(c)(ii) and 7(c)(iii), respectively, then notwithstanding such Sections, such Medical End Date or Benefits End Date shall end on the Executive’s Normal Retirement Date.
          8. Non-exclusivity of Rights. Except as expressly provided herein, nothing in this Agreement shall prevent or limit the Executive’s continuing or future participation in any benefit, bonus, incentive or other plan or program provided by the Company or any of its affiliated companies and for which the Executive may qualify, nor shall anything herein limit or otherwise prejudice such rights as the Executive may have under any other agreements with the Company or any of its affiliated companies, including employment agreements or stock option agreements. Amounts which are vested benefits or which the Executive is otherwise entitled to receive under any plan or program of the Company or any of its affiliated companies at or subsequent to the Date of Termination shall be payable in accordance with such plan or program.
          9. No Offset. The Company’s obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any circumstances, including, without limitation, any set-off, counterclaim, recoupment, defense or other right which the Company may have against the Executive or others whether by reason of the subsequent employment of the Executive or otherwise.
          10. Non-Competition and Non-Solicitation. (a) Noncompete. Unless the Executive otherwise elects by written notice to the Company prior to his Date of Termination (or in the case of a Company initiated termination, within 5 business days of receipt of a Notice of Termination, if such period extends beyond the Date of Termination) not to be bound by the provisions of this Section 10(a), during the one year period following the Executive’s Date of Termination for any reason (the “Restriction Period”), Executive shall not, directly or indirectly, engage in, become employed by, serve as an agent or consultant to, or become a partner, principal or stockholder (other than a holder of less than 1% of the outstanding voting shares of any publicly held company) of any business or entity that is engaged in any activity which is competitive with the business of the Company, National and their respective subsidiaries or affiliates in any geographic area in which the Company, National and/or any of their respective subsidiaries or affiliates is engaged in such competitive business.
          (b) Non-Solicitation of Employees. Regardless of whether the Executive has elected to be bound by Section 10(a), during the Restriction Period, the Executive shall not, directly or indirectly, for his own account or for the account of any other person or entity

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with which he is or shall become associated in any capacity, solicit for employment, employ or otherwise interfere with the relationship of Employer with any person who at any time during the six months preceding such solicitation, employment or interference is or was employed by or otherwise engaged to perform services for Employer other than any such solicitation or employment during the Executive’s employment with Employer on behalf of Employer.
          (c) Confidential Information. Regardless of whether the Executive has elected to be bound by Section 10(a), the Executive shall hold in a fiduciary capacity for the benefit of National and the Company all secret or confidential information, knowledge or data relating to National, the Company or any of their affiliated companies, and their respective businesses, (i) obtained by the Executive during his employment by the Company or any of its affiliated companies and (ii) not otherwise public knowledge (other than by reason of an unauthorized act by the Executive). After termination of the Executive’s employment with the Company, the Executive shall not, without the prior written consent of the Company, unless compelled pursuant to an order of a court or other body having jurisdiction over such matter, communicate or divulge any such information, knowledge or data to anyone other than the Company and those designated by it.
          (d) Non-disparagement. Regardless of whether the Executive has elected to be bound by Section 10(a), the Executive shall not publicly or privately disparage National or the Company, or any of their subsidiaries or affiliates, including any aspect of their respective business, products, employees, management or Board of Directors, in any manner which could adversely effect the business of National, the Company or such subsidiaries or affiliates. Furthermore, the Executive shall not, directly or indirectly, take any action or fail to take any action with the purpose of interfering with, damaging or disrupting the assets or business operations or affairs of National or the Company or any of their respective subsidiaries or affiliates.
          National and the Company shall not publicly or privately disparage the Executive, either personally or professionally. Nothing in this paragraph shall be construed to prevent any officer of National or the Company from discussing the Executive’s performance internally in the ordinary course of business.
          (e) Company Property. Except as expressly provided herein, promptly following the Executive’s termination of employment, the Executive shall return to the Company all property of National and the Company and all copies thereof in the Executive’s possession or under his control.
          (f) Additional Payment. Unless the Executive has elected not to be bound by Section 10(a), the Company shall make an additional lump sum payment to the Executive within 30 days following the Executive’s Date of Termination equal to one times the sum of (i) the Executive’s annual Base Salary and (ii) the Executive’s Average Bonus as compensation for the covenant contained in Section 10(a).

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          11. Injunctive Relief and Other Remedies with Respect to Covenants. The Executive acknowledges and agrees that the covenants and obligations of the Executive set forth in Section 10 relate to special, unique and extraordinary matters and that a violation of any of the terms of such covenants and obligations will cause the Company irreparable injury for which adequate remedies are not available at law. Therefore, the Executive agrees that the Company shall be entitled to an injunction, restraining order or such other equitable relief (without the requirement to post bond) restraining the Executive from committing any violation of the covenants and obligations contained in Section 10 These remedies are cumulative and are in addition to any other rights and remedies the Company may have at law or in equity. In no event shall an asserted violation of the provisions of Section 10 constitute a basis for deferring or withholding any amounts otherwise payable to the Executive under this Agreement.
          12. Successors. (a) This Agreement is personal to the Executive and, without the prior written consent of the Company, shall not be assignable by the Executive otherwise than by will or the laws of descent and distribution. This Agreement shall inure to the benefit of and be enforceable by the Executive’s legal representatives.
          (b) This Agreement shall inure to the benefit of and be binding upon the Company and its successors. The Company shall require any successor to all or substantially all of the business and/or assets of the Company, whether direct or indirect, by purchase, merger, consolidation, acquisition of stock, or otherwise, by an agreement in form and substance satisfactory to the Executive, expressly to assume and agree to perform this Agreement in the same manner and to the same extent as the Company would be required to perform if no such succession had taken place.
          (c) In the event the Executive ceases to be employed by the Company as a result of the transfer of the Executive’s employment to National or to another wholly owned subsidiary of National, for purposes of this Agreement, National or such other subsidiary, as the case may be, will automatically be deemed to be the Company from and after the date of such transfer and shall have the same rights, duties and obligations hereunder as the Company had immediately prior to such transfer; provided that (i) such provision shall not apply without the Executive’s consent if such transfer of employment occurs in connection with or in anticipation of a transaction involving the Company that would constitute a Change of Control under this Agreement, and (ii) the definition of a Change of Control hereunder shall be modified to exclude from said definition any transaction pertaining to the Company (and not National) unless National shall have otherwise agreed in writing that such definition shall not be so amended.
          13. Miscellaneous. (a) Applicable Law. This Agreement shall be governed by and construed in accordance with the laws of the State of New York, applied without reference to principles of conflict of laws.

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          (b) Arbitration. Except to the extent provided in Section 11, in the event that any dispute, controversy or claim arises between the Company or National and the Executive with respect to the subject matter of this Agreement and the enforcement of rights hereunder, such dispute, controversy or claim shall be resolved by binding arbitration before a panel of three arbitrators selected in accordance with the American Arbitration Association (the “AAA”). The arbitration shall be conducted in accordance with the Expedited Employment Arbitration Rules of the American Arbitration Association then in effect at the time of the arbitration (or such other rules as the parties may agree to in writing), and otherwise in accordance with principles which would be applied by a court of law or equity. The determination reached in such arbitration shall be final and binding on both parties without any right of appeal or further dispute. Execution of the determination by such arbitration panel may be sought in any court of competent jurisdiction. The arbitrators shall not be bound by judicial formalities and may abstain from following the strict rules of evidence and shall interpret this Agreement as an honorable engagement and not merely as a legal obligation. Unless otherwise agreed by the parties, any such arbitration shall take place in a location selected by the Company which is a convenient forum for such arbitration (taking into account the availability of a sufficient pool of experienced arbitrators) and not more than 100 miles from the Executive’s principal place of employment at the Effective Date (or at such other location as may be agreed upon by the parties), and shall be conducted in accordance with the Rules of the AAA. In the event of the occurrence of any proceeding (including the appeal of an arbitration decision) between the Company or National and the Executive with respect to the subject matter of this Agreement and the enforcement of rights hereunder, the Company or National shall reimburse the Executive for all reasonable costs and expenses relating to such proceeding, including reasonable attorneys’ fees and expenses, regardless of the final outcome, unless the arbitration panel determines that recovery by the Executive of all or a part of such fees, costs and expenses would be unjust. In no event shall the Executive reimburse the Company for any of the costs and expenses relating to such litigation or other proceeding.
          (c) Amendments. This Agreement may not be amended or modified otherwise than by a written agreement executed by the parties hereto or their respective successors and legal representatives.
          (d) Entire Agreement. This Agreement, as amended and restated, constitutes the entire agreement between the parties hereto with respect to the matters referred to herein; provided, however, that this Agreement is not intended to impair any rights of the Executive under any prior written agreement, any employee benefit plan of the Company or a Subsidiary or any written policy, program or procedure of the Company or a Subsidiary unless and to the extent specifically provided herein. No other agreement relating to the terms of the Executive’s employment by the Company, oral or otherwise, shall be binding between the parties unless it is in writing and signed by

17


 

the party against whom enforcement is sought. There are no promises, representations, inducements or statements between the parties other than those that are expressly contained herein. The Executive acknowledges that he is entering into this Agreement of his own free will and accord, and with no duress, that he has read this Agreement and that he understands it and its legal consequences.
          (e) Notices. All notices and other communications hereunder shall be in writing and shall be given by hand-delivery to the other party or by registered or certified mail, return receipt requested, postage prepaid, addressed as follows:
          If to the Executive:
at the home address of the Executive noted on the records of the Company
          If to the Company:
Seneca Resources Corporation
6363 Main Street
Williamsville, New York 14221
Attention: Corporate Secretary
          If to National:
National Fuel Gas Company
6363 Main Street
Williamsville, New York 14221
Attention: Corporate Secretary
or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notice and communications shall be effective when actually received by the addressee.
          (f) Source of Payments. All payments to be made hereunder shall be paid in cash from the general funds of the Company; provided, however, that such payments shall be reduced by the amount of any payments made to the Executive or his dependents, beneficiaries or estate from any trust or special or separate fund established by the Company or National to assure such payments. To the extent that the Company does not pay any such amount when due, National shall, or shall cause the Company, to make such payment. The Company or National shall not be required to establish a special or separate fund or other segregation of assets to assure such payments, and, if the Company or National shall make any investments to aid it in meeting its obligations hereunder, the Executive shall have no right, title or interest whatever in or to any such investments except as may otherwise be expressly provided in a separate written instrument relating to such investments. Nothing contained in this Agreement, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind or a fiduciary relationship, between the Company or National and the Executive or any other person. To the extent that any person acquires a right to receive payments from the

18


 

Company or National such right shall be no greater than the right of an unsecured creditor of the Company or National.
          (g) Tax Withholding; Section 409A. The Company shall withhold from any amounts payable under this Agreement such Federal, state or local taxes as shall be required to be withheld pursuant to any applicable law or regulation. To the extent that any payments hereunder are subject to the provisions of Section 409A of the Code, the Company intends that the amounts payable under this Agreement shall be administered in compliance with the requirements of that Section.
          (h) Severability; Reformation. In the event that one or more of the provisions of this Agreement shall become invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby. In the event that any of the provisions of any of Section 10 are not enforceable in accordance with its terms, the Executive and the Company agree that such Section shall be reformed to make such Section enforceable in a manner which provides the Company the maximum rights permitted at law.
          (i) Waiver. Waiver by any party hereto of any breach or default by the other party of any of the terms of this Agreement shall not operate as a waiver of any other breach or default, whether similar to or different from the breach or default waived. No waiver of any provision of this Agreement shall be implied from any course of dealing between the parties hereto or from any failure by either party hereto to assert its or the Executive’s rights hereunder on any occasion or series of occasions.
          (j) Counterparts. This Agreement may be executed in counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument.
          (k) Captions. The captions of this Agreement are not part of the provisions hereof and shall have no force or effect.

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          IN WITNESS WHEREOF, the Executive has hereunto set his hand and the Company has caused this amended and restated Agreement to be executed in its name on its behalf, and its corporate seal to be hereunto affixed and attested by its Secretary, all as of the day and year indicated above.
         
    SENECA RESOURCES CORPORATION
 
       
Attest:
  By:    
 
       
 
       
 
  Name:    
 
       
 
       
 
  Title:    
 
       
 
       
    NATIONAL FUEL GAS COMPANY
 
       
Attest:
  By:    
 
       
 
       
 
  Name:    
 
       
 
       
 
  Title:    
 
       
 
       
 
    EXECUTIVE:
 
       
     

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AMENDED AND RESTATED
EMPLOYMENT CONTINUATION
AND
NONCOMPETITION AGREEMENT
TABLE OF CONTENTS
         
    Page
1. Operation of Agreement
    2  
a. Effective Date
    2  
b. Termination of Employment Following a Potential Change in Control
    2  
 
       
2. Definitions
    2  
a. Change in Control
    2  
b. Potential Change in Control
    3  
 
       
3. Employment Period
    4  
 
       
4. Position and Duties
    4  
 
       
5. Compensation
    4  
a. Base Salary
    4  
b. Annual Bonus
    4  
c. Long-term Incentive Compensation Programs
    5  
d. Benefit Plans
    5  
e. Expenses
    5  
f. Vacation and Fringe Benefits
    5  
g. Indemnification
    5  
 
       
6. Termination
    6  
a. Death, Disability or Retirement
    6  
b. Voluntary Termination
    6  
c. Cause
    6  
d. Good Reason
    6  
e. Notice of Termination
    7  
f. Date of Termination
    7  
 
       
7. Obligations of the Company upon Termination
    8  
a. Death or Disability
    8  
b. Cause and Voluntary Termination
    8  
c. Termination by the Company other than for Cause and Termination by the Executive for Good Reason
    9  

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    Page
i. Severance Benefits
    9  
ii. Continuation of Medical Benefits
    9  
iii. Continuation of Other Welfare Benefits
    10  
iv. Vesting of Retirement Benefit Account
    10  
d. Discharge of the Company’s Obligations
    10  
e. Limit on Payments by the Company
    11  
i. Application of Section 7(e)
    11  
ii. Calculation of Benefits
    11  
iii. Imposition of Payment Cap
    11  
iv. Application of Section 280G
    12  
v. Applicable Tax Rates
    12  
vi. Adjustments in Respect of the Payment Cap
    13  
f. If Termination of Employment Occurs After the Executive Has Reached Age 62
    13  
 
       
8. Non-exclusivity of Rights
    14  
 
       
9. No Offset
    14  
 
       
10. Non-Competition and Non-Solicitation
    14  
a. Noncompete
    14  
b. Non-Solicitation of Employees
    14  
c. Confidential Information
    15  
d. Non-disparagement
    15  
e. Company Property
    15  
f. Additional Payment
    15  
 
       
11. Injunctive Relief and Other Remedies with Respect to Covenants
    16  
 
       
12. Successors
    16  
 
       
13. Miscellaneous
    16  
a. Applicable Law
    16  
b. Arbitration
    17  
c. Amendments
    17  
d. Entire Agreement
    17  
e. Notices
    18  
f. Source of Payments
    18  
g. Tax Withholding; Section 409A
    19  
h. Severability; Reformation
    19  
i. Waiver
    19  
j. Counterparts
    19  
k. Captions
    19  
 
       
Signature Page
    20  

22

Exhibit 10.3
AMENDED AND RESTATED
NATIONAL FUEL GAS COMPANY
2007 ANNUAL AT RISK COMPENSATION INCENTIVE PLAN
1. Definitions
     As used with respect to At Risk Awards, the following terms shall have the following meanings:
     (a)  “Acceleration Date” means (i) in the event of a Change in Ownership, the date on which such change occurs, or (ii) with respect to an Eligible Employee who is eligible for treatment under paragraph 8 hereof on account of the termination of his employment following a Change in Control, the date on which such termination occurs.
     (b)  “Award Notice” means a written notice from the Company to a Participant that sets forth the terms and conditions of an Award in addition to the terms and conditions established by this Plan and by the Committee’s exercise of its administrative powers.
     (c)  “At Risk Award” means an award granted by the Committee to a Participant under this Plan, and entitling the Participant to a cash payment based upon the extent to which specified Performance Goals are attained for a specified Performance Period, pursuant to such terms and conditions as the Committee may establish in an Award Notice. No Eligible Employee may receive more than one At Risk Award under this Plan in any fiscal year. In no event will the maximum value of any At Risk Award to any Eligible Employee in any fiscal year exceed the lower of (i) twice that employee’s base salary for that fiscal year, or (ii) two million dollars. An At Risk Award may be granted singly, in combination or in the alternative with other Awards granted under any Company benefit plan.
     (d)  “Board” means the Board of Directors of the Company.
     (e)  “Cause” means (i) the willful and continued failure by a Participant to substantially perform his duties with his employer after written warnings specifically identifying the lack of substantial performance are delivered to him by his employer, or (ii) the willful engaging by a Participant in illegal conduct which is materially and demonstrably injurious to the Company or a Subsidiary.
     (f) “Change in Control” shall be deemed to have occurred at such time as (i) any “person” within the meaning of Section 14(d) of the Exchange Act, other than the Company, a Subsidiary, or any employee benefit plan or plans sponsored by the Company or any Subsidiary, is or has become the “beneficial owner,” as defined in Rule 13d-3 under the Exchange Act, directly or indirectly, of twenty percent (20%) or more of the combined voting power of the outstanding securities of the Company ordinarily having the right to vote at the election of directors, or (ii) approval by the shareholders of the Company of (a) any consolidation or merger of the Company in which the Company is not the continuing or surviving corporation or pursuant to which shares of stock of the

 


 

Company would be converted into cash, securities or other property, other than a consolidation or merger of the Company in which the common shareholders of the Company immediately prior to the consolidation or merger have substantially the same proportionate ownership of common stock of the surviving corporation immediately after the consolidation or merger as immediately before, or (b) any consolidation or merger in which the Company is the continuing or surviving corporation but in which the common shareholders of the Company immediately prior to the consolidation or merger do not hold at least a majority of the outstanding common stock of the continuing or surviving corporation (except where such holders of Common Stock hold at least a majority of the common stock of the corporation which owns all of the Common Stock of the Company), or (c) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all the assets of the Company, or (iii) individuals who constitute the Board on January 1, 2007 (the “Incumbent Board”) have ceased for any reason to constitute at least a majority thereof, provided that any person becoming a director subsequent to January 1, 2007 whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at least three-quarters (3/4) of the directors comprising the Incumbent Board (either by specific vote or by approval of the proxy statement of the Company in which such person is named as nominee for director without objection to such nomination) shall be, for purposes of this Plan, considered as though such person were a member of the Incumbent Board.
     (g)  “Change in Ownership” means a change which results directly or indirectly in the Company’s Common Stock ceasing to be actively traded on a national securities exchange or the National Association of Securities Dealers Automated Quotation System.
     (h)  “Code” means the Internal Revenue Code of 1986, and the rules, regulations and interpretations promulgated thereunder, as amended from time to time.
     (i)  “Committee” means the Compensation Committee of the Board, or such other committee designated by the Board as authorized to administer this Plan with respect to At Risk Awards. The Committee shall consist of not less than two members, each of whom shall be “outside directors” as defined by Section 162(m) of the Code and the rules, regulations and interpretations promulgated thereunder, as amended from time to time.
     (j)  “Common Stock” means the common stock of the Company.
     (k)  “Company” means National Fuel Gas Company.
     (l)  “Eligible Employee” means those employees of the Company or its Subsidiaries who are expected to constitute “covered employees” within the meaning of Section 162(m) of the Code for the applicable fiscal year(s), and any other key management employee to whom an At Risk Award has been granted by the Committee.
     (m)  “Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time.

2


 

     (n)  “Good Reason” means a good faith determination made by a Participant that there has been any (i) material change by the Company of the Participant’s functions, duties or responsibilities which change could cause the Participant’s position with the Company to become of less dignity, responsibility, importance, prestige or scope, including, without limitation, the assignment to the Participant of duties and responsibilities inconsistent with his positions, (ii) assignment or reassignment by the Company of the Participant without the Participant’s consent, to another place of employment more than 30 miles from the Participant’s current place of employment, or (iii) reduction in the Participant’s total compensation or benefits or any component thereof, provided in each case that the Participant shall specify the event relied upon for such determination by written notice to the Board at any time within six months after the occurrence of such event.
     (o)  “Participant” means any individual who is holding an At Risk Award granted by the Committee under this Plan.
     (p)  “Performance Period” means the period established by the Committee in the Award Notice, for measurement of the extent to which a Performance Goal has been satisfied.
     (q)  “Performance Goal” means the performance objectives of earnings per share, Subsidiary net income and customer service/other goals, established by the Committee for each Eligible Employee who receives an At Risk Award.
     (r)  “Plan” means this Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Plan, as amended from time to time. Any reference in this Plan to a paragraph number refers to that portion of this Plan.
     (s)  “Subsidiary” means a corporation or other business entity in which the Company directly or indirectly has an ownership interest of eighty percent (80%) or more.
2. Administration
     With respect to At Risk Awards the Committee is given full authority to (a) make reasonable, good faith interpretations of this Plan and of Section 162(m) of the Code, to the extent not addressed by regulation, proposed regulation or publicly available interpretation of the Internal Revenue Service; (b) determine who shall be Eligible Employees and select Eligible Employees to receive At Risk Awards; (c) determine all the other terms and conditions of an At Risk Award, including the time or times of making At Risk Awards to Eligible Employees, the Performance Period, Performance Goals, and levels of At Risk Awards to be earned in relation to levels of achievement of the Performance Goals, and such other measures as may be necessary or desirable to achieve the purposes of this Plan; (d) determine whether At Risk Awards are to be granted singly, in combination or in the alternative with other Awards under any other Company benefit plans; (e) grant waivers of Plan terms and conditions, provided that any such waiver shall not be inconsistent with Section 162(m) of the Code and the rules,

3


 

regulations and interpretations promulgated thereunder, as amended from time to time; and (f) accelerate the vesting, exercise or payment of any At Risk Award or the Performance Period of an At Risk Award when any such action would not cause compensation paid or payable under such At Risk Award to cease to be deductible by the Company for federal income tax purposes. The Committee shall also have the authority to grant At Risk Awards in replacement of Awards previously granted under this Plan or awards under any other executive compensation or stock option plan of the Company or a Subsidiary.
     All determinations of the Committee shall be made by a majority of its members, and its determinations shall be final, binding and conclusive. The Committee, in its discretion, may delegate its authority and duties under this Plan with respect to At Risk Awards to the Company’s Chief Executive Officer or to other senior officers of the Company, but only to the extent, if any, permitted by Section 162(m) of the Code and notwithstanding any other provision of this Plan or an Award Notice, under such conditions as the Committee may establish. For the avoidance of doubt, neither the Committee nor any delegate thereof shall take any action under this Plan, including without limitation pursuant to this paragraph 2 or paragraphs 6 or 7, which would result in the imposition of an additional tax under section 409A of the Code on the Eligible Employee holding an At Risk Award granted hereunder.
3. Grant of At Risk Awards
     At Risk Awards may be made to any Eligible Employee for each of the fiscal years of the Company commencing with the 2007 fiscal year; provided, however, that At Risk Awards for a fiscal year may only be made within the time allowed under Section 162(m) of the Code and the rules, regulations and interpretations promulgated thereunder, as amended from time to time, applicable to such fiscal year. At Risk Awards are made by means of an Award Notice.
4. Payment of at Risk Awards
     Each At Risk Award granted to a Participant shall entitle such Participant to receive a cash payment based upon the extent to which such Participant’s Performance Goals for a particular Performance Period are attained, as specified by the Committee in the Award Notice and certified in writing by the Committee that such Participant’s Performance Goals have been attained. Payment of earned At Risk Awards shall be made in cash promptly after such certification. The Company shall be entitled to deduct from any payment under this Plan the amount of all applicable income and employment taxes required by law to be withheld with respect to such payment or may require the participant to pay to it such tax prior to and as a condition of the making of such payment.
5. Termination of Employment, Retirement, or Death of Participant
     (a)  General Rule. If a Participant’s employment with the Company or a Subsidiary

4


 

terminates for a reason other than death, disability, retirement, or an approved reason, all unearned or unpaid At Risk Awards shall be canceled or forfeited as the case may be, unless otherwise provided in this Section or in the Eligible Employee’s Award Notice. The Committee shall have the authority to promulgate rules and regulations to (i) determine what events constitute disability, retirement, or termination for an approved reason for purposes of the Plan, and (ii) determine the treatment of a Participant under this Plan in the event of his death, disability, retirement, or termination for an approved reason.
     (b) In the event of the disability, retirement or termination for an approved reason of a Participant during a Performance Period, his participation shall be deemed to continue to the end of the Performance Period, and subject to and based upon the extent to which such Participant’s Performance Goals for such Performance Period are attained (as specified by the Committee in the Award Notice and certified in writing by the Committee), he shall be paid a percentage of the amount earned, if any, according to the terms of the At Risk Award, proportionate to his period of active service during that Performance Period.
     (c) In the event of the death of a Participant during a Performance Period, the Participant’s designated beneficiary (or if none, then the Participant’s estate) shall be paid an amount proportionate to the period of active service during the Performance Period, based upon the maximum amount which could have been earned under the At Risk Award.
6. Amendments to at Risk Awards
     The Committee may, at any time, unilaterally amend any unearned or unpaid At Risk Award, including At Risk Awards earned but not yet paid, to the extent it deems appropriate; provided, however, that any such amendment which is adverse to the Participant shall require the Participant’s consent; and provided further, however, that the Committee shall have no authority to make any amendment which would cause compensation paid or payable under the At Risk Award to cease to be deductible by the Company for federal income tax purposes.
7. Amendment to Plan
     Subject to the shareholder approval requirements of Section 162(m) of the Code, the Committee may, from time to time, amend this Plan in any manner.
8. Change in Control and Change in Ownership
     (a) Background. All Participants shall be eligible for the treatment afforded by this paragraph 8 if there is a Change in Ownership or if their employment terminates within three years following a Change in Control, unless the termination is due to (i) death; (ii) disability entitling the Participant to benefits under his employer’s long-term disability plan; (iii) Cause; (iv) resignation by the Participant other than for Good Reason; or (v)

5


 

retirement entitling the Participant to benefits under his employer’s retirement plan.
     (b)  Vesting. If a Participant is eligible for treatment under this paragraph 8, the provisions of this paragraph shall determine the manner in which such At Risk Award shall be paid to him. For purposes of making such payment, each “current performance period” (defined to mean a Performance Period which period has commenced but not yet ended), shall be treated as terminating upon the Acceleration Date, and for each such “current performance period” and each “completed performance period” (defined to mean a Performance Period which has ended but for which the Committee has not, on the Acceleration Date, made a determination as to whether and to what degree the Performance Goals for such period have been attained), it shall be assumed that the Performance Goals have been attained at a level of 100% or the equivalent thereof. If the Participant is participating in one or more “current performance periods,” he shall be considered to have earned and, therefore, to be entitled to receive, a prorated portion of the At Risk Awards previously granted to him for each such Performance Period. Such prorated portion shall be determined by multiplying 100% of the At Risk Award granted to the Participant by a fraction, the numerator of which is the total number of whole and partial years (with each partial year being treated as a whole year) that have elapsed since the beginning of the Performance Period, and the denominator of which is the total number of years in such Performance Period. A Participant in one or more “completed performance periods” shall be considered to have earned and, therefore, be entitled to receive 100% of the At Risk Awards previously granted to him during each Performance Period.
     (c)  Payment of Awards. If a Participant is eligible for treatment under this paragraph 8, whether or not he is still employed by the Company or a Subsidiary, he shall be paid, in a single lump sum cash payment, as soon as practicable but in no event later than 90 days after the Acceleration Date, for all outstanding At Risk Awards.
     (d)  Miscellaneous. Upon a Change in Control or a Change in Ownership, (i) the provisions of paragraphs 5 and 9 hereof shall become null and void and of no force and effect insofar as they apply to a Participant who has been terminated under the conditions described in (a) above; and (ii) no action shall be taken which would affect the rights of any Participant or the operation of this Plan with respect to any At Risk Award to which the Participant may have become entitled hereunder on or prior to the date of the Change in Control or Change in Ownership or to which he may become entitled as a result of such Change in Control or Change in Ownership.
     (e)  Legal Fees. The Company shall pay all legal fees and related expenses incurred by a Participant in seeking to obtain or enforce any payment, benefit or right he may be entitled to under the Plan after a Change in Control or Change in Ownership; provided, however, the Participant shall be required to repay any such amounts to the Company to the extent a court of competent jurisdiction issues a final and non-appealable order setting forth the determination that the position taken by the Participant was frivolous or advanced in bad faith.

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9. Noncompetition Provision
     Notwithstanding anything contained in this Plan to the contrary, unless the Award Notice specifies otherwise, a Participant shall forfeit all unearned, and/or unpaid At Risk Awards, including At Risk Awards earned but not yet paid, and all interest, if any, accrued on the foregoing if, (i) in the opinion of the Committee, the Participant, without the written consent of the Company, engages directly or indirectly in any manner or capacity as principal, agent, partner, officer, director, employee, or otherwise, in any business or activity competitive with the business conducted by the Company or any Subsidiary; or (ii) the Participant performs any act or engages in any activity which in the opinion of the Committee is inimical to the best interests of the Company.
10. Nonassignability
     No Award under this Plan shall be subject in any manner to alienation, anticipation, sale, transfer (except by will or the laws of descent and distribution or pursuant to a domestic relations court order), assignment, pledge, or encumbrance. Following an approved transfer, any such Award shall continue to be subject to the same terms and conditions as were applicable immediately prior to transfer, and except as provided in the next sentence, the term “Participant” shall be deemed to refer to the transferee. The events of termination of employment of paragraph 5 shall continue to be applied with reference to the original Participant and following the termination of employment of the original Participant, the transferred Award shall be payable to the transferee only to the extent, and for the periods specified in paragraph 5, that the original Participant could have received payment of such Award. Except as expressly permitted by this paragraph, an Award shall be payable during the Participant’s lifetime only to him.
11. No Right to Continued Employment or Grants
     Participation in this Plan shall not give any Participant any right to remain in the employ of the Company or any Subsidiary. The Company or, in the case of employment with a Subsidiary, the Subsidiary, reserves the right to terminate any Participant at any time. Further, the adoption of this Plan shall not be deemed to give any person any right to be selected as a Participant or to be granted an Award.
12. No Right, Title or Interest in Company Assets
     To the extent any person acquires a right to receive payments from the Company under this Plan, such rights shall be no greater than the rights of an unsecured creditor of the Company.
13. Savings Provision
     This Plan is intended to comply with all the applicable conditions of Section 162(m) of the Code, so that compensation paid or payable hereunder shall constitute qualified “performance-based compensation” thereunder. To the extent any provision of this Plan

7


 

or any action by the Committee fails to so comply, it shall be deemed null and void, to the extent permitted by law.
14. Effective Date
     Upon approval by the shareholders of the Company as required by Section 162(m) of the Code, this Plan shall become effective as of December 7, 2006. This Plan was amended and restated effective as of September 24, 2008. The modifications made to the Plan by virtue of such amendment and restatement did not require approval by the shareholders of the Company under Section 162(m).

8

Exhibit 10.4
NATIONAL FUEL GAS COMPANY
EXECUTIVE ANNUAL CASH INCENTIVE PROGRAM
     NATIONAL FUEL GAS COMPANY (the “ Company ”) hereby establishes this NATIONAL FUEL GAS COMPANY EXECUTIVE ANNUAL CASH INCENTIVE PROGRAM (the “ Program ”) as of this 1st day of October, 2008, in accordance with the terms provided herein.
      Section 1. Incentive Program Purpose . The purposes of the Program are to enable the Company and its majority-owned subsidiaries (the “ Subsidiaries ”) to attract, retain, motivate and reward officers and key employees by providing them with short-term incentive opportunities directly linked to the Company’s and the individual’s performance.
      Section 2. Eligibility . Except for those executive officers who are participating for the same period in the National Fuel Gas Company Annual At Risk Compensation Incentive Plan, each officer of the Company and its Subsidiaries who has been designated by the Board as an “executive officer” for purposes of the Securities Exchange Act of 1934, as amended, shall participate in this Program (each, an “Executive Participant” ). In addition, the Chief Executive Officer of the Company (the “ CEO ”), at his sole discretion, may select other officers or key employees of the Company and its Subsidiaries to participate in the Program (each, a “ Designated Participant ”).
      Section 3. Performance Periods and Target Incentives . With respect to each Executive Participant and each Designated Participant (each, a “Participant” ), the CEO shall establish a target incentive opportunity (the “ Target Incentive ”) applicable to such Participant with respect to any Performance Period, which shall be a percentage of base salary; provided that, the Target Incentive with respect to each Executive Participant shall be subject to the approval of the Compensation Committee of the Company of the Board of Directors (the “Committee”). A “ Performance Period ” shall be the then-current fiscal year of the Company. In the event that an employee becomes an officer or an executive officer after the commencement of any Performance Period (including by reason of having first been hired after the commencement of the Performance Period), the CEO shall determine the basis, if any, on which such person shall be permitted to participate in the Program for such Performance Period (including, but not limited to, whether the Participant’s Target Incentive will be pro-rated to reflect his or her eligibility for only a portion of the Performance Period).
      Section 4. Performance Conditions and Performance Levels .
     (a)  Establishment of Performance Conditions . No later than ninety days following the beginning of the Performance Period, the CEO shall establish the performance objectives (the “ Performance Conditions ”) which must be achieved for a Participant to receive payment in respect of his or her Target Incentive (or a specified multiple thereof) for that Performance Period; provided that the Performance Conditions and the levels of achievement for an Executive Participant shall be approved by the Committee. The Performance Conditions may be based on the performance of the Company or one or more of its Subsidiaries, either on an absolute or comparative basis, and/or upon individual performance criteria established for the Participant or a class of Participants. The Performance Conditions need not be the same for each Participant, or for the same Participant with respect to different Performance Periods. Where more than one

 


 

Performance Condition is established, the Performance Conditions shall allocate the Target Incentive among the Performance Conditions, provided that, for this purpose, multiple Performance Conditions may be combined and treated as a single Performance Condition. At least seventy-five percent (75%) of a Participant’s Target Incentive will be dependent on objective Performance Conditions. Twenty-five percent (25%) of a Participant’s Target Incentive may be designated as discretionary.
     (b)  Threshold, Target and Maximum Performance Levels . With respect to each Performance Period, the CEO shall establish, at a minimum, a threshold level of performance (or the portion thereof allocable to a particular Performance Condition or Conditions (the “Allocable Portion” )) at which 100% of the Target Incentive shall be payable and a maximum level of performance at which 200% of the Target Incentive will be payable, subject in each case to the CEO’s discretion to reduce the amount payable to any Participant based on such factors as the CEO shall determine. For performance levels between two established performance levels, the percent of Target Incentive (or any Allocable Portion) payable will be determined by mathematical interpolation, where appropriate.
      Section 5. Performance Achievement . Payment of any compensation under the Program is expressly contingent upon achievement, in whole or in part, of the Performance Conditions for such Performance Period. The amount payable to a Participant with respect to his or her Target Incentive (or the Allocable Portion) with respect to any Performance Conditions will be determined based on the assessment of achievement against such Performance Conditions with respect to such Performance Period. To the extent that any Performance Condition is based on the individual performance of a Participant that is not otherwise objectively determinable by application of a formula or other mathematical or statistical measure, the level of achievement of such Performance Condition shall be determined based on the CEO’s subjective determination of the individual’s performance.
      Section 6. Payment of Cash . Except as provided in Section 8, any amount payable to a Participant in respect of any Performance Period shall be paid to the Participant (or, where applicable, the Participant’s beneficiary or legal representative) in a single lump sum cash amount not later than 2 1 / 2 months after the end of the calendar year in which the relevant Performance Period ends.
      Section 7. Employment Conditions to Payment .
     (a)  Full Award Requires Service for Entire Performance Period. To be entitled to payment in full of any amount payable in respect of any Target Incentive, a Participant must be in the continuous employ of the Company or a Subsidiary from the date he or she is selected as a Participant through the last day of the applicable Performance Period. Except as provided in Section 7(b), if a Participant’s employment terminates for any reason during a Performance Period (including, but not limited to, the Participant’s voluntary resignation), such Participant shall be entitled to receive payment of the amount, if any, determined pursuant to Section 7(c).
     (b)  Termination for Cause or Termination Before Six Months of the Performance Period Have Passed. If a Participant’s employment is terminated (i) for “Cause” at any time prior

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to payment of any amount in respect of any Target Incentive under Section 6, or (ii) for any other reason and fewer than six months of the Performance Period have passed, then such Participant shall forfeit any right to receive any payment in respect of his or her Target Incentive for that Performance Period (regardless of whether the Performance Period shall have been completed and an amount would otherwise have been payable to the Participant in respect of his or her Target Incentive). For purposes of this Plan, the term “ Cause ” means ( i ) the Participant’s failure to follow or comply with a reasonable and lawful written directive of the Board of Directors or the CEO, ( ii ) the Participant’s failure to perform the substantial responsibilities of his or her position, ( iii ) any act of dishonesty, gross negligence, or misconduct by the Participant, including any violation of a material Company policy or breach of fiduciary duty owed by the Participant to the Company (even if no harm results from such act), ( iv ) the Participant’s conviction of or entering a plea of guilty or nolo contendere to a crime constituting a felony or the Participant’s willful violation of any law, rule or regulation, or (v) the Participant engages in, or is interested in, (as owner, partner, shareholder, employee, director, agent, consultant or otherwise), any business which is a “competitor” of the Company. “Competitor” of the Company is any corporation, sole proprietorship, partnership, joint venture, syndicate, trust or any other form of organization or parent, subsidiary or division of any of the foregoing, which is engaged in the transportation, purchase, brokering, marketing or trading of natural gas or other energy products or services which are competitive to the Company’s products or services, any of which is engaged in within 50 miles of the geographic area in which the Company is engaged in such competitive business, provided that a present or future investment in the securities of companies listed on a national securities exchange or traded on the over-the-counter market to the extent such investments do not exceed 2% of the total outstanding shares of such company will not constitute engagement or interest in a “competitor.”
     (c)  Termination for Any Other Reason and the Passing of Six or More Months of the Performance Period . Subject to the last sentence of this Section 7(c), if a Participant’s employment terminates during a Performance Period for any reason other than Cause and six or more months of the Performance Period have passed, the amount payable to the Participant in respect of the Participant’s Target Incentive for any Performance Period shall be equal to the product of ( x ) the amount that would have been payable in respect of the Participant’s Target Incentive had such Participant been employed for the entire Performance Period (as determined in accordance with Section 5 based on the CEO’s assessment of the achievement of the Performance Conditions for the Performance Period) multiplied by ( y ) the Participant’s Pro-Rata Fraction. With respect to any Participant, the “ Pro-Rata Fraction ” is a fraction, the numerator of which is the number of days in the Performance Period completed prior to and including the date of Participant’s termination of employment, and the denominator of which is the total number of days in the Performance Period. To the extent a Participant becomes entitled to receive any payment as provided in this Section 7(c), such payment shall be made not later than 2 1 / 2 months after the end of the calendar year in which the relevant Performance Period ends. Any payment to a Participant pursuant to this Section 7(c) shall be subject to the CEO’s discretion described in Section 4(b), as well as such terms and conditions (including, but not limited to, the execution of a release and/or certain restrictive covenants in favor of the Company) as the CEO shall determine not later than the date of such Participant’s termination of employment.

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      Section 8. Change of Control . In the event of a Change of Control, all then in progress Performance Periods shall be deemed to have ended as of the end of the last fiscal quarter of the Company ended prior to the occurrence of such Change of Control and the rights of each Participant to receive payment in respect of any outstanding Target Incentive shall be determined in the following manner: ( i ) the Performance Period shall be deemed to have ended as of the end of the fiscal quarter ended coincident with or immediately prior to the occurrence of such Change of Control; ( ii ) the CEO, as determined immediately prior to such Change of Control, shall certify the amount payable with respect to each Target Incentive based on achievement of the Performance Conditions through the end of the truncated Performance Period, but annualizing the performance for the then current fiscal year and subject to such other adjustments, if any, specified by the Committee at the time such Performance Conditions are first established; and ( iii ) the amount payable to each Participant shall be equal to the product of ( A ) the amount determined pursuant to subclause (ii) and ( B ) a fraction, the numerator of which is the number of days in the Performance Period completed prior to, and including, the Change of Control and the denominator of which is the total number of days in the Performance Period.
     For purposes of this Plan, a “Change in Control” shall mean:
     (i) either ( a ) receipt by the Company of a report on Schedule 13D, or an amendment to such a report, filed with the Securities and Exchange Commission (the “ SEC ”) pursuant to Section 13(d) of the 1934 Act disclosing that any person (as such term is used in Section 13(d) of the 1934 Act) (“ Person ”), is the beneficial owner, directly or indirectly, of twenty (20) percent or more of the outstanding stock of the Company or ( b ) actual knowledge by the Company of facts, on the basis of which any Person is required to file such a report on Schedule 13D, or to make an amendment to such a report, with the SEC (or would be required to file such a report or amendment upon the lapse of the applicable period of time specified in Section 13(d) of the 1934 Act) disclosing that such Person is the beneficial owner, directly or indirectly, of twenty (20) percent or more of the outstanding stock of the Company;
     (ii) purchase by any Person, other than the Company, a Subsidiary or any employee benefit plan of the Company or any Subsidiary, of shares pursuant to a tender or exchange offer to acquire any stock of the Company (or securities convertible into stock) for cash, securities or any other consideration, provided that, after consummation of the offer, such Person is the beneficial owner (as defined in Rule 13d-3 under the 1934 Act), directly or indirectly, of twenty (20) percent or more of the outstanding stock of the Company (calculated as provided in paragraph (d) of Rule 13d-3 under the 1934 Act in the case of rights to acquire stock);
     (iii) consummation of ( a ) any consolidation or merger of the Company in which the Company is not the continuing or surviving corporation or pursuant to which shares of stock of the Company would be converted into cash, securities or other property, other than a consolidation or merger of the Company in which holders of its stock immediately prior to the consolidation or merger have substantially the same proportionate ownership of common stock of the surviving corporation immediately after the consolidation or merger as immediately before, or ( b ) any consolidation or merger in which the Company is the continuing or surviving corporation but in which the common shareholders of the Company

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immediately prior to the consolidation or merger do not hold at least a majority of the outstanding common stock of the continuing or surviving corporation (except where such holders of common stock hold at least a majority of the common stock of the corporation which owns all of the common stock of the Company), or ( c ) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all the assets of the Company; or
     (iv) a change in the majority of the members of the Board of Directors within a 24-month period unless the election or nomination for election by the Company’s shareholders of each new director was approved by the vote of at least two-thirds of the directors then still in office who were in office at the beginning of the 24-month period.
      Section 9. Administration . The CEO (or such other officer or officers to whom the CEO shall delegate such responsibility (each, a “Delegate” )) shall administer and interpret the Plan. The CEO shall establish the Performance Conditions for any Performance Period in accordance with Section 4 and determine whether such Performance Conditions have been obtained with respect to such Performance Period in accordance with Section 5. Any determination made by the CEO under the Plan shall be final and conclusive. The CEO (or any Delegate) may employ such legal counsel, consultants and agents (including counsel or agents who are employees of the Company or a Subsidiary) as it may deem desirable for the administration of the Plan and may rely upon any opinion received from any such counsel or consultant or agent and any computation received from such consultant or agent. All expenses incurred in the administration of the Plan, including, without limitation, for the engagement of any counsel, consultant or agent, shall be paid by the Company. Neither the CEO nor any Delegate shall be liable for any action or determination made in good faith under the Program or with respect to any Target Incentive awarded or payable thereunder.
      Section 10. Nonassignment . A Participant shall not be permitted to assign, alienate or otherwise transfer any interest in his or her Target Incentive and any attempt to do so shall be void. A Participant’s interests under this Plan shall not be subject to garnishment or execution or levy of any kind, and any attempt to cause any benefits to be so subjected shall not be recognized. This Plan shall be an unfunded plan and a Participant shall have only the rights of a general creditor of the Company with respect to such Participant’s interest under this Plan.
      Section 11. Impact on Benefit Plans . Payments under the Program shall be considered as earnings for purposes of any of the Company’s employee benefit plans, programs or arrangements, including, but not limited to, its qualified retirement plans or non-qualified retirement plans or for any other retirement or benefit plan, unless otherwise excluded under the terms of any such plan. Nothing herein shall prevent the Company from maintaining additional compensation plans and arrangements, provided however that no payments shall be made under such plans and arrangements if the effect thereof would be the payment of compensation otherwise payable under this Program regardless of whether the applicable Performance Condition was attained.
      Section 12. Successors . The obligation of the Company under the Program shall be binding upon the successors and assigns of the Company.

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      Section 13. Applicable Law . This Program shall be governed by and construed under the laws of the State of New York without regard to its conflict of law provisions.
      Section 14. Severability . In the event that any one or more of the provisions of this Program shall be held to be invalid, illegal or unenforceable, the validity, legality or enforceability of the remaining provisions shall not in any way be affected or impaired thereby.
      Section 15. Tax Withholding . The Company shall have the power to withhold from any amount payable hereunder an amount sufficient to satisfy federal, state and local or non-U.S. withholding tax requirements on any amount payable under this Program.
      Section 16. No Voluntary Election to Defer . Unless and to the extent expressly permitted by the Company on such terms and conditions as it shall deem necessary or appropriate, no amount payable under the Program may be electively deferred by a Participant past the date as of which such amount would otherwise be paid hereunder. Notwithstanding the foregoing, the Company may defer payment of any amount payable in respect of any Target Incentive if and to the extent such payment would, if made at the time otherwise required under the Program, not be deductible by the Company or any Subsidiary by reason of Section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”). Notwithstanding anything in this Program to the contrary, any deferral of payment permitted or required in accordance with this Section 16 shall at all times comply with the applicable provisions of Section 409A of the Code and all determinations with respect thereto shall be made in a manner intended to avoid the imposition on any Participant of the additional taxes set forth in such Section 409A.
      Section 17. No Guarantee of Employment . Nothing in this Plan shall interfere with or limit in any way the right of the Company or a Subsidiary to terminate any Participant’s employment at any time, nor confer upon any Participant any right to continue in the employ of the Company or a Subsidiary.
      Section 18. Headings . The descriptive headings of the Sections of this Program are inserted for convenience of reference only and shall not constitute a part of this Program. Except when otherwise indicated by the context, the singular shall be read and interpreted as the plural (when appropriate), and the plural shall include the singular.
      Section 19. Amendment or Termination of this Program . This Program may be amended, suspended or terminated by the Company at any time upon approval by the Compensation Committee of the Board of Directors (or such other committee of that the Board shall authorize to take such action). Notwithstanding the foregoing, no amendment, suspension or termination shall adversely affect a Participant’s rights with respect to any Target Incentive previously established, except as provided herein.

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Exhibit 10.5
NATIONAL FUEL GAS COMPANY
AND PARTICIPATING SUBSIDIARIES
EXECUTIVE RETIREMENT PLAN
Amended and Restated as of September 20, 2007
Further Amended and Restated as of September 24, 2008

 


 

TABLE OF CONTENTS
         
ARTICLE   PAGE NO.
ARTICLE 1 Purpose
      1
 
ARTICLE 2 Definitions
      1
 
ARTICLE 3 Determination of Retirement Benefits
      7
 
ARTICLE 4 Vesting; Forfeiture
      11
 
ARTICLE 5 Form of Payment of Benefits
      12
 
ARTICLE 6 Source of Payment
      18
 
ARTICLE 7 Administration of the Plan
      18
 
ARTICLE 8 Amendment and Termination
      20
 
ARTICLE 9 General Provisions
      20

 


 

ARTICLE 1
PURPOSE
     1.1 National Fuel Gas Company established this National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan effective as of February 19, 1987 for the purpose of attracting and retaining executives, and for these additional purposes: ( 1 ) to provide retirement benefits to eligible employees in addition to basic retirement benefits provided them under the National Fuel Gas Company Retirement Plan as it may be amended and restated; ( 2 ) to provide retirement benefits to such employees to make up for benefit reductions, if any, under the National Fuel Gas Company Retirement Plan caused by participation in the National Fuel Gas Company Deferred Compensation Plan, as it may be amended and restated; ( 3 ) to provide retirement benefits to such employees without regard to the $200,000 limit on qualified plans’ covered compensation that became effective respecting the National Fuel Gas Company Retirement Plan effective July 1, 1989 (and as that limit may change from time to time); and ( 4 ) to provide to such employees benefits which would have been payable from the tax-exempt trust under the National Fuel Gas Company Retirement Plan but for the limitations placed by Section 415 of the Code on benefits payable and contributions made with respect to such employees under such plans.
     1.2 The National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan is intended to constitute an unfunded deferred compensation plan under Section 201(2) of the Act and the Company’s obligation to pay benefits hereunder, if any, is unfunded and unsecured.
     1.3 The National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan has been amended to comply with the requirements of Section 409A of the Code.
ARTICLE 2
DEFINITIONS
     When used herein, the following terms shall have the following meanings:
     2.1 Act means the Employee Retirement Income Security Act of 1974, as amended from time to time.
     2.2 Annual Cash Compensation with respect to any Member shall include the following:

 


 

     (i) The Member’s base salary, whether or not the receipt of a portion thereof has been deferred;
     (ii) The Member’s compensation (whether or not the receipt of all or a portion thereof has been deferred) under National Fuel Gas Company’s short-term annual incentive program, known as the Annual At Risk Compensation Incentive Program (“ AARCIP ”) or any successor program thereto; and
     (iii) The Member’s other performance-related lump sum compensation (i.e. lump sum payments other than expense or tuition reimbursements, moving expense reimbursements, lump sum payments for eligible unused vacation, worker’s compensation payments, award payments for suggestions, severance payments or any other non-performance related lump sum payments) made on or after August 1, 1997.
The Member’s Annual Cash Compensation shall also exclude all commissions, stock, option or SAR awards, restricted stock awards, special allowances, supplemental compensation, any payment under the National Fuel Gas Company Performance Incentive Program and any other extra compensation or incentives or bonuses not expressly included in Annual Cash Compensation pursuant to the foregoing provisions of this Section 2.2.
     2.3 Basic Pension Plan means the National Fuel Gas Company Retirement Plan, as amended and restated from time to time.
     2.4 Basic Pension Plan Benefit means the benefit, stated as a monthly annuity for the Member’s life, commencing at the Member’s Normal Retirement Date, under which the annual payments shall equal the Benefit Base as determined under the Basic Pension Plan, taking into account the effect, if any, of the Benefit Limitations and the fact that deferrals under the National Fuel Gas Company Deferred Compensation Plan are excluded from the definition of Final Average Pay under the Basic Pension Plan.
     2.5 Beneficiary means the person or persons entitled to receive the amount, if any, payable under the Plan upon the death of a Member or retired Member in the Plan in accordance with the form of benefit distribution selected by the Member pursuant to Sections 5.2 and 5.3.
     2.6 Benefit Limitations means ( i ) the maximum “annual benefit” payable under the Basic Pension Plan in accordance with Section 415 of the Code and the implementing provisions of the Basic Pension Plan (as they operate in conjunction with the relevant provisions of other Company employee benefit plans), and ( ii ) the maximum amount of annual compensation of an employee that may be taken into account under the Basic Pension Plan in accordance with Section 401(a)(17) of the Code, as amended and supplemented, and the implementing provisions of the Basic Pension Plan.

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     2.7 Board of Directors means the Board of Directors of National Fuel Gas Company.
     2.8 Code means the Internal Revenue Code of 1986, as amended from time to time.
     2.9 Committee means the committee appointed from time to time by the Board of Directors to administer the Plan.
     2.10 Company means National Fuel Gas Company and each of the following subsidiaries, which participate in the Plan: National Fuel Gas Distribution Corporation, National Fuel Gas Supply Corporation, Seneca Resources Corporation, National Fuel Resources Inc., Penn-York Energy Corporation, Empire Exploration, Inc. and Horizon Energy Development, Inc., each of which has adopted or has indicated that it will adopt the Plan.
     2.11 Early Retirement Date shall be the Retirement Date selected by the Member that is no earlier than the first day of the calendar month immediately following or coinciding with the Member’s 55th birthday, or any first of a month thereafter, but prior to the Member’s Normal Retirement Date, provided the Member is Vested in either or both the Top-Hat Benefit or the Supplemental Benefit.
     2.12 Employment Year is the consecutive 12-month period commencing on the date on which the Member commenced employment with a Company, and each subsequent 12-month period commencing on each anniversary thereof.
     2.13 Final Average Pay means an amount equal to the average of the Annual Cash Compensation payable by the Company to a Member for the 60 consecutive month period during the 120 consecutive month period immediately preceding the date the Member retires which results in the Member receiving the highest average. If an AARCIP or other annual performance bonus is granted following the Member’s retirement date, unless such payment is expressly excluded from consideration in the computation of the Member’s benefits, that award shall be used in determining the Member’s Final Average Pay, if it is payable in connection with employment periods included in the 60-month period referred to above. In this event, the Member’s Retirement Benefits shall be increased, once the effect of such award is determined, and the increase shall be made retroactive to the Member’s Retirement Date, without interest (provided that no such retroactive application shall have the effect of accelerating the date at which Retirement Benefits shall commence to be paid in accordance with Section 5.2).
     Notwithstanding the preceding paragraph of this Section 2.13, if any such post retirement AARCIP award included in the definition of Annual Cash Compensation is used in determining Final Average Pay hereunder, AARCIP awards relating to no more

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than five of National Fuel Gas Company’s fiscal years may be used in determining Final Average Pay. An example of the effect of this provision is as follows. Assume that a Member retires on October 1, 2006, and that his salary and AARCIP awards were as follows for the following calendar year:
                 
            AARCIP Award (relating to
            fiscal year ending September
    Salary   30 but paid in December)
2001
  $ 480,000     $ 120,000  
2002
  $ 540,000     $ 150,000  
2003
  $ 600,000     $ 180,000  
2004
  $ 660,000     $ 210,000  
2005
  $ 780,000     $ 240,000  
2006
  $ 840,000     $ 270,000  
     This Member’s Final Average Pay would be $876,000 computed as follows:
[9/12 ($840,000) + 12/12 ($780,000) + 12/12 ($660,000) + 12/12 ($600,000) + 12/12 ($540,000) + 3/12 ($480,000) + $270,000 + $240,000 + $210,000 + $180,000 + $150,000] ÷ 5.
     2.14 409A Election Date means December 31, 2007 or such other date as the Company shall determine to be the latest date that benefits payable under the Plan may commence to be paid based on the Member’s election as to the form and timing of payment in respect of his or her benefits payable under the Basic Pension Plan without violating the election requirements applicable under Section 409A of the Code and any regulations, proposed regulations or other guidance promulgated thereunder.
     2.15 Future Supplemental Benefit means the portion of a Member’s Supplemental Benefit attributable to services rendered to the Company during any calendar year, or portion thereof, following the calendar year in which the Member first became eligible to commence participation in the Plan.
     2.16 Member means any person employed by a Company who is designated as a Member by the Chief Executive Officer of National Fuel Gas Company.
     2.17 Normal Retirement Date is the first day of the month coinciding with or immediately following the Member’s 65th birthday.
     2.18 Past Service Supplemental Benefit means the portion of a Member’s Supplemental Benefits attributable to services rendered to the Company during any calendar year, or portion thereof, prior to and including the year in which such Member commences participation in the Plan.

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     2.19 Plan means the National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as set forth herein and as amended and restated from time to time.
     2.20 Retirement Benefits means the benefits payable under this Plan.
     2.21 Retirement Date is the date with respect to which payment of Retirement Benefits under the Plan commence (which for this purpose shall be determined without regard to any six-month delay pursuant to Section 5.1 hereof).
     2.22 Social Security Benefit means the annual amount estimated by the Committee to be payable to a Member under the Social Security Act of 1935, as amended, at the Member’s Retirement Date, calculated on the assumption that the Member will not receive any future wages that would be treated as such for purposes of that act. If a Member’s Retirement Date precedes his attainment of age 62, the amount estimated to be payable to the Member at age 62 (without assuming any cost of living increases) shall be reduced as follows. The percentage early retirement factor applicable at age 62 (e.g., 80%) shall be further reduced by .75% per month for the first 24 months, and by .5% per month for the remaining months, if any, by which the Member’s Retirement Date precedes his attainment of age 62. The Social Security Benefit, once calculated, will be frozen as of the Member’s Retirement Date. For example, assume that the Member retired on his 59th birthday, and that his estimated Social Security benefit beginning at age 65 (Primary Insurance Amount) was $15,912 per annum. Using current Social Security tables, his age 62 early retirement factor (80%) would be further reduced to 56%. This Member’s Social Security Benefit would therefore equal $8,910.72.
     2.23 Social Security Offset means, in respect of a Member’s Supplemental Benefit, the product of ( i ) .0125 times the Member’s Years of Service times ( ii ) the Member’s Social Security Benefit.
     2.24 Supplemental Benefit means a benefit which is stated as a monthly annuity for the Member’s lifetime, commencing at the Member’s Normal Retirement Date, under which the annual payments shall equal the remainder of (1) minus (2) below, where (1) and (2) are:
  (1)   the Member’s Total Benefit Base;
 
  (2)   the sum of
  (i)   the Member’s Social Security Offset and
 
  (ii)   the Member’s Basic Pension Plan Benefit.

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If the remainder of (1) minus (2) is negative, the Member’s Supplemental Benefit shall be zero.
     2.25 Termination of Employment means the termination of a Member’s employment with the Company and each other entity which is in the same controlled group of affiliated employers as the Company, as determined in accordance with the rules under Section 414(b) and (c) of the Code (the “ 409A Service Recipients ”); provided, however, that in the case of any Member who ceases to be an employee but continues to provide services to any of the 409A Service Recipients following his termination of employment, or is reasonably expected (at the time of such termination of employment) to provide services to any of the 409A Service Recipients within 12 months of such termination of employment (a “ Continuing Service Member ”), the term Termination of Employment (and any similar terms used in this Plan) shall be deemed to refer to the date at which such Member incurs a “separation from service,” within the meaning of Section 409A of the Code and the regulations promulgated thereunder, from the 409A Service Recipients. This means that rather than being entitled to receive a distribution hereunder upon, or at a specified time following, a Termination of Employment, a Continuing Service Member shall only be entitled to receive such distribution upon, or at a specified time following, such a separation from service.
     2.26 Top-Hat Benefit means a benefit which is stated as a monthly annuity for the Member’s life, commencing at the Member’s Normal Retirement Date, under which the annual payments shall equal the remainder of (1) minus (2) below, where (1) and (2) are:
  (1)   the Member’s Benefit Base as determined under the Basic Pension Plan, but without reduction on account of Benefit Limitations and adjusted as if deferrals under the National Fuel Gas Company Deferred Compensation Plan were not excluded from the definition of Final Average Pay under the Basic Pension Plan and
 
  (2)   the Member’s Basic Pension Plan Benefit.
     2.27 Total Benefit Base means, with respect to a Vested Member, a monthly annuity for the Member’s life, commencing at his Normal Retirement Date, under which the annual payments shall equal an amount calculated by multiplying the sum of (1) and (2) by (3), where (1), (2) and (3) are:
  (1)   .0197 times the Member’s Years of Service not in excess of 30;
 
  (2)   .0132 times the Member’s Years of Service, if any, in excess of 30 (but not to exceed 10);
 
  (3)   the Member’s Final Average Pay.

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     2.28 Vesting
     (a) A Member’s Top-Hat Benefit shall vest in the same manner and subject to the same service requirements and/or other conditions that apply to become vested in the retirement benefits provided under the Basic Pension Plan.
     (b) A Member’s Supplemental Benefit shall vest on the later of ( i ) the first of the month coinciding with or immediately following his 55th birthday or ( ii ) the date on which the Member has completed five Years of Service with a Company.
     A “Vested” Member is a Member with respect to whom “Vesting” has occurred.
     2.29 Years of Service equals the number of Employment Years completed by a Member. With respect to an Employment Year in which a Member completed 1,000 or more hours, but less than a full year of service, the Member shall be credited with a fractional Year of Service equal to the quotient of (i) the number of full months of the Member’s service during such Employment Year and (ii) 12. Years of Service shall not exceed 40. Notwithstanding the foregoing sentence, if a Member retires prior to having completed 1,000 hours in his final Employment Year, the Member shall be credited with a fractional Year of Service as calculated above. No more than one Year of Service shall be credited in any Employment Year.
     2.30 In construing the Plan, masculine pronouns shall refer to both males and females, as appropriate.
ARTICLE 3
DETERMINATION OF RETIREMENT BENEFITS
     3.1 Introduction . The Plan provides a Member with a two-part benefit: the Top-Hat Benefit and the Supplemental Benefit. The Top-Hat Benefit makes a Member whole for any reduction in the regular pension he receives under the Basic Pension Plan resulting from Internal Revenue Code limitations and/or his participation in the National Fuel Gas Company Deferred Compensation Plan. The Supplemental Benefit provides an additional retirement benefit to the Basic Pension Plan. Unless the Past Service Supplemental Benefit and the Future Supplement Benefit are to be paid at the same time and in the same form, each shall be calculated in accordance with the terms of the Plan, but separately from each other.
     A Member who does not satisfy the requirements to Vest in a Top-Hat Benefit prior to the date his service for the Company terminates shall receive no benefit under the Plan. A Member who Vests in the Top-Hat Benefit, but does not Vest in the Supplemental Benefit, shall receive only a Top-Hat Benefit. A Member who is Vested in

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both the Top-Hat Benefit and the Supplemental Benefit and who terminates service with the Company after having attained an Early Retirement Date shall receive the Top-Hat Benefit and a portion of the Supplemental Benefit, as described in Section 3.3.
     3.2 Benefit for Member Retiring at Normal Retirement Date . A Member who retires on or after the Member’s Normal Retirement Date shall receive only the Supplemental Benefit if he shall have Vested in such Supplement Benefit. A Member who retires on or after his Normal Retirement Date, but has not Vested in the Supplement Benefit, shall receive the Top-Hat Benefit.
     3.3 Benefit for Members Terminating Service After Qualifying for Early Retirement .
     (a) The benefit payable under the Plan to a Vested Member whose Termination of Employment occurs after the Member has satisfied the conditions to retire at an Early Retirement Date shall equal the sum of (1) plus [(2) minus (3)], where (1), (2) and (3) are:
  (1)   the product of (i) and (ii), where (i) and (ii) are
  (i)   the Member’s Top-Hat Benefit,
 
  ( ii )   the early retirement percentage that would be applicable to the Member were the Top-Hat Benefit actually payable from the Basic Pension Plan commencing on the date on which payment of the Top-Hat Benefit is to commence hereunder (regardless of when payment of the Basic Pension Plan Benefit actually commences);
  (2)   the product of (i) and (ii ), where (i) and (ii) are
  ( i )   the remainder of (x) minus [the sum of (y) and (z)], where (x), (y) and (z) are:
  ( x )   the Member’s Total Benefit Base;
 
  ( y )   the amount determined under Section 3.3(a)(1);
 
  ( z )   (A) the Member’s Basic Pension Plan Benefit times (B) the early retirement percentage that would be applicable to the Member were the Basic Pension Plan to commence on the date on which payment of the Top-Hat Benefit is to commence hereunder (regardless of when payment of the Basic Pension Plan Benefit actually commences);

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  ( ii )   the Member’s Early Retirement Percentage as determined in Section 3.3(b) below; and
  (3)   the Member’s Social Security Offset.
Notwithstanding the foregoing, if the remainder of subclause (2) minus subclause (3) above is less than zero, then the Member shall receive (instead of the benefit calculated pursuant to the foregoing formula) the benefit described in subclause (1) above.
     (b) The Early Retirement Percentage applicable under the Plan to the Member’s Supplemental Benefit is determined in accordance with the following scale:
     
Age at Early Retirement Date   Early Retirement Percentage
65
  100
64   94
63   88
62   82
61   70
60   58
59   46
58   34
57   22
56   10
55 years and 2 months
  0
     The Early Retirement Percentage determined in accordance with the above scale respecting ages 62, 63 and 64, shall be increased by 1/2 of 1% for each whole calendar month by which a Member’s Early Retirement Date follows the first of the month coinciding with or immediately following his 62nd, 63rd, or 64th birthday, as the case may be. The Early Retirement Percentage determined in accordance with the above scale respecting ages 55 years and 2 months, 56, 57, 58, 59, 60, and 61, shall be increased by 1% for each whole calendar month by which his Early Retirement Date follows the first of the month coinciding with or immediately following his 55 year and 2 month, 56th, 57th, 58th, 59th, 60th and 61st birthdays, as the case may be. Furthermore, the Early Retirement Percentage shall be increased by .125% for each whole calendar month by which a Member’s Years of Service exceed 30; provided, however, that this shall never result in an Early Retirement Percentage in excess of 100%. (In the event a Member desires to retire on the earliest possible Early Retirement Date, i.e., on the first of the month coinciding with or immediately following his 55th birthday, the increase in percentage as a result of Years of Service in excess of 30 shall be made from a base percentage of -2%, in computing Early Retirement Percentage.)
     (c) The provisions of this Section 3.3 are illustrated by the following example. Assume that (i) a Member has 30 Years of Service under this Plan (29 under the Basic

9


 

Pension Plan) and a Final Average Pay of $300,000; (ii) he desires to retire in 2006 at age 58 (10% reduction under the Basic Pension Plan); (iii) the maximum amount of the Member’s Final Average Pay allowed to be taken into account under the Basic Pension Plan applicable limits under Section 401(a)(17) of the Code is limited to $220,000; and (iv) his Social Security Benefit was $15,000:
Step 1. Calculate the Top-Hat Benefit
[(.015 x $300,000) x 29] – the Member’s Basic Pension Plan Benefit
         
The Member’s Base Pension Plan Benefit is
    [(.015 x $220,000) x 29]
            ($3,300) x 29 = $95,700
       
so the Top-Hat Benefit is
    [(.015 x $300,000) x 29] -$95,700
            [$4,500 x 29] - $95,700
                $130,500 – 95,700=
    $ 34,800
Step 2. Adjust the Top-Hat Benefit for Early Retirement
         
$34,800 x .9 =
  $ 31,320  
Step 3. Determine the Total Benefit Base
         
[(.0197 x $300,000) x 30]
$5,910 x 30 =
  $ 177,300  
Step 4. Reduce the Total Benefit Base by the Top-Hat Benefit and the Basic Pension Plan Benefit, each as Adjusted for Early Retirement
         
$177,300 – [Adjusted Top-Hat Benefit + Adjusted Basic Pension Plan Benefit]
       
 
$177,300 – [$31,320 + (95,700 x .9)]
     $177,300 – [$31,320 + 86,130]
             $177,300 - $117,450 =
  $ 59,850  
Step 5. Adjust Reduced Total Benefit Base for the Early Retirement Percentage
         
$59,850 x .34 =
  $ 20,349  

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Step 6. Calculate the Social Security Offset
         
[(.0125 x 30) x $15,000]
    (0.3750) x $15,000 =
  $ 5,625  
Step 7. Determine the ERP Benefit Payable
Add the Adjusted Top-Hat Benefit (shown in Step 2) and the Adjusted Total Benefit Base, (shown in Step 5), then subtract the Social Security Offset (shown in Step 6)
         
($31,320 + 20,349) - $5,625
    $51,669- $5,625 =
  $ 46,044  
     3.4 Benefit for Members Terminating Service Before Qualifying for Early Retirement . The benefit payable under the Plan to a Member whose Termination of Employment occurs before the Member has attained an Early Retirement Date, but after the Member has Vested in his Top-Hat Benefit, and who has elected to commence receipt of his Top-Hat Benefit at an Early Retirement Date shall equal the Member’s Top-Hat Benefit adjusted to reflect the actuarial reduction therein for early commencement of the benefit that would be applicable to the Member were the Top-Hat Benefit actually payable from the Basic Pension Plan commencing on the date on which payment of the Top-Hat Benefit is to commence hereunder (regardless of when payment of the Basic Pension Plan Benefit actually commences).
     3.5 Late Retirement . A Member’s Years of Service shall be credited if they extend beyond his Normal Retirement Date (but shall not exceed 40 in total), and the Final Average Pay determination shall reflect such Years of Service. However, there shall be no actuarial adjustment to his Additional Benefit Base on account of a Member’s retirement after Normal Retirement Date; for such purpose the Additional Benefit Base hereunder shall be computed as if his late retirement date were his Normal Retirement Date.
ARTICLE 4
VESTING; FORFEITURE
     4.1 Time of Vesting . No Retirement Benefits will be payable to or in respect of any Member unless that Member remains employed by the Company until he is Vested in at least the Top-Hat Benefit under this Plan.
     4.2 Misconduct . Notwithstanding Section 4.1 hereof, no Retirement Benefits will be payable to or in respect of a Member whose employment is terminated by the

11


 

Company for serious, willful misconduct in respect of his obligations to the Company, including but not limited to the commission of a felony or a perpetration of a common law fraud which has damaged, or is likely to result in damage to, the Company (provided that, the same result shall obtain if, in the case of Member who terminates service before the Company is aware or has a reasonable opportunity to act on such conduct, the Committee determines that the Member could have been terminated by the Company due to such conduct in accordance with this Section 4.2.)
     4.3 Competition . If and so long as a Member or retired Member shall be employed by any corporation, entity or individual which is then engaged in a business competitive with the Company, or shall be engaged in any such business, or shall aid, advise or assist or attempt to aid, advise or assist any corporation, individual or entity in engaging in any such business, or shall endeavor, directly or indirectly, to interfere with the relations between the Company and any customer or engage in any activity that would be deemed by the Committee in its sole discretion to be detrimental to the Company’s best interests, the rights of such Member or retired Member to Retirement Benefits, including the rights of any Beneficiary, shall be forfeited with the same full force and effect as though the Retirement Benefits had not been granted under any of the provisions of the Plan, unless the Committee determines that such activity is not detrimental to the best interests of the Company; provided that from and after 60 days following cessation by the Member or retired Member of such activity and written notice by him to the Committee, his right to receive Retirement Benefits hereunder shall be restored, unless the Committee, in its sole discretion, determines that the prior activity has caused substantial damage to the Company. Notwithstanding anything else contained in this Section 4.3 to the contrary, this Section shall not apply following the occurrence of a Change in Control.
ARTICLE 5
FORM OF PAYMENT OF BENEFITS
     5.1 Time of Distribution of Retirement Benefits . Retirement Benefits shall be payable as soon as practicable after the Member’s Normal Retirement Date or Early Retirement Date; provided that after the 409A Election Date, no payment of benefits under this Plan shall commence prior to the six-month anniversary of the date of the Member’s Termination of Employment; and provided further , that , to the extent that the immediately preceding proviso delays payment of the Member’s Retirement Benefit, the Member shall be paid a lump sum, as soon as practicable (but not later than 30 days) after such six-month anniversary of the Member’s Termination of Employment, equal to the sum of ( i ) the Retirement Benefits that would have been payable prior to the six month anniversary of such Termination of Employment but for such mandatory delay in payment and ( ii ) an amount of interest on the Retirement Benefits referenced in subclause (i), at the short-term applicable federal rate (within the meaning of Section 1274(d) of the

12


 

Code), compounded semi-annually, in effect for January in the calendar year in which the Member’s Retirement Benefits would have commenced but for such six month delay (or at such other rate as the Committee shall specify from time to time), from the date such Retirement Benefits would otherwise have been paid to the Member until the six month anniversary of the Member’s Termination of Employment.
     5.2 Elections with Respect to Distribution of Retirement Benefits . Retirement Benefits shall be payable to or in respect of a Member eligible therefor in accordance with distribution elections made by the Member. Such election must specify the date at which any benefits payable to such Member under the Plan shall be payable, as well as the form in which such benefits are to be provided from among the options available under, and described in, Section 5.3. A Member who does not elect the date on which any benefits payable under the Plan shall commence to be paid shall commence receipt of such benefits on the later of ( i ) the earliest date on which the Member’s benefits hereunder could commence or ( ii ) the six-month anniversary of the date of the Member’s Termination of Employment. The following rules shall apply with respect to the distribution elections made in respect of the receipt of Retirement Benefits:
     (a) A Member who commences receipt of payment of his or her Retirement Benefit on or before the 409A Election Date and, on the 409A Election Date, was receiving Retirement Benefits in the same form of annuity as is applicable to the benefits payable to such Member under the Basic Pension Plan shall continue to receive such benefit in the same manner and form as the benefit received by such Member under the Basic Pension Plan.
     (b) A person who is (or becomes) a Member, who has not commenced receipt of a distribution of his or her Retirement Benefit prior to the 409A Election Date and who has not otherwise made an election prior to the 409A Election Date, shall make an election in accordance with Section 5.3, on or prior to the 409A Election Date, regarding the form of distribution of such Retirement Benefits, provided that such election shall also be applicable with respect to any Retirement Benefits accrued by the Member under this Plan after the 409A Election Date. A Member described in this Section 5.2(b) must also elect whether, if the Member terminates employment prior to his Normal Retirement Date, distribution of his or her Retirement Benefits shall commence as of an Early Retirement Date and, if so, when such benefits shall commence.
     (c) A Member who commences participation in the Plan after the 409A Election Date may, on the first day of the calendar year following the date that such Member is eligible to commence participation in the Plan, make an election in accordance with Section 5.3 regarding the distribution of his or her Top-Hat Benefit and his or her Future Supplemental Benefit accrued under this Plan and an election as to the date (which shall be at least six months) following the Member’s Termination of Employment (or, if later, at the earliest date as of which such Member’s benefits hereunder could otherwise commence) that such Member’s Vested Top-Hat Benefit and

13


 

Vested Future Supplemental Benefit, if any, payable under the Plan is to commence to be paid.
     (d) Unless the Member shall make a different election in accordance with Section 5.5, a Member’s Past Service Supplemental Benefit shall be paid to the Member in the normal form of payment as set forth in Section 5.3(a), commencing on the first day of the month coinciding with or immediately following the later of ( i ) the Member’s 55 th birthday and ( ii ) the Member’s Termination of Employment. For the avoidance of doubt, no election, other than an election made in compliance with Section 5.5 of the Plan, shall be made with respect to a Member’s Past Service Supplemental Benefit.
     5.3 Forms of Payment . Unless a Member shall elect an alternative form of payment in the manner described in Section 5.2 and except as described in Section 5.2(d), the Member’s Retirement Benefits shall be paid in the form specified in Section 5.3(a). A Member may elect to receive benefits, by making an election within the time period established under Section 5.2, in any of the alternative forms described in Sections 5.3(b) through 5.3(d). Each form of benefit is intended to be of actuarial equivalent value.
     (a)  Normal Form of Payment . The normal benefit form for Retirement Benefits is a four-year period certain annuity that is actuarially equivalent to the lump-sum present value (calculated using the most recently published mortality table that is generally accepted by American actuaries and reasonably applicable to the Plan, and a 6 percent annual interest rate or discount rate) of (i) the Member’s Supplemental Benefit, if the Member is Vested therein or (ii) otherwise, the Member’s Top-Hat Benefit. The first payment will paid on the six-month anniversary of the date of the Member’s Retirement or Early Retirement; provided that, at the time the Member makes an election pursuant to Section 5.2, the Member may elect to have the first payment be payable on the later of ( i ) the six-month anniversary of the Member’s Termination of Employment with the Company and its Subsidiaries and ( ii ) the first business day of the calendar year following the Member’s Retirement or Early Retirement. If a Member elects a delayed commencement date for Retirement Benefits, as permitted under the immediately preceding sentence, the lump sum present value of such Retirement Benefits shall be calculated as of the delayed commencement date, and no interest shall be payable in accordance with Section 5.1 due to such delay. Subsequent installments shall be paid on each of the first three anniversaries of the date on which the first installment is due to be paid. The Retirement Benefits of a Member who fails to make a timely distribution election under Section 5.2 shall be paid in accordance with the normal benefit form provided for in this Section 5.3(a).
     (b)  Single Life Annuity . Retirement Benefits may be paid in the form of a single life annuity for the Member’s lifetime payable in equal monthly installments which shall commence not earlier than the six-month anniversary of the Retirement or Early Retirement of the Member, as elected by such Member. The date on which such benefits

14


 

commence to be paid shall be established pursuant to the Member’s election or, in the absence of a timely election, pursuant to the default provided under Section 5.2.
     (c)  Ten-Year Period Certain and Life . Retirement Benefits may be paid in the form of an annuity in monthly installments for ten years from the Member’s Retirement or Early Retirement, as elected by such Member, and for life thereafter if the Member survives such ten-year period. Such payments shall commence not earlier than the six-month anniversary of the Member’s Retirement or Early Retirement, as elected by such Member. If the Member’s death occurs within such ten-year period, annuity payments shall continue for the remainder of the ten-year period to the Member’s Beneficiary. To provide for the possibility that benefit payments will continue after the Member’s lifetime, the benefit payable to the Member during his or her lifetime under this Section 5.3(c) shall be reduced from the benefit that would have been payable as a single life annuity under Section 5.3(b), based on the same factors that would apply were such benefit payable under the Basic Pension Plan, including the Member’s age. No adjustment shall be made to the amount payable to the Member in the event that no survivor benefit should become payable because the Member lives longer than 10 years following the date the Retirement Benefits commence to be paid. The date on which such benefits commence to be paid shall be established pursuant to the Member’s election or, in the absence of a timely election, pursuant to the default election provided under Section 5.2.
     (d)  Joint and Survivor Annuity . Retirement Benefits may be paid in the form of a joint and survivor annuity so that the Member receives a monthly installment for the duration of the Member’s life and the Member’s Beneficiary receives a monthly installment for the duration of his or her life in an amount that is either 50% or 100% of the Member’s monthly installment, as so elected by the Member. To provide for the possibility that benefit payments will continue after the Member’s lifetime, the benefit payable to the Member during his or her lifetime under this Section 5.3(d) shall be reduced from the benefit that would have been payable as a single life annuity under Section 5.3(b), based on the same factors that would apply were such benefit payable under the Basic Pension Plan, including the Member’s age and that of his or her Beneficiary. The date on which such benefits commence to be paid shall be established pursuant to the Member’s election or, in the absence of a timely election, pursuant to the default election provided under Section 5.2. No adjustment shall be made to the amount payable to the Member in the event that no survivor benefit should become payable because the Beneficiary that the Member selects shall not survive the Member. Notwithstanding the previous sentence, if the Beneficiary selected hereunder is the Member’s spouse and if said spousal Beneficiary dies prior to the fifth anniversary of the Member’s retirement date, the Member’s benefit shall be adjusted to be that which would have been payable as a single life annuity under Section 5.3(b), as of the first of the month coinciding with or next following the spouse’s date of death. There will be no actuarial adjustment made in calculating the benefit under this Section 5.3(d) as a result

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of the availability of this pop-up benefit other than as provided to reflect commencement of benefits prior to the Normal Retirement Date.
     5.4 Distribution of Benefits to Spouses/Beneficiaries . If the Member’s Retirement Benefits are payable to the Member in the normal form, and the Member dies prior to the date the last installment of such benefit is paid, any installments remaining to be paid at the date of the Member’s death will be paid to the Member’s Beneficiary at the same time and in the same amounts as they would have been paid to the Member. If the Member selects an optional form of distribution of his or her Retirement Benefits such that a portion of such Retirement Benefits is eligible to be paid to his Beneficiary after the Member’s death, such benefits shall be paid in accordance with the terms of the form of distribution elected by the Member; that is ( i ) with respect to any remaining payments related to the minimum 120 payments payable under the ten-year certain and life option, such remaining monthly payments shall continue to be paid to the Member’s Beneficiary at the same time and in the same amounts as they would have been payable to the Member, until a total of 120 monthly payments have been made to the Member and the Member’s Beneficiary (at which time payment to the Beneficiary will cease) and ( ii ) with respect to either joint and survivor annuity options, in the form of an annuity for the lifetime of the Member’s Beneficiary (if living at the time of the Member’s death) in a monthly amount that is equal to the percentage (50% or 100%) of the monthly benefit payable to the Member immediately prior to his or her death that was elected by the Member pursuant to Section 5.3(d). To the extent that payment of Retirement Benefits to a Member has been delayed from his Termination of Employment pursuant to Section 5.1 and the Member dies prior to the time such delayed payments shall have been made to the Member, the Member’s Beneficiary shall be paid a lump sum, as soon as practicable (but not later than 60 days) after the Member’s death, equal to the sum of ( i ) the Retirement Benefits that would have been payable to the Member prior to his death but for such mandatory delay in payment and ( ii ) an amount of interest on the Retirement Benefits referenced in subclause (i), at the short-term applicable federal rate (within the meaning of Section 1274(d) of the Code), compounded semi-annually, in effect for January in the calendar year in which the Member’s Retirement Benefits would have commenced but for such mandatory delay (or at such other rate as the Committee shall specify from time to time), from the date such Retirement Benefits would otherwise have been paid to the date of the Member’s death.
     5.5 Changes in Distributions Elections . A Member may only change ( i ) an election previously filed pursuant to Section 5.2 or ( ii ) the timing and form of payment of any Past Service Supplemental Benefit in accordance with the conditions specified in this Section 5.5. Except as otherwise expressly provided below, any such change in such an election or timing and form of payment, whether as to when payment of Retirement Benefits is to commence, or the form of distribution of such Retirement Benefits, must ( 1 ) be made in writing, ( 2 ) be delivered at least 12 months prior to the date as of which the applicable Member’s Retirement Benefits would otherwise have commenced to be

16


 

paid hereunder, and ( 3 ) delay commencement of payment of such applicable Retirement Benefits for at least five years from the date payment of such applicable Retirement Benefits would otherwise have commenced. For purposes of the foregoing sentence, a Member’s applicable Retirement Benefits means ( i ) in the case of a change to the timing or form of payment of the Past Service Supplemental Benefit, only the Past Service Supplemental Benefit, and ( ii ) in all other cases, any of the Member’s Retirement Benefits other than the Past Service Supplemental Benefit. For the avoidance of doubt, a Member may make a change pursuant to this Section 5.5, ( i ) solely in respect of the Member’s Past Service Supplemental Benefit, ( ii ) solely in respect of the Member’s Retirement Benefits other than the Member’s Past Service Supplemental Benefit or ( iii ) jointly or separately as to both the Member’s Past Service Supplemental Benefit and all of the Member’s other Retirement Benefits. In the event that payment of any portion of a Member’s Retirement Benefits are deferred following the Member’s Termination of Employment by reason of a change in the time and form of election pursuant to this Section 5.5, such delay shall not increase the Early Retirement Percentage applied to determine the amount of benefits payable to such Member under Section 3.3. Notwithstanding the foregoing, a Member who has elected to receive a distribution in the form of a life annuity under Section 5.3(b), a ten-year period certain and life annuity under Section 5.3(c) or either joint and survivor annuity form under Section 5.3(d) may elect to change from that form to any other annuity form at any time prior to the commencement of the receipt of Retirement Benefits hereunder. For example, a Member who has elected to receive his Retirement Benefits in the form of an annuity just for his life may change that election to a joint and survivor annuity without the 12 months advance notice and five year delay in commencement of payments described in the second sentence of this Section 5.5.
     5.6 Right to Adjust . The Committee shall have the right to adjust Retirement Benefits payable under this Plan to correct errors, and/or to provide uniform treatment of Members, retired Members or Beneficiaries.
     5.7 Spouse’s Benefit . In the event of a Vested Member’s death prior to the commencement of the receipt of Retirement Benefits hereunder, his spouse, if she shall survive him, shall receive Retirement Benefits hereunder for her lifetime commencing as of the first day of the month following the Member’s death equal to the greater of (i) or (ii):
     (i) .50 times the Member’s Supplemental Benefit, except that if the Member’s surviving spouse is more than five years younger than the Member, the .50 multiplier described in this clause shall be reduced by .00125 for each month in excess of 60 that the surviving spouse’s age is less than that of the Member. Thus, for example, the multiplier declines to .30 if the surviving spouse is 220 months younger than the Member.

17


 

     (ii) 50% of the Retirement Benefit which the Member would have received had payment thereof commenced on the day before the date of his death in the form of the Automatic Joint and Survivor Annuity (as defined and described in the Basic Pension Plan), determined without regard to whether the Member could have commenced such benefit on such date.
ARTICLE 6
SOURCE OF PAYMENT
     6.1 All payments provided for under the Plan shall be paid in cash from the general funds of the Company; provided, however, that such payments shall be reduced by the amount of any payments made to or in respect of a Member from any trust or special or separate fund established by the Company to assure such payments. The Company shall not be required to establish a special or separate fund or other segregation of assets to assure such payments, and, if the Company shall make any investments to aid it in meeting its obligations hereunder, the Member and his Beneficiary shall have no right, title, or interest whatever in or to any such investments except as may otherwise be expressly provided in a separate written instrument relating to such investments. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind between the Company and any Member or Beneficiary. To the extent that any Member or Beneficiary acquires a right to receive payments from the Company hereunder, such right shall be no greater than the right of an unsecured creditor of the Company.
ARTICLE 7
ADMINISTRATION OF THE PLAN
     7.1 Committee to Administer . The Plan shall be administered by the Committee which shall have full power and authority to interpret, construe and administer the Plan, and review claims for benefits under the Plan, and the Committee’s interpretations and constructions of the Plan and actions thereunder shall be binding and conclusive on all persons and for all purposes.
     7.2 Agents . For purposes of the Act, the members of the Committee shall be the named fiduciaries of the Plan for administration of the Plan (including but not limited to complying with reporting and disclosure requirements and establishing and maintaining Plan records), and shall engage such certified public accountants, who may be accountants for the Company, as it shall require or may deem advisable for purposes of the Plan. The Committee may arrange for the engagement of such legal counsel, who may be counsel for the Company, and make use of such agents and clerical or other

18


 

personnel as they each shall require or may deem advisable for purposes of the Plan. The Committee may rely upon the written opinion of such counsel and the accountants engaged by the Committee and may delegate to any agent, who may be a Company employee, or to any sub-committee or member of the Committee, its authority to perform any act hereunder, including without limitation those matters involving the exercise of discretion, provided that such delegation shall be subject to revocation at any time at the discretion of the Committee.
     7.3 Liability; Indemnity . To the maximum extent permitted by the Act, no member of the Committee, nor any of their agents, including Company officers or employees, shall be personally liable by reason of any contract or other instrument executed by any of them in their capacity as members of the Committee or otherwise, nor for any mistake of judgment made in good faith, and the Company shall indemnify and hold harmless, directly from its own assets, each member of the Committee and each other officer, employee, or director of the Company to whom any duty or power relating to the administration or interpretation of the Plan or to the management or control of the assets of the Plan may be delegated or allocated, against any cost or expense (including counsel fees) or liability (including any sum paid in settlement of a claim with the approval of the Company) arising out of any act or omission to act in connection with the Plan unless arising out of such person’s own fraud or bad faith. Said persons shall be entitled to rely conclusively upon, and shall be fully protected in any action taken by them or any of them in good faith in reliance upon, any table, valuation, certificate, opinion or report which shall be furnished to them or any of them by an actuary, accountant, counsel or other expert who shall be employed or engaged by them.
     7.4 Binding Effect of Decisions . The decision or action of this Committee with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final, conclusive and binding upon all persons having any interest in the Plan.
     7.5 Effect of Restatement . Notwithstanding anything else contained herein to the contrary, in no event shall the restatements of this Plan as of September 20, 2007 and September 24, 2008 reduce the amount of Retirement Benefits payable to any Member hereunder, or otherwise reduce the amount of such Member’s Final Average Pay, in either case below the amount that would have applied under the terms of this Plan as in effect immediately prior to such restatements.
     7.6 Section 409A of the Code . Notwithstanding anything herein to the contrary, the Committee and any of its delegates shall use their commercially reasonable best efforts to administer the plan in a manner that will cause the Plan and any payments to be made hereunder, to comply with the requirements of Section 409A, with the intent of avoiding the imposition of an additional tax under Section 409A of the Code on any Member.

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ARTICLE 8
AMENDMENT AND TERMINATION
     8.1 General Power to Amend . Subject to the application of Article 4 in the situations therein enumerated, the Plan may be amended, suspended or terminated, in whole or in part, by the Board of Directors, and Members may be adversely affected thereby provided that such actions may not deprive Vested Members of Retirement Benefits accrued until the date of such actions. In addition, the rights of Vested Members may be affected if ( i ) failing to make changes would be administratively burdensome; ( ii ) the Member voluntarily consents to such change in writing; or ( iii ) if changes are required by law.
     8.2 Limited Power of the President . Notwithstanding Section 8.1, the President of National Fuel Gas Company is empowered to amend, restate or otherwise change the Plan ( i ) as counsel may advise to be necessary or appropriate in order to ensure that the Plan continues to operate as a plan of deferred compensation for tax purposes in compliance with requirements of Section 409A, remain exempt from many of the provisions of the Act and otherwise continues to fulfill the purposes for which the Plan was adopted and intended; ( ii ) as he or she may deem necessary in order to make technical or clarifying changes not inconsistent with or in order to fulfill the purposes of the Plan; ( iii ) as counsel may advise to be necessary to reflect the impact of Benefit Limitations, as they may change from time to time; and ( iv ) in other respects except as will materially increase the cost of the Plan to the Companies or the benefits of the Plan to Members or as will otherwise reduce the accrued benefits of any Member without his or her consent.
ARTICLE 9
GENERAL PROVISIONS
     9.1 Effect of Corporate Reorganization . This Plan shall be binding upon and inure to the benefit of the Company and its successors and assigns and the Member, and his designees, Beneficiaries, legal representatives and estate. Nothing in this Plan shall preclude the Company from consolidating or merging into or with, or transferring all or substantially all of its assets to, another corporation which assumes this Plan and all obligations of the Company hereunder. Upon such a consolidation, merger or transfer of assets, and assumption of the Plan, the term “Company” shall refer to such other corporation and this Plan shall continue in full force and effect.
     9.2 Right to Discharge Member . Neither the Plan nor any action taken hereunder shall be construed as giving to a Member the right to be retained in the employ of the Company or as affecting the right of the Company to discharge any Member, at

20


 

any time without regard to the effect such discharge would have upon his eligibility for or receipt of benefits under the Plan.
     9.3 Withholding . The Company may withhold from any benefits payable under this Plan all federal, state, city or other taxes as shall be required (as determined by the Company) pursuant to any law or governmental regulation or ruling.
     9.4 Assignability . No right to any amount payable at any time under the Plan may be assigned, transferred, pledged, or encumbered, either voluntarily or by operation of law, except as provided expressly herein as to payments to a Beneficiary or as may otherwise be required by law. If, by reason of any attempted assignment, transfer, pledge, or encumbrance, or any bankruptcy or other event happening at any time, any amount payable under the Plan would be made subject to the debts or liabilities of the Member or his Beneficiary or would otherwise not be enjoyed by him, then the Committee, if it so elects, may terminate such person’s interest in any such payment and direct that the same be held and applied to or for the benefit of the Member, his Beneficiary, or any other person deemed to be the natural objects of his bounty, taking into account the expressed wishes of the Member (or, in the event of his death, his Beneficiary).
     9.5 Inability to Utilize Benefits . If the Committee shall find that any person to whom any amount is or was payable hereunder is unable to care for his affairs because of illness or accident or other reasons, or has died, then the Committee, if it so elects, may direct that any payment or any part thereof due such person shall be paid to his estate (unless a prior claim therefor has been made by a duly appointed legal representative) or be paid or applied for the benefit of such person or to or for the benefit of his spouse, children or other dependents, an institution maintaining or having custody of such person, any other person deemed by the Committee to be a proper recipient on behalf of such person otherwise entitled to payment, or any of them, in such manner and proportion as the Committee may deem proper. Any such payment shall be in complete discharge of the liability therefor of the Company, the Plan or the Committee or any member, officer or employee thereof. The Committee may withhold the payment of any amount that shall be payable in accordance with the provisions of the Plan to a person under legal disability until a representative of such person competent to receive such payment on his behalf shall have been properly appointed.
     9.6 Actuarial Equivalents . Except as otherwise provided herein, whenever it is necessary to determine under this Plan whether one benefit is less than, equal to, or larger than another, or whether one benefit is the actuarial equivalent of another whether or not such benefits are provided under this Plan, such determination shall be made using mortality, interest and any other assumptions used at the time in determining actuarial equivalents under the Basic Pension Plan.

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     9.7 Health Information . The Member shall provide to the Company, if so requested and as a precondition for remaining a Member, all health information and other information as the Company may require should it decide to purchase life insurance policies or annuity contracts.
     9.8 Additional Benefit . The benefits payable under this Plan shall be in addition to all other benefits provided for Employees of the Company, except as otherwise provided in this Plan.
     9.9 Headings . The captions preceding the sections and articles hereof have been inserted solely as a matter of convenience and in no way define or limit the scope or intent of any provisions of the Plan.
     9.10 Governing Law . Except to the extent that such laws are pre-empted by the Employee Retirement Income Security Act of 1974, as amended, this Plan shall be governed by the laws of the State of New York as from time to time in effect.

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EXHIBIT 12
NATIONAL FUEL GAS COMPANY
COMPUTATION OF RATIO OF
EARNINGS TO FIXED CHARGES
UNAUDITED
                                         
    Fiscal Year Ended September 30,
    2008   2007   2006   2005   2004
     
EARNINGS:
                                       
 
                                       
Income from Continuing Operations
  $ 268,728     $ 201,675     $ 184,614     $ 138,437     $ 141,920  
Plus Income Tax Expense
    167,922       131,813       108,245       85,621       89,820  
Less Investment Tax Credit (1)
    (697 )     (697 )     (697 )     (697 )     (697 )
(Less Income) Plus Loss from Unconsolidated Subsidiaries (3)
    (6,303 )     (4,979 )     (3,583 )     796       (805 )
Plus Distributions from Unconsolidated Subsidiaries
    8,280       1,613       4,651       1,990       785  
Plus Interest Expense on Long-Term Debt
    70,099       68,446       72,629       73,244       82,989  
Plus Other Interest Expense
    3,870       6,029       5,952       9,069       6,354  
Less Amortization of Loss on Reacquired Debt
    (1,156 )     (1,119 )     (1,118 )     (1,066 )     (1,350 )
Plus (Less) Allowance for Borrowed Funds Used in Construction
    2,100       374       296       201       298  
Plus Rentals (2)
    2,229       2,685       2,810       3,554       4,286  
     
 
                                       
 
  $ 515,072     $ 405,840     $ 373,799     $ 311,149     $ 323,600  
     
 
                                       
FIXED CHARGES:
                                       
 
                                       
Interest & Amortization of Premium and Discount of Funded Debt
  $ 70,099     $ 68,446     $ 72,629     $ 73,244     $ 82,989  
Plus Other Interest Expense
    3,870       6,029       5,952       9,069       6,354  
Less Amortization of Loss on Reacquired Debt
    (1,156 )     (1,119 )     (1,118 )     (1,066 )     (1,350 )
Plus (Less) Allowance for Borrowed Funds Used in Construction
    2,100       374       296       201       298  
Plus Rentals (2)
    2,229       2,685       2,810       3,554       4,286  
     
 
                                       
 
  $ 77,142     $ 76,415     $ 80,569     $ 85,002     $ 92,577  
     
 
                                       
RATIO OF EARNINGS TO FIXED CHARGES
    6.68       5.31       4.64       3.66       3.50  
 
(1)   Investment Tax Credit is included in Other Income
 
(2)   Rentals shown above represent the portion of all rentals (other than delay rentals) deemed representative of the interest factor.
 
(3)   Fiscal 2005 includes the Impairment of Investment in Partnership of $4,158.

 

Exhibit 21
Subsidiares of Registrant
As of September 30, 2008
     
Legal Name   Domicile
National Fuel Gas Company:
  USA, New Jersey
Leidy Hub, Inc.
  USA, New York
National Fuel Gas Distribution Corporation
  USA, New York
National Fuel Gas Supply Corporation
  USA, Pennsylvania
Seneca Resources Corporation
  USA, Pennsylvania
Highland Forest Resources, Inc.
  USA, New York
Empire Pipeline Company, LLC
  USA, New York
St. Clair Pipeline Company, LLC
  USA, New York
Empire State Pipeline
  USA, New York
Empire Pipeline, Inc.
  USA, New York
Horizon Energy Development, Inc.
  USA, New York
Horizon Energy Holdings, Inc.
  USA, New York
Horizon Energy Development B.V.
  The Netherlands
Horizon LFG, Inc.
  USA, New York
Toro Partners, LP
  USA, Texas
Data-Track Account Services, Inc.
  USA, New York
Horizon Power, Inc.
  USA, New York
Seneca Energy II, LLC
  USA, New York
Model City Energy, LLC
  USA, New York
Energy Systems Northeast, LLC
  USA, Delaware
National Fuel Resources, Inc.
  USA, New York
National Fuel Gas Midstream Corporation
  USA, Pennsylvania

 

Exhibit 23.1
NETHERLAND, SEWELL
& ASSOCIATES, INC.
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the reproduction of and reference to our audit report for Seneca Resources Corporation dated October 16, 2008, appearing in this National Fuel Gas Company Annual Report on Form 10-K.
We also consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-123654, 333-85711, and 333-102200), Form S-4 (No. 333-155238) and Form S-8 (Nos. 33-49693, 333-51595, 333-55124, 333-102211, 333-102220, 333-117131, 333-117132, 333-130280, 333-130281 and 333-143701) of National Fuel Gas Company of our audit report dated October 16, 2008, appearing in this National Fuel Gas Company Annual Report on Form 10-K.
         
  NETHERLAND, SEWELL & ASSOCIATES, INC.
 
 
  By:   /s/ J. Carter Henson, Jr., P. E.    
    J. Carter Henson, Jr., P. E.   
    Senior Vice President   
 
Houston, Texas
November 26, 2008

Exhibit 23.2
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-123654, 333-85711, and 333-102200), Form S-4 (No. 333-155238) and Form S-8 (Nos. 33-49693, 333-51595, 333-55124, 333-102211, 333-102220, 333-117131, 333-117132, 333-130280, 333-130281 and 333-143701) of National Fuel Gas Company of our report dated November 26, 2008 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Buffalo, New York
November 26, 2008

Exhibit 31.1
CERTIFICATION
     I, D. F. Smith, certify that:
     1. I have reviewed this annual report on Form 10-K of National Fuel Gas Company;
     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
     (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
     (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
     (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
     (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
     (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
     (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: November 26, 2008
     
/s/ D. F. Smith
 
D. F. Smith
   
President and Chief Executive Officer
   

 

Exhibit 31.2
CERTIFICATION
     I, R. J. Tanski, certify that:
     1. I have reviewed this annual report on Form 10-K of National Fuel Gas Company;
     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
     (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
     (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
     (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
     (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
     (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
     (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: November 26, 2008
     
/s/ R. J. Tanski
 
R. J. Tanski
   
Treasurer and Principal Financial Officer
   

 

Exhibit 32      
NATIONAL FUEL GAS COMPANY
Certification Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
          Each of the undersigned, D. F. SMITH, the President and Chief Executive Officer, and R. J. TANSKI, the Treasurer and Principal Financial Officer, of NATIONAL FUEL GAS COMPANY (the “Company”), DOES HEREBY CERTIFY that:
  1.   The Company’s Annual Report on Form 10-K for the year ended September 30, 2008 (the “Annual Report”) fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934, as amended; and
 
  2.   Information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
          IN WITNESS WHEREOF, each of the undersigned has executed this statement this 26th day of November, 2008.
         
     
  /s/ D. F. Smith    
  President and Chief Executive Officer   
     
 
     
  /s/ R. J. Tanski    
  Treasurer and Principal Financial Officer   
     
 

 

Exhibit 99.1
[Letterhead of Netherland, Sewell & Associates, Inc.]
October 16, 2008
Mr. Matthew D. Cabell
Seneca Resources Corporation
1201 Louisiana Street, Suite 400
Houston, Texas 77002
Dear Mr. Cabell:
In accordance with your request, we have audited the estimates prepared by Seneca Resources Corporation (Seneca), as of September 30, 2008, of the proved reserves and future revenue to the Seneca interest in certain oil and gas properties located in the United States and the Gulf of Mexico. These estimates are based on constant prices and costs, as discussed in subsequent paragraphs of this letter. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a) and subsequent staff interpretations and guidance. The estimates of reserves and future revenue have been prepared in accordance with the definitions and guidelines of the SEC and, with the exception of the exclusion of future income taxes, conform to the Statement of Financial Accounting Standards No. 69.
The following table sets forth Seneca’s estimates of the net reserves and future net revenue, as of September 30, 2008, for the audited properties:
All Properties
                                         
    Net Reserves   Future Net Revenue (M$)
    Oil   NGL   Gas           Present Worth
Category   (MBBL)   (MBBL)   (MMCF)   Total   at 10%
 
                                       
Proved Developed
    38,779.5       114.8       202,518.6       3,728,117.0       1,679,270.0  
Proved Undeveloped
    7,303.9       0.0       23,380.4       619,876.7       238,761.9  
 
                                       
 
                                       
Total Proved
    46,083.4       114.8       225,899.0       4,347,993.5       1,918,031.8  
Totals may not add because of rounding.
     For the purposes of this audit, the properties were divided into sections for the East Coast, Gulf Coast, and West Coast Divisions. The following tables set forth Seneca’s estimates of the net reserves and future net revenue by division, as of September 30, 2008, for the audited properties:
East Coast Division
                                         
    Net Reserves   Future Net Revenue (M$)
    Oil   NGL   Gas           Present Worth
Category   (MBBL)   (MBBL)   (MMCF)   Total   at 10%
 
                                       
Proved Developed
    356.8       0.0       115,823.5       669,499.5       305.818.9  
Proved Undeveloped
    39.8       0.0       12,574.3       65,194.2       18,580.9  
 
                                       
 
                                       
Total Proved
    396.5       0.0       128,397.9       734,693.7       324,399.8  

 


 

Gulf Coast Division
                                         
    Net Reserves   Future Net Revenue (M$)
    Oil   NGL   Gas           Present Worth
Category   (MBBL)   (MBBL)   (MMCF)   Total   at 10%
 
                                       
Proved Developed
    1,198.0       114.8       18,241.8       127,560.5       116,874.2  
Proved Undeveloped
    44.8       0.0       6,399.3       28,671.3       21,143.9  
 
                                       
 
                                       
Total Proved
    1,242.8       114.8       24,641.1       156,231.8       138,018.2  
West Coast Division
                                         
    Net Reserves   Future Net Revenue (M$)
    Oil   NGL   Gas           Present Worth
Category   (MBBL)   (MBBL)   (MMCF)   Total   at 10%
 
                                       
Proved Developed
    37,224.7       0.0       68,453.4       2,931,057.3       1,256,576.5  
Proved Undeveloped
    7,219.3       0.0       4,406.7       526,011.1       199,037.0  
 
                                       
Total Proved
    44,444.0       0.0       72,860.1       3,457,068.5       1,455,613.9  
Totals may not add because of rounding.
The oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.
When compared on a field-by-field basis, some of the estimates of Seneca are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. However, in our opinion the estimates of Seneca’s proved reserves and future revenue shown herein are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. These principles are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We are satisfied with the methods and procedures used by Seneca in preparing the September 30, 2008, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Seneca.
The estimates shown herein are for proved developed and proved undeveloped reserves. Proved developed reserves include proved developed producing and proved developed non-producing reserves. Seneca’s estimates do not include probable or possible reserves that may exist for these properties, nor do they include any consideration of undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.
Oil prices used by Seneca are based on regional posted prices in effect on September 30, 2008, and are adjusted by lease for quality, transportation fees, and local price differentials. Gas prices used by Seneca are based on regional spot market prices in effect on September 30, 2008, and are adjusted by lease for energy content, transportation fees, and local price differentials. As a reference, the September 30, 2008, Plains Marketing, L.P. West Texas Intermediate posted price was $97.00 per barrel and the September 30, 2008, Platts Henry Hub spot market price was $7.120 per MMBTU. All prices are held constant throughout the lives of the properties.
Lease and well operating costs used by Seneca are based on historical operating expense records. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs

 


 

to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Seneca are not included. Lease and well operating costs are held constant throughout the lives of the properties. Seneca’s estimates of capital costs are included as required for workovers, new development wells, production equipment, and abandonment. The future capital costs are held constant to the date of expenditure.
It should be understood that our audit does not constitute a complete reserves study of the oil and gas properties of Seneca. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of major properties making up approximately 99 percent of the company’s total proved reserves and accounting for approximately 99 percent of the present worth for those reserves. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Seneca with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of Seneca’s overall reserves management processes and practices.
In evaluating the information at our disposal concerning this audit, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.
Supporting data documenting this audit, along with data provided by Seneca, are on file in our office. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists with respect to Seneca as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We do not own an interest in these properties and are not employed on a contingent basis.
                     
            Sincerely,  
 
                   
            NETHERLAND, SEWELL & ASSOCIATES, INC.
 
                   
 
          By:   /s/ C.H. (Scott) Rees III, P.E.    
 
                   
 
              C.H. (Scott) Rees III, P.E.    
 
              Chairman and Chief Executive Officer    
 
                   
By:
  /s/ Danny D. Simmons, P.E.       By:   /s/ Mike K. Norton, P.G.    
 
                   
 
  Danny D. Simmons, P.E.           Mike K. Norton, P.G.    
 
  President and Chief Operating Officer           Senior Vice President    
 
                   
Date Signed: October 16, 2008   Date Signed: October 16, 2008
RBT: JJH

 

EXHIBIT 99.2
Exploration and Production
()

 


 

Pipeline and Storage
()

 


 

Timber
()

 


 

Utility
()

 


 

Energy Marketing
()