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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K

			
 		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)	
		
 	OF THE SECURITIES EXCHANGE ACT OF 1934	
For the Fiscal Year Ended September 30, 2004
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:

Title of Each Class		Name of Each Exchange on Which 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 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 an accelerated filer (as defined in Rule 12b-2 of the Act).     Yes  þ           No  o
      The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $1,997,020,000 as of March 31, 2004.
      Common Stock, $1 Par Value, outstanding as of November 30, 2004: 83,178,717 shares.
DOCUMENTS INCORPORATED BY REFERENCE
      Portions of the registrant’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 17, 2005 are incorporated by reference into Part III of this report.

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For the Fiscal Year Ended September 30, 2004
CONTENTS

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PART I 	
  ITEM 1 	 	BUSINESS 	 	 	3	 	
 	 	   THE COMPANY AND ITS SUBSIDIARIES	 	 	3	 	
 	 	   RATES AND REGULATION	 	 	4	 	
 	 	   THE UTILITY SEGMENT	 	 	5	 	
 	 	   THE PIPELINE AND STORAGE SEGMENT	 	 	5	 	
 	 	   THE EXPLORATION AND PRODUCTION SEGMENT	 	 	6	 	
 	 	   THE INTERNATIONAL SEGMENT	 	 	6	 	
 	 	   THE ENERGY MARKETING SEGMENT	 	 	6	 	
 	 	   THE TIMBER SEGMENT	 	 	6	 	
 	 	   ALL OTHER CATEGORY AND CORPORATE 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	 	
  ITEM 2 	 	PROPERTIES 	 	 	12	 	
 	 	   GENERAL INFORMATION ON FACILITIES	 	 	12	 	
 	 	   EXPLORATION AND PRODUCTION ACTIVITIES	 	 	12	 	
  ITEM 3 	 	LEGAL PROCEEDINGS 	 	 	16	 	
  ITEM 4 	 	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 	 	 	17	 	

PART II 	
  ITEM 5 	 	MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 	 	 	17	 	
  ITEM 6 	 	SELECTED FINANCIAL DATA 	 	 	18	 	
  ITEM 7 	 	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 	 	 	19	 	
  ITEM 7A 	 	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 	 	 	50	 	
  ITEM 8 	 	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 	 	 	51	 	
  ITEM 9 	 	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 	 	 	100	 	
  ITEM 9A 	 	CONTROLS AND PROCEDURES 	 	 	100	 	
  ITEM 9B 	 	OTHER INFORMATION 	 	 	101	 	
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PART III 	
  ITEM 10 	 	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 	 	 	101	 	
  ITEM 11 	 	EXECUTIVE COMPENSATION 	 	 	101	 	
  ITEM 12 	 	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 	 	 	101	 	
  ITEM 13 	 	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 	 	 	102	 	
  ITEM 14 	 	PRINCIPAL ACCOUNTANT FEES AND SERVICES 	 	 	102	 	
 	
  PART IV	
  ITEM 15 	 	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 	 	 	102	 	
  SIGNATURES	 	 	108	 	
  EX-10.1 Executive Life Insurance Plan	
  EX-10.2 Executive Retirement Plan	
  EX-10.3 Administrative Rules	
  EX-10.4 Retirement and Consulting Agreement	
  EX-12 Computation of Ratio of Earnings	
  EX-23.1 Consent of Engineer	
  EX-23.2 Consent of Engineer	
  EX-23.3 Consent of Accounting Firm	
  EX-31.1 CEO Certification 302	
  EX-31.2 CFO Certification 302	
  EX-32 906 Certification	
  EX-99.1 Seneca Resources Corporation	
  EX-99.2 Seneca Energy Canada, Inc.	
  EX-99.3 Maps - Locations National Fuel	
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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, Management’s Discussion and Analysis of Financial Condition and Results of Operations (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, those statements that are designated with an asterisk (“*”) following the statement, as well as those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.
PART I

Item 1	Business	
The Company and its Subsidiaries
      National Fuel Gas Company (the Registrant), a holding company registered under the Public Utility Holding Company Act of 1935, as amended (the Holding Company Act), was organized under the laws of the State of New Jersey in 1902. Except as otherwise indicated below, the Registrant owns 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 consisting of six reportable 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 732,000 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 entities 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 (ii) 28 underground natural gas storage fields owned and operated by Supply Corporation as well as four other underground natural gas storage fields operated jointly with various other interstate gas pipeline companies. Empire, an intrastate pipeline company, transports natural gas for Distribution Corporation and for other utilities, large industrial customers and power producers in New York State. Empire owns 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. The Company acquired Empire in February 2003.
      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, and in the Gulf Coast region of Texas, Louisiana, and Alabama. Also, Exploration and Production operations are conducted in the provinces of Alberta, Saskatchewan and British Columbia in Canada by Seneca Energy Canada, Inc. (SECI), formerly Player Resources Ltd. SECI is an Alberta, Canada corporation and a subsidiary of Seneca. At September 30, 2004, the Company had U.S. and Canadian reserves of 65,213 thousand barrels (Mbbl) and 224,784 million cubic feet (MMcf).
      4. The International segment operations are carried out by Horizon Energy Development, Inc. (Horizon), a New York corporation. Horizon engages 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
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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 whose principal asset is majority ownership of United Energy, a.s. (UE), a wholesale power and district heating company located in the northern part of the Czech Republic. Horizon B.V. is also pursuing power development projects in other parts of Europe.
      5. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation, which markets natural gas to industrial, commercial, public authority and residential end-users in western and central New York and northwestern Pennsylvania, offering competitively priced energy and energy management services for its customers.
      6. 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, 2004, the Company owned and managed approximately 87,000 acres of timber property.
      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 H — Business Segment Information.
      The Company’s other direct wholly-owned subsidiaries are not included in any of the six reportable business segments and consist of the following:

			
 	• 	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. Further information can be found in Item 8 at Note J — Acquisitions;	
 		
 	• 	Leidy Hub, Inc. (Leidy), 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 which provides collection services principally for the Company’s subsidiaries; and	
 		
 	• 	Horizon Power, Inc. (Horizon Power), a New York corporation which is designated as an “exempt wholesale generator” under the Holding Company Act and is developing or operating mid-range independent power production facilities and landfill gas electric generation facilities.	
      No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 2004.
Rates and Regulation
      The Company is subject to regulation by the Securities and Exchange Commission (SEC) under the broad regulatory provisions of the Holding Company Act, including provisions relating to issuance of securities, sales and acquisitions of securities and utility assets, intra-company transactions and limitations on diversification. In 2003, both houses of Congress passed comprehensive energy bills that included repeal of the Holding Company Act, but since November 2003 have been unable to reconcile their differences and pass any comprehensive energy legislation. The Company is unable to predict at this time what the ultimate outcome of legislative or regulatory changes will be and, therefore, whether the Holding Company Act will be repealed and what impact the repeal of the Holding Company Act might have on the Company.*
      The Utility segment’s rates, services and other matters are regulated by the State of New York Public Service Commission (NYPSC) with respect to services provided within New York and by the Pennsylvania Public Utility Commission (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 Matters” and Item 8 at Note B-Regulatory Matters.
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      The Pipeline and Storage segment’s rates, services and other matters with respect to Supply Corporation are regulated by the Federal Energy Regulatory Commission (FERC) and by the NYPSC with respect to Empire. For additional discussion of the Pipeline and Storage segment’s rates and regulation, see Item 7, MD&A under the heading “Rate Matters” and Item 8 at Note B-Regulatory Matters.
      The discussion under Item 8 at Note B-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 the International segment, rates charged for the sale of thermal energy and electric energy at the retail level are subject to regulation and audit in the Czech Republic by the Czech Ministry of Finance. The regulation of electric energy rates at the retail level indirectly impacts the rates charged by the International segment for its electric energy sales at the wholesale level.
      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 28.0% of the Company’s 2004 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” 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 28.6% of the Company’s 2004 net income available for common stock.
      Supply Corporation has service agreements for all of its firm storage capacity, which totals approximately 68,728 thousand dekatherms (MDth). The Utility segment has contracted for 27,865 MDth or 40.6% of the total storage capacity, and the Energy Marketing segment accounts for another 3,868 MDth or 5.6% of the total storage capacity. Nonaffiliated customers have contracted for the remaining 36,995 MDth or 53.8% of the firm storage capacity. Following an industry trend, most 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, and from time to time thereafter. At the beginning of 2005, approximately 88% of Supply Corporation’s firm storage capacity (including the 40.6% contracted for by affiliated shippers) was committed under contracts that could have expired or been terminated before the end of 2005. Based on contract expirations and termination notifications received before the deadline for termination effective within 2005, contracts representing approximately 3.3% of Supply Corporation’s firm storage capacity will be terminated during 2005.* Supply Corporation has been successful in marketing and obtaining executed contracts for storage service (at discounted rates) as it becomes available and expects to continue to do so.*
      Supply Corporation’s firm transportation capacity is not a fixed quantity, due to the diverse weblike nature of its pipeline system, and is subject to change as different transportation paths and receipt/delivery point combinations are identified with the market. Supply Corporation currently has firm transportation service agreements for approximately 2,232 MDth per day (contracted capacity). The Utility segment accounts for approximately 1,122 MDth per day or 50.3% of contracted capacity, and the Energy Marketing segment represents another 78 MDth per day or 3.5% of contracted capacity. The remaining 1,032 MDth or 46.2% of contracted capacity are subject to firm contracts with nonaffiliated customers.
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      At the beginning of 2005, 47% of Supply Corporation’s contracted capacity was committed under affiliate contracts that could have expired or been terminated effective before the end of 2005. Based on contract expirations and termination notices received before the deadline for termination effective within 2005, affiliate contracts representing only 0.3% of contracted capacity will actually expire or be terminated effective during 2005. Similarly, 28% of contracted capacity was committed under unaffiliated shipper contracts that could expire or be terminated effective before the end of 2005. Based on contract expirations and termination notices received before the deadline for termination within 2005, unaffiliated contracts representing 11% of contracted capacity will actually expire or be terminated effective during 2005. Supply Corporation has been successful in marketing and obtaining executed contracts for such transportation service previously (at discounted rates when necessary), and expects to continue to do so.*
      Empire has service agreements for the 2004-2005 winter period for all of its firm transportation capacity, which totals approximately 562 MDth per day. Approximately 74% of Empire’s firm transportation capacity is contracted on a long-term basis. None of these transportation contracts could be terminated or will expire in 2005 or 2006. The Utility segment accounts for approximately 60 MDth per day or 10.7% of Empire’s total capacity, and the Energy Marketing segment accounts for approximately 10 MDth per day or 1.8% of Empire’s total capacity, with the remaining 87.5% of Empire’s capacity subject to firm contracts with nonaffiliated customers. Approximately 14% of Empire’s total capacity (including 5% of its total capacity contracted with affiliated shippers) is currently contracted under seasonal or annual contracts which will expire effective before the end of 2005.* Empire expects that all of this capacity will be re-contracted under seasonal and/or annual arrangements for future contracting periods.*
      Additional discussion of the Pipeline and Storage segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition” 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 32.6% of the Company’s 2004 net income available for common stock.
      Additional discussion of the Exploration and Production segment appears below under the headings “Sources and Availability of Raw Materials” and “Competition,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The International Segment
      The International segment contributed approximately 3.6% of the Company’s 2004 net income available for common stock.
      Additional discussion of the International segment appears below under the heading “Sources and Availability of Raw Materials,” “Competition” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Energy Marketing Segment
      The Energy Marketing segment contributed approximately 3.3% of the Company’s 2004 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” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Timber Segment
      The Timber segment contributed approximately 3.4% of the Company’s 2004 net income available for common stock.
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      Additional discussion of the Timber segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition” 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 0.5% of the Company’s 2004 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.
Sources and Availability of Raw Materials
      Natural gas is the principal raw material for the Utility segment. In 2004, the Utility segment purchased 105 billion cubic feet (Bcf) of gas, of which 85 Bcf served core market demand and 17 Bcf was used for off-system sales. The remaining 3 Bcf represents gas used in operations offset by storage withdrawals. Gas purchased from producers and suppliers in the southwestern United States and Canada under firm contracts (seasonal and longer) accounted for 71% of the core market purchases. Purchases of gas on the spot market (contracts for one month or less) accounted for the remaining 29% of the Utility segment’s 2004 core market purchases. Purchases from Conoco Phillips Company (16%), Cinergy Marketing & Trading, L.P. (13%), BP Energy Company (11%), Occidental Energy Marketing, Inc. (10%) and Anadarko Energy Services Company (9%) accounted for 59% of the Utility’s 2004 core market gas purchases. No other producer or supplier provided the Utility segment with more than 9% of its gas requirements in 2004.
      Supply Corporation transports and stores gas owned by its customers, whose gas originates in the southwestern 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” and in Item 7, MD&A.
      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 Notes H-Business Segment Information and N-Supplementary Information for Oil and Gas Producing Activities.
      Coal is the principal raw material for the International segment, constituting 54% of the cost of raw materials needed in 2004 to operate the boilers which produce steam or hot water. Natural gas, oil, limestone and water combined accounted for the remaining 46% of such materials. Coal is purchased and delivered directly from the adjacent Mostecka Uhelna Spolecnost, a.s. mine in the Czech Republic for UE’s largest coal-fired plant under a contract where price and quantity are the subject of negotiation each year. The Company has been informed that this mine is expected to have reserves through 2030, although the Company has not been provided with an independent reserve study to support this information.* Natural gas is imported into the Czech Republic from sources in Russia and the North Sea and is transported through the Transgas pipeline system, which is majority owned by RWE AG, a German multi-utility. The International segment purchases natural gas from one of the eight regional gas distribution companies in the Czech Republic. Oil is also imported into the Czech Republic. The International segment purchases oil from domestic and foreign refineries.
      With respect to the Timber segment, Highland requires an adequate supply of timber to process in its sawmill and kiln operations. Approximately 50% of the timber processed during 2004 came from land owned by Seneca.
      The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2004, this segment purchased 44 Bcf of natural gas, of which 42 Bcf served core market demands. The remaining 2 Bcf largely represents gas used in operations.
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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 deregulation of the natural gas industry has enhanced the competitive position of natural gas relative to other energy sources, such as fuel oil or electricity, by removing some of the historical regulatory impediments to adding customers and responding to market forces. In addition, 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 the Federal Energy Policy Act of 1992 and initiatives undertaken by the FERC and various states. It remains unclear what the impact will be on the Company of any further restructuring in response to legislation or other events.*
      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 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. Regulators in both New York and Pennsylvania have adopted retail competition programs for natural gas supply purchases. However, regulators in Pennsylvania have not pursued such programs recently, and there have been no significant new market entrants in New York. To date, the Utility segment’s traditional distribution function remains largely unchanged; however, the NYPSC continues to encourage customer choice at the retail residential level.
      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 (i.e., bypass). In addition, competition continues with fuel oil suppliers and may increase with electric utilities making retail energy sales.*
      The Utility segment competes, through its unbundled flexible services, in its most vulnerable markets (the large commercial and industrial markets).* The Utility segment continues to (i) develop or promote new sources and uses of natural gas or new services, rates and contracts and (ii) emphasize and provide 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 particularly 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 announced in February 2004, Empire is pursuing a project to expand its natural gas pipeline 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 heading “Investing Cash Flow.”
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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 and SECI each originate and act as operator on most prospects, minimize the risk of exploratory efforts through partnership-type arrangements, apply the latest technology for both exploratory studies and drilling operations, and focus on market niches that suit their size, operating expertise and financial criteria.
Competition: The International Segment
      Horizon competes with other entities seeking to develop or acquire foreign and domestic energy projects. Horizon, through UE, faces competition in the sale of thermal energy. Most customers can opt to install boilers to produce their thermal energy, rather than purchase thermal energy from the district heating system. In addition, UE, which sells electricity at the wholesale level, faces competition in the sale of electricity. UE must submit price bids on an annual basis for the sale of its electricity to the regional distribution company. A large percentage of the electricity purchased by the regional distribution companies is produced by the Czech Republic’s dominant state-owned energy producer.
Competition: The Energy Marketing Segment
      The Energy Marketing segment competes with other marketers of natural gas and with other providers of energy management services. Although the deregulation of natural gas utilities continues to progress, the competition in this area is well developed with regard to price and services from both local and regional 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 hardwoods 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 both nationally and internationally.
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 revenues in New York is mitigated by a weather normalization clause which is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is more than 2.2% warmer than normal results in a surcharge being added to customers’ current bills, while weather that is more than 2.2% 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 design which allows recovery of fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed only to recover the variable costs associated with actual transportation or storage of gas.
      Volumes transported by Empire may vary materially depending on weather, and can have a moderate effect on its revenues. Empire’s allowed rates 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
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designed to recover variable costs associated with actual transportation of gas, to recover return on equity, and to recover income taxes.
      Variations in weather conditions can materially affect the volume of gas consumed by customers of the Energy Marketing segment and the amount of thermal energy consumed by the heating customers of the International segment. Volume variations can have a corresponding impact on revenues within these segments.
      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 out lower-grade species from the timber stands to encourage the growth of higher-grade species. During 2004, several factors, including the sale of acreage in 2003, changes in market demands, and facility upgrades resulted in a change in our cutting schedule and a more level harvest each month.
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 “Other Matters” and in Item 8, Note G — Commitments and Contingencies.
Miscellaneous
      The Company and its wholly-owned or majority-owned subsidiaries had a total of 2,918 full-time employees at September 30, 2004, with 2,055 employees in all of its U.S. operations and 863 employees in its international operations. This is a decrease of 3.9% from the 3,037 total employed at September 30, 2003.
      Agreements covering employees in collective bargaining units in New York were renegotiated, effective as of November 2003, and are scheduled to expire in February 2008. Certain agreements covering employees in collective bargaining units in Pennsylvania were renegotiated, effective November 2003, and are scheduled to expire in April 2009. Other agreements covering employees in collective bargaining units in Pennsylvania were renegotiated, effective November 2003, and are scheduled to expire in May 2009. An agreement covering employees in collective bargaining units in the Czech Republic is scheduled to expire on December 31, 2004. A new four-year contract is currently being negotiated.
      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, 2004(1)

Name and Age (as of		Current Company Positions and Other Material	
September 30, 2004)		Business Experience During Past Five Years	
			
Philip C. Ackerman
(60)	 	Chairman of the Board of Directors since January 2002; Chief Executive Officer since October 2001; President since July 1999; and President of Horizon since September 1995. Mr. Ackerman has served as a Director since March 1994, and previously served as Senior Vice President from June 1989 to July 1999 and President of Distribution Corporation from October 1995 to July 1999.	
David F. Smith
(51)	 	President of Distribution Corporation since July 1999; Senior Vice President of Supply Corporation since July 2000. Mr. Smith served as Senior Vice President of Distribution Corporation from January 1993 to July 1999.	
Dennis J. Seeley
(61)	 	President of Supply Corporation since March 2000; President of Empire since February 2003; Senior Vice President of Distribution Corporation since February 1997. Mr. Seeley served as Vice President of the Company from January 2000 to April 2000.	
James A. Beck
(57)	 	President of Seneca since October 1996 and President of Highland since March 1998.	
Ronald J. Tanski
(52)	 	Treasurer of the Company since April 2004; Controller of the Company from February 2003 through March 2004; Senior Vice President of Distribution Corporation since July 2001; Controller of Distribution Corporation from February 1997 through March 2004; Treasurer of Distribution Corporation since April 2004; Treasurer and Secretary of Supply Corporation since April 2004; Secretary and Treasurer of Horizon since February 1997; and Vice President of Distribution Corporation from April 1993 to July 2001.	
Karen M. Camiolo
(45)	 	Controller of the Company since April 2004; Controller of Distribution Corporation and Supply Corporation since April 2004; Chief Auditor of the Company from July 1994 through March 2004.	
Anna Marie Cellino
(51)	 	Secretary of the Company since October 1995; Senior Vice President of Distribution Corporation since July 2001; and Vice President of Distribution Corporation from June 1994 to July 2001.	
Bruce H. Hale
(55)	 	President of Horizon Power since March 2001; Vice President of Horizon since September 1995. Mr. Hale previously served as Senior Vice President of Supply Corporation from February 1997 to March 2003.	
John R. Pustulka
(52)	 	Senior Vice President of Supply Corporation since July 2001; and Vice President of Supply Corporation from April 1993 to July 2001.	
James D. Ramsdell
(49)	 	Senior Vice President of Distribution Corporation since July 2001; and Vice President of Distribution Corporation from June 1994 to 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 have served or currently serve as officers or directors of other subsidiaries of the Company.	
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Item 2	Properties	
General Information on Facilities
      The investment of the Company in net property, plant and equipment was $3.0 billion at September 30, 2004. Approximately 58% 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 (31%), is primarily located in California, in the Appalachian region of the United States, in Wyoming, in the Gulf Coast region of Texas, Louisiana, and Alabama and in the provinces of Alberta, Saskatchewan and British Columbia in Canada. The remaining investment in net property, plant and equipment consisted primarily of the International segment (7%) which is located in the Czech Republic, the Timber segment (3%) which is located primarily in northwestern Pennsylvania, and All Other and Corporate operations (1%). During the past five years, the Company has made significant additions to property, plant and equipment in order to augment the reserve base of oil and gas in the United States and Canada, and to expand and improve transmission and distribution facilities for both retail and transportation customers. Net property, plant and equipment has increased $646 million, or 27%, since 1999.
      The Utility segment had a net investment in property, plant and equipment of $1.0 billion at September 30, 2004. The net investment in its gas distribution network (including 14,781 miles of distribution pipeline) and its service connections to customers represent approximately 57% and 29%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2004.
      The Pipeline and Storage segment had a net investment of $696.5 million in property, plant and equipment at September 30, 2004. Transmission pipeline represents 37% of this segment’s total net investment and includes 2,575 miles of pipeline required to move large volumes of gas throughout its service area. Storage facilities consist of 32 storage fields, four of which are jointly operated with certain pipeline suppliers, and 439 miles of pipeline. Net investment in storage facilities includes $91.1 million of gas stored underground-noncurrent, representing the cost of the gas required 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 29 compressor stations with 75,306 installed compressor horsepower.
      The Exploration and Production segment had a net investment in property, plant and equipment of $923.7 million at September 30, 2004. Of this amount, $780.9 million relates to properties located in the United States. The remaining net investment of $142.8 million relates to properties located in Canada.
      The International segment had a net investment in property, plant and equipment of $227.9 million at September 30, 2004. This represents UE’s net investment in district heating and electric generation facilities.
      The Timber segment had a net investment in property, plant and equipment of $82.8 million at September 30, 2004. Located primarily in northwestern Pennsylvania, the net investment includes two sawmills and approximately 87,000 acres of land and timber.
      The Utility and Pipeline and Storage segments’ facilities provided the capacity to meet the Company’s 2004 peak day sendout, including transportation service, of 1,756.3 MMcf, which occurred on January 15, 2004. Withdrawals from storage of 736.2 MMcf provided approximately 41.9% of the requirements on that day.
      Company maps are included in exhibit 99.3 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, and in the Gulf Coast region of Texas, Louisiana, and Alabama. Also, Exploration and Production operations are conducted in the provinces of Alberta, Saskatchewan and British Columbia in Canada. Further discussion of oil and gas producing activities is included in Item 8, Note N-Supplementary Information for Oil and Gas Producing Activities.
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Note N sets forth proved developed and undeveloped reserve information for Seneca. During 2004, Seneca’s proved developed and undeveloped reserves decreased modestly from the prior year. Natural gas reserves decreased from 251 Bcf at September 30, 2003 to 225 Bcf at September 30, 2004 and oil reserves decreased from 69,764 Mbbl to 65,213 Mbbl. These decreases are attributed primarily to the fact that U.S. and Canadian production outpaced net extensions and discoveries. Seneca’s proved developed and undeveloped reserves also decreased in 2003 as compared to 2002. Natural gas reserves decreased from 258 Bcf at September 30, 2002 to 251 Bcf at September 30, 2003 and oil reserves decreased from 99,717 Mbbl to 69,764 Mbbl. These decreases are attributed to the following factors: (i) U.S. and Canadian production and sales of Canadian properties (refer to Item 7, MD&A) and (ii) downward reserve revisions primarily related to the Canadian properties sold during the year (reflected in Note N as revisions of previous estimates).
      Seneca’s oil and gas reserves reported in Note N as of September 30, 2004 were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Ralph E. Davis 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 basis of reporting Seneca’s reserves to the EIA is identical to that reported in Note N.
      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	
			
		2004		2003		2002	
							
United States	 	 	 	 	 	 	 	 	 	 	 	 	
Gulf Coast Region	 	 	 	 	 	 	 	 	 	 	 	 	
 	Average Sales Price per Mcf of Gas	 	$	5.61	 	 	$	5.41	 	 	$	2.89	 	
 	Average Sales Price per Barrel of Oil	 	$	35.31	 	 	$	29.17	 	 	$	22.83	 	
 	Average Sales Price per Mcf of Gas (after hedging)	 	$	4.78	 	 	$	4.22	 	 	$	3.69	 	
 	Average Sales Price per Barrel of Oil (after hedging)	 	$	31.51	 	 	$	27.88	 	 	$	22.51	 	
 	Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	 	$	0.60	 	 	$	0.56	 	 	$	0.60	 	
 	Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	 	 	73	 	 	 	75	 	 	 	100	 	
West Coast Region	 	 	 	 	 	 	 	 	 	 	 	 	
 	Average Sales Price per Mcf of Gas	 	$	5.54	 	 	$	5.01	 	 	$	2.86	 	
 	Average Sales Price per Barrel of Oil	 	$	31.89	 	 	$	26.12	 	 	$	19.94	 	
 	Average Sales Price per Mcf of Gas (after hedging)	 	$	5.72	 	 	$	5.12	 	 	$	2.86	 	
 	Average Sales Price per Barrel of Oil (after hedging)	 	$	22.86	 	 	$	23.67	 	 	$	20.09	 	
 	Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	 	$	1.05	 	 	$	1.00	 	 	$	0.81	 	
 	Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	 	 	55	 	 	 	59	 	 	 	63	 	
Appalachian Region	 	 	 	 	 	 	 	 	 	 	 	 	
 	Average Sales Price per Mcf of Gas	 	$	5.91	 	 	$	5.07	 	 	$	3.74	 	
 	Average Sales Price per Barrel of Oil	 	$	31.30	 	 	$	28.77	 	 	$	23.76	 	
 	Average Sales Price per Mcf of Gas (after hedging)	 	$	5.72	 	 	$	5.10	 	 	$	3.74	 	
 	Average Sales Price per Barrel of Oil (after hedging)	 	$	31.30	 	 	$	28.77	 	 	$	23.76	 	
 	Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	 	$	0.54	 	 	$	0.43	 	 	$	0.53	 	
 	Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	 	 	14	 	 	 	14	 	 	 	12	 	
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		For the Year Ended	
		September 30	
			
		2004		2003		2002	
							
Total United States	 	 	 	 	 	 	 	 	 	 	 	 	
 	Average Sales Price per Mcf of Gas	 	$	5.66	 	 	$	5.28	 	 	$	2.99	 	
 	Average Sales Price per Barrel of Oil	 	$	33.13	 	 	$	27.16	 	 	$	21.03	 	
 	Average Sales Price per Mcf of Gas (after hedging)	 	$	5.11	 	 	$	4.52	 	 	$	3.58	 	
 	Average Sales Price per Barrel of Oil (after hedging)	 	$	26.06	 	 	$	25.11	 	 	$	21.01	 	
 	Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	 	$	0.76	 	 	$	0.72	 	 	$	0.67	 	
 	Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	 	 	142	 	 	 	148	 	 	 	175	 	
Canada	 	 	 	 	 	 	 	 	 	 	 	 	
 	Average Sales Price per Mcf of Gas	 	$	4.87	 	 	$	4.67	 	 	$	2.29	 	
 	Average Sales Price per Barrel of Oil	 	$	30.94	 	 	$	26.41	 	 	$	19.94	 	
 	Average Sales Price per Mcf of Gas (after hedging)	 	$	4.87	 	 	$	4.20	 	 	$	3.59	 	
 	Average Sales Price per Barrel of Oil (after hedging)	 	$	30.94	 	 	$	15.85	 	 	$	18.11	 	
 	Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	 	$	1.00	 	 	$	1.65	 	 	$	1.29	 	
 	Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	 	 	22	 	 	 	55	 	 	 	64	 	
Total Company	 	 	 	 	 	 	 	 	 	 	 	 	
 	Average Sales Price per Mcf of Gas	 	$	5.51	 	 	$	5.18	 	 	$	2.88	 	
 	Average Sales Price per Barrel of Oil	 	$	32.98	 	 	$	26.90	 	 	$	20.63	 	
 	Average Sales Price per Mcf of Gas (after hedging)	 	$	5.06	 	 	$	4.47	 	 	$	3.58	 	
 	Average Sales Price per Barrel of Oil (after hedging)	 	$	26.40	 	 	$	21.84	 	 	$	19.94	 	
 	Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	 	$	0.80	 	 	$	0.97	 	 	$	0.84	 	
 	Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	 	 	164	 	 	 	203	 	 	 	239	 	
Productive Wells

							
		United States					

		Gulf Coast		West Coast		Appalachian			
		Region		Region		Region		Total U.S.	
									
At September 30, 2004		Gas		Oil		Gas		Oil		Gas		Oil		Gas		Oil	
																	
Productive Wells — Gross	 	 	32	 	 	 	34	 	 	 	—	 	 	 	1,155	 	 	 	1,912	 	 	 	31	 	 	 	1,944	 	 	 	1,220	 	
Productive Wells — Net	 	 	20	 	 	 	15	 	 	 	—	 	 	 	1,146	 	 	 	1,837	 	 	 	25	 	 	 	1,857	 	 	 	1,186	 	
Productive Wells

					
		Canada		Total Company	
					
At September 30, 2004		Gas		Oil		Gas		Oil	
									
Productive Wells — Gross	 	 	177	 	 	 	49	 	 	 	2,121	 	 	 	1,269	 	
Productive Wells — Net	 	 	124	 	 	 	34	 	 	 	1,981	 	 	 	1,220	 	
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Developed and Undeveloped Acreage

							
		United States					
							
		Gulf		West							
		Coast		Coast		Appalachian		Total				Total	
At September 30, 2004		Region		Region		Region		U.S.		Canada		Company	
													
Developed Acreage 	— Gross	 	 	102,270	 	 	 	9,839	 	 	 	508,466	 	 	 	620,575	 	 	 	109,194	 	 	 	729,769	 	
 	— Net	 	 	76,549	 	 	 	9,469	 	 	 	481,732	 	 	 	567,750	 	 	 	74,302	 	 	 	642,052	 	
Undeveloped Acreage 	— Gross	 	 	206,619	 	 	 	—	 	 	 	464,525	 	 	 	671,144	 	 	 	421,690	 	 	 	1,092,834	 	
 	— Net	 	 	115,909	 	 	 	—	 	 	 	440,004	 	 	 	555,913	 	 	 	316,820	 	 	 	872,733	 	
      As of September 30, 2004, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 142,172 acres in 2005 (106,758 net acres), 98,660 acres in 2006 (91,148 net acres), 130,707 acres in 2007 (80,783 net acres), and 721,295 acres thereafter (594,044 net acres). 
Drilling Activity

					
		Productive		Dry	
					
For the Year Ended September 30		2004		2003		2002		2004		2003		2002	
													
United States	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gulf Coast Region	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net Wells Completed 	— Exploratory	 	 	—	 	 	 	1.25	 	 	 	1.27	 	 	 	0.50	 	 	 	—	 	 	 	3.67	 	
 	 	— Development	 	 	0.65	 	 	 	2.10	 	 	 	0.31	 	 	 	—	 	 	 	—	 	 	 	—	 	
West Coast Region	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net Wells Completed 	— Exploratory	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	— Development	 	 	49.00	 	 	 	30.97	 	 	 	47.99	 	 	 	—	 	 	 	—	 	 	 	2.00	 	
Appalachian Region	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net Wells Completed 	— Exploratory	 	 	—	 	 	 	3.00	 	 	 	3.00	 	 	 	3.00	 	 	 	0.10	 	 	 	1.00	 	
 	 	— Development	 	 	41.00	 	 	 	58.00	 	 	 	27.00	 	 	 	—	 	 	 	—	 	 	 	0.10	 	
Total United States	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net Wells Completed 	— Exploratory	 	 	—	 	 	 	4.25	 	 	 	4.27	 	 	 	3.50	 	 	 	0.10	 	 	 	4.67	 	
 	 	— Development	 	 	90.65	 	 	 	91.07	 	 	 	75.30	 	 	 	—	 	 	 	—	 	 	 	2.10	 	
Canada	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net Wells Completed 	— Exploratory	 	 	52.85	 	 	 	5.00	 	 	 	0.20	 	 	 	6.08	 	 	 	2.50	 	 	 	4.00	 	
 	 	— Development	10.50	 	 	 	17.16	 	 	 	33.70	 	 	 	—	 	 	 	5.00	 	 	 	7.90	 	
Total	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net Wells Completed 	— Exploratory	 	 	52.85	 	 	 	9.25	 	 	 	4.47	 	 	 	9.58	 	 	 	2.60	 	 	 	8.67	 	
 	 	— Development	101.15	 	 	 	108.23	 	 	 	109.00	 	 	 	—	 	 	 	5.00	 	 	 	10.00	 	
Present Activities

								
			United States					
								
			Gulf		West							
			Coast		Coast		Appalachian		Total				Total	
At September 30, 2004		Region		Region		Region		U.S.		Canada		Company	
													
Wells in Process of Drilling(1) 	— Gross	 	 	1.00	 	 	 	5.00	 	 	 	25.00	 	 	 	31.00	 	 	 	1.00	 	 	 	32.00	 	
	— Net	 	 	0.67	 	 	 	5.00	 	 	 	24.05	 	 	 	29.72	 	 	 	1.00	 	 	 	30.72	 	

		
(1) 	Includes wells awaiting completion.	
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Item 3	Legal Proceedings	
      In an action instituted in the New York State Supreme Court, Chautauqua County on January 31, 2000 against Seneca, NFR and “National Fuel Gas Corporation,” Donald J. and Margaret Ortel and Brian and Judith Rapp, “individually and on behalf of all those similarly situated,” allege, in an amended complaint which adds National Fuel Gas Company as a party defendant that (a) Seneca underpaid royalties due under leases operated by it, and (b) Seneca’s co-defendants (i) fraudulently participated in and concealed such alleged underpayment, and (ii) induced Seneca’s alleged breach of such leases. Plaintiffs seek an accounting, declaratory and related injunctive relief, and compensatory and exemplary damages. Defendants have denied each of plaintiffs’ material substantive allegations and set up twenty-five affirmative defenses in separate verified answers.
      A motion was made by plaintiffs on July 15, 2002 to certify a class comprising all persons presently and formerly entitled to receive royalties on the sale of natural gas produced and sold from wells operated in New York by Seneca (and its predecessor Empire Exploration, Inc). On December 23, 2002, the court granted certification of the proposed class, as modified to exclude those leaseholders whose leases provide for calculation of royalties based upon a flat fee, or flat fee per cubic foot of gas produced. The court’s order states that there are approximately 749 potential class members. Discovery has begun on the merits of the claims.
      In an action instituted in the New York State Supreme Court, Kings County on February 18, 2003 against Distribution Corporation and Paul J. Hissin, an unaffiliated third party, plaintiff Donna Fordham-Coleman, as administratrix of the estate of Velma Arlene Fordham, alleges that Distribution Corporation’s denial of natural gas service in November 2000 to the plaintiff’s decedent, Velma Arlene Fordham, caused decedent’s death in February 2001. The plaintiff seeks damages for wrongful death and pain and suffering, plus punitive damages. Distribution Corporation has denied plaintiff’s material allegations, set up seven affirmative defenses in separate verified answers and filed a cross-claim against the co-defendant. Distribution Corporation believes and will vigorously assert that plaintiff’s allegations lack merit. The Court changed venue of the action to New York State Supreme Court, Erie County. The litigation is in the early stages of discovery. For a discussion of a related matter before the NYPSC, refer to Item 7 — MD&A of this report under the heading “Regulatory Matters.”
      On December 22, 2003, the Pennsylvania Department of Environmental Protection (DEP) issued an order to Seneca to halt its timber harvesting operations on 21,000 acres in Cameron, Elk and McKean counties in Pennsylvania. The order asserts certain violations of DEP regulations concerning erosion, sedimentation and stream crossings. The order requires Seneca to apply for certain permits, control erosion, submit plans for removal of water encroachments not included in permit applications, notify the DEP of additional current or planned timber harvesting operations, and grant the DEP access to timber acreage. On January 9, 2004, Seneca filed with the Pennsylvania Environmental Hearing Board (Hearing Board) a notice of appeal, objecting to each finding and order contained in the order, and asserting that the DEP’s findings are factually incorrect, an arbitrary exercise of the DEP’s functions and duties, and contrary to law. Also on January 9, 2004, Seneca filed with the Hearing Board a petition requesting a stay of operation of portions of the order. On January 16, 2004, the parties settled Seneca’s request for a stay. Seneca has resumed its timber harvesting operations pursuant to the terms of the settlement. The settlement preserves various issues raised by the DEP’s order for a hearing on the merits of Seneca’s notice of appeal. The most substantial question involves whether Seneca is required to apply for a permit under Section 102.5(b) of Title 25 of the Pennsylvania Code, governing earth disturbance activities of greater than 25 acres. The DEP takes the position that Seneca must aggregate the acreage of all of its logging sites across its entire 21,000 acre tract for purposes of determining whether its earth disturbing activities meet the 25 acres threshold. Seneca maintains that no permit is required, because the law does not require aggregation and each of its individual logging sites disturbs less than 25 acres. Seneca is engaged in negotiations to resolve this dispute on acceptable terms, and litigation deadlines have been extended to accommodate those discussions.
      The Company believes, based on the information presently known, that the ultimate resolution of these matters, individually or in the aggregate, will not be material to the consolidated financial condition, results of operations, or cash flow of the Company.* No assurances can be given, however, as to the ultimate outcomes
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of these matters, and it is possible that the outcomes, individually or in the aggregate could be material to results of operations or cash flow for a particular quarter or annual period.*
      For a discussion of various environmental and other matters, refer to Item 7, MD&A and Item 8 at Note G — Commitments and Contingencies.
      The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Company’s present liquidity position, nor 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, 2004.
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 D-Capitalization and Short-Term Borrowings and Note M-Market for Common Stock and Related Shareholder Matters (unaudited).
      On July 1, 2004, the Company issued a total of 1,800 unregistered shares of Company common stock to the six non-employee directors of the Company then serving on the Board of Directors, 300 shares to each such director. All of these unregistered shares were issued as partial consideration for such directors’ services during the quarter ended September 30, 2004, pursuant to the Company’s Retainer Policy for Non-Employee Directors. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as transactions not involving a public offering. 
Issuer Purchases of Equity Securities

						Total Number of			
						Shares Purchased		Maximum Number of	
						as Part of Publicly		Shares that May Yet	
		Total Number of				Announced Share		Be Purchased Under	
		Shares		Average Price		Repurchase Plans		Share Repurchase	
Period		Purchased(a)		Paid per Share		or Programs		Plans or Programs	
									
July 1-31, 2004	 	 	59,546	 	 	$	26.04	 	 	 	—	 	 	 	—	 	
Aug. 1-31, 2004	 	 	35,616	 	 	$	26.49	 	 	 	—	 	 	 	—	 	
Sept. 1-30, 2004	 	 	216,163	 	 	$	27.97	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Total	 	 	311,325	 	 	$	27.43	 	 	 	—	 	 	 	—	 	

 
			
(a)		Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices and/or applicable withholding taxes.	
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Item 6	Selected Financial Data(1)	

		Year Ended September 30	
			
		2004		2003		2002		2001		2000	

		(Thousands)	
Summary of Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	2,031,393	 	 	$	2,035,471	 	 	$	1,464,496	 	 	$	2,059,836	 	 	$	1,412,416	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Purchased Gas	 	 	949,452	 	 	 	963,567	 	 	 	462,857	 	 	 	1,002,466	 	 	 	488,383	 	
 	Fuel Used in Heat and Electric Generation	 	 	65,722	 	 	 	61,029	 	 	 	50,635	 	 	 	54,968	 	 	 	54,893	 	
 	Operation and Maintenance	 	 	413,593	 	 	 	386,270	 	 	 	394,157	 	 	 	364,318	 	 	 	350,383	 	
 	Property, Franchise and Other Taxes	 	 	72,111	 	 	 	82,504	 	 	 	72,155	 	 	 	83,730	 	 	 	78,878	 	
 	Depreciation, Depletion and Amortization	 	 	189,538	 	 	 	195,226	 	 	 	180,668	 	 	 	174,914	 	 	 	142,170	 	
 	Impairment of Oil and Gas Producing Properties	 	 	—	 	 	 	42,774	 	 	 	—	 	 	 	180,781	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	 	 	1,690,416	 	 	 	1,731,370	 	 	 	1,160,472	 	 	 	1,861,177	 	 	 	1,114,707	 	
Gain (Loss) on Sale of Timber Properties	 	 	(1,252	)	 	 	168,787	 	 	 	—	 	 	 	—	 	 	 	—	 	
Gain (Loss) on Sale of Oil and Gas Producing Properties	 	 	4,645	 	 	 	(58,472	)	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Operating Income	 	 	344,370	 	 	 	414,416	 	 	 	304,024	 	 	 	198,659	 	 	 	297,709	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Income from Unconsolidated Subsidiaries	 	 	805	 	 	 	535	 	 	 	224	 	 	 	1,794	 	 	 	1,669	 	
 	Impairment of Investment in Partnership	 	 	—	 	 	 	—	 	 	 	(15,167	)	 	 	—	 	 	 	—	 	
 	Other Income	 	 	6,671	 	 	 	6,887	 	 	 	7,017	 	 	 	10,639	 	 	 	6,366	 	
 	Interest Expense on Long-Term Debt	 	 	(83,827	)	 	 	(92,766	)	 	 	(90,543	)	 	 	(81,851	)	 	 	(67,195	)	
 	Other Interest Expense	 	 	(6,763	)	 	 	(12,290	)	 	 	(15,109	)	 	 	(25,294	)	 	 	(32,890	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Income Before Income Taxes and Minority Interest in Foreign Subsidiaries	 	 	261,256	 	 	 	316,782	 	 	 	190,446	 	 	 	103,947	 	 	 	205,659	 	
Income Tax Expense	 	 	92,737	 	 	 	128,161	 	 	 	72,034	 	 	 	37,106	 	 	 	77,068	 	
Minority Interest in Foreign Subsidiaries	 	 	(1,933	)	 	 	(785	)	 	 	(730	)	 	 	(1,342	)	 	 	(1,384	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Income Before Cumulative Effect of Changes in Accounting	 	 	166,586	 	 	 	187,836	 	 	 	117,682	 	 	 	65,499	 	 	 	127,207	 	
Cumulative Effect of Changes in Accounting	 	 	—	 	 	 	(8,892	)	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net Income Available for Common Stock	 	$	166,586	 	 	$	178,944	 	 	$	117,682	 	 	$	65,499	 	 	$	127,207	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
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		Year Ended September 30	
			
		2004		2003		2002		2001		2000	

		(Thousands)	
Per Common Share Data	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Basic Earnings per Common Share	 	$	2.03	 	 	$	2.21	(2)	 	$	1.47	 	 	$	0.83	 	 	$	1.63	 	
 	Diluted Earnings per Common Share	 	$	2.01	 	 	$	2.20	(2)	 	$	1.46	 	 	$	0.82	 	 	$	1.61	 	
 	Dividends Declared	 	$	1.10	 	 	$	1.06	 	 	$	1.03	 	 	$	0.99	 	 	$	0.95	 	
 	Dividends Paid	 	$	1.09	 	 	$	1.05	 	 	$	1.02	 	 	$	0.97	 	 	$	0.94	 	
 	Dividend Rate at Year-End	 	$	1.12	 	 	$	1.08	 	 	$	1.04	 	 	$	1.01	 	 	$	0.96	 	
At September 30:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Number of Common Shareholders	 	 	19,063	 	 	 	19,217	 	 	 	20,004	 	 	 	20,345	 	 	 	21,164	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net Property, Plant and Equipment (Thousands)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Utility	 	$	1,048,428	 	 	$	1,028,393	 	 	$	960,015	 	 	$	945,693	 	 	$	939,753	 	
 	Pipeline and Storage	 	 	696,487	 	 	 	705,927	 	 	 	487,793	 	 	 	483,222	 	 	 	474,972	 	
 	Exploration and Production	 	 	923,730	 	 	 	925,833	 	 	 	1,072,200	 	 	 	1,081,622	 	 	 	998,852	 	
 	International	 	 	227,905	 	 	 	219,199	 	 	 	207,191	 	 	 	178,250	 	 	 	172,602	 	
 	Energy Marketing	 	 	80	 	 	 	171	 	 	 	125	 	 	 	262	 	 	 	360	 	
 	Timber	 	 	82,838	 	 	 	87,600	 	 	 	110,624	 	 	 	90,453	 	 	 	95,607	 	
 	All Other	 	 	21,172	 	 	 	22,042	 	 	 	6,797	 	 	 	1,209	 	 	 	1,241	 	
 	Corporate	 	 	6,124	 	 	 	1,883	 	 	 	—	 	 	 	2	 	 	 	4	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total Net Plant	 	$	3,006,764	 	 	$	2,991,048	 	 	$	2,844,745	 	 	$	2,780,713	 	 	$	2,683,391	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total Assets (Thousands)	 	$	3,711,798	 	 	$	3,719,060	 	 	$	3,401,309	 	 	$	3,445,231	 	 	$	3,251,031	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Capitalization (Thousands)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive Shareholders’ Equity	 	$	1,253,701	 	 	$	1,137,390	 	 	$	1,006,858	 	 	$	1,002,655	 	 	$	987,437	 	
Long-Term Debt, Net of Current Portion	 	 	1,133,317	 	 	 	1,147,779	 	 	 	1,145,341	 	 	 	1,046,694	 	 	 	953,622	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total Capitalization	 	$	2,387,018	 	 	$	2,285,169	 	 	$	2,152,199	 	 	$	2,049,349	 	 	$	1,941,059	 	

		
(1) 	Certain prior year amounts have been reclassified to conform with current year presentation.	
 		
(2) 	Includes cumulative effect of changes in accounting of ($0.11) basic and diluted.	

Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	
OVERVIEW
      The Company is a diversified energy company consisting of six reportable business segments. Refer to Item I, Business, for a more detailed description of each of the segments. This Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), provides information concerning:

			
 	1. 	The critical accounting policies 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;	
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 	5. 	Contractual Obligations; and	
 		
 	6. 	Other Matters, including: a.) disclosures and tables concerning market risk sensitive instruments, b.) rate matters in the Company’s New York, Pennsylvania and FERC regulated jurisdictions, c.) environmental matters, and d.) 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.
      Throughout MD&A, a few events will stand out that impact the results of operations and capital resources and liquidity of the Company for 2004 and 2003. First, the Company, in its Exploration and Production segment, sold its Southeast Saskatchewan oil and gas properties in 2003 after a thorough review of the economics of its non-regulated business. These properties were sold given their overall marginal contribution to earnings. Second, the Company’s Exploration and Production segment benefited from higher commodity prices in 2004. Third, the Company, in its Pipeline and Storage segment, purchased Empire State Pipeline (Empire) from Duke Energy Corporation on February 6, 2003. Empire was acquired because the Company believes that the pipeline better positions the Company to bring Canadian gas supplies into the East Coast markets of the United States as demand for natural gas along the East Coast increases.* In furtherance of that objective, in February 2004, the Company announced that it is pursuing an extension of the Empire State Pipeline as an upstream supply link for Phase I of the Millennium Pipeline. Fourth, the Company, in its Timber segment, sold approximately 70,000 acres of timber properties in August 2003 as a means of financing its acquisition of Empire. The Company recognized the concerns about its debt to capital ratio after the Empire acquisition and therefore sold these timber properties to reduce the short-term debt used to initially finance the acquisition.
      Another event, which occurred in 2003 and is discussed more fully in Item 8 at Note J – Acquisitions, is the acquisition of all of the partnership interests in Toro Partners, L.P. (Toro). The Company has been successful in operating landfill gas projects, where the gas is used to generate electricity, and this acquisition allows the Company to operate short-distance landfill gas pipelines that purchase, transport and resell landfill gas to customers.
      Overall, the Company emphasized debt reduction in 2004 and, to that end, has reduced its debt to capitalization ratio from .57 at September 30, 2003 to .51 at September 30, 2004.
CRITICAL ACCOUNTING POLICIES
      The Company has prepared its consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. 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 policies, which are defined as those policies whereby judgments or uncertainties could affect the application of those 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.
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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). Unevaluated properties are excluded from the depletion calculation until they are evaluated. Once they are evaluated, costs associated with these properties are transferred to the pool of costs being depleted.
      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 is performed on a country-by-country basis and determines a limit, or ceiling, to 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 revenues 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 taxes. 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 or subtractions to 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. The Company recorded non-cash impairments relating to its Canadian properties in 2003 which amounted to $28.9 million (after tax) and resulted from downward revisions to crude oil reserves (related to the Canadian properties sold) as well as a decline in crude oil prices subsequent to the March 31, 2003 ceiling test calculation. At September 30, 2003, the capitalized costs of Canadian oil and gas properties less accumulated depletion and related deferred taxes were nearly equal to the ceiling for Canadian oil and gas properties. During 2004, the Canadian oil and gas properties passed the quarterly ceiling tests but capitalized costs less accumulated depletion and related deferred taxes were still nearly equal to the ceiling at September 30, 2004. A downward revision to reserves or prices could result in an impairment of the Canadian oil and gas properties in the future.
      It is difficult to predict what factors could lead to future impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations or subtractions to proved reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.
      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 Statement of Financial Accounting Standards No. 71, “Accounting for the Effect of Certain Types of Regulation” 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
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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 B — 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, options and futures contracts. The Company, in its Pipeline and Storage segment, uses an interest rate collar to limit interest rate fluctuations on certain variable rate debt. In accordance with the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, the Company accounts for these instruments as effective cash flow hedges or fair value hedges. As such, 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, gains or losses from the derivative financial instruments would be marked-to-market on 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 value of the non exchange-traded derivative financial instruments are based on valuations determined by the counterparties. Refer to the “Market Risk Sensitive Instruments” section in Item 7, MD&A, 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 annual rate of increase in per capita cost of covered medical and prescription benefits. Changes in actuarial assumptions and actuarial experience 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.” 
RESULTS OF OPERATIONS
EARNINGS
2004 Compared with 2003
      The Company’s earnings were $166.6 million in 2004 compared with earnings of $178.9 million in 2003. The decrease in earnings is primarily the result of lower earnings in the Timber and Utility segments partially offset by higher earnings in the Exploration and Production, International, and Pipeline and Storage
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segments, as shown in the table below. Earnings were impacted by several events in 2004 and 2003, including:

	2004 Events	

			
 	• 	A $5.2 million reduction to deferred income tax expense in the International segment resulting from a change in the statutory income tax rate in the Czech Republic;	
 		
 	• 	Settlement of a pension obligation which resulted in the recording of additional expense amounting to $6.4 million after tax, allocated among the segments as follows: $2.2 million to the Utility segment ($1.2 million in the New York jurisdiction and $1.0 million in the Pennsylvania jurisdiction), $2.0 million to the Pipeline and Storage segment ($1.8 million to Supply Corporation and $0.2 million to Empire State Pipeline), $0.9 million to the Exploration and Production segment, $0.4 million to the International segment, $0.3 million to the Energy Marketing segment and $0.6 million to the Corporate and All Other categories;	
 		
 	• 	An adjustment to the 2003 sale of the Company’s Southeast Saskatchewan oil and gas properties in the Exploration and Production segment which increased 2004 earnings by $4.6 million; and	
 		
 	• 	An adjustment to the Company’s 2003 sale of its timber properties in the Timber segment, which reduced 2004 earnings by $0.8 million after tax.	

	2003 Events	

			
 	• 	The Company’s Timber segment completed the sale of approximately 70,000 acres of its timber property, recording an after tax gain of $102.2 million;	
 		
 	• 	The Company’s Exploration and Production segment completed the sale of its Southeast Saskatchewan oil and gas properties in Canada, recording an after tax loss of $39.6 million;	
 		
 	• 	The Company’s Exploration and Production segment recorded after tax impairment charges of $28.9 million related to its Canadian oil and gas assets;	
 		
 	• 	An impairment in the amount of $8.3 million, representing the cumulative effect of a change in accounting for goodwill in the Company’s International segment; and	
 		
 	• 	A reduction in the amount of $0.6 million, representing the cumulative effect of a change in accounting for plugging and abandonment costs in the Company’s Exploration and Production segment.	
      For a more complete discussion of the cumulative effect of changes in accounting, refer to Note A — Summary of Significant Accounting Policies in Item 8 of this report. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.
2003 Compared with 2002
      The Company’s earnings were $178.9 million in 2003 compared with earnings of $117.7 million in 2002. The increase in earnings of $61.2 million was primarily the result of higher earnings in the Timber, Utility, and Pipeline and Storage segments partially offset by lower earnings in the Energy Marketing segment and losses in the Exploration and Production and International segments, as shown in the table below. This earnings fluctuation was impacted by the 2003 events listed above. Also, in 2002, earnings included a non-cash impairment of the Company’s investment in the Independence Pipeline project in the Pipeline and Storage segment in the amount of $9.9 million (after tax). Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.
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Earnings (Loss) by Segment

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands)	
Utility	 	$	46,718	 	 	$	56,808	 	 	$	49,505	 	
Pipeline and Storage	 	 	47,726	 	 	 	45,230	 	 	 	29,715	 	
Exploration and Production	 	 	54,344	 	 	 	(31,930	)	 	 	26,851	 	
International	 	 	5,982	 	 	 	(9,623	)	 	 	(4,443	)	
Energy Marketing	 	 	5,535	 	 	 	5,868	 	 	 	8,642	 	
Timber	 	 	5,637	 	 	 	112,450	 	 	 	9,689	 	
 	 	 		 	 	 		 	 	 		 	
 	Total Reportable Segments	 	 	165,942	 	 	 	178,803	 	 	 	119,959	 	
All Other	 	 	1,530	 	 	 	193	 	 	 	(885	)	
Corporate	 	 	(886	)	 	 	(52	)	 	 	(1,392	)	
 	 	 		 	 	 		 	 	 		 	
 	Total Consolidated	 	$	166,586	 	 	$	178,944	 	 	$	117,682	 	
 	 	 		 	 	 		 	 	 		 	
UTILITY
Revenues
Utility Operating Revenues

			
		Year Ended September 30	
			
		2004		2003		2002	
							
				(Thousands)			
Retail Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Residential	 	$	808,740	 	 	$	801,984	 	 	$	538,345	 	
 	Commercial	 	 	137,092	 	 	 	137,905	 	 	 	86,963	 	
 	Industrial	 	 	17,454	 	 	 	23,263	 	 	 	18,332	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	963,286	 	 	 	963,152	 	 	 	643,640	 	
 	 	 		 	 	 		 	 	 		 	
Off-System Sales	 	 	106,841	 	 	 	107,220	 	 	 	68,606	 	
Transportation	 	 	80,563	 	 	 	86,374	 	 	 	83,267	 	
Other	 	 	1,951	 	 	 	6,237	 	 	 	(1,292	)	
 	 	 		 	 	 		 	 	 		 	
 	 	$	1,152,641	 	 	$	1,162,983	 	 	$	794,221	 	
 	 	 		 	 	 		 	 	 		 	
Utility Throughput — million cubic feet (MMcf) 

			
		Year Ended September 30	
			
		2004		2003		2002	
							
Retail Sales:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Residential	 	 	70,109	 	 	 	76,449	 	 	 	64,639	 	
 	Commercial	 	 	12,752	 	 	 	14,177	 	 	 	11,549	 	
 	Industrial	 	 	2,261	 	 	 	3,537	 	 	 	3,715	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	85,122	 	 	 	94,163	 	 	 	79,903	 	
 	 	 		 	 	 		 	 	 		 	
Off-System Sales	 	 	16,839	 	 	 	17,999	 	 	 	21,541	 	
Transportation	 	 	60,565	 	 	 	64,232	 	 	 	61,909	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	162,526	 	 	 	176,394	 	 	 	163,353	 	
 	 	 		 	 	 		 	 	 		 	
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Degree Days

									
								Percent (Warmer)	
								Colder Than	
									
Year Ended September 30				Normal		Actual		Normal		Prior Year	
											
2004:	 	 	Buffalo	 	 	 	6,729	 	 	 	6,572	 	 	 	(2.3	)%	 	 	(7.9	)%	
 	 	 	Erie	 	 	 	6,277	 	 	 	6,086	 	 	 	(3.0	)%	 	 	(10.1	)%	
2003:	 	 	Buffalo	 	 	 	6,815	 	 	 	7,137	 	 	 	4.7	%	 	 	22.9	%	
 	 	 	Erie	 	 	 	6,135	 	 	 	6,769	 	 	 	10.3	%	 	 	26.9	%	
2002:	 	 	Buffalo	 	 	 	6,847	 	 	 	5,808	 	 	 	(15.2	)%	 	 	(12.6	)%	
 	 	 	Erie	 	 	 	6,146	 	 	 	5,334	 	 	 	(13.2	)%	 	 	(16.0	)%	
2004 Compared with 2003
      Operating revenues for the Utility segment decreased $10.3 million in 2004 compared with 2003. This resulted largely from a decrease in transportation revenues of $5.8 million and a decrease in other revenues of $4.3 million. Transportation revenues decreased because of lower volumes being transported as a result of fuel switching, a general economic downturn in the Utility segment’s service territory and warmer weather, as shown in the degree day table above. Retail revenues did not change significantly from the prior year as the impact to revenues of lower retail sales volumes was largely offset by the recovery of higher gas costs (gas costs are recovered dollar for dollar in revenues) and a base rate increase in the Utility segment’s Pennsylvania jurisdiction. The recovery of higher gas costs resulted from a much higher cost of purchased gas. See further discussion of purchased gas below under the heading “Purchased Gas.” Warmer weather and lower customer usage per account were the major factors in the decrease in retail sales volumes. The decrease in retail industrial sales volumes can be attributed to fuel switching and a general economic downturn in the Utility segment’s service territory.
      The decrease in other operating revenues is largely related to the three-year rate settlement approved by the NYPSC which ended on September 30, 2003. As part of the three-year rate settlement, 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 2003, Distribution Corporation utilized $7.6 million of the cost mitigation reserve by recording $7.6 million of other operating revenues. While the three-year rate settlement was extended for an additional year, the provisions of the settlement which gave rise to the other operating revenues in 2003 did not continue in 2004, causing other operating revenues to decrease by $7.6 million in 2004. The impact of utilizing a portion of the cost mitigation reserve in revenues in 2003 was offset by an equal amount of operation and maintenance expense and interest expense (thus there is no earnings impact). Partially offsetting this decrease in revenues, in accordance with the three-year rate settlement which ended on September 30, 2003, Distribution Corporation recorded a refund provision of $4.0 million as a reduction of other operating revenues. While the provisions of the settlement were extended for a one-year period, as previously discussed, this refund provision did not recur in 2004 because the New York rate jurisdiction’s earnings did not exceed the sharing threshold. The refund provision relates to a 50% sharing with customers of earnings over a predetermined amount.
      Effective September 22, 2004, Distribution Corporation stopped making off-system sales as a result of the FERC’s Order 2004, “Standards of Conduct for Transmission Providers,” as discussed more fully in the Rate Matters section below. As a result of this decision, Distribution Corporation most likely will not have any off-system sales in 2005.* However, due to profit sharing with retail customers, the margins resulting from off-system sales have been minimal and there should be no material impact to margins in 2005.*
2003 Compared with 2002
      Operating revenues for the Utility segment increased $368.8 million in 2003 compared with 2002. This resulted from an increase in retail and off-system gas sales revenues of $319.5 million and $38.6 million, respectively. Transportation and other revenues also increased by $3.1 million and $7.5 million, respectively.
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      The increase in retail gas sales revenues for the Utility segment was largely a function of the recovery of higher gas costs, coupled with an increase in retail sales volumes, as shown above. The increase in retail sales volumes was primarily the result of colder weather, as shown in the degree day table above. Off-system sales revenues increased because of higher gas prices, which more than offset lower volumes. However, due to profit sharing with retail customers, the margins resulting from off-system sales were minimal. Colder weather also caused transportation revenues and volumes to increase.
      The increase in other operating revenues is largely related to the three-year rate settlement which ended on September 30, 2003, as discussed above. In 2003, Distribution Corporation utilized $7.6 million of the cost mitigation reserve by recording $7.6 million of other operating revenues, compared to $2.2 million in 2002. In both years, the impact of reversing a portion of the cost mitigation reserve was offset by an equal amount of operation and maintenance expense and interest expense (thus there is no earnings impact). The increase in other operating revenues also reflects a $1.3 million decrease in refund provisions. In accordance with the three-year rate settlement discussed above, Distribution Corporation recorded refund provisions related to a 50% sharing with customers of earnings over a predetermined amount. The refund provisions associated with this earnings sharing mechanism were $4.0 million and $5.3 million in 2003 and 2002, respectively.
Earnings
2004 Compared with 2003
      The Utility segment’s earnings in 2004 were $46.7 million, a decrease of $10.1 million when compared with earnings of $56.8 million in 2003. The major factors driving this decrease were an increase in pension and other post-retirement expenses of $9.9 million after tax, higher bad debt expenses of $3.8 million after tax, warmer weather in the Pennsylvania jurisdiction ($2.5 million after tax), and lower usage per customer account in the New York jurisdiction ($2.2 million after tax). These negative factors were partially offset by the absence of a refund provision in the New York jurisdiction in 2004 related to an earnings sharing mechanism in the New York jurisdiction ($2.6 million after tax), as discussed above. Other offsetting factors included a base rate increase in the Pennsylvania jurisdiction of $1.5 million after tax and lower interest expense of $4.7 million after tax.
      The increase in pension and other post-retirement expenses referred to above can be attributed largely to three factors. First, in accordance with the one-year settlement extension commencing on October 1, 2003 in the New York rate jurisdiction (referred to above), the Company was required to record an additional $8.0 million before tax ($5.2 million after tax) of pension and other post-retirement expense for the year ended September 30, 2004 without a corresponding increase in revenues. Second, the Utility segment recorded $2.2 million of expense after tax associated with the settlement of a pension obligation. Third, pension and other post-retirement expenses in the Pennsylvania rate jurisdiction increased by $2.5 million after tax as the rate settlement in that jurisdiction reflected higher pension funding amounts and the amortization of previous other post-retirement deferrals.
      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 2004, the WNC preserved $1.0 million of earnings since the weather was warmer than normal in the New York service territory. For 2003, the WNC reduced earnings by approximately $3.8 million because it was colder than normal in the New York service territory.
2003 Compared with 2002
      The Utility segment’s earnings in 2003 were $56.8 million, an increase of $7.3 million when compared with earnings of $49.5 million in 2002. The major factor driving this increase was the impact of colder weather in the Utility segment’s Pennsylvania jurisdiction, which contributed approximately $5.6 million to
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the increase in earnings. The remainder of the increase was primarily attributable to lower interest expense, primarily on deferred gas costs (which declined approximately $1.0 million after tax).
      In 2003, the WNC reduced earnings by approximately $3.8 million because it was colder than normal in the New York service territory. For 2002, the WNC preserved earnings of approximately $9.9 million because it was warmer than normal in the New York service territory.
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 $7.30 per thousand cubic feet (Mcf) in 2004, an increase of 5% from the average cost of $6.94 per Mcf in 2003. The average cost of purchased gas in 2003 was 48% higher than the average cost of $4.68 per Mcf in 2002. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1. 
PIPELINE AND STORAGE
Revenues
Pipeline and Storage Operating Revenues

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands)	
Firm Transportation	 	$	120,443	 	 	$	109,508	 	 	$	88,082	 	
Interruptible Transportation	 	 	3,084	 	 	 	3,944	 	 	 	3,315	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	123,527	 	 	 	113,452	 	 	 	91,397	 	
 	 	 		 	 	 		 	 	 		 	
Firm Storage Service	 	 	63,962	 	 	 	63,223	 	 	 	62,733	 	
Interruptible Storage Service	 	 	20	 	 	 	36	 	 	 	7	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	63,982	 	 	 	63,259	 	 	 	62,740	 	
 	 	 		 	 	 		 	 	 		 	
Other	 	 	22,198	 	 	 	24,709	 	 	 	13,247	 	
 	 	 		 	 	 		 	 	 		 	
 	 	$	209,707	 	 	$	201,420	 	 	$	167,384	 	
 	 	 		 	 	 		 	 	 		 	
Pipeline and Storage Throughput — (MMcf)

			
		Year Ended September 30	
			
		2004		2003		2002	
							
Firm Transportation	 	 	338,991	 	 	 	340,925	 	 	 	290,507	 	
Interruptible Transportation	 	 	12,692	 	 	 	10,004	 	 	 	7,315	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	351,683	 	 	 	350,929	 	 	 	297,822	 	
 	 	 		 	 	 		 	 	 		 	
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2004 Compared with 2003
      Operating revenues for the Pipeline and Storage segment increased $8.3 million in 2004 as compared with 2003. The acquisition of Empire from Duke Energy Corporation on February 6, 2003 was a significant factor contributing to the revenue increase. For 2004, Empire recorded operating revenues of $33.4 million ($32.3 million in firm transportation revenues, $0.3 million in interruptible transportation revenues and $0.8 million in other revenues). For the period of February 6, 2003 to September 30, 2003, Empire recorded operating revenues of $20.9 million ($19.8 million in firm transportation revenues, $0.8 million in interruptible transportation revenues and $0.3 million in other revenues). Another factor contributing to the increase in operating revenues in the Pipeline and Storage segment was a $5.0 million increase in revenues from unbundled pipeline sales included in other revenues in the table above due to higher natural gas commodity prices and higher volumes. These increases to operating revenues were partially offset by lower intercompany rental income of approximately $6.5 million and lower cashout revenues of $1.3 million, both of which are included in other revenues in the table above. Cashout revenues represent a cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper. Cashout revenues are completely offset by purchased gas expense. While transportation volumes increased 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.
2003 Compared with 2002
      Operating revenues for the Pipeline and Storage segment increased $34.0 million in 2003 as compared with 2002. For 2003, the acquisition of Empire was a significant factor contributing to the revenue increase. For the period of February 6, 2003 to September 30, 2003, Empire recorded operating revenues of $20.9 million. Another factor contributing to the increase in operating revenues in the Pipeline and Storage segment was a $6.5 million increase in revenues from unbundled pipeline sales included in other revenues in the table above due primarily to higher natural gas commodity prices and volumes. While transportation volumes increased 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
2004 Compared with 2003
      The Pipeline and Storage segment’s earnings in 2004 were $47.7 million, an increase of $2.5 million when compared with earnings of $45.2 million in 2003. The increase can be attributed primarily to the earnings impact of the increase in revenues from unbundled pipeline sales of $3.2 million after tax, discussed above, as well as the increased earnings contribution from Empire of $2.8 million. Also, Supply Corporation interest expense decreased by $1.9 million after tax. Offsetting these increases, Supply Corporation recorded $1.8 million of expense after tax associated with the settlement of a pension obligation in 2004. Supply Corporation also experienced an earnings impact associated with higher operation and maintenance expense of $1.5 million after tax.
2003 Compared with 2002
      The Pipeline and Storage segment’s earnings in 2003 were $45.2 million, an increase of $15.5 million when compared with earnings of $29.7 million in 2002. A major factor in the earnings increase was the fact that 2002 included an after tax impairment charge of $9.9 million ($15.2 million pre tax) related to the Company’s investment in Independence Pipeline Company (a partnership discontinued in 2002 that had proposed to construct and operate a 400-mile pipeline to transport natural gas from Defiance, Ohio to Leidy, Pennsylvania). Higher revenues from unbundled pipeline sales ($4.2 million after tax) were also a contributor to the earnings increase. The Empire acquisition in February 2003 contributed $3.0 million to 2003 earnings.
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EXPLORATION AND PRODUCTION
Revenues
Exploration and Production Operating Revenues

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands)	
Gas (after Hedging)	 	$	167,127	 	 	$	150,982	 	 	$	148,467	 	
Oil (after Hedging)	 	 	119,564	 	 	 	147,101	 	 	 	152,746	 	
Gas Processing Plant	 	 	28,614	 	 	 	28,879	 	 	 	16,995	 	
Other	 	 	1,815	 	 	 	1,308	 	 	 	6,627	 	
Intrasegment Elimination(1)	 	 	(23,422	)	 	 	(22,956	)	 	 	(13,855	)	
 	 	 		 	 	 		 	 	 		 	
 	 	$	293,698	 	 	$	305,314	 	 	$	310,980	 	

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

			
		Year Ended September 30	
			
		2004		2003		2002	
							
Gas Production (MMcf)	 	 	 	 	 	 	 	 	 	 	 	 	
 	Gulf Coast	 	 	17,596	 	 	 	18,441	 	 	 	25,776	 	
 	West Coast	 	 	4,057	 	 	 	4,467	 	 	 	4,889	 	
 	Appalachia	 	 	5,132	 	 	 	5,123	 	 	 	4,402	 	
 	Canada	 	 	6,228	 	 	 	5,774	 	 	 	6,387	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	33,013	 	 	 	33,805	 	 	 	41,454	 	
 	 	 		 	 	 		 	 	 		 	
Oil Production (Mbbl)	 	 	 	 	 	 	 	 	 	 	 	 	
 	Gulf Coast	 	 	1,534	 	 	 	1,473	 	 	 	1,815	 	
 	West Coast	 	 	2,650	 	 	 	2,872	 	 	 	3,004	 	
 	Appalachia	 	 	20	 	 	 	10	 	 	 	9	 	
 	Canada	 	 	324	 	 	 	2,382	 	 	 	2,834	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	4,528	 	 	 	6,737	 	 	 	7,662	 	
 	 	 		 	 	 		 	 	 		 	
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Average Prices

			
		Year Ended September 30	
			
		2004		2003		2002	
							
Average Gas Price/ Mcf	 	 	 	 	 	 	 	 	 	 	 	 	
 	Gulf Coast	 	$	5.61	 	 	$	5.41	 	 	$	2.89	 	
 	West Coast	 	$	5.54	 	 	$	5.01	 	 	$	2.86	 	
 	Appalachia	 	$	5.91	 	 	$	5.07	 	 	$	3.74	 	
 	Canada	 	$	4.87	 	 	$	4.67	 	 	$	2.29	 	
 	Weighted Average	 	$	5.51	 	 	$	5.18	 	 	$	2.88	 	
 	Weighted Average After Hedging(1)	 	$	5.06	 	 	$	4.47	 	 	$	3.58	 	
Average Oil Price/ Barrel (bbl)	 	 	 	 	 	 	 	 	 	 	 	 	
 	Gulf Coast	 	$	35.31	 	 	$	29.17	 	 	$	22.83	 	
 	West Coast(2)	 	$	31.89	 	 	$	26.12	 	 	$	19.94	 	
 	Appalachia	 	$	31.30	 	 	$	28.77	 	 	$	23.76	 	
 	Canada	 	$	30.94	 	 	$	26.41	 	 	$	19.94	 	
 	Weighted Average	 	$	32.98	 	 	$	26.90	 	 	$	20.63	 	
 	Weighted Average After Hedging(1)	 	$	26.40	 	 	$	21.84	 	 	$	19.94	 	

		
(1) 	Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note E — Financial Instruments in Item 8 of this report.	
 		
(2) 	Includes low gravity oil which generally sells for a lower price.	
2004 Compared with 2003
      Operating revenues for the Exploration and Production segment decreased $11.6 million in 2004 as compared with 2003. Oil production revenue after hedging decreased $27.5 million due to a 2,209 Mbbl decline in production offset partly by higher weighted average prices after hedging ($4.56 per barrel). Most of the decrease in oil production occurred in Canada (a 2,058 Mbbl decrease) as a result of the September 2003 sale of the Company’s Southeast Saskatchewan properties, which is discussed below. Gas production revenue after hedging increased $16.1 million. Increases in the weighted average price of gas after hedging ($0.59 per Mcf) more than offset an overall decrease in gas production. Most of the decrease in gas production occurred in the Gulf Coast (an 845 MMcf decline), which is consistent with the expected decline rates in the region. Lower West Coast production (a 410 MMcf decline), down mainly due to a decline in this segment’s South Lost Hills wells, was more than offset by a 454 MMcf increase in Canadian gas production. The increase in Canadian gas production is attributable to additional drilling in East Central Alberta. The decline in the South Lost Hills wells was attributable to the maturing of the wells.
      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.
2003 Compared with 2002
      Operating revenues for the Exploration and Production segment decreased $5.7 million in 2003 as compared with 2002. Oil production revenue after hedging decreased $5.6 million due to a 925,000 barrel decline in production offset partly by higher weighted average prices after hedging ($1.90 per barrel). Gas production revenue after hedging increased $2.5 million. Increases in the weighted average price of gas after hedging ($0.89 per Mcf) more than offset an overall decrease in gas production. Most of the decrease in gas production occurred in the Gulf Coast (a 7,335 MMcf decline). The Company had anticipated some of this decline in gas and oil production due to reduced activity in the Gulf Coast region. Other factors in the overall production decrease included an outside-operated offshore pipeline leak that required four key producing blocks to be shut-in for ten days, and a decline in drilling activity in Canada related to a decision to sell the
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Company’s Southeast Saskatchewan properties. Also, earlier in the year certain production in the Gulf Coast region was shut-in during Hurricane Lili and some of those wells did not return to pre-hurricane production levels. Gas processing plant revenues increased $11.9 million due to higher gas prices (because there is a similar increase in purchased gas expense, the impact on earnings is insignificant). Other revenues decreased $5.3 million largely due to the Exploration and Production segment experiencing negative mark-to-market adjustments on derivative financial instruments of $1.9 million during 2003 compared to positive mark-to-market adjustments on derivative financial instruments of $2.7 million in 2002.
Earnings
2004 Compared with 2003
      The Exploration and Production segment’s earnings in 2004 were $54.3 million, an increase of $86.2 million when compared with a loss of $31.9 million in 2003. Earnings were impacted by a few events. In 2003, the Company sold its Southeast Saskatchewan properties, recording an after tax loss of $39.6 million. In 2004, the Company recorded an adjustment to the sale of its Southeast Saskatchewan properties which increased 2004 earnings by $4.6 million. When the transaction closed in September 2003, the initial proceeds received were subject to an adjustment based on actual working capital and the resolution of certain income tax matters. Those items were resolved with the buyer in 2004 and, as a result, the Company received an additional $4.6 million of sales proceeds. The Company recorded impairment charges of $28.9 million after tax in 2003 related to its Canadian oil and gas properties. Also contributing to the increase was the fact that the loss in 2003 included a charge of $0.6 million representing the cumulative effect of a change in accounting for plugging and abandonment costs. These events sum up to $73.7 million of the overall earnings increase of $86.2 million. The remaining increase can be attributed to decreases in depletion, lease operating, and interest expense of $6.2 million after tax, $15.9 million after tax, and $1.7 million after tax, respectively, which more than offset the earnings impact of a $7.4 million decrease in oil and gas revenues, discussed above, and a $3.2 million increase in income tax expense due to a higher effective tax rate. The decrease in depletion and lease operating expenses primarily reflects the absence of the Company’s former Southeast Saskatchewan properties from results of operations in 2004. The decrease in interest expense was the result of lower debt balances. The higher effective tax rate resulted from the elimination of cross-border intercompany loans in September 2003 as a result of the sale of the Southeast Saskatchewan properties.
2003 Compared with 2002
      The Exploration and Production segment experienced a loss of $31.9 million in 2003, a decrease of $58.8 million when compared with earnings of $26.9 million in 2002. The main reason for this decrease was the loss of $39.6 million recorded upon the sale of the Company’s Southeast Saskatchewan oil and gas properties. During 2003, the Company reviewed the economics of its non-regulated business including certain oil and gas properties. The Southeast Saskatchewan properties were identified as a candidate for sale given their overall marginal contribution to earnings. Impairment charges of $28.9 million after tax recorded in 2003 related to the Company’s Canadian oil and gas assets also contributed to the decrease. Lower oil and gas revenues, as discussed above, decreased earnings by approximately $2.0 million. As an offset, the Exploration and Production segment experienced lower depletion expense of $2.9 million after tax (attributable to the production decline) and lower general and administrative expenses of $2.1 million after tax (attributable to cost-cutting efforts in Canada). Another offsetting factor was a lower effective income tax rate, which benefitted earnings by approximately $3.4 million.
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INTERNATIONAL
Revenues
International Operating Revenues

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands)	
Heating	 	$	88,395	 	 	$	80,752	 	 	$	65,386	 	
Electricity	 	 	30,949	 	 	 	29,386	 	 	 	26,960	 	
Other	 	 	4,081	 	 	 	3,932	 	 	 	2,969	 	
 	 	 		 	 	 		 	 	 		 	
 	 	$	123,425	 	 	$	114,070	 	 	$	95,315	 	
 	 	 		 	 	 		 	 	 		 	
International Heating and Electric Volumes

			
		Year Ended September 30	
			
		2004		2003		2002	
							
Heating Sales (Gigajoules)(1)	 	 	8,538,554	 	 	 	8,766,567	 	 	 	8,689,887	 	
Electricity Sales (megawatt hours)	 	 	936,877	 	 	 	973,968	 	 	 	972,832	 	

		
(1) 	Gigajoules = one billion joules. A joule is a unit of energy.	
2004 Compared with 2003
      Operating revenues for the International segment increased $9.4 million in 2004 as compared with 2003. Substantially all of this increase can be attributed to an increase in the value of the Czech koruna compared to the U.S. dollar.
2003 Compared with 2002
      Operating revenues for the International segment increased $18.8 million in 2003 as compared with 2002. Substantially all of this increase can be attributed to an increase in the value of the Czech koruna compared to the U.S. dollar.
Earnings
2004 Compared with 2003
      The International segment’s earnings in 2004 were $6.0 million, an increase of $15.6 million when compared with a loss of $9.6 million in 2003. Earnings were impacted by two events. During 2004, the government in the Czech Republic enacted legislation that gradually reduces the corporate statutory income tax rate from 31% to 24% over a three-year period commencing January 1, 2004. In accordance with accounting principles generally accepted in the United States of America (GAAP), the Company recorded the full benefit resulting from the change in the income tax rate ($5.2 million) as a reduction to deferred income tax expense during 2004. During 2003, the Company recorded a $8.3 million impairment charge resulting from the Company’s change in accounting for goodwill, as discussed below. These two events account for $13.5 million of the earnings increase in the International segment. An increase in the value of the Czech koruna compared to the U.S. dollar improved earnings by approximately $1.1 million.
2003 Compared with 2002
      The International segment experienced a loss of $9.6 million in 2003 compared with a loss of $4.4 million in 2002. This decrease can be attributed primarily to an $8.3 million impairment charge, resulting from the Company’s change in accounting for goodwill. The Company’s goodwill balance as of October 1, 2002 totaled $8.3 million and was related to the Company’s investments in the Czech Republic,
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which are included in the International segment. In accordance with SFAS 142, “Goodwill and Other Intangible Assets” (SFAS 142), the Company stopped amortization of goodwill and tested its goodwill for impairment as of October 1, 2002. The Company used discounted cash flows to estimate the fair value of its goodwill at October 1, 2002 and determined that the goodwill had no remaining value. Based on projected restructuring in the Czech Republic electricity market, the Company could not be assured that the level of future cash flows from the Company’s investments in the Czech Republic would attain the level that was originally forecasted.* In accordance with SFAS 142, this impairment was reported as a cumulative effect of a change in accounting in the quarter ending December 31, 2002. Partially offsetting the negative impact of the impairment, an increase in the value of the Czech koruna compared to the U.S. dollar reduced the 2003 loss by approximately $1.0 million. Lower operating costs at the U.S. level (primarily lower project development costs and pension costs) further reduced the 2003 loss by approximately $1.0 million.
ENERGY MARKETING
Revenues
Energy Marketing Operating Revenues

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands)	
Natural Gas (after Hedging)	 	$	283,747	 	 	$	304,390	 	 	$	151,219	 	
Other	 	 	602	 	 	 	270	 	 	 	38	 	
 	 	 		 	 	 		 	 	 		 	
 	 	$	284,349	 	 	$	304,660	 	 	$	151,257	 	
 	 	 		 	 	 		 	 	 		 	
Energy Marketing Volumes

			
		Year Ended September 30	
			
		2004		2003		2002	
							
Natural Gas — (MMcf)	 	 	41,651	 	 	 	45,135	 	 	 	33,042	 	
2004 Compared with 2003
      Operating revenues for the Energy Marketing segment decreased $20.3 million in 2004 as compared with 2003. This decrease primarily reflects lower gas sales revenue due to lower throughput, which was the result of warmer weather and the loss of several large volume but low margin customers to other marketers.
2003 Compared with 2002
      Operating revenues for the Energy Marketing segment increased $153.4 million in 2003 as compared with 2002. This increase primarily reflects higher gas sales revenue due to higher natural gas commodity prices. Higher volumes, which were principally the result of the addition of several high volume but low margin customers and colder weather, also contributed to the increase in operating revenues.
Earnings
2004 Compared with 2003
      The Energy Marketing segment earnings in 2004 were $5.5 million, a decrease of $0.4 million when compared with earnings of $5.9 million in 2003. While margins on gas sales improved slightly, this increase was offset by expenses associated with the settlement of a pension obligation and a higher effective tax rate.
2003 Compared with 2002
      The Energy Marketing segment earnings in 2003 were $5.9 million, a decrease of $2.7 million when compared with earnings of $8.6 million in 2002. This decrease primarily reflects lower margins on gas sales,
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primarily due to end of winter local distribution company operational constraints, combined with price volatility and weather related demand swings.
TIMBER
Revenues
Timber Operating Revenues

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands)	
Log Sales	 	$	21,790	 	 	$	27,341	 	 	$	21,528	 	
Green Lumber Sales	 	 	5,923	 	 	 	6,200	 	 	 	6,567	 	
Kiln Dry Lumber Sales	 	 	27,416	 	 	 	21,814	 	 	 	15,976	 	
Other	 	 	841	 	 	 	871	 	 	 	3,336	 	
 	 	 		 	 	 		 	 	 		 	
 	 	$	55,970	 	 	$	56,226	 	 	$	47,407	 	
 	 	 		 	 	 		 	 	 		 	
Timber Board Feet

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands)	
Log Sales	 	 	6,848	 	 	 	8,764	 	 	 	8,174	 	
Green Lumber Sales	 	 	9,552	 	 	 	11,913	 	 	 	12,878	 	
Kiln Dry Lumber Sales	 	 	15,020	 	 	 	13,300	 	 	 	10,794	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	31,420	 	 	 	33,977	 	 	 	31,846	 	
 	 	 		 	 	 		 	 	 		 	
2004 Compared with 2003
      Operating revenues for the Timber segment did not change significantly in 2004 as compared with 2003. The decrease in log sales of $5.6 million was principally due to the Company’s August 2003 sale of approximately 70,000 acres of timber properties discussed below. However, kiln dry lumber sales increased $5.6 million due to an increase in activity at the Company’s mill operations. As a result of the sale of the timber properties, a larger percentage of timber processed in the Company’s mills is now purchased from third parties.
2003 Compared with 2002
      Operating revenues for the Timber segment increased $8.8 million in 2003, as compared with 2002. The increase can largely be attributed to higher sales of cherry veneer logs that command higher than average prices. Higher kiln dry lumber sales also contributed to the increase. Partially offsetting the increase in log sales and kiln dry lumber sales, other revenues decreased $2.5 million primarily because 2002 included a $2.4 million gain on the sale of standing timber.
Earnings
2004 Compared with 2003
      The Timber segment earnings in 2004 were $5.6 million, a decrease of $106.9 million when compared with earnings of $112.5 million in 2003. This earnings fluctuation is largely a reflection of the sale of timber properties discussed below. In 2003, the Company recorded a gain of $102.2 million after tax on that sale. In 2004, the Company received final timber cruise information of the properties it sold and, based on that information, determined that property records pertaining to $1.3 million ($0.8 million after tax) of timber property were not properly shown as having been transferred to the purchaser. As a result, the Company
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removed those assets from its property records and adjusted the previously recognized gain downward by recognizing a pre tax loss of $1.3 million. The combination of these two events caused earnings to be lower by $103.0 million. The remainder of the decrease is attributable to lower sales of cherry logs in 2004. While kiln dry lumber sales increased, this benefit was largely offset by an increase in costs associated with purchased timber.
2003 Compared with 2002
      The Timber segment earnings in 2003 were $112.5 million, an increase of $102.8 million when compared with earnings of $9.7 million in 2002. The increase was primarily due to the sale of approximately 70,000 acres of timber properties on August 1, 2003 for approximately $186.0 million. As a result of the sale, the Company recorded a gain of approximately $102.2 million after tax. After the August sale, the Company had approximately 87,000 acres of timber property remaining.
OPERATIONS OF UNCONSOLIDATED SUBSIDIARIES
      The Company’s unconsolidated subsidiaries consist of equity method investments in Seneca Energy II, LLC (Seneca Energy), Model City Energy, LLC (Model City) and Energy Systems North East, LLC (ESNE). The Company has a 50% ownership interest 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. In 2002, the Company wrote off it’s 33 1/3% equity method investment in Independence Pipeline Company. The write-off amounted to $15.2 million ($9.9 million after tax) and is recorded on the Consolidated Statement of Income as Impairment of Investment in Partnership. Aside from this impairment, income from unconsolidated subsidiaries has been relatively small, amounting to $0.8 million, $0.5 million and $0.2 million in 2004, 2003 and 2002, respectively.
INTEREST CHARGES
      Although most of the variances in Interest Charges are discussed in the earnings discussion by segment above, following is a summary on a consolidated basis:
      Interest on long-term debt was $8.9 million lower in 2004 compared to 2003; however, interest on long-term debt was $2.2 million higher in 2003 compared to 2002. The decrease in 2004 resulted mainly from a lower average amount of long-term debt outstanding and lower weighted average interest rates. The increase in 2003 resulted mainly from a higher average amount of long-term debt outstanding which more than offset lower weighted average interest rates.
      Other interest charges decreased $5.5 million in 2004 and $2.8 million in 2003. The decrease in both years was primarily the result of lower weighted average interest rates on short-term debt combined with a lower average amount of short-term debt outstanding.
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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	
			
		2004		2003		2002	

		(Millions)	
Provided by Operating Activities	 	$	444.3	 	 	$	326.8	 	 	$	345.6	 	
Capital Expenditures	 	 	(172.3	)	 	 	(152.2	)	 	 	(232.4	)	
Investment in Subsidiaries, Net of Cash Acquired	 	 	—	 	 	 	(228.8	)	 	 	—	 	
Investment in Partnerships	 	 	—	 	 	 	(0.4	)	 	 	(0.5	)	
Net Proceeds from Sale of Timber Properties	 	 	—	 	 	 	186.0	 	 	 	—	 	
Net Proceeds from Sale of Oil and Gas Producing Properties	 	 	7.1	 	 	 	78.5	 	 	 	22.1	 	
Other Investing Activities	 	 	2.0	 	 	 	12.1	 	 	 	5.0	 	
Short-Term Debt, Net Change	 	 	38.6	 	 	 	(147.6	)	 	 	(224.8	)	
Long-Term Debt, Net Change	 	 	(243.1	)	 	 	20.7	 	 	 	139.6	 	
Issuance of Common Stock	 	 	23.8	 	 	 	17.0	 	 	 	10.9	 	
Dividends Paid on Common Stock	 	 	(89.1	)	 	 	(84.5	)	 	 	(81.0	)	
Effect of Exchange Rates on Cash	 	 	3.4	 	 	 	1.6	 	 	 	1.5	 	
 	 	 		 	 	 		 	 	 		 	
Net Increase (Decrease) in Cash and Temporary Cash Investments	 	$	14.7	 	 	$	29.2	 	 	$	(14.0	)	
 	 	 		 	 	 		 	 	 		 	
OPERATING CASH FLOW
      Internally generated cash from operating activities consists of net income available for common stock, adjusted for noncash expenses, noncash income and changes in operating assets and liabilities. Noncash items include depreciation, depletion and amortization, impairment of oil and gas producing properties (in 2003), deferred income taxes, impairment of investment in partnership (in 2002), income or loss from unconsolidated subsidiaries net of cash distributions, minority interest in foreign subsidiaries, gain or loss on sale of timber properties, gain or loss on sale of oil and gas producing properties and cumulative effect of changes in accounting.
      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 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, no cost collars, options and futures contracts in an attempt to manage this energy commodity price risk.
      Net cash provided by operating activities totaled $444.3 million in 2004, an increase of $117.5 million compared with the $326.8 million provided by operating activities in 2003. Most of this increase occurred in the Utility segment, largely attributable to gas cost recovery timing differences.
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INVESTING CASH FLOW
Expenditures for Long-Lived Assets
      Expenditures for long-lived assets include additions to property, plant and equipment (capital expenditures) and investments in corporations (stock acquisitions) or partnerships, net of any cash acquired.
      The Company’s expenditures for long-lived assets totaled $172.3 million in 2004. The table below presents these expenditures:

		Year Ended	
		September 30, 2004	
			
		Total Expenditures	
		For Long-Lived	
		Assets	
			
		(Millions)	
Utility	 	$	55.4	 	
Pipeline and Storage	 	 	23.2	 	
Exploration and Production	 	 	77.7	 	
International	 	 	7.5	 	
Timber	 	 	2.8	 	
All Other and Corporate	 	 	5.7	 	
 	 	 		 	
 	 	$	172.3	 	
 	 	 		 	
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 made 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 $31.4 million for the Canadian region, $19.4 million for the Gulf Coast region, $17.4 million for the West Coast region and $9.5 million for the Appalachian region. These amounts included approximately $12.1 million spent to develop proved undeveloped reserves.
International
      The majority of the International segment’s capital expenditures were concentrated in improvements and replacements within the district heating and power generation plants in the Czech Republic.
Timber
      The majority of the Timber segment’s capital expenditures were for equipment for this segment’s sawmill and kiln operations.
All Other and Corporate
      The majority of the All Other and Corporate capital expenditures were for capital improvements to the Company’s new corporate headquarters.
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Estimated Capital Expenditures
      The Company’s estimated capital expenditures for the next three years are:*

			
		Year Ended September 30,	
			
		2005		2006		2007	

		(Millions)	
Utility	 	$	54.0	 	 	$	52.0	 	 	$	51.0	 	
Pipeline and Storage	 	 	22.0	 	 	 	22.0	 	 	 	22.0	 	
Exploration and Production(1)	 	 	93.0	 	 	 	91.0	 	 	 	89.0	 	
International	 	 	15.0	 	 	 	26.0	 	 	 	29.0	 	
Timber	 	 	2.0	 	 	 	1.0	 	 	 	1.0	 	
All Other and Corporate	 	 	5.0	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	
 	 	$	191.0	 	 	$	192.0	 	 	$	192.0	 	

		
(1) 	Includes estimated expenditures for the years ended September 30, 2005, 2006 and 2007 of approximately $14 million, $27 million and $29 million, respectively, to develop proved undeveloped reserves.	
      Estimated capital expenditures for the Utility segment in 2005 will be concentrated in the areas of main and service line improvements and replacements and, to a minor extent, the installation of new services.*
      Estimated capital expenditures for the Pipeline and Storage segment in 2005 will be concentrated in the reconditioning of storage wells and the replacement of storage and transmission lines.*
      The Company also 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. As announced in February 2004, the Company is pursuing a project to expand its natural gas pipeline operations to serve new markets in New York and elsewhere in the Northeast by extending the Empire State Pipeline.* This proposed extension project would provide an upstream supply link for Phase I of the Millennium Pipeline and will transport Canadian and other natural gas supplies to downstream customers, including KeySpan Gas East Corporation, which has entered into a precedent agreement to be a major shipper, subject to the satisfaction of various conditions.* The pipeline extension will be designed to move at least 250 MMcf of natural gas per day.* The preliminary estimate of the cost for developing the Empire extension project is $140 million and the targeted in-service date is late in calendar 2006.* The estimated capital expenditures do not include any expenditures for the Empire extension project. As of September 30, 2004, the Company had incurred approximately $0.6 million in costs (all of which have been reserved) related to this project.
      Estimated capital expenditures in 2005 for the Exploration and Production segment include approximately $32.0 million for Canada, $29.0 million for the Gulf Coast region ($28.0 million on the off-shore program in the Gulf of Mexico), $20.0 million for the West Coast region and $12.0 million for the Appalachian region.*
      The estimated capital expenditures for the International segment in 2005 will be concentrated on improvements and replacements within the district heating and power generation plants in the Czech Republic.* The estimated capital expenditures do not include any expenditures for the Company’s European power development projects. Currently, any costs incurred on these power development projects are expensed. The Company’s European power development projects currently include one project in Italy and one project in Bulgaria. In Italy, the Company has signed a joint development agreement with an Italian utility for the construction of a 400-megawatt combined-cycle natural gas fired electric generating plant. The estimated cost of this project is $200.0 million to $210.0 million. In Bulgaria, the Company is pursuing the opportunity to construct, own and operate two new 100-megawatt gas-fired combined-cycle plants. The estimated cost of this project is $200.0 million to $220.0 million. Whether the Company moves forward to construct these projects will depend on successful negotiation of various operating agreements as well as the availability of funds from banks or other financial institutions to cover a significant amount of the construction costs.* The respective projects would serve as collateral for such financing arrangements.*
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      Estimated capital expenditures in the Timber segment will be concentrated on the construction or purchase of new facilities and equipment for this segment’s sawmill and kiln operations.*
      Estimated capital expenditures in the All Other and Corporate category will be concentrated on the purchase of equipment for a 55-megawatt electric generation facility in Buffalo, New York combined with capital improvements to the Company’s corporate headquarters.
      The Company continuously evaluates capital expenditures and investments in corporations and partnerships. 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
      In February 2004 and August 2004, the Company repaid $125.0 million of maturing 7.75% debentures at par and $100.0 million of maturing 6.82% medium-term notes at par, respectively. The Company used available cash and short-term borrowings to repay this debt.
      Consolidated short-term debt increased $38.6 million during 2004. Although a certain amount of short-term borrowings were initially used to repay the maturing debt discussed above, the Company was able to use cash flow from operations to repay most of this additional short-term debt. 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, exploration and development expenditures and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At September 30, 2004, the Company had outstanding short-term notes payable to banks and commercial paper of $26.5 million and $130.3 million, respectively. The Company has SEC authorization under the Holding Company Act to borrow and have outstanding as much as $750.0 million of short-term debt at any time through December 31, 2005. As for bank loans, the Company maintains a number of individual (bi-lateral) 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. Each of these credit lines, which aggregate to $400.0 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.* The total amount available to be issued under the Company’s commercial paper program is $200.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $220.0 million. Of that amount, $110.0 million is committed to the Company through September 25, 2005 and $110.0 million is committed to the Company through September 30, 2005. The Company anticipates that it will be able to replace this facility at or before its maturity.*
      Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not at the last day of any fiscal quarter, exceed .625 from October 1, 2003 through September 30, 2004 and .60 from October 1, 2004 and thereafter. At September 30, 2004, the Company’s debt to capitalization ratio (as calculated under the facility) was .51. The constraints specified in the committed credit facility would permit an additional $576.0 million in short-term and/or long-term debt to be outstanding before the Company’s debt to capitalization ratio would exceed .60. If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible.* However, the Company expects that it could borrow under its uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.*
      Under the Company’s existing indenture covenants, at September 30, 2004, the Company would have been permitted to issue up to a maximum of $713.0 million in additional long-term unsecured indebtedness at then current market interest rates (further limited by the debt to capitalization ratio constraints noted in
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the previous paragraph) in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands.*
      The Company’s 1974 indenture pursuant to which $399.0 million (or 35%) of the Company’s long-term debt (as of September 30, 2004) 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 $220.0 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 fails 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, 2004, the Company had no debt outstanding under the committed credit facility.
      The Company’s embedded cost of long-term debt was 6.4% at September 30, 2004 and 6.5% at September 30, 2003. Refer to “Interest Rate Risk” in this Item for a more detailed break-down of the Company’s embedded cost of long-term debt.
      The Company also has authorization from the SEC, in an order under the Holding Company Act, to issue long-term debt securities and equity securities in an aggregate amount of up to $1.5 billion during the order’s authorization period, which commenced in November 2002 and extends to December 31, 2005. The Company has an effective registration statement on file with the SEC under which it has available capacity to issue an additional $550.0 million of debt and equity securities under the Securities Act of 1933, and within the authorization granted by the SEC under the Holding Company Act. The Company may sell all or a portion of the remaining registered securities if warranted by market conditions and the Company’s capital requirements. Any offer and sale of the above mentioned $550.0 million of debt and equity securities will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
      The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.
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 $34.3 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters, computer equipment and other items and are accounted for as operating leases. The Company’s unconsolidated subsidiaries, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $10.0 million. The Company has guaranteed 50%, or $5.0 million, of these capital lease commitments.
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CONTRACTUAL OBLIGATIONS
      The following table summarizes the Company’s expected future contractual cash obligations as of September 30, 2004, and the twelve-month periods over which they occur:

			
		Payments by Expected Maturity Dates	
			
		2005		2006		2007		2008		2009		Thereafter		Total	

		(Millions)	
Long-Term Debt	 	$	14.3	 	 	$	14.3	 	 	$	9.3	 	 	$	209.3	 	 	$	104.1	 	 	$	796.3	 	 	$	1,147.6	 	
Short-Term Bank Notes	 	$	26.5	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	26.5	 	
Commercial Paper	 	$	130.3	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	130.3	 	
Operating Lease Obligations	 	$	8.7	 	 	$	7.1	 	 	$	6.1	 	 	$	5.2	 	 	$	4.8	 	 	$	2.4	 	 	$	34.3	 	
Capital Lease Obligations	 	$	0.8	 	 	$	1.1	 	 	$	0.9	 	 	$	0.8	 	 	$	0.4	 	 	$	1.0	 	 	$	5.0	 	
Purchase Obligations:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Gas Purchase Contracts(1)	 	$	589.5	 	 	$	87.0	 	 	$	11.1	 	 	$	5.8	 	 	$	5.7	 	 	$	68.4	 	 	$	767.5	 	
 	Transportation and Storage Contracts	 	$	134.4	 	 	$	135.4	 	 	$	133.0	 	 	$	125.9	 	 	$	69.5	 	 	$	12.4	 	 	$	610.6	 	
 	Other	 	$	2.4	 	 	$	0.8	 	 	$	0.4	 	 	$	0.4	 	 	$	0.4	 	 	$	—	 	 	$	4.4	 	

		
(1) 	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 the Financial Accounting Standards Board’s Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (see Item 7, MD&A under the heading “Critical Accounting Policies — 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 on the table above.*
OTHER MATTERS
      The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Company’s present liquidity position, nor 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 substantially all domestic employees of the Company. 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 2004, the Company contributed $37.1 million to the Retirement Plan. The Company anticipates that the annual contribution to the Retirement Plan in 2005 will be in the range of $25.0 million to $35.0 million.* The Company expects that all subsidiaries having domestic 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 for substantially all domestic retired employees under a post-retirement benefit plan (Post-Retirement Plan). The Company has been making contributions to the Post-Retirement Plan over the last several years and anticipates that it will continue making contributions to the Post-Retirement Plan.* During 2004, the Company contributed $39.7 million to
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the Post-Retirement Plan. The Company anticipates that the annual contribution to the Post-Retirement Plan in 2005 will be in the range of $30.0 million to $40.0 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, options 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, 2004 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 “Inside FERC” or on the New York Mercantile Exchange. 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, 2004. At September 30, 2004, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2009.

	Natural Gas Price Swap Agreements	

		Expected Maturity Dates	
			
		2005		2006		2007		2008		2009		Total	
													
Notional Quantities (Equivalent Bcf)	 	 	11.3	 	 	 	8.4	 	 	 	1.8	 	 	 	1.2	 	 	 	0.3	 	 	 	23.0	 	
Weighted Average Fixed Rate (per Mcf)	 	$	5.47	 	 	$	5.68	 	 	$	5.02	 	 	$	4.80	 	 	$	4.81	 	 	$	5.47	 	
Weighted Average Variable Rate (per Mcf)	 	$	7.12	 	 	$	6.74	 	 	$	6.13	 	 	$	5.58	 	 	$	5.50	 	 	$	6.81	 	

	Crude Oil Price Swap Agreements	

		Expected Maturity Dates	
			
		2005		2006		2007		Total	
									
Notional Quantities (Equivalent bbls)	 	 	2,743,000	 	 	 	1,755,000	 	 	 	540,000	 	 	 	5,038,000	 	
Weighted Average Fixed Rate (per bbl)	 	 	$30.51	 	 	 	$33.27	 	 	 	$35.55	 	 	 	$32.01	 	
Weighted Average Variable Rate (per bbl)	 	 	$46.74	 	 	 	$41.31	 	 	 	$38.41	 	 	 	$43.95	 	
      At September 30, 2004, the Company would have had to pay its respective counterparties an aggregate of approximately $25.0 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have had to pay an aggregate of approximately $57.2 million to its counterparties to terminate the crude oil price swap agreements outstanding at September 30, 2004.
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      At September 30, 2003, the Company had natural gas price swap agreements covering 13.1 Bcf at a weighted average fixed rate of $4.24 per Mcf. The Company also had crude oil price swap agreements covering 2,184,000 bbls at a weighted average fixed rate of $25.44 per bbl. The increase in price swap agreements from September 2003 to September 2004 is largely a result of management’s decision to hedge farther into the future in the Exploration and Production segment given the high commodity prices available. It is also a reflection of management’s decision to use crude oil price swap agreements instead of crude oil no cost collars in the Exploration and Production segment, as discussed below.
      The following table discloses the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas and crude oil price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2004, the Company had not entered into any natural gas or crude oil no cost collars extending beyond 2006.

	No Cost Collars	

		Expected Maturity Dates	
			
		2005		2006		Total	
							
Natural Gas	 	 	 	 	 	 	 	 	 	 	 	 	
 	Notional Quantities (Equivalent Bcf)	 	 	5.1	 	 	 	0.4	 	 	 	5.5	 	
 	Weighted Average Ceiling Price (per Mcf)	 	 	$8.31	 	 	$	7.88	 	 	 	$8.28	 	
 	Weighted Average Floor Price (per Mcf)	 	 	$4.94	 	 	$	4.77	 	 	 	$4.93	 	
Crude Oil	 	 	 	 	 	 	 	 	 	 	 	 	
 	Notional Quantities (Equivalent bbls)	 	 	105,000	 	 	 	—	 	 	 	105,000	 	
 	Weighted Average Ceiling Price (per bbl)	 	 	$28.56	 	 	 	—	 	 	 	$28.56	 	
 	Weighted Average Floor Price (per bbl)	 	 	$25.00	 	 	 	—	 	 	 	$25.00	 	
      At September 30, 2004, the Company would have had to pay an aggregate of approximately $1.6 million to terminate the natural gas no cost collars outstanding at that date. The Company would have had to pay an aggregate of approximately $2.1 million to terminate the crude oil no cost collars outstanding at that date.
      At September 30, 2003, the Company had natural gas no cost collars covering 3.7 Bcf at a weighted average floor price of $3.46 per Mcf and a weighted average ceiling price of $7.21 per Mcf. The Company also had crude oil no cost collars covering 1,290,000 bbls at a weighted average floor price of $23.91 per bbl and a weighted average ceiling price of $28.00 per bbl. The increase in natural gas no cost collars from September 2003 to September 2004 is a result of management’s decision to hedge farther out into the future in the Exploration and Production segment given the high commodity prices available. The decrease in crude oil no cost collars from September 2003 to September 2004 is a result of management’s decision to use crude oil price swap agreements instead of crude oil no cost collars to hedge future crude oil production in the Exploration and Production segment. With the current commodity price environment, management determined that it could better meet its commodity price objectives through the use of price swap agreements.
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	Options	
      The following table discloses the notional quantities and weighted average strike prices by expected maturity dates for options used by the Exploration and Production segment to manage natural gas price risk. The put options provide for the Company to receive monthly payments from other parties when a variable price falls below an established floor or “strike” price. The call options provide for the Company to pay monthly payments to other parties when a variable price rises above an established ceiling or “strike” price. At September 30, 2004, the Company held no options with maturity dates extending beyond 2006. 

			
		Expected Maturity Dates	
			
		2005		2006		Total	
							
Natural Gas Put Options Purchased	 	 	 	 	 	 	 	 	 	 	 	 	
 	Notional Quantities (Equivalent Bcf)	 	 	0.8	 	 	 	0.3	 	 	 	1.1	 	
 	Weighted Average Strike Price (per Mcf)	 	$	6.05	 	 	$	5.83	 	 	$	5.99	 	
Natural Gas Call Options Sold	 	 	 	 	 	 	 	 	 	 	 	 	
 	Notional Quantities (Equivalent Bcf)	 	 	0.8	 	 	 	0.3	 	 	 	1.1	 	
 	Weighted Average Strike Price (per Mcf)	 	$	7.84	 	 	$	8.69	 	 	$	8.06	 	
      At September 30, 2004, the Company would have received from the respective counterparties an aggregate of approximately $0.2 million to terminate the put options outstanding at that date. The Company would have had to pay an aggregate of approximately $1.0 million to terminate the call options outstanding at that date. The Company did not have any options outstanding at September 30, 2003.
      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, 2004, the Company held no futures contracts with maturity dates extending beyond 2007.

	Futures Contracts	

		Expected Maturity Dates	
			
		2005		2006		2007		Total	
									
Net Contract Volumes Purchased (Sold) (Equivalent Bcf)	 	 	(3.5	)	 	 	(0.4	)	 	 	0.1	 	 	 	(3.8	)	
Weighted Average Contract Price (per Mcf)	 	$	6.16	 	 	$	6.29	 	 	$	5.88	 	 	$	6.17	 	
Weighted Average Settlement Price (per Mcf)	 	$	7.74	 	 	$	6.96	 	 	$	6.33	 	 	$	7.69	 	
      At September 30, 2004, the Company would have had to pay $6.2 million to terminate these futures contracts.
      At September 30, 2003, the Company had futures contracts covering 3.6 Bcf (net long position) at a weighted average contract price of $5.60 per Mcf. The change from a net long position at September 30, 2003 to a net short position at September 30, 2004 can largely be explained by the high commodity price environment experienced by the Energy Marketing segment in 2004. With high commodity prices, customers have been reluctant to enter into fixed price sales commitments. With fewer fixed price sales commitments, the Energy Marketing segment has purchased fewer contracts since it no longer faces as great a risk of commodity price increases.
      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 the parent companies of the respective counterparties to its derivatives. At September 30, 2004, the Company used seven counterparties for its over the counter derivatives. At September 30, 2004, no individual counterparty represented greater than 20% of total credit risk (measured as volumes hedged by an individual counterparty as a percentage of the Company’s total volumes hedged).
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Exchange Rate Risk
      The International segment’s investment in the Czech Republic is valued in Czech korunas, and, as such, this investment is subject to currency exchange risk when the Czech korunas are translated into U.S. dollars. The Exploration and Production segment’s investment in Canada is valued in Canadian dollars, and, as such, this investment is subject to currency exchange risk when the Canadian dollars are translated into U.S. dollars. This exchange rate risk to the Company’s investments in the Czech Republic and Canada results in increases or decreases to the Cumulative Foreign Currency Translation Adjustment (CTA), a component of Accumulated Other Comprehensive Income/ Loss on the Consolidated Balance Sheets. When the foreign currency increases in value in relation to the U.S. dollar, there is a positive adjustment to CTA. When the foreign currency decreases in value in relation to the U.S. dollar, there is a negative adjustment to CTA.
Interest Rate Risk
      The Company’s exposure to interest rate risk arises primarily from its borrowing under short-term debt instruments. At September 30, 2004, these instruments consisted of domestic short-term bank loans and commercial paper totaling $156.8 million. The interest rate on these short-term bank loans and commercial paper approximated 1.8% at September 30, 2004.
      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, 2004: 

			
		Principal Amounts by Expected Maturity Dates	
			
		2005		2006		2007		2008		2009		Thereafter		Total	

		(Dollars in Millions)	
National Fuel Gas Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-Term Fixed Rate Debt	 	$	—	 	 	$	—	 	 	$	—	 	 	$	200	 	 	$	100	 	 	$	796.3	 	 	$	1,096.3	 	
Weighted Average Interest Rate Paid	 	 	0	%	 	 	0	%	 	 	0	%	 	 	6.3	%	 	 	6.0	%	 	 	6.5	%	 	 	6.4	%	
Fair Value = $1,147.9 million	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Notes	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-Term Debt(1)	 	$	14.3	 	 	$	14.3	 	 	$	9.3	 	 	$	9.3	 	 	$	4.1	 	 	$	—	 	 	$	51.3	 	
Weighted Average Interest Rate Paid(2)	 	 	4.1	%	 	 	4.1	%	 	 	2.8	%	 	 	2.8	%	 	 	2.8	%	 	 	—	 	 	 	3.5	%	
Fair Value = $51.3 million	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

		
(1) 	$41.4 million is variable rate debt; $9.9 million is fixed rate debt.	
 		
(2) 	Weighted average interest rate excludes the impact of an interest rate collar on $41.4 million of variable rate debt.	
      The Company uses an interest rate collar to limit interest rate fluctuations on $41.4 million of variable rate debt included in Other Notes in the table above. Under the interest rate collar the Company makes quarterly payments to (or receives payments from) another party when a variable rate falls below an established floor rate (the Company pays the counterparty) or exceeds an established ceiling rate (the Company receives payment from the counterparty). Under the terms of the collar, which extends until 2009, the variable rate is based on London InterBank Offered Rate. The floor rate of the collar is 5.15% and the ceiling rate is 9.375%. The Company would have had to pay $2.2 million to terminate the interest rate collar at September 30, 2004.
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RATE 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 October 11, 2000, the NYPSC approved a settlement agreement (Agreement) between Distribution Corporation, Staff of the Department of Public Service, the New York State Consumer Protection Board and Multiple Intervenors (an advocate for large commercial and industrial customers) (collectively, “Parties”) that established rates for the three-year period ending September 30, 2003. On July 25, 2003, the Parties and other interests executed a settlement agreement (Settlement) to extend the terms of the Agreement and Distribution Corporation’s restructuring plan one year commencing October 1, 2003. The Settlement was approved by the NYPSC in an order issued on September 18, 2003. As approved, the Settlement continued existing base rates, but reduced the level above which earnings are shared 50/50 with customers from the previous 11.5% return on equity to 11.0%. In addition, the Settlement increased the combined pension and other post-retirement benefit expense by $8.0 million, without a corresponding increase in revenues. Most other features of Distribution Corporation’s service remained largely unchanged. In April 2004, Distribution Corporation commenced confidential settlement negotiations with the NYPSC and other parties concerning, among other things, its revenue requirement for the year ending September 30, 2005. Those settlement discussions failed to produce an agreement prior to the expiration of the Settlement. On August 27, 2004, Distribution Corporation filed proposed tariff amendments and supporting testimony designed to increase its annual revenues by $41.3 million beginning October 1, 2004. The rate request was filed to address throughput reductions and increased operating costs such as uncollectibles and personnel expenses. In accordance with standard rate case procedure, the NYPSC suspended Distribution Corporation’s filing as provided by law in order to allow time for an investigation and hearings. Following hearings and further proceedings, the Commission will issue an order approving, rejecting or modifying Distribution Corporation’s rate request for an anticipated effective date of late July, 2005. Distribution Corporation is unable to ascertain the outcome of the rate proceeding at this time. The existing base rates and other provisions of the Settlement that expired on September 30, 2004 will continue to be in effect until the Commission issues an order concerning Distribution Corporation’s rate request.
      On June 1, 2004, Distribution Corporation submitted a filing to the NYPSC supporting the removal of a $5 million annual bill credit originally established under the terms of the Agreement. The filing requested removal of the bill credit effective October 1, 2004. On September 28, 2004, the NYPSC issued an order rejecting Distribution Corporation’s request for the stated reason that Distribution Corporation’s earnings were adequate, in the NYPSC’s opinion, without removal of the bill credit. Distribution Corporation is contemplating further action on the NYPSC’s order.
      In another order issued on September 28, 2004, the NYPSC directed the continuation, with modification, of four programs under the Settlement that were scheduled to expire on September 30, 2004. The effect of the NYPSC’s order was to unilaterally extend the terms of the Settlement without Distribution Corporation’s consent. Although the NYPSC’s order stated that it provided for funding of the programs, Distribution Corporation petitioned Supreme Court, Albany County for an injunction to allow the programs to expire on their own terms. Distribution Corporation’s petition was partially successful, and the proceeding remains pending.
      On September 20, 2001, the NYPSC issued an order under which Distribution Corporation was directed to show cause why an action for penalties of $19.0 million should not be commenced against it for alleged violations of consumer protection requirements. On December 3, 2001, Distribution Corporation filed its response which vigorously asserted that the allegations lacked merit. Distribution Corporation continues to so believe. On July 28, 2004, the NYPSC concluded the investigation of issues raised in the order without
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assessing any fines or penalties. As part of the settlement of the NYPSC’s investigation, Distribution Corporation will commit $1.5 million to a new program designed to assist low-income customers who are transitioning from public assistance. Distribution Corporation has also agreed to incur costs up to $0.3 million for an audit of customer service practices. The NYPSC has agreed not to seek any penalties should any violations be uncovered during the audit. For a discussion of related legal matters, refer to Item 3, “Legal Proceedings.”
Pennsylvania Jurisdiction
      On April 16, 2003, Distribution Corporation filed a request with the PaPUC to increase annual operating revenues by $16.5 million to cover increases in the cost of providing service, to be effective June 15, 2003. The PaPUC suspended the effective date to January 15, 2004. Distribution Corporation filed this request for several reasons including increases in the costs associated with Distribution Corporation’s ongoing construction program as well as increases in uncollectible accounts and personnel expenses. On October 16, 2003, the parties reached a settlement of all issues. The settlement was submitted to the Administrative Law Judge, who, on November 17, 2003, issued a decision recommending adoption of the settlement. The settlement provides for a base rate increase of $3.5 million and authorizes deferral accounting for pension and other post-retirement benefit expenses. The settlement was approved by the PaPUC on December 18, 2003, and rates became effective January 15, 2004.
      On September 15, 2004, Distribution Corporation filed revised tariffs with the PaPUC to increase annual revenues by $22.8 million to cover increases in the cost of service to be effective November 14, 2004. The rate request was filed to address throughput reductions and increased operating costs such as uncollectibles and personnel expenses. Applying standard procedure, the PaPUC suspended Distribution Corporation’s tariff filing to perform an investigation and hold hearings. With this suspension, the effective date was changed to June 14, 2005 and the proceeding remains pending.
Pipeline and Storage
      Supply Corporation currently does not have a rate case on file with the FERC. Management will continue to monitor Supply Corporation’s financial position to determine the necessity of filing a rate case in the future.
      On November 25, 2003, the FERC issued Order 2004 “Standards of Conduct for Transmission Providers” (“Order 2004”). Order 2004 was clarified in Order 2004-A on April 16, 2004 and Order 2004-B on August 2, 2004. Order 2004, which went into effect September 22, 2004, regulates the conduct of transmission providers (such as Supply Corporation) with their “energy affiliates.” The FERC broadened the definition of “energy affiliates” to include any affiliate of a transmission provider if that affiliate engages in or is involved in transmission (gas or electric) transactions, or manages or controls transmission capacity, or buys, sells, trades or administers natural gas or electric energy or engages in financial transactions relating to the sale or transmission of natural gas or electricity. Supply Corporation’s principal energy affiliates will be Seneca, NFR and, possibly, Distribution Corporation.* Order 2004 provides that companies may request waivers, which the Company has done with respect to Distribution Corporation and is awaiting rulings. Order 2004 also provides an exemption for local distribution companies that are affiliated with interstate pipelines (such as Distribution Corporation), but the exemption is limited, with very minor exceptions, to local distribution corporations that do not make any off-system sales and do not purchase gas in ways FERC considers to be “financial or futures transactions or hedging.” While Distribution Corporation stopped making such off-system sales effective September 22, 2004, some of its gas purchase arrangements might be considered by FERC to be “financial or futures transactions or hedging.” Supply Corporation and Distribution Corporation would like to continue operating as they do, whether by waiver, amendment or further clarification of the new rules, or by complying with the requirements applicable if Distribution Corporation were an energy affiliate. Treating Distribution Corporation as an energy affiliate, without any waivers, would require changes in the way Supply Corporation and Distribution Corporation operate which would decrease efficiency, but probably would not increase capital or operating expenses to an extent that would be material to the financial condition of the Company.* Until there is further clarification from the FERC on the scope of these
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exemptions and rulings on the Company’s waiver requests, the Company is unable to predict the ultimate impact Order 2004 will have on the Company. As previously mentioned, Distribution Corporation stopped making off-system sales, effective September 22, 2004. The Company does not expect that change to have a material effect on the Company’s results of operations, as margins resulting from off-system sales are minimal as a result of profit sharing with retail customers.*
      Empire currently does not have a rate case on file with the NYPSC. Management will continue to monitor its financial position in the New York jurisdiction to determine the necessity of filing a rate case in the future.
ENVIRONMENTAL MATTERS
      It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The Company has estimated its clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be $14.0 million.* This liability has been recorded on the Consolidated Balance Sheet at September 30, 2004. Other than discussed in Note G (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.* The Company is subject to various federal, state and local laws and regulations (including those of the Czech Republic and Canada) 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.
      For further discussion refer to Item 8 at Note G — Commitments and Contingencies under the heading “Environmental Matters.”
NEW ACCOUNTING PRONOUNCEMENTS
      In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (SAB 106). SAB 106 addresses the application of SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) to companies that follow the full-cost method of accounting for oil and gas property acquisition, exploration and development costs. For a discussion of SAB 106 and its impact on the Company, refer to Item 8 at Note A — Summary of Significant Accounting Policies.
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, those which are designated with an asterisk (“*”) and those which are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions, are “forward-looking” statements as defined in the Private Securities
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Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

			
 	1. 	Changes in economic conditions, including economic disruptions caused by terrorist activities or acts of war;	
 		
 	2. 	Changes in demographic patterns and weather conditions, including the occurrence of severe weather;	
 		
 	3. 	Changes in the availability and/or price of natural gas, oil and coal;	
 		
 	4. 	Inability to obtain new customers or retain existing ones;	
 		
 	5. 	Significant changes in competitive factors affecting the Company;	
 		
 	6. 	Governmental/regulatory actions, initiatives and proceedings, including those affecting acquisitions, financings, allowed rates of return, industry and rate structure, franchises, permits, and environmental/safety requirements;	
 		
 	7. 	Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;	
 		
 	8. 	Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs;	
 		
 	9. 	The nature and projected profitability of pending and potential projects and other investments;	

			
 	10. 	Occurrences affecting the Company’s ability to obtain funds from operations, debt or equity to finance needed capital expenditures and other investments;	
 		
 	11. 	Uncertainty of oil and gas reserve estimates;	
 		
 	12. 	Ability to successfully identify and finance acquisitions and ability to operate and integrate existing and any subsequently acquired business or properties;	
 		
 	13. 	Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves;	
 		
 	14. 	Significant changes from expectations in the Company’s actual production levels for natural gas or oil;	
 		
 	15. 	Changes in the availability and/or price of derivative financial instruments;	
 		
 	16. 	Changes in the price of natural gas or oil and the effect of such changes on the accounting treatment or valuation of financial instruments for the Company’s natural gas and oil reserves;	
 		
 	17. 	Inability of the various counterparties to meet their obligations with respect to the Company’s financial instruments;	
 		
 	18. 	Regarding foreign operations, changes in trade and monetary policies, inflation and exchange rates, taxes, operating conditions, laws and regulations related to foreign operations, and political and governmental changes;	
 		
 	19. 	Significant changes in tax rates or policies or in rates of inflation or interest;	
 		
 	20. 	Significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur;	
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 	21. 	Changes in accounting principles or the application of such principles to the Company;	
 		
 	22. 	Changes in laws and regulations to which the Company is subject, including tax, environmental and employment laws and regulations;	
 		
 	23. 	The cost and effects of legal and administrative claims against the Company;	
 		
 	24. 	Changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefit plans;	
 		
 	25. 	Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide post-retirement benefits; or	
 		
 	26. 	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:	 	 	 	 	
 	  Report of Independent Registered Public Accounting Firm	 	 	52	 	
 	  Consolidated Statements of Income and Earnings Reinvested in the Business, three years ended September 30, 2004	 	 	53	 	
 	  Consolidated Balance Sheets at September 30, 2004 and 2003	 	 	54	 	
 	  Consolidated Statement of Cash Flows, three years ended September 30, 2004	 	 	55	 	
 	  Consolidated Statement of Comprehensive Income, three years ended September 30, 2004	 	 	56	 	
 	  Notes to Consolidated Financial Statements	 	 	57	 	
Financial Statement Schedules:	 	 	 	 	
 	For the three years ended September 30, 2004	 	 	 	 	
 	  II-Valuation and Qualifying Accounts	 	 	100	 	
      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 L — Quarterly Financial Data (unaudited) and Note N — Supplementary Information for Oil and Gas Producing Activities, 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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2004 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. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion.
      As discussed in Note A to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, and No. 143, Accounting for Asset Retirement Obligations, on October 1, 2002.

		
 	PRICEWATERHOUSECOOPERS LLP	
Buffalo, New York
December 9, 2004
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NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS
REINVESTED IN THE BUSINESS

		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands of dollars, except per	
		common share amounts)	
INCOME	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	2,031,393	 	 	$	2,035,471	 	 	$	1,464,496	 	
 	 	 		 	 	 		 	 	 		 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Purchased Gas	 	 	949,452	 	 	 	963,567	 	 	 	462,857	 	
 	Fuel Used in Heat and Electric Generation	 	 	65,722	 	 	 	61,029	 	 	 	50,635	 	
 	Operation and Maintenance	 	 	413,593	 	 	 	386,270	 	 	 	394,157	 	
 	Property, Franchise and Other Taxes	 	 	72,111	 	 	 	82,504	 	 	 	72,155	 	
 	Depreciation, Depletion and Amortization	 	 	189,538	 	 	 	195,226	 	 	 	180,668	 	
 	Impairment of Oil and Gas Producing Properties	 	 	—	 	 	 	42,774	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	1,690,416	 	 	 	1,731,370	 	 	 	1,160,472	 	
 	Gain (Loss) on Sale of Timber Properties	 	 	(1,252	)	 	 	168,787	 	 	 	—	 	
 	Gain (Loss) on Sale of Oil and Gas Producing Properties	 	 	4,645	 	 	 	(58,472	)	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	
Operating Income	 	 	344,370	 	 	 	414,416	 	 	 	304,024	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	 	 	
 	Income from Unconsolidated Subsidiaries	 	 	805	 	 	 	535	 	 	 	224	 	
 	Impairment of Investment in Partnership	 	 	—	 	 	 	—	 	 	 	(15,167	)	
 	Other Income	 	 	6,671	 	 	 	6,887	 	 	 	7,017	 	
 	Interest Expense on Long-Term Debt	 	 	(83,827	)	 	 	(92,766	)	 	 	(90,543	)	
 	Other Interest Expense	 	 	(6,763	)	 	 	(12,290	)	 	 	(15,109	)	
 	 	 		 	 	 		 	 	 		 	
Income Before Income Taxes and Minority	 	 	 	 	 	 	 	 	 	 	 	 	
 	Interest in Foreign Subsidiaries	 	 	261,256	 	 	 	316,782	 	 	 	190,446	 	
 	 	Income Tax Expense	 	 	92,737	 	 	 	128,161	 	 	 	72,034	 	
 	 	Minority Interest in Foreign Subsidiaries	 	 	(1,933	)	 	 	(785	)	 	 	(730	)	
 	 	 		 	 	 		 	 	 		 	
Income Before Cumulative Effect of Changes In Accounting	 	 	166,586	 	 	 	187,836	 	 	 	117,682	 	
 	 	Cumulative Effect of Changes in Accounting	 	 	—	 	 	 	(8,892	)	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	
Net Income Available for Common Stock	 	 	166,586	 	 	 	178,944	 	 	 	117,682	 	
 	 	 		 	 	 		 	 	 		 	
EARNINGS REINVESTED IN THE BUSINESS	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at Beginning of Year	 	 	642,690	 	 	 	549,397	 	 	 	513,488	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	809,276	 	 	 	728,341	 	 	 	631,170	 	
Dividends on Common Stock	 	 	90,350	 	 	 	85,651	 	 	 	81,773	 	
 	 	 		 	 	 		 	 	 		 	
Balance at End of Year	 	$	718,926	 	 	$	642,690	 	 	$	549,397	 	
 	 	 		 	 	 		 	 	 		 	
Earnings Per Common Share:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Income Before Cumulative Effect of Changes in Accounting	 	$	2.03	 	 	$	2.32	 	 	$	1.47	 	
 	Cumulative Effect of Changes in Accounting	 	 	—	 	 	 	(0.11	)	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	
 	Net Income Available for Common Stock	 	$	2.03	 	 	$	2.21	 	 	$	1.47	 	
 	 	 		 	 	 		 	 	 		 	
Diluted:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Income Before Cumulative Effect of Changes in Accounting	 	$	2.01	 	 	$	2.31	 	 	$	1.46	 	
 	Cumulative Effect of Changes in Accounting	 	 	—	 	 	 	(0.11	)	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	
 	Net Income Available for Common Stock	 	$	2.01	 	 	$	2.20	 	 	$	1.46	 	
 	 	 		 	 	 		 	 	 		 	
Weighted Average Common Shares Outstanding:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Used in Basic Calculation	 	 	82,045,535	 	 	 	80,808,794	 	 	 	79,821,430	 	
 	Used in Diluted Calculation	 	 	82,900,438	 	 	 	81,357,896	 	 	 	80,534,453	 	
See Notes to Consolidated Financial Statements
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NATIONAL FUEL GAS COMPANY
CONSOLIDATED BALANCE SHEETS

			
		At September 30,	
			
		2004		2003	

		(Thousands of dollars)	
ASSETS	
Property, Plant and Equipment	 	$	4,602,779	 	 	$	4,657,343	 	
 	Less — Accumulated Depreciation, Depletion and Amortization	 	 	1,596,015	 	 	 	1,666,295	 	
 	 	 		 	 	 		 	
 	 	 	 	3,006,764	 	 	 	2,991,048	 	
 	 	 		 	 	 		 	
Current Assets	 	 	 	 	 	 	 	 	
 	Cash and Temporary Cash Investments	 	 	66,153	 	 	 	51,421	 	
 	Receivables — Net of Allowance for Uncollectible Accounts of $17,440 and $17,943, Respectively	 	 	129,825	 	 	 	136,604	 	
 	Unbilled Utility Revenue	 	 	18,574	 	 	 	20,155	 	
 	Gas Stored Underground	 	 	68,511	 	 	 	89,640	 	
 	Materials and Supplies — at average cost	 	 	43,922	 	 	 	32,311	 	
 	Unrecovered Purchased Gas Costs	 	 	7,532	 	 	 	28,692	 	
 	Prepayments	 	 	38,760	 	 	 	46,860	 	
 	Fair Value of Derivative Financial Instruments	 	 	23	 	 	 	1,698	 	
 	 	 		 	 	 		 	
 	 	 	373,300	 	 	 	407,381	 	
 	 	 		 	 	 		 	
Other Assets	 	 	 	 	 	 	 	 	
 	Recoverable Future Taxes	 	 	83,847	 	 	 	84,818	 	
 	Unamortized Debt Expense	 	 	19,573	 	 	 	22,119	 	
 	Other Regulatory Assets	 	 	66,862	 	 	 	52,381	 	
 	Deferred Charges	 	 	3,411	 	 	 	7,528	 	
 	Other Investments	 	 	72,556	 	 	 	64,025	 	
 	Investments in Unconsolidated Subsidiaries	 	 	16,444	 	 	 	16,425	 	
 	Goodwill	 	 	5,476	 	 	 	5,476	 	
 	Intangible Assets	 	 	45,994	 	 	 	49,664	 	
 	Other	 	 	17,571	 	 	 	18,195	 	
 	 	 		 	 	 		 	
 	 	 	331,734	 	 	 	320,631	 	
 	 	 		 	 	 		 	
Total Assets	 	$	3,711,798	 	 	$	3,719,060	 	
 	 	 		 	 	 		 	
CAPITALIZATION AND LIABILITIES	
Capitalization:	 	 	 	 	 	 	 	 	
Comprehensive Shareholders’ Equity	 	 	 	 	 	 	 	 	
 	Common Stock, $1 Par Value Authorized — 200,000,000 Shares; Issued and Outstanding — 82,990,340 Shares and 81,438,290 Shares, Respectively	 	$	82,990	 	 	$	81,438	 	
 	Paid In Capital	 	 	506,560	 	 	 	478,799	 	
 	Earnings Reinvested in the Business	 	 	718,926	 	 	 	642,690	 	
 	 	 		 	 	 		 	
Total Common Shareholder Equity Before Items	 	 	 	 	 	 	 	 	
 	 	Of Other Comprehensive Loss	 	 	1,308,476	 	 	 	1,202,927	 	
 	Accumulated Other Comprehensive Loss	 	 	(54,775	)	 	 	(65,537	)	
 	 	 		 	 	 		 	
Total Comprehensive Shareholders’ Equity	 	 	1,253,701	 	 	 	1,137,390	 	
Long-Term Debt, Net of Current Portion	 	 	1,133,317	 	 	 	1,147,779	 	
 	 	 		 	 	 		 	
Total Capitalization	 	 	2,387,018	 	 	 	2,285,169	 	
 	 	 		 	 	 		 	
Minority Interest in Foreign Subsidiaries	 	 	37,048	 	 	 	33,281	 	
 	 	 		 	 	 		 	
Current and Accrued Liabilities	 	 	 	 	 	 	 	 	
 	Notes Payable to Banks and Commercial Paper	 	 	156,800	 	 	 	118,200	 	
 	Current Portion of Long-Term Debt	 	 	14,260	 	 	 	241,731	 	
 	Accounts Payable	 	 	115,979	 	 	 	118,563	 	
 	Amounts Payable to Customers	 	 	3,154	 	 	 	692	 	
 	Other Accruals and Current Liabilities	 	 	91,164	 	 	 	52,851	 	
 	Fair Value of Derivative Financial Instruments	 	 	95,099	 	 	 	17,928	 	
 	 	 		 	 	 		 	
 	 	 	476,456	 	 	 	549,965	 	
 	 	 		 	 	 		 	
Deferred Credits	 	 	 	 	 	 	 	 	
 	Accumulated Deferred Income Taxes	 	 	458,095	 	 	 	423,282	 	
 	Taxes Refundable to Customers	 	 	11,065	 	 	 	13,519	 	
 	Unamortized Investment Tax Credit	 	 	7,498	 	 	 	8,199	 	
 	Cost of Removal Regulatory Liability	 	 	82,020	 	 	 	76,782	 	
 	Other Regulatory Liabilities	 	 	67,669	 	 	 	72,632	 	
 	Pension Liability	 	 	91,587	 	 	 	153,240	 	
 	Asset Retirement Obligation	 	 	32,292	 	 	 	27,493	 	
 	Other Deferred Credits	 	 	61,050	 	 	 	75,498	 	
 	 	 		 	 	 		 	
 	 	 	811,276	 	 	 	850,645	 	
 	 	 		 	 	 		 	
Commitments and Contingencies	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	
Total Capitalization and Liabilities	 	$	3,711,798	 	 	$	3,719,060	 	
 	 	 		 	 	 		 	
See Notes to Consolidated Financial Statements
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NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands of dollars)	
Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net Income Available for Common Stock	 	$	166,586	 	 	$	178,944	 	 	$	117,682	 	
 	Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	(Gain) Loss on Sale of Timber Properties	 	 	1,252	 	 	 	(168,787	)	 	 	—	 	
 	 	(Gain) Loss on Sale of Oil and Gas Producing Properties	 	 	(4,645	)	 	 	58,472	 	 	 	—	 	
 	 	Impairment of Oil and Gas Producing Properties	 	 	—	 	 	 	42,774	 	 	 	—	 	
 	 	Depreciation, Depletion and Amortization	 	 	189,538	 	 	 	195,226	 	 	 	180,668	 	
 	 	Deferred Income Taxes	 	 	40,329	 	 	 	78,369	 	 	 	62,013	 	
 	 	Impairment of Investment in Partnership	 	 	—	 	 	 	—	 	 	 	15,167	 	
 	 	Cumulative Effect of Changes in Accounting	 	 	—	 	 	 	8,892	 	 	 	—	 	
 	 	(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions	 	 	(19	)	 	 	703	 	 	 	361	 	
 	 	Minority Interest in Foreign Subsidiaries	 	 	1,933	 	 	 	785	 	 	 	730	 	
 	 	Other	 	 	9,839	 	 	 	11,289	 	 	 	9,842	 	
 	 	Change in:	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Receivables and Unbilled Utility Revenue	 	 	4,840	 	 	 	(28,382	)	 	 	40,786	 	
 	 	 	Gas Stored Underground and Materials and Supplies	 	 	9,860	 	 	 	(12,421	)	 	 	8,717	 	
 	 	 	Unrecovered Purchased Gas Costs	 	 	21,160	 	 	 	(16,261	)	 	 	(8,318	)	
 	 	 	Prepayments	 	 	8,146	 	 	 	(2,773	)	 	 	(1,737	)	
 	 	 	Accounts Payable	 	 	(5,134	)	 	 	13,699	 	 	 	(24,025	)	
 	 	 	Amounts Payable to Customers	 	 	2,462	 	 	 	692	 	 	 	(51,223	)	
 	 	 	Other Accruals and Current Liabilities	 	 	38,718	 	 	 	8,595	 	 	 	(27,332	)	
 	 	 	Other Assets	 	 	(10,693	)	 	 	(32,681	)	 	 	11,869	 	
 	 	 	Other Liabilities	 	 	(29,872	)	 	 	(10,298	)	 	 	10,350	 	
 	 	 		 	 	 		 	 	 		 	
Net Cash Provided by Operating Activities	 	 	444,300	 	 	 	326,837	 	 	 	345,550	 	
 	 	 		 	 	 		 	 	 		 	
Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Capital Expenditures	 	 	(172,341	)	 	 	(152,251	)	 	 	(232,368	)	
 	Investment in Subsidiaries, Net of Cash Acquired	 	 	—	 	 	 	(228,814	)	 	 	—	 	
 	Investment in Partnerships	 	 	—	 	 	 	(375	)	 	 	(536	)	
 	Net Proceeds from Sale of Timber Properties	 	 	—	 	 	 	186,014	 	 	 	—	 	
 	Net Proceeds from Sale of Oil and Gas Producing Properties	 	 	7,162	 	 	 	78,531	 	 	 	22,068	 	
 	Other	 	 	1,974	 	 	 	12,065	 	 	 	5,012	 	
 	 	 		 	 	 		 	 	 		 	
Net Cash Used in Investing Activities	 	 	(163,205	)	 	 	(104,830	)	 	 	(205,824	)	
 	 	 		 	 	 		 	 	 		 	
Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Change in Notes Payable to Banks and Commercial Paper	 	 	38,600	 	 	 	(147,622	)	 	 	(224,845	)	
 	Net Proceeds from Issuance of Long-Term Debt	 	 	—	 	 	 	248,513	 	 	 	243,844	 	
 	Reduction of Long-Term Debt	 	 	(243,085	)	 	 	(227,826	)	 	 	(104,212	)	
 	Proceeds from Issuance of Common Stock	 	 	23,763	 	 	 	17,019	 	 	 	10,915	 	
 	Dividends Paid on Common Stock	 	 	(89,092	)	 	 	(84,530	)	 	 	(80,974	)	
 	 	 		 	 	 		 	 	 		 	
Net Cash Used in Financing Activities	 	 	(269,814	)	 	 	(194,446	)	 	 	(155,272	)	
 	 	 		 	 	 		 	 	 		 	
Effect of Exchange Rates on Cash	 	 	3,451	 	 	 	1,644	 	 	 	1,535	 	
 	 	 		 	 	 		 	 	 		 	
Net Increase (Decrease) in Cash and Temporary Cash Investments	 	 	14,732	 	 	 	29,205	 	 	 	(14,011	)	
Cash and Temporary Cash Investments At Beginning of Year	 	 	51,421	 	 	 	22,216	 	 	 	36,227	 	
 	 	 		 	 	 		 	 	 		 	
Cash and Temporary Cash Investments At End of Year	 	$	66,153	 	 	$	51,421	 	 	$	22,216	 	
 	 	 		 	 	 		 	 	 		 	
Supplemental Disclosure of Cash Flow Information	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash Paid For:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Interest	 	$	90,705	 	 	$	104,452	 	 	$	100,397	 	
 	Income Taxes	 	$	30,214	 	 	$	56,146	 	 	$	29,985	 	
 	 	 		 	 	 		 	 	 		 	
See Notes to Consolidated Financial Statements
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NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands of dollars)	
Net Income Available for Common Stock	 	$	166,586	 	 	$	178,944	 	 	$	117,682	 	
 	 	 		 	 	 		 	 	 		 	
Other Comprehensive Income (Loss), Before Tax:	 	 	 	 	 	 	 	 	 	 	 	 	
Minimum Pension Liability Adjustment	 	 	56,612	 	 	 	(86,170	)	 	 	(52,977	)	
Foreign Currency Translation Adjustment	 	 	21,466	 	 	 	54,472	 	 	 	24,278	 	
Reclassification Adjustment for Realized Foreign Currency Translation Gain in Net Income	 	 	—	 	 	 	(9,607	)	 	 	—	 	
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	 	 	3,629	 	 	 	2,419	 	 	 	(2,086	)	
Unrealized Loss on Derivative Financial Instruments Arising During the Period	 	 	(129,934	)	 	 	(47,777	)	 	 	(42,584	)	
Reclassification Adjustment for Realized (Gain) Loss on Derivative Financial Instruments in Net Income	 	 	49,142	 	 	 	69,809	 	 	 	(20,063	)	
 	 	 		 	 	 		 	 	 		 	
Other Comprehensive Income (Loss), Before Tax	 	 	915	 	 	 	(16,854	)	 	 	(93,432	)	
 	 	 		 	 	 		 	 	 		 	
Income Tax Expense (Benefit) Related to Minimum Pension Liability Adjustment	 	 	19,814	 	 	 	(30,159	)	 	 	(18,542	)	
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	 	 	1,270	 	 	 	847	 	 	 	(730	)	
Income Tax Benefit Related to Unrealized Loss on Derivative Financial Instruments Arising During the Period	 	 	(49,113	)	 	 	(18,594	)	 	 	(17,341	)	
Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gain) Loss on Derivative Financial Instruments in Net Income	 	 	18,182	 	 	 	26,953	 	 	 	(8,040	)	
 	 	 		 	 	 		 	 	 		 	
Income Taxes — Net	 	 	(9,847	)	 	 	(20,953	)	 	 	(44,653	)	
 	 	 		 	 	 		 	 	 		 	
Other Comprehensive Income (Loss)	 	 	10,762	 	 	 	4,099	 	 	 	(48,779	)	
 	 	 		 	 	 		 	 	 		 	
Comprehensive Income	 	$	177,348	 	 	$	183,043	 	 	$	68,903	 	
 	 	 		 	 	 		 	 	 		 	
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 subsidiaries. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated.
      The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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

	Regulation	
      The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to accounting principles generally accepted in the United States of America, 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 B — Regulatory Matters for further discussion.
      In the International segment, rates charged for the sale of thermal energy and electric energy at the retail level are subject to regulation and audit in the Czech Republic by the Czech Ministry of Finance. The regulation of electric energy rates at the retail level indirectly impacts the rates charged by the International segment for its electric energy sales at the wholesale level.

	Revenues	
      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 Pipeline and Storage, International and Energy Marketing segments record revenue as bills are rendered for service supplied on a calendar month basis. The International segment also records monthly revenue on an estimated basis for certain heating customers. The customers make estimated payments on a monthly basis and a final true-up and bill is rendered at the end of the calendar year. The Company’s Timber segment records revenue on lumber and log sales as products are shipped.
      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.

	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.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note B — Regulatory Matters for further discussion.
      The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a weather normalization clause (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 more than 2.2% warmer than normal results in a surcharge being added to customers’ current bills, while weather that is more than 2.2% 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.
      Oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. All costs directly associated with property acquisition, exploration and development activities are capitalized, up to certain specified limits. If capitalized costs exceed these limits at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The Company’s capitalized costs exceeded the full cost ceiling for the Company’s Canadian properties at June 30, 2003 and September 30, 2003. The Company recognized impairments of $31.8 million and $11.0 million at June 30, 2003 and September 30, 2003, respectively.
      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.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	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 unevaluated 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	
			
		2004		2003	

		(Thousands)	
Utility	 	$	1,426,540	 	 	$	1,380,278	 	
Pipeline and Storage	 	 	946,866	 	 	 	854,923	 	
Exploration and Production	 	 	1,517,856	 	 	 	1,673,827	 	
International	 	 	379,356	 	 	 	349,132	 	
Energy Marketing	 	 	1,169	 	 	 	1,159	 	
Timber	 	 	97,290	 	 	 	96,315	 	
All Other and Corporate	 	 	28,442	 	 	 	20,541	 	
 	 	 		 	 	 		 	
 	 	$	4,397,519	 	 	$	4,376,175	 	
 	 	 		 	 	 		 	
      Average depreciation, depletion and amortization rates are as follows: 

			
		Year Ended September 30	
			
		2004		2003		2002	
							
Utility	 	 	2.8	%	 	 	2.8	%	 	 	2.8	%	
Pipeline and Storage	 	 	4.1	%	 	 	4.4	%	 	 	3.6	%	
Exploration and Production, per Mcfe(1)	 	$	1.49	 	 	$	1.34	 	 	$	1.19	 	
International	 	 	4.2	%	 	 	4.2	%	 	 	4.2	%	
Energy Marketing	 	 	8.7	%	 	 	10.9	%	 	 	16.4	%	
Timber	 	 	6.5	%	 	 	7.0	%	 	 	3.2	%	
All Other and Corporate	 	 	6.2	%	 	 	1.7	%	 	 	2.7	%	

		
(1) 	Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Oil and Gas Producing Properties, depletion of oil and gas producing properties amounted to $1.47, $1.30 and $1.16 per Mcfe of production in 2004, 2003 and 2002, respectively.	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Cumulative Effect of Changes in Accounting	
      Effective October 1, 2002, the Company adopted 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. In the Company’s case, SFAS 143 changed the accounting for plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells. In prior fiscal years, the Company accounted for plugging and abandonment costs using the Securities and Exchange Commission’s full cost accounting rules. SFAS 143 was calculated retroactively to determine the cumulative effect through October 1, 2002. This cumulative effect reduced earnings $0.6 million, net of income tax. If the new method of accounting for plugging and abandonment costs had been effective for 2002, there would not have been a material change to net income available for common stock. A reconciliation of the Company’s asset retirement obligation calculated in accordance with SFAS 143 is shown below ($000s): 

			
		Year Ended	
		September 30	
			
		2004		2003	

		(Thousands)	
Balance at Beginning of Year	 	$	27,493	 	 	$	36,090	 	
Liabilities Incurred and Revisions of Estimates	 	 	3,510	 	 	 	242	 	
Liabilities Settled	 	 	(831	)	 	 	(13,227	)	
Accretion Expense	 	 	1,933	 	 	 	2,602	 	
Exchange Rate Impact	 	 	187	 	 	 	1,786	 	
 	 	 		 	 	 		 	
Balance at End of Year	 	$	32,292	 	 	$	27,493	 	
 	 	 		 	 	 		 	
      In the Company’s Utility and Pipeline and Storage segment, costs of removal are collected from customers through depreciation expense. 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, 2004 and 2003, the costs of removal reclassified to other regulatory liabilities amounted to $82.0 million and $76.8 million, respectively.
      Effective October 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). In accordance with SFAS 142, the Company stopped amortization of goodwill and tested it for impairment as of October 1, 2002. The Company’s goodwill balance as of October 1, 2002 totaled $8.3 million and was related to the Company’s investments in the Czech Republic, which are included in the International segment. As a result of the impairment test, the Company recognized an impairment of $8.3 million. The Company used discounted cash flows to estimate the fair value of its goodwill and determined that the goodwill had no remaining value. Based on projected restructuring in the Czech electricity market, the Company could not be assured that the level of future cash flows from the Company’s investments in the Czech Republic would attain the level that was originally forecasted. In accordance with SFAS 142, this impairment was reported as a cumulative effect of change in accounting. Goodwill amortization amounted to $0.6 million in 2002.

	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 E — Financial Instruments for further discussion.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      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, no cost collars, options 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. Any ineffectiveness associated with the cash flow hedges is recorded in the Consolidated Statements of Income. The Company did not experience any material ineffectiveness with regard to its cash flow hedges during 2004, 2003 or 2002. 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 or interest expense on the Consolidated Statements of Income. 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. 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 2004, 2003 or 2002.

	Accumulated Other Comprehensive Income (Loss)	
      The components of Accumulated Other Comprehensive Income (Loss) are as follows:

			
		Year Ended	
		September 30	
			
		2004		2003	

		(Thousands)	
Minimum Pension Liability Adjustment	 	$	(53,648	)	 	$	(90,446	)	
Cumulative Foreign Currency Translation Adjustment	 	 	51,516	 	 	 	30,050	 	
Net Unrealized Loss on Derivative Financial Instruments	 	 	(56,733	)	 	 	(6,872	)	
Net Unrealized Gain on Securities Available for Sale	 	 	4,090	 	 	 	1,731	 	
 	 	 		 	 	 		 	
Accumulated Other Comprehensive Loss	 	$	(54,775	)	 	$	(65,537	)	
 	 	 		 	 	 		 	
      At September 30, 2004, it is estimated that $45.4 million of the net unrealized loss on derivative financial instruments shown in the table above will be reclassified into the Consolidated Statement of Income during 2005. As disclosed in Note E — Financial Instruments, the Company’s derivative financial instruments extend out to 2009.

	Gas Stored Underground — Current	
      In the Utility segment, gas stored underground — current in the amount of $46.6 million is carried at lower of cost or market, on a last-in, first-out (LIFO) method. Based upon the average price of spot market gas purchased in September 2004, 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 $113.3 million at September 30, 2004. All other gas stored underground — current 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)

	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).

	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. No provision has been made for domestic income taxes applicable to certain undistributed earnings of foreign subsidiaries as these amounts are considered to be permanently reinvested outside the United States.

	Consolidated Statement of Cash Flows	
      For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash and temporary cash investments includes cash held in margin accounts to serve as collateral for open positions on exchange-traded futures contracts and exchange-traded options. The amounts held in margin accounts amounted to $8.6 million and $1.5 million at September 30, 2004 and 2003, 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. The only potentially dilutive securities the Company has outstanding are stock options. The diluted weighted average shares outstanding shown on the Consolidated Statement of Income reflects the potential dilution as a result of these stock options as determined using the Treasury Stock Method. Stock options that are antidilutive are excluded from the calculation of diluted earnings per common share. For 2004, 2003 and 2002, 2,296,828, 7,789,688 and 5,260,633 stock options, respectively, were excluded as being antidilutive.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Stock-Based Compensation	
      The Company accounts for stock-based compensation using the intrinsic value method specified by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. Under that method, no compensation expense was recognized for options granted under the plans for the years ended September 30, 2004, 2003 and 2002. Had compensation expense been determined based on fair value at the grant dates, which is the accounting treatment specified by SFAS 123, “Accounting for Stock-Based Compensation,” the Company’s net income and earnings per share would have been reduced to the pro forma amounts below: 

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands, except per share amounts)	
Net Income Available for Common Stock As Reported	 	$	166,586	 	 	$	178,944	 	 	$	117,682	 	
Deduct: Total Compensation Expense Determined Based on Fair Value at the Grant Dates	 	 	1,318	 	 	 	3,105	 	 	 	4,641	 	
 	 	 		 	 	 		 	 	 		 	
Pro Forma Net Income Available for Common Stock	 	$	165,268	 	 	$	175,839	 	 	$	113,041	 	
 	 	 		 	 	 		 	 	 		 	
Earnings Per Common Share:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Basic — As Reported	 	$	2.03	 	 	$	2.21	 	 	$	1.47	 	
 	Basic — Pro Forma	 	$	2.01	 	 	$	2.18	 	 	$	1.42	 	
 	Diluted — As Reported	 	$	2.01	 	 	$	2.20	 	 	$	1.46	 	
 	Diluted — Pro Forma	 	$	1.99	 	 	$	2.16	 	 	$	1.40	 	
      The weighted average fair value per share of options granted in 2004, 2003 and 2002 was $4.66, $4.17 and $4.32, respectively. These weighted average fair values were estimated on the date of grant using a binomial option pricing model with the following weighted average assumptions: 

			
		Year Ended September 30	
			
		2004		2003		2002	
							
Quarterly Dividend Yield	 	 	1.12	%	 	 	1.10	%	 	 	1.07	%	
Annual Standard Deviation (Volatility)	 	 	21.77	%	 	 	22.24	%	 	 	21.83	%	
Risk Free Rate	 	 	4.61	%	 	 	3.33	%	 	 	4.88	%	
Expected Term — in Years	 	 	7.0	 	 	 	6.5	 	 	 	5.5	 	

	New Accounting Pronouncements	
      In September 2004, the SEC issued SAB 106. SAB 106 addresses the application of SFAS 143 to companies that follow the full cost method of accounting for oil and gas property acquisition, exploration and development costs. SAB 106 states that after adoption of SFAS 143, the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation. The Company adopted SAB 106 for purposes of the full cost ceiling calculation at September 30, 2004. The adoption of SAB 106 did not have any impact on the Company’s financial statements and did not have a material effect on the results of the ceiling test calculation.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note B — Regulatory Matters

	Regulatory Assets and Liabilities	
      The Company has recorded the following regulatory assets and liabilities:

			
		At September 30	
			
		2004		2003	

		(Thousands)	
Regulatory Assets(1):	 	 	 	 	 	 	 	 	
Recoverable Future Taxes (Note C)	 	$	83,847	 	 	$	84,818	 	
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A)	 	 	7,532	 	 	 	28,692	 	
Unamortized Debt Expense (Note A)	 	 	9,882	 	 	 	11,364	 	
Pension and Post-Retirement Benefit Costs (2)(Note F)	 	 	62,664	 	 	 	47,750	 	
Other(2)	 	 	4,198	 	 	 	4,631	 	
 	 	 		 	 	 		 	
 	Total Regulatory Assets	 	 	168,123	 	 	 	177,255	 	
 	 	 		 	 	 		 	
Regulatory Liabilities:	 	 	 	 	 	 	 	 	
Cost of Removal Regulatory Liability (See Cumulative Effect Discussion in Note A)	 	 	82,020	 	 	 	76,782	 	
Amounts Payable to Customers (See Regulatory Mechanisms in Note A)	 	 	3,154	 	 	 	692	 	
New York Rate Settlements(3)	 	 	26,048	 	 	 	30,900	 	
Taxes Refundable to Customers (Note C)	 	 	11,065	 	 	 	13,519	 	
Pension and Post-Retirement Benefit Costs(3) (Note F)	 	 	13,232	 	 	 	23,719	 	
Other(3)	 	 	28,389	 	 	 	18,013	 	
 	 	 		 	 	 		 	
 	Total Regulatory Liabilities	 	 	163,908	 	 	 	163,625	 	
 	 	 		 	 	 		 	
Net Regulatory Position	 	$	4,215	 	 	$	13,630	 	

		
(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.

	New York Rate Settlements	
      With respect to utility services provided in New York, the Company has entered into rate settlements approved by the State of New York Public Service Commission (NYPSC). The rate settlements provide for a sharing mechanism, whereby earnings above an 11.5% (11.0%, effective October 1, 2003) return on equity are to be shared equally between shareholders and customers. As a result of this sharing mechanism, the Company had liabilities of $12.0 million and $11.4 million at September 30, 2004 and 2003, respectively. Other aspects of the settlements include a special reserve of $3.5 million and $5.4 million at September 30, 2004 and 2003, respectively, to be applied against the Company’s incremental costs resulting from the
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NYPSC’s gas restructuring effort and a “cost mitigation reserve” of $5.6 million and $8.2 million at September 30, 2004 and 2003, respectively. The cost mitigation reserve is an accumulation of certain refunds from upstream pipeline companies and certain credits which can be used to offset certain specific expense items. Various other regulatory liabilities have also been created through the New York rate settlements and amounted to $4.9 million and $5.9 million at September 30, 2004 and 2003, respectively. 
Note C — Income Taxes
      The components of federal, state and foreign income taxes included in the Consolidated Statement of Income are as follows:

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands)	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current Income Taxes —
Federal	 	$	42,502	 	 	$	37,335	 	 	$	7,743	 	
 	 	State	 	 	7,871	 	 	 	11,990	 	 	 	1,384	 	
 	 	Foreign	 	 	2,035	 	 	 	467	 	 	 	894	 	
 	Deferred Income Taxes —
Federal	 	 	29,559	 	 	 	53,311	 	 	 	50,205	 	
 	 	State	 	 	9,620	 	 	 	12,983	 	 	 	9,968	 	
 	 	Foreign	 	 	1,150	 	 	 	12,075	 	 	 	1,840	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	92,737	 	 	 	128,161	 	 	 	72,034	 	
Other Income:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Deferred Investment Tax Credit	 	 	(697	)	 	 	(693	)	 	 	(697	)	
Minority Interest in Foreign Subsidiaries	 	 	374	 	 	 	(566	)	 	 	(277	)	
Cumulative Effect of Change in Accounting	 	 	—	 	 	 	(354	)	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	
Total Income Taxes	 	$	92,414	 	 	$	126,548	 	 	$	71,060	 	
 	 	 		 	 	 		 	 	 		 	
      The U.S. and foreign components of income (loss) before income taxes are as follows: 

			
		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands)	
U.S. 	 	$	232,928	 	 	$	383,695	 	 	$	180,349	 	
Foreign	 	 	26,072	 	 	 	(78,202	)	 	 	8,394	 	
 	 	 		 	 	 		 	 	 		 	
 	 	$	259,000	 	 	$	305,493	 	 	$	188,743	 	
 	 	 		 	 	 		 	 	 		 	
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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	
			
		2004		2003		2002	

		(Thousands)	
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35%	 	$	90,650	 	 	$	106,923	 	 	$	66,060	 	
Increase (Reduction) in Taxes Resulting from:	 	 	 	 	 	 	 	 	 	 	 	 	
 	State Income Taxes	 	 	11,369	 	 	 	16,232	 	 	 	7,379	 	
 	Foreign Tax Differential	 	 	(1,166	)	 	 	3,318	 	 	 	(481	)	
 	Foreign Tax Rate Reduction	 	 	(5,174	)	 	 	—	 	 	 	—	 	
 	Miscellaneous	 	 	(3,265	)	 	 	75	 	 	 	(1,898	)	
 	 	 		 	 	 		 	 	 		 	
Total Income Taxes	 	$	92,414	 	 	$	126,548	 	 	$	71,060	 	
 	 	 		 	 	 		 	 	 		 	
      Legislation was enacted in the Czech Republic which reduces the corporate statutory income tax rate from 31% to 24% over a three-year period. The foreign tax rate reduction amount shown above reflects a reduction in deferred income taxes that were provided in prior years when a higher statutory tax rate was in effect.
      Significant components of the Company’s deferred tax liabilities and assets are as follows: 

			
		At September 30	
			
		2004		2003	

		(Thousands)	
Deferred Tax Liabilities:	 	 	 	 	 	 	 	 	
 	Property, Plant and Equipment	 	$	568,114	 	 	$	519,578	 	
 	Other	 	 	37,051	 	 	 	21,532	 	
 	 	 		 	 	 		 	
Total Deferred Tax Liabilities	 	 	605,165	 	 	 	541,110	 	
 	 	 		 	 	 		 	
Deferred Tax Assets:	 	 	 	 	 	 	 	 	
 	Minimum Pension Liability Adjustment	 	 	(28,887	)	 	 	(48,701	)	
 	Capital Loss Carryover	 	 	(12,546	)	 	 	(18,607	)	
 	Unrealized Hedging Losses	 	 	(33,890	)	 	 	(4,509	)	
 	Other	 	 	(74,624	)	 	 	(52,368	)	
 	 	 		 	 	 		 	
 	 	 	(149,947	)	 	 	(124,185	)	
 	Valuation Allowance	 	 	2,877	 	 	 	6,357	 	
 	 	 		 	 	 		 	
Total Deferred Tax Assets	 	 	(147,070	)	 	 	(117,828	)	
 	 	 		 	 	 		 	
Total Net Deferred Income Taxes	 	$	458,095	 	 	$	423,282	 	
 	 	 		 	 	 		 	
      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 $11.1 million and $13.5 million at September 30, 2004 and 2003, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $83.8 million and $84.8 million at September 30, 2004 and 2003, respectively.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The Company has undistributed earnings of foreign subsidiaries that relate to its operations in the Czech Republic. These earnings are considered to be permanently reinvested outside the United States and, accordingly, no U.S. income taxes have been provided thereon. In the event such earnings are distributed, the Company may be subject to U.S. income taxes and foreign withholding taxes, net of allowable foreign tax credits or deductions. At September 30, 2004, such undistributed earnings totaled $49.6 million. In addition, there was a $35.8 million positive cumulative translation adjustment attributable to this investment, and similarly, no U.S. income taxes have been provided thereon.
      The American Jobs Creation Act of 2004 was signed into law on October 22, 2004. The Company is reviewing the aspects of this legislation which affect, or will affect, the Company’s various segments, including the provision providing a substantially reduced tax rate of 5.25% on certain dividends received from foreign affiliates. This provision is effective, at the election of the Company, for foreign dividends received in either 2005 or 2006.
      A capital loss carryover of $36 million exists at September 30, 2004, which expires if not utilized by September 30, 2008. Although realization is not assured, management estimates that a portion of the deferred tax asset associated with this carryover will be realized during the carryover period, and a valuation allowance is recorded for the remaining portion. Adjustments to the valuation allowance may be necessary in the future if estimates of capital gain income are revised.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note D — Capitalization and Short-Term Borrowings

	Summary of Changes in Common Stock Equity	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
						Earnings		Accumulated	
		Common Stock				Reinvested		Other	
				Paid In		in the		Comprehensive	
		Shares		Amount		Capital		Business		Income (Loss)	

		(Thousands, except per share amounts)	
Balance at September 30, 2001	 	 	79,406	 	 	$	79,406	 	 	$	430,618	 	 	$	513,488	 	 	$	(20,857	)	
Net Income Available for Common Stock	 	 	 	 	 	 	 	 	 	 	 	 	 	 	117,682	 	 	 	 	 	
Dividends Declared on Common Stock ($1.03 Per Share)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(81,773	)	 	 	 	 	
Other Comprehensive Loss, Net of Tax	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(48,779	)	
Common Stock Issued Under Stock and Benefit Plans	 	 	859	 	 	 	859	 	 	 	16,214	 	 	 	 	 	 	 	 	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Balance at September 30, 2002	 	 	80,265	 	 	 	80,265	 	 	 	446,832	 	 	 	549,397	 	 	 	(69,636	)	
Net Income Available for Common Stock	 	 	 	 	 	 	 	 	 	 	 	 	 	 	178,944	 	 	 	 	 	
Dividends Declared on Common Stock ($1.06 Per Share)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(85,651	)	 	 	 	 	
Other Comprehensive Income, Net of Tax	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	4,099	 	
Cancellation of Shares	 	 	(3	)	 	 	(3	)	 	 	(63	)	 	 	 	 	 	 	 	 	
Common Stock Issued Under Stock and Benefit Plans	 	 	1,176	 	 	 	1,176	 	 	 	32,030	 	 	 	 	 	 	 	 	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Balance at September 30, 2003	 	 	81,438	 	 	 	81,438	 	 	 	478,799	 	 	 	642,690	 	 	 	(65,537	)	
Net Income Available for Common Stock	 	 	 	 	 	 	 	 	 	 	 	 	 	 	166,586	 	 	 	 	 	
Dividends Declared on Common Stock ($1.10 Per Share)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(90,350	)	 	 	 	 	
Other Comprehensive Income, Net of Tax	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	10,762	 	
Common Stock Issued Under Stock and Benefit Plans	 	 	1,552	 	 	 	1,552	 	 	 	27,761	 	 	 	 	 	 	 	 	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Balance at September 30, 2004	 	 	82,990	 	 	$	82,990	 	 	$	506,560	 	 	$	718,926	(1)	 	$	(54,775	)	

		
(1) 	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, 2004, $644.5 million of accumulated earnings was free of such limitations.	

	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.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The Company also has a Director Stock Program under which it issues shares of the Company common stock to its non-employee directors as partial consideration for their services as directors.

	Shareholder Rights Plan	
      In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). Effective April 30, 1999, the Plan was amended and is now embodied in an Amended and Restated Rights Agreement, under which the Board of Directors made adjustments in connection with the two-for-one stock split of September 7, 2001.
      The holders of the Company’s common stock have one right (Right) for each of their shares. Each Right, which will initially be evidenced by the Company’s common stock certificates representing the outstanding shares of common stock, entitles the holder to purchase one-half of one share of common stock at a purchase price of $65.00 per share, being $32.50 per half share, subject to adjustment (Purchase Price).
      The Rights become exercisable upon the occurrence of a distribution date. At any time following a distribution date, each holder of a Right may exercise its right to receive common stock (or, under certain circumstances, other property of the Company) having a value equal to two times the Purchase Price of the Right then in effect. 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 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 common stock of the acquiring company having a value equal to two times the Purchase Price of the Right then in effect. 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 announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of 10% or more of the total voting power of the Company, 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 announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of 10% or more of the total voting power of the Company, 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.
      After a distribution date, Rights that are owned by an acquiring person will be null and void. 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, 2008, unless they are exchanged or redeemed earlier than that date.
      The Rights have anti-takeover effects because they will cause substantial dilution of the common stock if a person attempts to acquire the Company on terms not approved by the Board of Directors.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	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, restricted stock, performance units or performance shares. Stock options 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 is exercisable less than one year or more than ten years after the date of each grant.
      Transactions involving option shares for all plans are summarized as follows: 

		Number of			
		Shares Subject		Weighted Average	
		to Option		Exercise Price	
					
Outstanding at September 30, 2001	 	 	9,372,686	 	 	$	21.92	 	
Granted in 2002(2)	 	 	5,673,172	 	 	$	22.26	 	
Exercised in 2002(1)	 	 	(247,910	)	 	$	15.76	 	
Forfeited in 2002	 	 	(168,444	)	 	$	25.56	 	
 	 	 		 	 	 		 	
Outstanding at September 30, 2002	 	 	14,629,504	 	 	$	22.12	 	
Granted in 2003	 	 	233,500	 	 	$	24.61	 	
Exercised in 2003(1)	 	 	(673,866	)	 	$	16.56	 	
Forfeited in 2003	 	 	(123,800	)	 	$	23.55	 	
 	 	 		 	 	 		 	
Outstanding at September 30, 2003	 	 	14,065,338	 	 	$	22.41	 	
Granted in 2004	 	 	87,000	 	 	$	24.95	 	
Exercised in 2004(1)	 	 	(1,571,794	)	 	$	18.29	 	
Forfeited in 2004	 	 	(84,105	)	 	$	25.40	 	
 	 	 		 	 	 		 	
Outstanding at September 30, 2004	 	 	12,496,439	 	 	$	22.93	 	
 	 	 		 	 	 		 	
Option shares exercisable at September 30, 2004	 	 	11,594,368	 	 	$	22.83	 	
Option shares available for future grant at September 30, 2004(3)	 	 	919,537	 	 	 	 	 	

		
(1) 	In connection with exercising these options, 557,410, 200,708 and 43,834 shares were surrendered and canceled during 2004, 2003 and 2002, respectively.	
 		
(2) 	Including 3,097,172 non-qualified stock options issued in November 2001. The Company canceled 3,097,172 stock appreciation rights (SARs) in November 2001 and issued 3,097,172 non-qualified stock options. The Company eliminated all future awards of SARs.	
 		
(3) 	Including shares available for restricted stock grants.	
      The following table summarizes information about options outstanding at September 30, 2004: 

					
		Options Outstanding		Options Exercisable	
					
				Weighted					
		Number		Average		Weighted		Number		Weighted	
		Outstanding		Remaining		Average		Exercisable		Average	
Range of Exercise Price		at 9/30/04		Contractual Life		Exercise Price		at 9/30/04		Exercise Price	
											
$13.90-$16.68	 	 	441,060	 	 	 	1.0	 	 	$	14.23	 	 	 	441,060	 	 	$	14.23	 	
$16.69-$19.46	 	 	1,139,558	 	 	 	2.0	 	 	$	18.38	 	 	 	1,139,558	 	 	$	18.38	 	
$19.47-$22.24	 	 	2,545,696	 	 	 	5.0	 	 	$	21.26	 	 	 	2,432,296	 	 	$	21.25	 	
$22.25-$25.02	 	 	6,073,297	 	 	 	5.3	 	 	$	23.34	 	 	 	5,354,957	 	 	$	23.19	 	
$25.03-$27.80	 	 	2,296,828	 	 	 	6.3	 	 	$	27.63	 	 	 	2,226,497	 	 	$	27.68	 	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      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 periods during which the vesting restrictions exist. 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.
      The following table summarizes the awards of restricted stock over the past three years: 

			
		Year Ended September 30	
			
		2004		2003		2002	
							
Shares of Restricted Stock Awarded	 	 	—	 	 	 	—	 	 	 	100,000	 	
Weighted Average Market Price of Stock on Award Date	 	 	—	 	 	 	—	 	 	$	24.50	 	
      As of September 30, 2004, 98,528 shares of non-vested restricted stock were outstanding. Vesting restrictions will lapse as follows: 2005 — 33,600 shares; 2006 — 34,600 shares; 2007 — 29,000 shares; and 2010 — 1,328 shares.
      Compensation expense related to restricted stock under the Company’s stock plans was $0.7 million, $1.0 million and $0.7 million for the years ended September 30, 2004, 2003 and 2002, respectively.

	Redeemable Preferred Stock	
      As of September 30, 2004, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.

	Long-Term Debt	
      The outstanding long-term debt is as follows:

			
		At September 30	
			
		2004		2003	

		(Thousands)	
Debentures(1):	 	 	 	 	 	 	 	 	
 	7 3/4% due February 2004	 	$	—	 	 	$	125,000	 	
Medium-Term Notes(1):	 	 	 	 	 	 	 	 	
 	6.0% to 7.50% due August 2004 to June 2025	 	 	749,000	 	 	 	849,000	 	
Notes(1):	 	 	 	 	 	 	 	 	
 	5.25% to 6.50% due March 2013 to September 2022(2)	 	 	347,272	 	 	 	347,400	 	
 	 	 		 	 	 		 	
 	 	 	1,096,272	 	 	 	1,321,400	 	
 	 	 		 	 	 		 	
Other Notes:	 	 	 	 	 	 	 	 	
 	Secured(3)	 	 	41,433	 	 	 	50,767	 	
 	Unsecured	 	 	9,872	 	 	 	17,343	 	
 	 	 		 	 	 		 	
Total Long-Term Debt	 	 	1,147,577	 	 	 	1,389,510	 	
Less Current Portion	 	 	14,260	 	 	 	241,731	 	
 	 	 		 	 	 		 	
 	 	$	1,133,317	 	 	$	1,147,779	 	

		
(1) 	These debentures, medium-term notes and notes are unsecured.	
 		
(2) 	At September 30, 2004 and 2003, $97,272,000 and $97,400,000, respectively, of these notes were callable at par at any time after September 15, 2006. The change in the amount outstanding from year to year is	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

		
	attributable to the estates of individual note holders exercising put options due to the death of an individual note holder.	
 		
(3) 	These notes constitute “project financing” and are secured by the various project documentation and natural gas transportation contracts related to the Empire State Pipeline.	
      As of September 30, 2004, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $14.3 million in 2005, $14.3 million in 2006, $9.3 million in 2007, $209.3 million in 2008, $104.1 million in 2009 and $796.3 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 (bi-lateral) 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. Each of these credit lines, which aggregate to $400.0 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. The total amount available to be issued under the Company’s commercial paper program is $200.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $220.0 million. Of that amount, $110.0 million is committed to the Company through September 25, 2005, and $110.0 million is committed to the Company through September 30, 2005.
      At September 30, 2004, the Company had outstanding short-term notes payable to banks and commercial paper of $26.5 million and $130.3 million, respectively. All of this debt was domestic. At September 30, 2003, the Company had outstanding notes payable to banks and commercial paper of $55.2 million and $63.0 million, respectively.
      The weighted average interest rate on notes payable to banks was 1.82% and 1.27% at September 30, 2004 and 2003, respectively. The weighted average interest rate on commercial paper was 1.85% and 1.18% at September 30, 2004 and 2003, respectively.

	Debt Restrictions	
      Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio (as calculated under that facility) will not at the last day of any fiscal quarter exceed .625 from October 1, 2003 through September 30, 2004 and .60 from October 1, 2004 and thereafter. At September 30, 2004, the Company’s debt to capitalization ratio (as calculated under the facility) was .51. The constraints specified in the committed credit facility would permit an additional $576.0 million in short-term and/or long-term debt to be outstanding before the Company’s debt to capitalization ratio would exceed .60. 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 and 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, 2004, the Company would have been permitted to issue up to a maximum of $713.0 million in additional long-term unsecured indebtedness at then current market interest rates (further limited by the debt to capitalization ratio constraints noted in the previous paragraph) in addition to being able to issue new indebtedness to replace maturing debt.
      The Company’s 1974 indenture pursuant to which $399.0 million (or 35%) of the Company’s long-term debt (as of September 30, 2004) 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
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 $220.0 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 fails 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, 2004, the Company had no debt outstanding under the committed credit facility. 
Note E — 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	
			
		2004		2004		2003		2003	
		Carrying		Fair		Carrying		Fair	
		Amount		Value		Amount		Value	

		(Thousands)	
Long-Term Debt	 	$	1,147,577	 	 	$	1,199,189	 	 	$	1,389,510	 	 	$	1,520,606	 	
      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 insurance are stated at their cash surrender values 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 includes cash surrender values of insurance contracts and marketable equity securities. The cash surrender values of the insurance contracts amounted to $56.1 million and $53.5 million at September 30, 2004 and 2003, respectively. The fair value of the equity mutual fund was $7.8 million and $4.8 million at September 30, 2004 and 2003, respectively. The gross unrealized gain on the equity mutual fund was $0.1 million at September 30, 2004, as compared with a gross unrealized loss of $0.6 million at September 30, 2003. The fair value of the stock of an insurance company was $8.7 million and $5.7 million at September 30, 2004 and 2003, respectively. The gross unrealized gain on this stock was $6.2 million and $3.2 million at September 30, 2004 and 2003, respectively. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	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, options 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 price quoted on the New York Mercantile Exchange (NYMEX) or a quoted natural gas price in “Inside FERC.” 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, 2004, the Company had natural gas price swap agreements covering a notional amount of 23.0 Bcf extending through 2009 at a weighted average fixed rate of $5.47 per Mcf. Of this amount, 3.3 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $5.51 per Mcf. The remaining 19.7 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $5.47 per Mcf. The Company also had crude oil price swap agreements covering a notional amount of 5,038,000 bbls extending through 2007 at a weighted average fixed rate of $32.01 per bbl. At September 30, 2004, the Company would have had to pay a net $82.2 million to terminate the price swap agreements.
      Under the no cost collars, the Company receives monthly payments from (or makes payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). The variable price is either a crude oil price quoted on the NYMEX or a quoted natural gas price in “Inside FERC.” These derivative financial instruments are accounted for as cash flow hedges and are used to lock in a price range for the anticipated sale of natural gas and crude oil production in the Exploration and Production segment. At September 30, 2004, the Company had no cost collars on natural gas covering a notional amount of 5.5 Bcf extending through 2006 with a weighted average floor price of $4.93 per Mcf and a weighted average ceiling price of $8.28 per Mcf. The Company also had no cost collars on crude oil covering a notional amount of 105,000 bbls extending through 2005 with a weighted average floor price of $25.00 per bbl and a weighted average ceiling price of $28.56 per bbl. At September 30, 2004, the Company would have had to pay $3.7 million to terminate the no cost collars.
      At September 30, 2004, the Company, in the Exploration and Production segment, had purchased natural gas put options and sold natural gas call options extending through 2006. The call options sold by the Company cover a notional amount of 1.1 Bcf at a weighted average strike price of $8.06 per Mcf. The put options purchased by the Company cover a notional amount of 1.1 Bcf at a weighted average strike price of $5.99 per Mcf. These derivative financial instruments are accounted for as cash flow hedges. The call options are used to establish a ceiling price (the Company makes payments to the counterparty when a variable price rises above the ceiling price) for the anticipated sale of natural gas in the Exploration and Production segment. At September 30, 2004, the Company would have had to pay $1.0 million to terminate these call options. The put options are used to establish a floor price (the Company receives payment from the counterparty when a variable price falls below the floor price) for the anticipated sale of natural gas in the Exploration and Production segment. At September 30, 2004, the Company would have received $0.2 million to terminate these put options.
      At September 30, 2004, the Company had long (purchased) futures contracts covering 3.5 Bcf of gas extending through 2007 at a weighted average contract price of $6.13 per Mcf. Of this amount, 3.1 Bcf is
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
accounted for as fair value hedges. They 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 commercial and industrial customers. The remaining 0.4 Bcf is accounted for as cash flow hedges. The Company would have received $5.1 million to terminate these futures contracts at September 30, 2004.
      At September 30, 2004, the Company had short (sold) futures contracts covering 7.3 Bcf of gas extending through 2006 at a weighted average contract price of $6.19 per Mcf. Of this amount, 5.9 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 Exploration and Production segment and the All Other category. The remaining 1.4 Bcf is accounted for as fair value hedges, since these contracts hedge against falling prices, a risk to which the Energy Marketing segment is exposed on its gas storage inventory and fixed price gas purchase commitments. The Company would have had to pay $11.3 million to terminate these futures contracts at September 30, 2004.
      The Company may be exposed to credit risk on some of the derivative financial instruments discussed 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 the parent companies of the respective counterparties to its derivative financial instruments. At September 30, 2004, the Company used seven counterparties for its over the counter derivative financial instruments. At September 30, 2004, no individual counterparty represented greater than 20% of total credit risk (measured as volumes hedged by an individual counterparty as a percentage of the Company’s total volumes hedged).
      The Company uses an interest rate collar to limit interest rate fluctuations on certain variable rate debt in the Pipeline and Storage segment. Under the interest rate collar the Company makes quarterly payments (or receives payments from) another party when a variable rate falls below an established floor rate (the Company pays the counterparty) or exceeds an established ceiling rate (the Company receives payment from the counterparty). Under the terms of the collar, which extends until 2009, the variable rate is based on London InterBank Offered Rate. The floor rate of the collar is 5.15% and the ceiling rate is 9.375%. At September 30, 2004 the notional amount on the collar was $44.3 million. The Company would have had to pay $2.2 million to terminate the interest rate collar at September 30, 2004.
Note F — Retirement Plan and Other Post-Retirement Benefits
      The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan) that covers substantially all domestic employees of the Company. The Company provides health care and life insurance benefits for substantially all domestic retired employees under a post-retirement benefit plan (Post-Retirement Plan).
      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 Voluntary Employees’ Beneficiary Association (VEBA) trusts for its Post-Retirement Plan. 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’ post-retirement health care and life insurance benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its Post-Retirement Plan. They are separate accounts in the Retirement Plan used to pay retiree medical benefits for the associated participants in the Retirement Plan. Contributions are tax-deductible when made and investments accumulate tax-free. Retirement Plan and Post-Retirement Plan assets primarily consist of equity and fixed income investments or units in commingled funds or money market funds.
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      The Company recovers certain of its net periodic pension and post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization. For financial reporting purposes, to the extent there is recovery in rates, 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. The regulatory treatment of a substantial amount of these regulatory assets and liabilities is governed by policy statements issued by the regulatory commissions having jurisdiction over the Utility and Pipeline and Storage segments. Pension and post-retirement benefit costs reflect the amount recovered from customers in rates during the year. Under the NYPSC’s policies, the Company segregates the amount of such costs collected in rates, but not yet contributed to the Retirement and Post-Retirement Plans, into a regulatory liability account. This liability accrues interest at the NYPSC-mandated interest rate, and this interest cost is included in pension and post-retirement benefit costs. For purposes of disclosure, the liability also remains in the disclosed pension and post-retirement benefit liability amount because it has not yet been contributed.
      The expected returns on plan assets of the Retirement Plan and Post-Retirement Plan are applied to the market-related value of plan assets of the respective plans. For the Retirement Plan, the market-related value of assets recognizes the performance of its portfolio over five years and reduces the effects of short-term market fluctuations. The market-related value of Post-Retirement Plan assets is set equal to market value.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      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 Post-Retirement Plan are as follows:

					
		Retirement Plan		Other Post-Retirement Benefits	

		Year Ended September 30		Year Ended September 30	
					
		2004		2003		2002		2004		2003		2002	

		(Thousands)	
Change in Benefit Obligation	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Benefit Obligation at Beginning of Period	 	$	694,960	 	 	$	625,470	 	 	$	580,046	 	 	$	467,418	 	 	$	393,851	 	 	$	304,548	 	
Service Cost	 	 	14,598	 	 	 	13,043	 	 	 	11,639	 	 	 	6,027	 	 	 	5,844	 	 	 	4,658	 	
Interest Cost	 	 	40,565	 	 	 	40,967	 	 	 	40,720	 	 	 	26,393	 	 	 	26,124	 	 	 	21,617	 	
Plan Participants’ Contributions	 	 	—	 	 	 	—	 	 	 	—	 	 	 	627	 	 	 	682	 	 	 	610	 	
Amendments	 	 	—	 	 	 	—	 	 	 	420	 	 	 	—	 	 	 	—	 	 	 	—	 	
Actuarial (Gain) Loss	 	 	(19,593	)	 	 	51,302	 	 	 	28,880	 	 	 	(62,146	)	 	 	57,983	 	 	 	76,972	 	
Benefits Paid	 	 	(36,998	)	 	 	(35,822	)	 	 	(36,235	)	 	 	(16,316	)	 	 	(17,066	)	 	 	(14,554	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Benefit Obligation at End of Period	 	$	693,532	 	 	$	694,960	 	 	$	625,470	 	 	$	422,003	 	 	$	467,418	 	 	$	393,851	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Change in Plan Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair Value of Assets at Beginning of Period	 	$	491,333	 	 	$	485,927	 	 	$	536,625	 	 	$	166,494	 	 	$	150,293	 	 	$	161,959	 	
Actual Return on Plan Assets	 	 	81,946	 	 	 	6,145	 	 	 	(29,898	)	 	 	38,960	 	 	 	390	 	 	 	(18,181	)	
Employer Contribution	 	 	37,085	 	 	 	35,083	 	 	 	15,435	 	 	 	39,720	 	 	 	32,195	 	 	 	20,459	 	
Plan Participants’ Contributions	 	 	—	 	 	 	—	 	 	 	—	 	 	 	627	 	 	 	682	 	 	 	610	 	
Benefits Paid	 	 	(36,998	)	 	 	(35,822	)	 	 	(36,235	)	 	 	(16,316	)	 	 	(17,066	)	 	 	(14,554	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Fair Value of Assets at End of Period	 	$	573,366	 	 	$	491,333	 	 	$	485,927	 	 	$	229,485	 	 	$	166,494	 	 	$	150,293	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Reconciliation of Funded Status	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded Status	 	$	(120,166	)	 	$	(203,627	)	 	$	(139,543	)	 	$	(192,518	)	 	$	(300,924	)	 	$	(243,558	)	
Unrecognized Net Actuarial Loss	 	 	159,554	 	 	 	222,250	 	 	 	132,064	 	 	 	108,943	 	 	 	212,242	 	 	 	157,247	 	
Unrecognized Transition (Asset) Obligation	 	 	—	 	 	 	—	 	 	 	(3,716	)	 	 	64,144	 	 	 	71,272	 	 	 	78,399	 	
Unrecognized Prior Service Cost	 	 	9,171	 	 	 	10,274	 	 	 	11,451	 	 	 	20	 	 	 	26	 	 	 	30	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net Amount Recognized at End of Period	 	$	48,559	 	 	$	28,897	 	 	$	256	 	 	$	(19,411	)	 	$	(17,384	)	 	$	(7,882	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Amounts Recognized in the Balance Sheets Consist of:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accrued Benefit Liability	 	$	(91,587	)	 	$	(153,240	)	 	$	(75,116	)	 	$	(27,263	)*	 	$	(23,163	)*	 	$	(20,375	)*	
 	Prepaid Benefit Cost	 	 	14,536	 	 	 	10,782	 	 	 	10,944	 	 	 	7,852	 	 	 	5,779	 	 	 	12,493	 	
 	Regulatory Assets	 	 	33,904	 	 	 	21,934	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	Intangible Assets	 	 	9,171	 	 	 	10,274	 	 	 	11,451	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	Accumulated Other Comprehensive Loss (Pre-Tax)	 	 	82,535	 	 	 	139,147	 	 	 	52,977	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net Amount Recognized at End of Period	 	$	48,559	 	 	$	28,897	 	 	$	256	 	 	$	(19,411	)	 	$	(17,384	)	 	$	(7,882	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discount Rate	 	 	6.25	%	 	 	6.00	%	 	 	6.75	%	 	 	6.25	%**	 	 	6.00	%	 	 	6.75	%	
Expected Return on Plan Assets	 	 	8.25	%	 	 	8.25	%	 	 	8.50	%	 	 	8.25	%	 	 	8.25	%	 	 	8.50	%	
Rate of Compensation Increase	 	 	6.11	%	 	 	6.11	%	 	 	6.11	%	 	 	6.11	%	 	 	6.11	%	 	 	6.11	%	

			
 	* 	Amounts are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets.	

		
** 	The weighted average discount rate was 6.0% through 12/8/2003. Subsequent to 12/8/2003, the discount rate used was 6.25%.	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

					
		Retirement Plan		Other Post-Retirement Benefits	

		Year Ended September 30		Year Ended September 30	
					
		2004		2003		2002		2004		2003		2002	

		(Thousands)	
Components of Net Periodic Benefit Cost	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Service Cost	 	$	14,598	 	 	$	13,043	 	 	$	11,639	 	 	$	6,027	 	 	$	5,844	 	 	$	4,658	 	
Interest Cost	 	 	40,565	 	 	 	40,967	 	 	 	40,720	 	 	 	26,393	 	 	 	26,124	 	 	 	21,617	 	
Expected Return on Plan Assets	 	 	(48,281	)	 	 	(47,260	)	 	 	(48,454	)	 	 	(14,898	)	 	 	(12,268	)	 	 	(13,551	)	
Amortization of Prior Service Cost	 	 	1,103	 	 	 	1,176	 	 	 	1,205	 	 	 	4	 	 	 	4	 	 	 	4	 	
Amortization of Transition Amount	 	 	—	 	 	 	(3,716	)	 	 	(3,716	)	 	 	7,127	 	 	 	7,127	 	 	 	7,127	 	
Recognition of Actuarial (Gain) or Loss	 	 	9,438	 	 	 	2,231	 	 	 	(1,061	)	 	 	17,092	 	 	 	14,866	 	 	 	4,289	 	
Net Amortization and Deferral for Regulatory Purposes	 	 	722	 	 	 	3,781	 	 	 	7,379	 	 	 	(9,731	)	 	 	(15,423	)	 	 	(729	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net Periodic Benefit Cost	 	$	18,145	 	 	$	10,222	 	 	$	7,712	 	 	$	32,014	 	 	$	26,274	 	 	$	23,415	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Other Comprehensive (Income) Loss (Pre-Tax) Attributable to Change in Additional Minimum Liability Recognition	 	$	(56,612	)	 	$	86,170	 	 	$	52,977	 	 	$	—	 	 	$	—	 	 	$	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discount Rate	 	 	6.00	%	 	 	6.75	%	 	 	7.25	%	 	 	6.25	%*	 	 	6.75	%	 	 	7.25	%	
Expected Return on Plan Assets	 	 	8.25	%	 	 	8.50	%	 	 	8.50	%	 	 	8.25	%	 	 	8.50	%	 	 	8.50	%	
Rate of Compensation Increase	 	 	6.11	%	 	 	6.11	%	 	 	6.11	%	 	 	6.11	%	 	 	6.11	%	 	 	6.11	%	

		
* 	The weighted average discount rate was 6.0% through 12/8/2003. Subsequent to 12/8/2003, the discount rate used was 6.25%.	
      In accordance with the provisions of SFAS No. 87, “Employers’ Accounting for Pensions,” the Company recorded an additional minimum liability at September 30, 2004, 2003 and 2002 representing the excess of the accumulated benefit obligation over the fair value of plan assets plus accrued amounts previously recorded. An intangible asset, as shown in the table above, has offset the additional liability to the extent of previously Unrecognized Prior Service Cost. The amount in excess of Unrecognized Prior Service Cost is recorded net of the related tax benefit as accumulated other comprehensive loss. The pre-tax amount of the accumulated other comprehensive loss is shown in the table above. The projected benefit obligation, accumulated benefit obligation and fair value of assets for the retirement plan were as follows: 

		2004		2003		2002	
							
Projected Benefit Obligation	 	$	693,532	 	 	$	694,960	 	 	$	625,470	 	
Accumulated Benefit Obligation	 	$	616,513	 	 	$	611,858	 	 	$	550,099	 	
Fair Value of Plan Assets	 	$	573,366	 	 	$	491,333	 	 	$	485,927	 	
      The effect of the discount rate change for the Retirement Plan in 2004, was to decrease the benefit obligation by $20.2 million. The effects of the discount rate changes in 2003 and 2002 were to increase the Benefit Obligation of the Retirement Plan by $57.4 million and $34.0 million as of the end of each period, respectively.
      The Company made cash contributions totaling $37.1 million to the Retirement Plan during the year ended September 30, 2004. The Company expects that the annual contribution to the Retirement Plan in 2005 will be in the range of $25.0 million to $35.0 million. The following benefit payments, which reflect expected future service, are expected to be paid during the next five years and the five years thereafter:
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$40.5 million in 2005; $42.3 million in 2006; $44.3 million in 2007; $46.2 million in 2008; $48.6 million in 2009; and $279.3 million in the five years thereafter.
      In addition to the Retirement Plan discussed above, the Company also has a nonqualified 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 $13.7 million, $5.1 million and $8.5 million in 2004, 2003 and 2002, respectively. The accumulated benefit obligation for this plan was $18.2 million and $40.0 million at September 30, 2004 and 2003, respectively. The projected benefit obligation for the plan was $35.7 million and $48.3 million at September 30, 2004 and 2003, respectively. The actuarial valuations for this plan were determined based on a discount rate of 6.25%, 6.0% and 6.75% as of September 30, 2004, 2003 and 2002 respectively; a weighted rate of compensation increase of 10.0% as of September 30, 2004, and 8.11% as of September 30, 2003 and 2002; and an expected long-term rate of return on plan assets of 8.25%, at September 30, 2004 and 2003, and 8.5% at September 30, 2002. In January 2004, a participant of the plan received a $23.0 million lump sum payment under a provision of an agreement previously entered into between the Company and the participant. Under GAAP, this payment was considered a partial settlement of the projected benefit obligation of the plan. Accordingly, GAAP required that a pro rata portion of this plan’s unrecognized actuarial losses resulting from experience different from that assumed and from changes in assumptions be currently recognized. Therefore, $9.9 million before tax ($6.4 million, after tax) was recognized as a settlement expense (included in Operation and Maintenance Expense) on the income statement.
      On December 8, 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. This Act introduces 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. The discount rate was changed from 6.0% to 6.25% per annum as of the remeasurement date, which resulted in a decrease in the benefit obligation of $15.9 million. The accumulated post-retirement benefit obligation decreased by $42.9 million and the Net Periodic Post-Retirement Benefit Cost decreased by $4.2 million as a result of the Act. The effect of the subsidy by Net Periodic Post-Retirement Benefit Cost component is shown below and is reflected within Components of Net Periodic Benefit Cost shown in the table above. 

		Effect of Subsidy	
			
Service Cost	 	$	(286,527	)	
Interest Cost	 	 	(1,500,001	)	
Net Amortization and Deferral of Actuarial (Gain) Loss	 	 	(2,372,270	)	
 	 	 		 	
Net Periodic Post-Retirement Benefit Cost	 	$	(4,158,798	)	
 	 	 		 	
      The estimated gross amount of subsidy receipts is as follows: 

First Year	 	$	—	 	
Second Year	 	$	(649,599	)	
Third Year	 	$	(1,475,809	)	
Fourth Year	 	$	(1,672,331	)	
Fifth Year	 	$	(1,861,515	)	
Next Five Years	 	$	(11,935,959	)	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Effective July 1, 2004, the Medicare Part B Reimbursement trend assumption was changed. The effect of this change was to decrease the Accumulated Post-Retirement Benefit Obligation by $3.5 million for 2004.
      The effects of the discount rate changes in 2003 and 2002 were to increase the Other Post-Retirement Benefit Obligation by $45.1 million and $21.7 million as of the end of each period, respectively. The prescription drug aging assumptions and related factors were changed in 2003 to better reflect anticipated future experience. The effect of the changed prescription drug assumptions was to decrease the Accumulated Post-Retirement Benefit Obligation by $22.6 million. Other actuarial experience increased the Accumulated Post-Retirement Benefit Obligation in 2003 by $35.1 million. In 2002, the impact of changes in health care trend assumptions to better reflect anticipated future experiences was an increase in the Accumulated Post-Retirement Benefit Obligation of $57.9 million.
      The annual rate of increase in the per capita cost of covered medical care benefits was assumed to be 12.0% for 2002, 11.0% for 2003, 10.0% for 2004 and gradually decline to 5.5% by the year 2010 and remain level thereafter. The annual rate of increase for medical care benefits provided by healthcare maintenance organizations was assumed to be 12.0% in 2002, 11.0% in 2003, 10.0% in 2004 and gradually decline to 5.5% by the year 2010 and remain level thereafter. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed to be 15.0% for 2002, 13.5% for 2003 and 12.0% for 2004, and gradually decline to 5.5% by the year 2010 and remain level thereafter. The annual rate of increase in the per capita Medicare Part B Reimbursement was assumed to be 8.0% for 2002, 7.0% for 2003, 9.25% for 2004 and gradually decline to 5.0% by the year 2013 and remain level thereafter.
      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 Benefit Obligation as of October 1, 2004 would be increased by $57.4 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 2004 by $5.8 million. If the health care cost trend rates were decreased by 1% in each year, the Benefit Obligation as of October 1, 2004 would be decreased by $47.4 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 2004 by $4.7 million.
      The Company made cash contributions totaling $39.7 million to the Other Post-Retirement Benefit Plan during the year ended September 30, 2004. The Company expects that the annual contribution to the Other Post-Retirement Benefit Plan in 2005 will be in the range of $30.0 million to $40.0 million.
      The Company’s retirement plan weighted average asset allocations at September 30, 2004, 2003 and 2002 by asset category are as follows: 

					
				Percentage of Plan	
				Assets at	
				September 30	
		Target Allocation			
Asset Category		2005		2004		2003		2002	
									
Equity Securities	 	 	60-65%	 	 	 	61	%	 	 	53	%	 	 	55	%	
Fixed Income Securities	 	 	25-30%	 	 	 	28	%	 	 	32	%	 	 	29	%	
Other	 	 	10-15%	 	 	 	11	%	 	 	15	%	 	 	16	%	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	
Total	 	 	 	 	 	 	100	%	 	 	100	%	 	 	100	%	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The Company’s post-retirement plan weighted average asset allocations at September 30, 2004, 2003 and 2002 by asset category are as follows:

					
				Percentage of Plan	
				Assets at	
				September 30	
		Target Allocation			
Asset Category		2005		2004		2003		2002	
									
Equity Securities	 	 	93%	 	 	 	91	%	 	 	85	%	 	 	90	%	
Fixed Income Securities	 	 	3%	 	 	 	1	%	 	 	1	%	 	 	0	%	
Other	 	 	4%	 	 	 	8	%	 	 	14	%	 	 	10	%	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	
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 pension trust 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.
Note G — Commitments and Contingencies

	Environmental Matters	
      The Company is subject to various federal, state and local laws and regulations (including those of the Czech Republic and Canada) 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. The Company has estimated its remaining clean-up costs related to the sites described below in paragraphs (i) and (ii) will be $14.0 million. This liability has been recorded on the Consolidated Balance Sheet at September 30, 2004. Other than as discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, adverse changes in environmental regulations, new information or other factors could impact the Company.

	(i) Former Manufactured Gas Plant Sites	
      The Company has incurred or is incurring clean-up costs at five former manufactured gas plant sites in New York and Pennsylvania. Remediation is substantially complete at a site where the Company has been designated by the New York Department of Environmental Conservation (DEC) as a potentially responsible party (PRP). The Company is engaged in litigation regarding that site with the DEC and the party who bought the site from the Company’s predecessor. At a second site, remediation is complete. At a third site, the Company is negotiating with the DEC for clean-up under a voluntary program. A fourth site, which allegedly contains, among other things, manufactured gas plant waste, is in the investigation stage. Remediation has been completed at a fifth site; however, post-remedial construction care and maintenance is ongoing.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	(ii) Third Party Waste Disposal Sites	
      The Company has been identified by the DEC or the United States Environmental Protection Agency as one of a number of companies considered to be PRPs with respect to two waste disposal sites in New York which were operated by unrelated third parties. The PRPs are alleged to have contributed to the materials that may have been collected at such waste disposal sites by the site operators. The ultimate cost to the Company with respect to the remediation of these sites will depend on such factors as the remediation plan selected, the extent of site contamination, the number of additional PRPs at each site and the portion of responsibility, if any, attributed to the Company. The remediation has been completed at one site, with final payments pending. At a second waste disposal site, settlement was reached in the amount of $9.3 million to be allocated among five PRPs. The allocation process is currently being determined. Further negotiations remain in process for additional settlements related to this site.

	(iii) Other	
      The Company received, in 1998 and again in October 1999, notice that the DEC believes the Company is responsible for contamination discovered at an additional former manufactured gas plant site in New York. The Company, however, has not been named as a PRP. The Company responded to these notices that other companies operated that site before its predecessor did, that liability could be imposed upon it only if hazardous substances were disposed at the site during a period when the site was operated by its predecessor, and that it was unaware of any such disposal. The Company has not incurred any clean-up costs at this site nor has it been able to reasonably estimate the probability or extent of potential liability.

	Other	
      The Company, in its Utility segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase capacity on nonaffiliated pipelines to meet customer gas supply needs. Substantially all of these contracts (representing 88% of contracted demand capacity) expire within the next five years. Costs incurred under these contracts are purchased gas costs, 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 is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B — Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation, and none of these other regulatory matters, are currently expected to have a material adverse effect on the financial condition of the Company.
Note H — Business Segment Information
      The Company has six reportable segments: Utility, Pipeline and Storage, Exploration and Production, International, Energy Marketing and Timber. The breakdown of the Company’s 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, an intrastate pipeline which was acquired on
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
February 6, 2003 (see Note J — Acquisitions). 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 transports gas to major industrial companies, utilities (including Distribution Corporation) and power producers. In June 2002, the Company wrote off its 33 1/3% equity method investment in Independence Pipeline Company, a partnership that had proposed to construct and operate a 400-mile pipeline to transport natural gas from Defiance, Ohio to Leidy, Pennsylvania. As shown in the table below, this impairment amounted to $15.2 million.
      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, in the Gulf Coast region of Texas, Louisiana and Alabama and in the provinces of Alberta, Saskatchewan and British Columbia in Canada. Seneca’s production is, for the most part, sold to purchasers located in the vicinity of its wells. On September 30, 2003, Seneca sold its southeast Saskatchewan oil and gas properties for a loss of $58.5 million, as shown in the table below for the year ended September 30, 2003. Proved reserves associated with the properties sold were 19.4 million barrels of oil and 0.3 Bcf of natural gas. When the transaction closed, the initial proceeds received were subject to an adjustment based on working capital and the resolution of certain income tax matters. In 2004, those items were resolved with the buyer and, as a result, the Company received an additional $4.6 million of sales proceeds.
      The International segment’s operations are carried out by Horizon. Horizon engages in foreign energy projects through the investment of its indirect subsidiaries as the sole or partial owner of various business entities. Horizon’s current emphasis is the Czech Republic, where, through its subsidiaries, it owns majority interests in companies having district heating and power generation plants in the northern Bohemia region.
      The Energy Marketing segment is comprised of NFR’s operations. NFR markets natural gas to industrial, commercial, public authority and residential end-users in western and central New York and northwestern Pennsylvania, offering competitively priced energy and energy management services 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 several sawmills and kilns in Pennsylvania. On August 1, 2003, the Company sold approximately 70,000 acres of timber property in Pennsylvania and New York. A gain of $168.8 million was recognized on the sale of this timber property, as shown in the table below for the year ended September 30, 2003. During 2004, the Company received final timber cruise information of the properties it sold and, based on that information, determined that property records pertaining to $1.3 million of timber property were not properly shown as having been transferred to the purchaser. As a result, the Company removed those assets from its property records and adjusted the previously recognized gain downward by recognizing a pretax loss of $1.3 million.
      The data presented in the tables below reflect the reportable 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. Expenditures for long-lived assets include additions to property, plant and equipment and equity investments in corporations (stock acquisitions) or partnerships, net of any cash acquired. 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, 2004	
			
				Pipeline		Exploration				Total				Corporate and			
				and		and				Energy				Reportable				Intersegment		Total	
		Utility		Storage		Production		International		Marketing		Timber		Segments		All Other		Eliminations		Consolidated	

		(Thousands)	
Revenue from External Customers	 	$	1,137,288	 	 	$	122,970	 	 	$	293,698	 	 	$	123,425	 	 	$	284,349	 	 	$	55,968	 	 	$	2,017,698	 	 	$	13,695	 	 	$	—	 	 	$	2,031,393	 	
Intersegment Revenues	 	$	15,353	 	 	$	86,737	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	2	 	 	$	102,092	 	 	$	—	 	 	$	(102,092	)	 	$	—	 	
Interest Expense	 	$	21,945	 	 	$	10,933	 	 	$	50,642	 	 	$	7,080	 	 	$	33	 	 	$	2,218	 	 	$	92,851	 	 	$	919	 	 	$	(3,180	)	 	$	90,590	 	
Depreciation, Depletion and Amortization	 	$	39,101	 	 	$	37,345	 	 	$	89,943	 	 	$	15,257	 	 	$	102	 	 	$	6,277	 	 	$	188,025	 	 	$	1,071	 	 	$	442	 	 	$	189,538	 	
Income Tax Expense	 	$	31,393	 	 	$	30,968	 	 	$	28,899	 	 	$	(6,137)	 	 	$	3,964	 	 	$	3,320	 	 	$	92,407	 	 	$	829	 	 	$	(499	)	 	$	92,737	 	
Significant Item:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Loss on Sale of Timber Properties	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	1,252	 	 	$	1,252	 	 	$	—	 	 	$	—	 	 	$	1,252	 	
Significant Item:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gain on Sale of Oil and Gas Producing Properties	 	$	—	 	 	$	—	 	 	$	4,645	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	4,645	 	 	$	—	 	 	$	—	 	 	$	4,645	 	
Segment Profit (Loss):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	$	46,718	 	 	$	47,726	 	 	$	54,344	 	 	$	5,982	 	 	$	5,535	 	 	$	5,637	 	 	$	165,942	 	 	$	1,530	 	 	$	(886	)	 	$	166,586	 	
Expenditures for Additions to Long-Lived Assets	 	$	55,449	 	 	$	23,196	 	 	$	77,654	 	 	$	7,498	 	 	$	10	 	 	$	2,823	 	 	$	166,630	 	 	$	200	 	 	$	5,511	 	 	$	172,341	 	
 	 	At September 30, 2004	
 	 		
 	 	(Thousands)	
Segment Assets	 	$	1,390,361	 	 	$	777,800	 	 	$	1,039,524	 	 	$	268,119	 	 	$	65,971	 	 	$	143,101	 	 	$	3,684,876	 	 	$	73,583	 	 	$	(46,661	)	 	$	3,711,798	 	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			
		Year Ended September 30, 2003	
			
				Pipeline		Exploration				Total				Corporate and			
				and		and				Energy				Reportable				Intersegment		Total	
		Utility		Storage		Production		International		Marketing		Timber		Segments		All Other		Eliminations		Consolidated	

		(Thousands)	
Revenue from External Customers	 	$	1,145,336	 	 	$	106,499	 	 	$	305,314	 	 	$	114,070	 	 	$	304,660	 	 	$	56,226	 	 	$	2,032,105	 	 	$	3,366	 	 	$	—	 	 	$	2,035,471	 	
Intersegment Revenues	 	$	17,647	 	 	$	94,921	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	112,568	 	 	$	—	 	 	$	(112,568	)	 	$	—	 	
Interest Expense	 	$	29,122	 	 	$	14,000	 	 	$	53,326	 	 	$	8,700	 	 	$	33	 	 	$	2,507	 	 	$	107,688	 	 	$	521	 	 	$	(3,153	)	 	$	105,056	 	
Depreciation, Depletion and Amortization	 	$	38,186	 	 	$	35,940	 	 	$	99,292	 	 	$	13,910	 	 	$	117	 	 	$	7,543	 	 	$	194,988	 	 	$	238	 	 	$	—	 	 	$	195,226	 	
Income Tax Expense	 	$	36,857	 	 	$	30,863	 	 	$	(17,537	)	 	$	876	 	 	$	3,350	 	 	$	72,692	 	 	$	127,101	 	 	$	279	 	 	$	781	 	 	$	128,161	 	
Significant Item:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gain on Sale of Timber Properties	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	168,787	 	 	$	168,787	 	 	$	—	 	 	$	—	 	 	$	168,787	 	
Significant Item:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Loss on Sale of Oil and Gas Producing Properties	 	$	—	 	 	$	—	 	 	$	58,472	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	58,472	 	 	$	—	 	 	$	—	 	 	$	58,472	 	
Significant Non-Cash Item:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Impairment of Oil and Gas Producing Properties	 	$	—	 	 	$	—	 	 	$	42,774	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	42,774	 	 	$	—	 	 	$	—	 	 	$	42,774	 	
Segment Profit (Loss):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Cumulative Effect of Changes in Accounting	 	$	56,808	 	 	$	45,230	 	 	$	(31,293	)	 	$	(1,368	)	 	$	5,868	 	 	$	112,450	 	 	$	187,695	 	 	$	193	 	 	$	(52	)	 	$	187,836	 	
Expenditures for Additions to Long-Lived Assets	 	$	49,944	 	 	$	199,327	 	 	$	75,837	 	 	$	2,499	 	 	$	164	 	 	$	3,493	 	 	$	331,264	 	 	$	48,293	(1)	 	$	1,883	 	 	$	381,440	 	
		 	
		At September 30, 2003	
			
		(Thousands)	
Segment Assets	 	$	1,411,808	 	 	$	812,846	 	 	$	969,512	 	 	$	247,721	 	 	$	54,134	 	 	$	125,915	 	 	$	3,621,936	 	 	$	77,195	 	 	$	19,929	 	 	$	3,719,060	 	

		
(1) 	Amount includes the acquisition of all of the partnership interests in Toro Partners, L.P. and is disclosed in Note J — Acquisitions.	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			
		Year Ended September 30, 2002	
			
				Pipeline		Exploration				Total				Corporate and			
				and		and				Energy				Reportable				Intersegment		Total	
		Utility		Storage		Production		International		Marketing		Timber		Segments		All Other		Eliminations		Consolidated	

		(Thousands)	
Revenue from External Customers	 	$	776,577	 	 	$	80,165	 	 	$	310,980	 	 	$	95,315	 	 	$	151,257	 	 	$	47,407	 	 	$	1,461,701	 	 	$	2,795	 	 	$	—	 	 	$	1,464,496	 	
Intersegment Revenues	 	$	17,644	 	 	$	87,219	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	104,863	 	 	$	7,340	 	 	$	(112,203	)	 	$	—	 	
Interest Expense	 	$	30,790	 	 	$	10,424	 	 	$	55,367	 	 	$	8,045	 	 	$	76	 	 	$	2,896	 	 	$	107,598	 	 	$	420	 	 	$	(2,366	)	 	$	105,652	 	
Depreciation, Depletion and Amortization	 	$	37,412	 	 	$	23,626	 	 	$	103,946	 	 	$	11,977	 	 	$	161	 	 	$	3,429	 	 	$	180,551	 	 	$	115	 	 	$	2	 	 	$	180,668	 	
Income Tax Expense	 	$	31,657	 	 	$	18,148	 	 	$	15,108	 	 	$	(2,030	)	 	$	5,103	 	 	$	4,476	 	 	$	72,462	 	 	$	(473	)	 	$	45	 	 	$	72,034	 	
Significant Non-Cash Item:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Impairment of Investment in Partnership	 	$	—	 	 	$	15,167	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	15,167	 	 	$	—	 	 	$	—	 	 	$	15,167	 	
Segment Profit (Loss): Net Income	 	$	49,505	 	 	$	29,715	 	 	$	26,851	 	 	$	(4,443	)	 	$	8,642	 	 	$	9,689	 	 	$	119,959	 	 	$	(885	)	 	$	(1,392	)	 	$	117,682	 	
Expenditures for Additions to Long-Lived Assets	 	$	51,550	 	 	$	30,329	 	 	$	114,602	 	 	$	4,244	 	 	$	51	 	 	$	25,574	 	 	$	226,350	 	 	$	6,554	 	 	$	—	 	 	$	232,904	 	
		 		
		At September 30, 2002		

				
		(Thousands)		
Segment Assets	 	 	$	1,248,426	 	 	$	532,543	 	 	$	1,161,310	 	 	$	241,466	 	 	$	52,850	 	 	$	131,721	 	 	$	3,368,316	 	 	$	33,563	 	 	$	(570	)	 	$	3,401,309	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			
		For the Year Ended September 30	
			
Geographic Information		2004		2003		2002	

		(Thousands)	
Revenues from External Customers(1):	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$	1,867,335	 	 	$	1,818,980	 	 	$	1,293,239	 	
Czech Republic	 	 	123,425	 	 	 	114,070	 	 	 	95,315	 	
Canada	 	 	40,633	 	 	 	102,421	 	 	 	75,942	 	
 	 	 		 	 	 		 	 	 		 	
 	 	$	2,031,393	 	 	$	2,035,471	 	 	$	1,464,496	 	

			
		At September 30	

			
		(Thousands)	
Long-Lived Assets:	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$	2,967,277	 	 	$	2,975,329	 	 	$	2,621,001	 	
Czech Republic	 	 	228,179	 	 	 	219,695	 	 	 	216,044	 	
Canada	 	 	143,042	 	 	 	116,655	 	 	 	258,196	 	
 	 	 		 	 	 		 	 	 		 	
 	 	$	3,338,498	 	 	$	3,311,679	 	 	$	3,095,241	 	

		
(1) 	Revenue is based upon the country in which the sale originates.	
Note I — Investments in Unconsolidated Subsidiaries
      The Company’s unconsolidated subsidiaries consist of equity method investments in Seneca Energy II, LLC (Seneca Energy), Model City Energy, LLC (Model City) and Energy Systems North East, LLC (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, 2004 and 2003 is as follows: 

			
		At September 30	
			
		2004		2003	

		(Thousands)	
ESNE	 	$	10,045	 	 	$	11,113	 	
Seneca Energy	 	 	5,169	 	 	 	4,445	 	
Model City	 	 	1,230	 	 	 	867	 	
 	 	 		 	 	 		 	
 	 	$	16,444	 	 	$	16,425	 	
 	 	 		 	 	 		 	
Note J — Acquisitions
      On February 6, 2003, the Company acquired Empire from a subsidiary of Duke Energy Corporation for $189.2 million in cash (including cash acquired) plus $57.8 million of project debt. Empire’s results of operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on February 6, 2003. Empire is a 157-mile, 24-inch pipeline that begins at the United States/ Canadian border at the Niagara River near Buffalo, New York, which is within the Company’s service territory, and terminates in Central New York just north of Syracuse, New York. Empire has almost all of its capacity under contract, with a substantial portion being long-term contracts. Empire
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
delivers natural gas supplies to major industrial companies, utilities (including the Company’s Utility segment), and power producers. The Company believes that the acquisition of Empire better positions the Company to bring Canadian gas supplies into the East Coast markets of the United States as demand for natural gas along the East Coast increases. Details of the acquisition are as follows (all figures in thousands):

Assets Acquired (see Condensed Balance Sheet below)	 	$	257,397	 	
Liabilities Assumed (see Condensed Balance Sheet below)	 	 	(68,192	)	
Cash Acquired at Acquisition	 	 	(8,053	)	
 	 	 		 	
Cash Paid, Net of Cash Acquired	 	$	181,152	 	

		
	Condensed Balance Sheet:	
 	 	 	 	 	 	
Property, Plant and Equipment	 	$	220,792	 	
Current Assets	 	 	14,984	 	
Goodwill	 	 	5,476	 	
Intangible Assets (see Note K)	 	 	8,580	 	
Other Assets	 	 	7,565	 	
 	 	 		 	
 	Total Assets	 	$	257,397	 	
 	 	 		 	
Equity	 	$	189,205	 	
Long-Term Debt, Net of Current Portion	 	 	48,433	 	
 	 	 		 	
 	Total Capitalization	 	 	237,638	 	
Current Liabilities	 	 	15,265	 	
Other Liabilities	 	 	4,494	 	
 	 	 		 	
 	Total Capitalization and Liabilities	 	$	257,397	 	
 	 	 		 	
      On June 3, 2003, the Company acquired for approximately $47.8 million in cash (including cash acquired) all of the partnership interests in Toro, which owns and operates short-distance landfill gas pipeline companies that purchase, transport and resell landfill gas to customers in six states located primarily in the Midwestern United States. Toro’s results of operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on June 3, 2003. The existing landfill gas purchase and sale agreements at these facilities remained in place. The Company believes there are opportunities for expansion at many of these locations. The acquisition consisted of approximately $15.3 million in property, plant and equipment, $31.9 million in intangible assets (as discussed in Note K), $1.1 million of current assets and $0.5 million of current liabilities. Details of the acquisition are as follows (all figures in thousands): 

Assets Acquired	 	$	48,319	 	
Liabilities Assumed	 	 	(497	)	
Cash Acquired at Acquisition	 	 	(160	)	
 	 	 		 	
Cash Paid, Net of Cash Acquired	 	$	47,662	 	
 	 	 		 	
Note K — Intangible Assets
      As a result of the Empire and Toro acquisitions discussed in Note J — 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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: 

					
		At September 30, 2004		At September 30, 2003	
					
		Gross Carrying		Accumulated		Net Carrying			
		Amount		Amortization		Amount		Net Carrying Amount	
									
Intangible Assets Subject to Amortization	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Long-Term Transportation Contracts	 	$	8,580	 	 	$	(1,782	)	 	$	6,798	 	 	$	7,867	 	
 	Long-Term Gas Purchase Contracts	 	 	31,864	 	 	 	(1,839	)	 	 	30,025	 	 	 	31,522	 	
Intangible Assets Not Subject to Amortization	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Retirement Plan Intangible Asset (see Note F)	 	 	9,171	 	 	 	—	 	 	 	9,171	 	 	 	10,275	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	 	$	49,615	 	 	$	(3,621	)	 	$	45,994	 	 	$	49,664	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Aggregate Amortization Expense	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	For the Year Ended September 30, 2004	 	$	2,567	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	For the Year Ended September 30, 2003	 	$	1,054	 	 	 	 	 	 	 	 	 	 	 	 	 	
      Amortization expense for the transportation contracts is estimated to be $1.1 million annually for 2005, 2006, 2007 and 2008. Amortization is estimated to be $0.5 million for 2009. Amortization expense for the gas purchase contracts is estimated to be $1.6 million annually for 2005, 2006, 2007, 2008 and 2009.
Note L — 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 Statement of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis.

						Net					
						Income			
						Available		Earnings Per	
						for		Common Share	
		Operating		Operating		Common			
Quarter Ended		Revenues		Income		Stock		Basic		Diluted	
											
2004			
		(Thousands, except per common share amounts)	
9/30/2004	 	$	278,197	 	 	$	27,675	 	 	$	7,754	 	 	$	0.09	 	 	$	0.09	 	
6/30/2004	 	$	419,006	 	 	$	72,324	 	 	$	32,563	(1)	 	$	0.40	 	 	$	0.39	 	
3/31/2004	 	$	801,677	 	 	$	148,554	 	 	$	77,055	(2)	 	$	0.94	 	 	$	0.93	 	
12/31/2003	 	$	532,513	 	 	$	95,817	 	 	$	49,214	(3)	 	$	0.60	 	 	$	0.60	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2003											
											
9/30/2003	 	$	297,170	 	 	$	122,674	 	 	$	58,146	(4)	 	$	0.71	 	 	$	0.71	 	
6/30/2003	 	$	449,530	 	 	$	35,411	 	 	$	2,219	(5)	 	$	0.03	 	 	$	0.03	 	
3/31/2003	 	$	809,065	 	 	$	156,703	 	 	$	80,538	 	 	$	1.00	 	 	$	0.99	 	
12/31/2002	 	$	479,706	 	 	$	99,628	 	 	$	38,041	(6)	 	$	0.47	 	 	$	0.47	 	

		
(1) 	Includes expense of $0.8 million related to an adjustment to the gain on sale of timber properties recognized in 2003.	
 		
(2) 	Includes expense of $6.4 million due to the recognition of a pension settlement loss and income of $4.6 million due to an adjustment to the loss on sale of oil and gas properties recognized in 2003.	
 		
(3) 	Includes income of $5.2 million related to tax rate changes in the Czech Republic.	
 		
(4) 	Includes expense of $6.3 million related to the impairment of oil and gas producing properties, loss of $39.6 million related to the sale of oil and gas producing properties, and a gain of $102.2 million from the sale of timber properties.	
 		
(5) 	Includes expense of $22.6 million related to the impairment of oil and gas producing properties.	
 		
(6) 	Includes expense of $8.3 million related to the cumulative effect of change in accounting (SFAS 142) and an expense of $0.6 million due to the cumulative effect of change in accounting (SFAS 143).	
Note M — Market for Common Stock and Related Shareholder Matters (unaudited)
      At September 30, 2004, there were 19,063 holders 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 D — Capitalization and Short-Term Borrowings. The quarterly price ranges
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(based on intra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 2004 and 2003, are shown below:

					
		Price Range			
				Dividends	
Quarter Ended		High		Low		Declared	
							
2004	 	 	 	 	 	 	 	 	 	 	 	 	
	 	 	 	 	 	 	 	 	 	 	 	 	
9/30/2004	 	$	28.43	 	 	$	24.84	 	 	$	.280	 	
6/30/2004	 	$	25.57	 	 	$	23.75	 	 	$	.280	 	
3/31/2004	 	$	26.48	 	 	$	24.26	 	 	$	.270	 	
12/31/2003	 	$	25.01	 	 	$	21.71	 	 	$	.270	 	
2003	 	 	 	 	 	 	 	 	 	 	 	 	
	 	 	 	 	 	 	 	 	 	 	 	 	
9/30/2003	 	$	27.51	 	 	$	22.51	 	 	$	.270	 	
6/30/2003	 	$	26.90	 	 	$	21.60	 	 	$	.270	 	
3/31/2003	 	$	22.25	 	 	$	18.97	 	 	$	.260	 	
12/31/2002	 	$	21.86	 	 	$	17.95	 	 	$	.260	 	
Note N — Supplementary Information for Oil and Gas Producing Activities
      The following supplementary information is presented in accordance with SFAS No. 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	
			
		2004		2003	

		(Thousands)	
Proved Properties(1)	 	$	1,489,284	 	 	$	1,647,075	 	
Unproved Properties	 	 	27,277	 	 	 	30,955	 	
 	 	 		 	 	 		 	
 	 	 	1,516,561	 	 	 	1,678,030	 	
Less — Accumulated Depreciation, Depletion and Amortization	 	 	609,469	 	 	 	763,258	 	
 	 	 		 	 	 		 	
 	 	$	907,092	 	 	$	914,772	 	

		
(1) 	Includes asset retirement costs of $22.2 million and $18.1 million at September 30, 2004 and 2003, respectively.	
      Costs related to unproved properties are excluded from amortization as they represent unevaluated properties that require additional drilling to determine the existence of oil and gas reserves. Following is a summary of such costs excluded from amortization at September 30, 2004: 

					
				Year Costs Incurred	
		Total as of			
		September 30, 2004		2004		2003		2002		Prior	

				(Thousands)	
Acquisition Costs	 	$	27,277	 	 	$	7,650	 	 	$	6,748	 	 	$	2,884	 	 	$	9,995	 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	

		Year Ended September 30	
			
		2004		2003		2002	

		(Thousands)	
United States	 	 	 	 	 	 	 	 	 	 	 	 	
Property Acquisition Costs:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Proved	 	$	(8	)	 	$	(13	)	 	$	9,316	 	
 	Unproved	 	 	3,529	 	 	 	1,920	 	 	 	698	 	
Exploration Costs	 	 	10,503	 	 	 	17,947	 	 	 	25,583	 	
Development Costs	 	 	31,881	 	 	 	23,649	 	 	 	51,792	 	
Asset Retirement Costs	 	 	2,292	 	 	 	242	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	48,197	 	 	 	43,745	 	 	 	87,389	 	
Canada	 	 	 	 	 	 	 	 	 	 	 	 	
Property Acquisition Costs:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Proved	 	 	29	 	 	 	181	 	 	 	(536	)	
 	Unproved	 	 	3,167	 	 	 	6,217	 	 	 	2,804	 	
Exploration Costs	 	 	22,624	 	 	 	6,641	 	 	 	8,779	 	
Development Costs	 	 	5,500	 	 	 	17,745	 	 	 	15,332	 	
Asset Retirement Costs	 	 	1,218	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	
 	 	 	32,538	 	 	 	30,784	 	 	 	26,379	 	
Total	 	 	 	 	 	 	 	 	 	 	 	 	
Property Acquisition Costs:(1)	 	 	 	 	 	 	 	 	 	 	 	 	
 	Proved	 	 	21	 	 	 	168	 	 	 	8,780	 	
 	Unproved	 	 	6,696	 	 	 	8,137	 	 	 	3,502	 	
Exploration Costs	 	 	33,127	 	 	 	24,588	 	 	 	34,362	 	
Development Costs	 	 	37,381	 	 	 	41,394	 	 	 	67,124	 	
Asset Retirement Costs	 	 	3,510	 	 	 	242	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	
 	 	$	80,735	 	 	$	74,529	 	 	$	113,768	 	
 	 	 		 	 	 		 	 	 		 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      For the years ended September 30, 2004, 2003 and 2002, the Company spent $12.1 million, $1.7 million and $18.2 million, respectively, developing proved undeveloped reserves.

	Results of Operations for Producing Activities	

		Year Ended September 30,	
			
		2004		2003		2002	

		(Thousands, except per Mcfe amounts)	
United States	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Natural Gas (includes revenues from sales to affiliates of $72, $69 and $43, respectively)	 	$	151,570	 	 	$	148,104	 	 	$	104,954	 	
 	Oil, Condensate and Other Liquids	 	 	139,301	 	 	 	118,277	 	 	 	101,549	 	
 	 	 		 	 	 		 	 	 		 	
Total Operating Revenues(1)	 	 	290,871	 	 	 	266,381	 	 	 	206,503	 	
Production/ Lifting Costs	 	 	39,677	 	 	 	39,162	 	 	 	42,956	 	
Accretion Expense	 	 	1,756	 	 	 	1,800	 	 	 	—	 	
Depreciation, Depletion and Amortization ($1.41, $1.29 and $1.25 per Mcfe of production)	 	 	73,396	 	 	 	70,127	 	 	 	80,142	 	
Income Tax Expense	 	 	65,337	 	 	 	62,672	 	 	 	30,253	 	
 	 	 		 	 	 		 	 	 		 	
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	 	 	110,705	 	 	 	92,620	 	 	 	53,152	 	
 	 	 		 	 	 		 	 	 		 	
Canada	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Natural Gas	 	 	30,359	 	 	 	26,992	 	 	 	14,621	 	
 	Oil, Condensate and Other Liquids	 	 	10,018	 	 	 	62,908	 	 	 	56,511	 	
 	 	 		 	 	 		 	 	 		 	
Total Operating Revenues(1)	 	 	40,377	 	 	 	89,900	 	 	 	71,132	 	
Production/ Lifting Costs	 	 	8,176	 	 	 	33,038	 	 	 	30,109	 	
Accretion Expense	 	 	177	 	 	 	802	 	 	 	—	 	
Depreciation, Depletion and Amortization ($1.83, $1.30 and $0.93 per Mcfe of production)	 	 	14,922	 	 	 	26,165	 	 	 	21,707	 	
Impairment of Oil and Gas Producing Properties(2)	 	 	—	 	 	 	42,774	 	 	 	—	 	
Income Tax Expense (Benefit)	 	 	5,235	 	 	 	(3,273	)	 	 	4,672	 	
 	 	 		 	 	 		 	 	 		 	
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	 	 	11,867	 	 	 	(9,606	)	 	 	14,644	 	
 	 	 		 	 	 		 	 	 		 	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			
		Year Ended September 30,	
			
		2004		2003		2002	

		(Thousands, except per Mcfe amounts)	
Total	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Natural Gas (includes revenues from sales to affiliates of $72, $69 and $43, respectively)	 	 	181,929	 	 	 	175,096	 	 	 	119,575	 	
 	Oil, Condensate and Other Liquids	 	 	149,319	 	 	 	181,185	 	 	 	158,060	 	
 	 	 		 	 	 		 	 	 		 	
Total Operating Revenues(1)	 	 	331,248	 	 	 	356,281	 	 	 	277,635	 	
Production/ Lifting Costs	 	 	47,853	 	 	 	72,200	 	 	 	73,065	 	
Accretion Expense	 	 	1,933	 	 	 	2,602	 	 	 	—	 	
Depreciation, Depletion and Amortization ($1.47, $1.30 and $1.16 per Mcfe of production)	 	 	88,318	 	 	 	96,292	 	 	 	101,849	 	
Impairment of Oil and Gas Producing Properties(2)	 	 	—	 	 	 	42,774	 	 	 	—	 	
Income Tax Expense	 	 	70,572	 	 	 	59,399	 	 	 	34,925	 	
 	 	 		 	 	 		 	 	 		 	
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	 	$	122,572	 	 	$	83,014	 	 	$	67,796	 	

		
(1) 	Exclusive of hedging gains and losses. See further discussion in Note E — Financial Instruments	
 		
(2) 	See discussion of impairment in Note A — Summary of Significant Accounting Policies	

	Reserve Quantity Information (unaudited)	
      The Company’s proved oil and gas reserves are located in the United States and Canada. 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 Coast		West Coast		Appalachian		Total				Total	
		Region		Region		Region		U.S.		Canada		Company	
													
Proved Developed and Undeveloped Reserves:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
September 30, 2001	 	 	89,858	 	 	 	98,498	 	 	 	78,457	 	 	 	266,813	 	 	 	55,567	 	 	 	322,380	 	
Extensions and Discoveries	 	 	6,530	 	 	 	5,770	 	 	 	4,242	 	 	 	16,542	 	 	 	20,263	 	 	 	36,805	 	
Revisions of Previous Estimates	 	 	1,613	 	 	 	(26,063	)	 	 	342	 	 	 	(24,108	)	 	 	(20,676	)	 	 	(44,784	)	
Production	 	 	(25,776	)	 	 	(4,889	)	 	 	(4,402	)	 	 	(35,067	)	 	 	(6,387	)	 	 	(41,454	)	
Sales of Minerals in Place	 	 	(14,361	)	 	 	—	 	 	 	(365	)	 	 	(14,726	)	 	 	—	 	 	 	(14,726	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
September 30, 2002	 	 	57,864	 	 	 	73,316	 	 	 	78,274	 	 	 	209,454	 	 	 	48,767	 	 	 	258,221	 	
Extensions and Discoveries	 	 	10,538	 	 	 	—	 	 	 	5,844	 	 	 	16,382	 	 	 	11,641	 	 	 	28,023	 	
Revisions of Previous Estimates	 	 	(2,278	)	 	 	1,213	 	 	 	2,224	 	 	 	1,159	 	 	 	(2,211	)	 	 	(1,052	)	
Production	 	 	(18,441	)	 	 	(4,467	)	 	 	(5,123	)	 	 	(28,031	)	 	 	(5,774	)	 	 	(33,805	)	
Sales of Minerals in Place	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(270	)	 	 	(270	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			
		Gas MMcf	

		U.S.			
					
		Gulf Coast		West Coast		Appalachian		Total				Total	
		Region		Region		Region		U.S.		Canada		Company	
													
September 30, 2003	 	 	47,683	 	 	 	70,062	 	 	 	81,219	 	 	 	198,964	 	 	 	52,153	 	 	 	251,117	 	
Extensions and Discoveries	 	 	2,632	 	 	 	—	 	 	 	3,784	 	 	 	6,416	 	 	 	15,925	 	 	 	22,341	 	
Revisions of Previous Estimates	 	 	(4,984	)	 	 	1,831	 	 	 	(1,111	)	 	 	(4,264	)	 	 	(11,004	)	 	 	(15,268	)	
Production	 	 	(17,596	)	 	 	(4,057	)	 	 	(5,132	)	 	 	(26,785	)	 	 	(6,228	)	 	 	(33,013	)	
Sales of Minerals in Place	 	 	(1	)	 	 	(392	)	 	 	—	 	 	 	(393	)	 	 	—	 	 	 	(393	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
September 30, 2004	 	 	27,734	 	 	 	67,444	 	 	 	78,760	 	 	 	173,938	 	 	 	50,846	 	 	 	224,784	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Proved Developed Reserves:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
September 30, 2001	 	 	87,893	 	 	 	47,442	 	 	 	78,457	 	 	 	213,792	 	 	 	53,463	 	 	 	267,255	 	
September 30, 2002	 	 	57,274	 	 	 	57,286	 	 	 	78,273	 	 	 	192,833	 	 	 	39,253	 	 	 	232,086	 	
September 30, 2003	 	 	45,402	 	 	 	54,180	 	 	 	81,218	 	 	 	180,800	 	 	 	42,745	 	 	 	223,545	 	
September 30, 2004	 	 	25,827	 	 	 	53,035	 	 	 	78,760	 	 	 	157,622	 	 	 	46,223	 	 	 	203,845	 	

		Oil Mbbl	

		U.S.			
					
		Gulf Coast		West Coast		Appalachian		Total				Total	
		Region		Region		Region		U.S.		Canada		Company	
													
Proved Developed and Undeveloped Reserves:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
September 30, 2001	 	 	6,294	 	 	 	68,424	 	 	 	77	 	 	 	74,795	 	 	 	40,533	 	 	 	115,328	 	
Extensions and Discoveries	 	 	57	 	 	 	1,360	 	 	 	20	 	 	 	1,437	 	 	 	586	 	 	 	2,023	 	
Revisions of Previous Estimates	 	 	781	 	 	 	129	 	 	 	6	 	 	 	916	 	 	 	(10,278	)	 	 	(9,362	)	
Production	 	 	(1,815	)	 	 	(3,004	)	 	 	(9	)	 	 	(4,828	)	 	 	(2,834	)	 	 	(7,662	)	
Sales of Minerals in Place	 	 	(200	)	 	 	—	 	 	 	—	 	 	 	(200	)	 	 	(410	)	 	 	(610	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
September 30, 2002	 	 	5,117	 	 	 	66,909	 	 	 	94	 	 	 	72,120	 	 	 	27,597	 	 	 	99,717	 	
Extensions and Discoveries	 	 	104	 	 	 	—	 	 	 	46	 	 	 	150	 	 	 	729	 	 	 	879	 	
Revisions of Previous Estimates	 	 	(365	)	 	 	(185	)	 	 	8	 	 	 	(542	)	 	 	(4,119	)	 	 	(4,661	)	
Production	 	 	(1,473	)	 	 	(2,872	)	 	 	(10	)	 	 	(4,355	)	 	 	(2,382	)	 	 	(6,737	)	
Sales of Minerals in Place	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(19,434	)	 	 	(19,434	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
September 30, 2003	 	 	3,383	 	 	 	63,852	 	 	 	138	 	 	 	67,373	 	 	 	2,391	 	 	 	69,764	 	
Extensions and Discoveries	 	 	19	 	 	 	—	 	 	 	18	 	 	 	37	 	 	 	181	 	 	 	218	 	
Revisions of Previous Estimates	 	 	213	 	 	 	(17	)	 	 	11	 	 	 	207	 	 	 	(144	)	 	 	63	 	
Production	 	 	(1,534	)	 	 	(2,650	)	 	 	(20	)	 	 	(4,204	)	 	 	(324	)	 	 	(4,528	)	
Sales of Minerals in Place	 	 	(1	)	 	 	(303	)	 	 	—	 	 	 	(304	)	 	 	—	 	 	 	(304	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
September 30, 2004	 	 	2,080	 	 	 	60,882	 	 	 	147	 	 	 	63,109	 	 	 	2,104	 	 	 	65,213	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Proved Developed Reserves:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
September 30, 2001	 	 	6,259	 	 	 	44,304	 	 	 	77	 	 	 	50,640	 	 	 	33,676	 	 	 	84,316	 	
September 30, 2002	 	 	5,111	 	 	 	41,735	 	 	 	94	 	 	 	46,940	 	 	 	24,100	 	 	 	71,040	 	
September 30, 2003	 	 	2,533	 	 	 	40,079	 	 	 	139	 	 	 	42,751	 	 	 	2,391	 	 	 	45,142	 	
September 30, 2004	 	 	2,061	 	 	 	38,631	 	 	 	148	 	 	 	40,840	 	 	 	2,104	 	 	 	42,944	 	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited)	
      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. 

			
		Year Ended September 30,	
			
		2004		2003		2002	

		(Thousands)	
United States	 	 	 	 	 	 	 	 	 	 	 	 	
Future Cash Inflows	 	$	3,728,168	 	 	$	2,684,286	 	 	$	2,764,556	 	
 	Less:	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Future Production Costs	 	 	676,361	 	 	 	579,321	 	 	 	546,182	 	
 	 	Future Development Costs	 	 	124,298	 	 	 	116,639	 	 	 	117,999	 	
 	 	Future Income Tax Expense at Applicable Statutory Rate	 	 	995,327	 	 	 	613,893	 	 	 	653,347	 	
 	 	 		 	 	 		 	 	 		 	
 	Future Net Cash Flows	 	 	1,932,182	 	 	 	1,374,433	 	 	 	1,447,028	 	
 	Less:	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	10% Annual Discount for Estimated Timing of Cash Flows	 	 	996,813	 	 	 	641,185	 	 	 	665,941	 	
 	 	 		 	 	 		 	 	 		 	
 	Standardized Measure of Discounted Future Net Cash Flows	 	 	935,369	 	 	 	733,248	 	 	 	781,087	 	
 	 	 		 	 	 		 	 	 		 	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			
		Year Ended September 30,	
			
		2004		2003		2002	

		(Thousands)	
Canada	 	 	 	 	 	 	 	 	 	 	 	 	
Future Cash Inflows	 	 	343,026	 	 	 	279,772	 	 	 	888,515	 	
 	Less:	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Future Production Costs	 	 	111,519	 	 	 	85,817	 	 	 	413,006	 	
 	 	Future Development Costs	 	 	13,222	 	 	 	9,787	 	 	 	25,398	 	
 	 	Future Income Tax Expense at Applicable Statutory Rate	 	 	60,610	 	 	 	58,436	 	 	 	101,919	 	
 	 	 		 	 	 		 	 	 		 	
 	Future Net Cash Flows	 	 	157,675	 	 	 	125,732	 	 	 	348,192	 	
 	Less:	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	10% Annual Discount for Estimated Timing of Cash Flows	 	 	46,945	 	 	 	40,575	 	 	 	103,097	 	
 	 	 		 	 	 		 	 	 		 	
 	Standardized Measure of Discounted Future Net Cash Flows	 	 	110,730	 	 	 	85,157	 	 	 	245,095	 	
 	 	 		 	 	 		 	 	 		 	
Total	 	 	 	 	 	 	 	 	 	 	 	 	
Future Cash Inflows	 	 	4,071,194	 	 	 	2,964,058	 	 	 	3,653,071	 	
 	Less:	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Future Production Costs	 	 	787,880	 	 	 	665,138	 	 	 	959,188	 	
 	 	Future Development Costs	 	 	137,520	 	 	 	126,426	 	 	 	143,397	 	
 	 	Future Income Tax Expense at Applicable Statutory Rate	 	 	1,055,937	 	 	 	672,329	 	 	 	755,266	 	
 	 	 		 	 	 		 	 	 		 	
 	Future Net Cash Flows	 	 	2,089,857	 	 	 	1,500,165	 	 	 	1,795,220	 	
 	Less:	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	10% Annual Discount for Estimated Timing of Cash Flows	 	 	1,043,758	 	 	 	681,760	 	 	 	769,038	 	
 	 	 		 	 	 		 	 	 		 	
 	Standardized Measure of Discounted Future Net Cash Flows	 	$	1,046,099	 	 	$	818,405	 	 	$	1,026,182	 	
 	 	 		 	 	 		 	 	 		 	
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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,	
			
		2004		2003		2002	

		(Thousands)	
United States	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year	 	$	733,248	 	 	$	781,087	 	 	$	605,350	 	
 	Sales, Net of Production Costs	 	 	(251,194	)	 	 	(227,219	)	 	 	(163,548	)	
 	Net Changes in Prices, Net of Production Costs	 	 	592,326	 	 	 	11,130	 	 	 	441,085	 	
 	Purchases of Minerals in Place	 	 	—	 	 	 	—	 	 	 	—	 	
 	Sales of Minerals in Place	 	 	(5,554	)	 	 	—	 	 	 	(27,197	)	
 	Extensions and Discoveries	 	 	16,638	 	 	 	29,266	 	 	 	42,970	 	
 	Changes in Estimated Future Development Costs	 	 	(40,042	)	 	 	(35,062	)	 	 	(42,069	)	
 	Previously Estimated Development Costs Incurred	 	 	32,653	 	 	 	36,423	 	 	 	45,310	 	
 	Net Change in Income Taxes at Applicable Statutory Rate	 	 	(166,055	)	 	 	24,796	 	 	 	(126,263	)	
 	Revisions of Previous Quantity Estimates	 	 	(5,107	)	 	 	(3,572	)	 	 	(32,646	)	
 	Accretion of Discount and Other	 	 	28,456	 	 	 	116,399	 	 	 	38,095	 	
 	 	 		 	 	 		 	 	 		 	
Standardized Measure of Discounted Future Net Cash Flows at End of Year	 	 	935,369	 	 	 	733,248	 	 	 	781,087	 	
 	 	 		 	 	 		 	 	 		 	
Canada	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year	 	 	85,157	 	 	 	245,095	 	 	 	181,439	 	
 	Sales, Net of Production Costs	 	 	(32,201	)	 	 	(56,862	)	 	 	(41,023	)	
 	Net Changes in Prices, Net of Production Costs	 	 	29,230	 	 	 	8,167	 	 	 	111,148	 	
 	Purchases of Minerals in Place	 	 	—	 	 	 	—	 	 	 	—	 	
 	Sales of Minerals in Place	 	 	—	 	 	 	(120,960	)	 	 	(3,084	)	
 	Extensions and Discoveries	 	 	36,986	 	 	 	28,241	 	 	 	29,813	 	
 	Changes in Estimated Future Development Costs	 	 	(8,491	)	 	 	(14,045	)	 	 	18,151	 	
 	Previously Estimated Development Costs Incurred	 	 	5,055	 	 	 	29,657	 	 	 	12,361	 	
 	Net Change in Income Taxes at Applicable Statutory Rate	 	 	(2,640	)	 	 	(6,280	)	 	 	(6,910	)	
 	Revisions of Previous Quantity Estimates	 	 	(19,369	)	 	 	(41,205	)	 	 	(88,571	)	
 	Accretion of Discount and Other	 	 	17,003	 	 	 	13,349	 	 	 	31,771	 	
 	 	 		 	 	 		 	 	 		 	
Standardized Measure of Discounted Future Net Cash Flows at End of Year	 	 	110,730	 	 	 	85,157	 	 	 	245,095	 	
 	 	 		 	 	 		 	 	 		 	
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			
		Year Ended September 30,	
			
		2004		2003		2002	

		(Thousands)	
Total	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year	 	 	818,405	 	 	 	1,026,182	 	 	 	786,789	 	
 	Sales, Net of Production Costs	 	 	(283,395	)	 	 	(284,081	)	 	 	(204,571	)	
 	Net Changes in Prices, Net of Production Costs	 	 	621,556	 	 	 	19,297	 	 	 	552,233	 	
 	Purchases of Minerals in Place	 	 	—	 	 	 	—	 	 	 	—	 	
 	Sales of Minerals in Place	 	 	(5,554	)	 	 	(120,960	)	 	 	(30,281	)	
 	Extensions and Discoveries	 	 	53,624	 	 	 	57,507	 	 	 	72,783	 	
 	Changes in Estimated Future Development Costs	 	 	(48,533	)	 	 	(49,107	)	 	 	(23,918	)	
 	Previously Estimated Development Costs Incurred	 	 	37,708	 	 	 	66,080	 	 	 	57,671	 	
 	Net Change in Income Taxes at Applicable Statutory Rate	 	 	(168,695	)	 	 	18,516	 	 	 	(133,173	)	
 	Revisions of Previous Quantity Estimates	 	 	(24,476	)	 	 	(44,777	)	 	 	(121,217	)	
 	Accretion of Discount and Other	 	 	45,459	 	 	 	129,748	 	 	 	69,866	 	
 	 	 		 	 	 		 	 	 		 	
Standardized Measure of Discounted Future Net Cash Flows at End of Year	 	$	1,046,099	 	 	$	818,405	 	 	$	1,026,182	 	
 	 	 		 	 	 		 	 	 		 	
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Schedule II — Valuation and Qualifying Accounts

				Additions		Additions					
		Balance at		Charged to		Charged to				Balance at	
		Beginning		Costs and		Other				End of	
Description		of Period		Expenses		Accounts(1)		Deductions(2)		Period	

		(Thousands)	
Year Ended September 30, 2004	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reserve for Doubtful Accounts	 	$	17,943	 	 	$	20,328	 	 	$	—	 	 	$	20,831	 	 	$	17,440	 	
Deferred Tax Valuation Allowance	 	$	6,357	 	 	$	(3,480	)	 	$	—	 	 	$	—	 	 	$	2,877	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Year Ended September 30, 2003	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reserve for Doubtful Accounts	 	$	17,299	 	 	$	17,275	 	 	$	—	 	 	$	16,631	 	 	$	17,943	 	
Deferred Tax Valuation Allowance	 	$	—	 	 	$	6,357	 	 	$	—	 	 	$	—	 	 	$	6,357	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Year Ended September 30, 2002	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reserve for Doubtful Accounts	 	$	18,521	 	 	$	16,082	 	 	$	2,834	 	 	$	20,138	 	 	$	17,299	 	

		
(1) 	Represents amounts reclassified from regulatory asset and regulatory liability accounts under various rate settlements.	
 		
(2) 	Amounts represent net accounts receivable written-off.	

		
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	
      None

Item 9A	Controls and Procedures	
      The following information includes the evaluation of disclosure controls and procedures by the Company’s Chief Executive Officer and Treasurer, along with any significant changes in internal controls of the Company.
Evaluation of Disclosure Controls and Procedures
      The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (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 under the Exchange Act is recorded, processed, summarized and reported within required time periods. The Company’s management, including the Chief Executive Officer and Treasurer, 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 Treasurer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Controls Over Financial Reporting
      The Company maintains a system of internal control over financial reporting that is designed to provide reasonable assurance that the Company’s transactions are properly authorized, the Company’s assets are safeguarded against unauthorized or improper use, and the Company’s transactions are properly recorded and reported to permit preparation of the Company’s financial statements in conformity with GAAP. There were no changes in the Company’s internal control over financial reporting that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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Item 9B	Other Information	
      None
PART III

Item 10	Directors and Executive Officers of the Registrant	
      The information required by this item concerning the directors of the Company is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information concerning directors is set forth in the definitive Proxy Statement under the captions entitled “Nominees for Election as Directors for Three-Year Terms to Expire in 2008,” “Directors Whose Terms Expire in 2007,” “Directors Whose Terms Expire in 2006,” and “Compliance with Section 16(a) of the Securities Exchange Act of 1934” 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.

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 February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information concerning executive compensation is set forth in the definitive Proxy Statement under the captions “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and, excepting the “Report of the Compensation Committee” and the “Corporate Performance Graph,” 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 February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The equity compensation plan information is set forth in the definitive Proxy Statement under the caption “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 February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information concerning security ownership of certain beneficial owners is set forth in the definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
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     (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 February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information concerning security ownership of management is set forth in the definitive Proxy Statement under the caption “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	
      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 February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information regarding certain relationships and related transactions is set forth in the definitive Proxy Statement under the caption “Compensation Committee Interlocks and Insider Participation” 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 February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information concerning principal accountant fees and services is set forth in the definitive Proxy Statement under the caption “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			
Number		Description of 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)	
 	    3(ii)	 	 	By-Laws:	
 	•	 	 	National Fuel Gas Company By-Laws as amended on December 9, 2004 (Exhibit 3(ii), Form 8-K dated December 9, 2004 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			
Number		Description of 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)	
 	•	 	 	Amended and Restated Rights Agreement, dated as of April 30, 1999, between the Company and HSBC Bank USA (Exhibit 10.2, Form 10-Q for the quarterly period ended March 31, 1999 in File No. 1-3880)	
 	•	 	 	Certificate of Adjustment, dated September 7, 2001, to the Amended and Restated Rights Agreement dated as of April 30, 1999, between the Company and HSBC Bank USA (Exhibit 4, Form 8-K dated September 7, 2001 in File No. 1-3880)	
 	•	 	 	Officers Certificate establishing 6.50% Notes due 2022, dated September 18, 2002 (Exhibit 4, Form 8-K dated October 3, 2002 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)	
 	 (10)	 	 	Material Contracts:	
 	  (ii)	 	 	Contracts upon which the Company’s business is substantially dependent:	
 	•	 	 	Credit Agreement, dated as of September 30, 2002, among the Company, the Lenders and JPMorgan Chase Bank (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 2002 in File No. 1-3880)	
 	•	 	 	First Amendment to Credit Agreement, among the Company, the Lenders and JPMorgan Chase Bank, dated September 29, 2003 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 2003 in File No. 1-3880)	
 	•	 	 	Second Amendment to Credit Agreement, among the Company, the Lenders and JPMorgan Chase Bank, dated September 26, 2004 (Exhibit 99, Form 8-K dated September 30, 2004 in File No. 1-3880)	
 	 (iii)	 	 	Compensatory plans for officers:	
 	•	 	 	Retirement Benefit Agreement, dated September 22, 2003, between the Company and David F. Smith (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 2003 in File No. 1-3880)	
 	•	 	 	Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, among the Company, National Fuel Gas Distribution Corporation and each of Philip C. Ackerman, Anna Marie Cellino, Joseph P. Pawlowski, James D. Ramsdell, Dennis J. Seeley, David F. Smith and Ronald J. Tanski (Exhibit 10.1, Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880)	
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Exhibit			
Number		Description of Exhibits	
			
 	•	 	 	Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, among the Company, National Fuel Gas Supply Corporation and each of Bruce H. Hale and John R. Pustulka (Exhibit 10.2, Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880)	
 	•	 	 	Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, among the Company, Seneca Resources Corporation and James A. Beck (Exhibit 10.3, Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880)	
 	•	 	 	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 1997 Award and Option Plan, amended through June 14, 2001 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 2001 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)	
 	•	 	 	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 19, 1996 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1996 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)	
 	•	 	 	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)	
 	•	 	 	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)	
 	•	 	 	Amended Restated Split Dollar Insurance Agreement, effective June 15, 2000, among the Company, Bernard J. Kennedy, and Joseph B. Kennedy, as Trustee of the Trust under the Agreement dated January 9, 1998 (Exhibit 10.1, Form 10-Q for the quarterly period ended June 30, 2000 in File No. 1-3880)	
 	•	 	 	Contingent Benefit Agreement effective June 15, 2000, between the Company and Bernard J. Kennedy (Exhibit 10.2, Form 10-Q for the quarterly period ended June 30, 2000 in File No. 1-3880	
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Exhibit			
Number		Description of Exhibits	
			
 	•	 	 	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)	
 	•	 	 	Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and Joseph P. Pawlowski (Exhibit 10.7, 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 Joseph P. Pawlowski, dated March 23, 1999 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)	
 	•	 	 	Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and Dennis J. Seeley (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1999 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 Dennis J. Seeley, dated March 29, 1999 (Exhibit 10.10, 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 Bruce H. Hale (Exhibit 10.11, 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 Bruce H. Hale, dated March 29, 1999 (Exhibit 10.12, 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)	
 	10	.1	 	National Fuel Gas Company Parameters for Executive Life Insurance Plan	
 	•	 	 	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)	
 	10	.2	 	National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement (I), dated September 1, 2003	
 	•	 	 	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)	
 	•	 	 	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)	
 	•	 	 	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)	
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Exhibit			
Number		Description of Exhibits	
			
 	•	 	 	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)	
 	•	 	 	Retirement Supplement Agreement, dated January 11, 2002, between the Company and Joseph P. Pawlowski (Exhibit 10.6, Form 10-K/A for fiscal year ended September 30, 2001 in File No. 1-3880)	
 	•	 	 	Amendment No. 1 to Retirement Supplement Agreement, dated March 11, 2004, between the Company and Joseph P. Pawlowski (Exhibit 10(iii), Form 10-Q for the quarterly period ended March 31, 2004 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)	
 	•	 	 	Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan (Exhibit A, Definitive Proxy Statement, Schedule 14(A) filed January 10, 2002 in File No. 1-3880)	
 	10	.3	 	Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated, effective September 9, 2004	
 	•	 	 	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)	
 	10	.4	 	Retirement and Consulting Agreement, dated September 5, 2001, between the Company and Bernard J. Kennedy	
 	(12	)	 	Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 1998 through 2003	
 	(21	)	 	Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report on Form 10-K	
 	(23	)	 	Consents of Experts:	
 	23	.1	 	Consent of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation	
 	23	.2	 	Consent of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc.	
 	23	.3	 	Consent of Independent Accountants	
 	(31	)	 	Rule 13a-15(e)/15d-15(e) Certifications	
 	31	.1	 	Written statements of Chief Executive Officer pursuant to Rule 13a-15(e)/15d-15(e) of the Exchange Act.	
 	31	.2	 	Written statements of Principal Financial Officer pursuant to Rule 13a-15(e)/15d-15(e) of the Exchange Act.	
 	(32	)	 	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	
 	(99	)	 	Additional Exhibits:	
 	99	.1	 	Report of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation	
 	99	.2	 	Report of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc.	
 	99	.3	 	Company Maps	
 	•	 	 	The Company agrees to furnish to the SEC upon request the following instruments with respect to long-term debt that the Company has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(ii)(A):	
 	 	 	 	Secured Credit Agreement, dated as of June 5, 1997, among the Empire State Pipeline, as borrower, Empire State Pipeline, Inc., the Lenders party thereto, JPMorgan Chase Bank (f/k/a The Chase Manhattan Bank), as administrative agent, and Chase Securities, as arranger.	
 	 	 	 	First Amendment to Secured Credit Agreement, dated as of May 28, 2002, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, and JPMorgan Chase Bank, as administrative agent.	
 	 	 	 	Second Amendment to Secured Credit Agreement, dated as of February 6, 2003, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, as amended, and JPMorgan Chase Bank, as administrative agent.	
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Exhibit			
Number		Description of Exhibits	
			
 	•	 	 	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.	
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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/ P. C. ACKERMAN	

 	P. C. Ackerman	
 	Chairman of the Board, President	
 	and Chief Executive Officer	
Date: December 9, 2004
      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		Date	

/s/ P. C. ACKERMAN

P. C. Ackerman	 	Chairman of the Board, President, Chief Executive Officer and Director	 	December 9, 2004	
 	
/s/ R. T. BRADY

R. T. Brady	 	Director	 	December 9, 2004	
 	
/s/ R. D. CASH

R. D. Cash	 	Director	 	December 9, 2004	
 	
/s/ R. E. KIDDER

R. E. Kidder	 	Director	 	December 9, 2004	
 	
/s/ B. S. LEE

B. S. Lee	 	Director	 	December 9, 2004	
 	
/s/ G. L. MAZANEC

G. L. Mazanec	 	Director	 	December 9, 2004	
 	
/s/ J. F. RIORDAN

J. F. Riordan	 	Director	 	December 9, 2004	
 	
/s/ R. J. TANSKI

R. J. Tanski	 	Treasurer and Principal Financial Officer	 	December 9, 2004	
 	
/s/ K. M. CAMIOLO

K. M. Camiolo	 	Controller and Principal Accounting Officer	 	December 9, 2004	
108

Exhibit 10.1
National Fuel Gas Company
Parameters for Executive Life Insurance Plan
to Replace the Split Dollar Plan
Once an officer reaches age 50 the Company, at the option of the CEO, may pay an insurance carrier up to $15,000 a year for one or more insurance policies selected by the officer, subject to the following guidelines:

Ø	 	Officer has the option to purchase one or more insurance policies from the following insurance carriers:	

°	 	Northwestern Mutual Life Insurance	
 	
°	 	Guardian Life Insurance Company	
 	
°	 	Massachusetts Mutual Life Insurance	

Ø	 	The above carriers will remain available so long as each carrier has a rating equivalent to or better than a Standard & Poor’s rating of A+.	

Ø	 	Officer may select one or more of the following insurance products:	

°	 	Term Life – Life insurance which provides protection for a specific period of time. It provides a benefit only if the insured passes away during the term.	
 	
°	 	Whole Life – Life insurance which provides permanent protection for the insured person’s lifetime. The stated premium remains constant over the life of the policy. This type of insurance also builds cash value which can be borrowed.	
 	
°	 	Universal Life – Life insurance which provides permanent protection characterized by flexible premiums and flexible face amount. This type of insurance builds cash value.	
 	
°	 	Variable Life – Life insurance for which the death benefit and cash value fluctuate according to investment performance, if tied to one of the following indices: S & P 500 Index, Wilshire 5000 Index, Russell 2000 Index, Russell 2500 Index or MSCI EAFE Index.	

Ø	 	The annual payment to the carrier by the Company will terminate upon the termination of the officer’s employment with the Company.	

Ø	 	The $15,000 will be taxable compensation to the officer.	
 	 	 	
APPROVED:	 	APPROVED:	
 	 	 	
/s/ George L. Mazanec	 	/s/ Philip C. Ackerman	

 	
George L. Mazanec
Chairman, Compensation Committee	 	Philip C. Ackerman
Chief Executive Officer	
 	 	 	
Date:                                                                                      	 	Date:                                                                                      	

 

Exhibit 10.2
NATIONAL FUEL GAS COMPANY AND PARTICIPATING SUBSIDIARIES
EXECUTIVE RETIREMENT PLAN 2003 TRUST AGREEMENT (I)

 

TABLE OF CONTENTS

 	 	Page
	
SECTION 1. Restatement and Title of the Trust	 	 	2	 	
SECTION 2. Acceptance by the Trustee	 	 	4	 	
SECTION 3. Limitation on Use of Funds; Trustee Responsibility Regarding Payments to Member or Beneficiary When the Company is Insolvent; Payments to the Company	 	 	4	 	
SECTION 4. Duties and Powers of the Trustee with Respect to Investments	 	 	6	 	
SECTION 5. Additional Powers and Duties of the Trustee	 	 	8	 	
SECTION 6. Payments by the Trustee	 	 	11	 	
SECTION 7. Third Parties	 	 	14	 	
SECTION 8. Taxes, Expenses and Compensation	 	 	14	 	
SECTION 9. Administration and Records	 	 	15	 	
SECTION 10. Removal or Resignation of the Trustee and Designation of Successor Trustee	 	 	17	 	
SECTION 11. Enforcement of Trust Agreement and Legal Proceedings	 	 	18	 	
SECTION 12. Change in Control Defined	 	 	19	 	
SECTION 13. Termination	 	 	21	 	
SECTION 14. Amendments	 	 	21	 	
SECTION 15. Non-alienation	 	 	22	 	
SECTION 16. Communications	 	 	22	 	
SECTION 17. Miscellaneous Provisions	 	 	24	 	
EXHIBIT A	 	 	 	 	
i

 

NATIONAL FUEL GAS COMPANY AND PARTICIPATING SUBSIDIARIES
EXECUTIVE RETIREMENT PLAN 2003 TRUST AGREEMENT (I)
     This 2003 RESTATEMENT OF THE TRUST AGREEMENT, made and entered into as of September 1, 2003, by NATIONAL FUEL GAS COMPANY, a corporation organized under the laws of the State of New Jersey, (the Company), and HSBC Bank USA, a bank organized under the laws of the state of New York (the Trustee)
W I T N E S S E T H:
     WHEREAS, the Company established an excess benefit plan, within the meaning of Section 3(36) of the Employee Retirement Income Security Act of 1974, as amended (ERISA), called the National Fuel Gas Company and Subsidiaries Supplemental Executive Retirement Plan (the SERP), for the benefit of certain employees;
     WHEREAS, the Company subsequently established an unfunded plan of deferred compensation under ERISA § 201(2), called the National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan (the Plan), and amended the Plan, so that the Plan provides benefits in addition to and inclusive of those provided under the SERP, and the SERP was terminated effective April 25, 1988;
     WHEREAS, the Plan provides for the Company to pay all benefits from its general assets and does not require it to pay benefits from the assets of any trust or special or separate fund established by the Company to assure those payments;
     WHEREAS, the Company established a revocable trust fund, subject to the Company’s Insolvency, to aid it in meeting its obligations under the SERP, and amended that trust as of May 10, 1996 to aid the Company in meeting its obligations under the Plan;
     WHEREAS, the Company remains concerned that benefits may not be paid under the Plan if there is a Change in Control and wishes to assure payment on and after a Change in Control;

 

     WHEREAS, the Company wishes to benefit all participants in the Plan, called Members, whether retired or not, and Beneficiaries, on and after a Change in Control;
     WHEREAS, the Company wishes to amend the trust further to provide additional protection to Members and Beneficiaries of the Plan by making the trust generally irrevocable on a Change in Control and to provide that protection as equitably as possible among those Members and Beneficiaries;
     WHEREAS, the Company intends to make contributions to the trust fund to aid it in meeting its obligations under the Plan, until that trust fund is revoked by the Company under the circumstances described in this Trust Agreement, when the trust fund will be returned to the Company, and to provide for the payment of benefits on and after a Change in Control, and in other circumstances, and those contributions will be held by the Trustee, and invested, reinvested and distributed, including subject to the Company’s Insolvency, in accordance with this Trust Agreement;
     WHEREAS, the Trustee is under no duty to determine whether any contributions are in accordance with the Plan or to collect or enforce payment of any contribution; and
     WHEREAS, it is the intention of the parties that this Trust constitute an unfunded arrangement and will not affect the status of the Plan as an unfunded plan maintained for the purpose of providing deferred compensation for a select group of management or highly compensated employees for purposes of Title I of the Employee Retirement Income Security Act of 1974, as amended (ERISA).
     NOW, THEREFORE, in consideration of the mutual covenants in this Trust Agreement, the Company and the Trustee declare and agree as follows:
      SECTION 1. Restatement and Title of the Trust.
      1.1. The Company continues with the Trustee a Trust as restated in its entirety by this agreement, known as the “The National Fuel Gas Company and Participating Subsidiaries
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Executive Retirement Plan 2003 Trust (I)” (the Trust), consisting of sums of money and other property acceptable to the Trustee as from time to time are paid or delivered to the Trustee. All that money and other property, all investments and reinvestments made with it or proceeds of it and all earnings and profits on it, less all payments and charges as authorized in this Trust Agreement, are referred to as the “Trust Fund”. The Trust Fund will be held by the Trustee IN TRUST and will be dealt with in accordance with the provisions of this Trust Agreement.
      1.2. The Trust continued by this Trust Agreement is revocable; it will become irrevocable on a Change in Control.
      1.3. The Company at all times has the power to reacquire assets of the Trust Fund by substituting readily marketable securities, other than securities of the Company or any affiliate, of an equivalent value, net of any costs of disposition, and that other property, following that substitution, will constitute the Trust Fund.
      1.4. The Trust is intended to be a grantor trust, of which Company is the grantor, within the meaning of subpart E part 1, subchapter J, chapter 1, subtitle A of the Internal Revenue Code of 1986, as amended, (the Code) and will be construed accordingly.
      1.5. The principal of the Trust, and any earnings on it, will be held separate and apart from other funds of the Company and, except with respect to the revocability of the Trust prior to a Change in Control, will be used exclusively for the uses and purposes of Members, Beneficiaries and general creditors as in set forth in this Trust Agreement. Members and Beneficiaries have no preferred claim on, or any beneficial ownership interest in, any assets of the Trust. Any rights created under the Plan and this Trust Agreement will be mere unsecured contractual rights of Members and Beneficiaries against the Company. Any assets held by the Trust will be subject to the claims of the Company’s general creditors under federal and state law in the event of Insolvency.
      1.6. Prior to a Change in Control, the Company, in its sole discretion, at any time, or from time to time, may make additional deposits of cash or other property in trust with
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the Trustee to augment the principal to be held, administered and disposed of by the Trustee as provided in this Trust Agreement. Neither the Trustee nor any Member or Beneficiary has any right to compel these additional deposits.
      1.7. On a Change in Control, the Company, as soon as possible, but not longer than 15 business days following the Change in Control, must make an irrevocable contribution to the Trust in an amount sufficient to pay each Member or Beneficiary the benefits to which Members and Beneficiaries would be entitled pursuant to the terms of the Plan as of the date of the Change in Control.
      1.8. Within 30 business days following the end of each Plan year ending after a Change in Control, the Company is required to deposit irrevocably additional cash or other property to the Trust in an amount sufficient to pay each Member or Beneficiary the benefits payable pursuant to the terms of the Plan as of the close of the Plan year.
      SECTION 2. Acceptance by the Trustee.
      2.1. The Trustee continues the Trust established under this Trust Agreement on the terms and subject to the provisions set forth in this Trust Agreement, and it agrees to continue to discharge and perform fully and faithfully all the duties and obligations imposed on it under this Trust Agreement.
      SECTION 3. Limitation on Use of Funds; Trustee Responsibility Regarding Payments to Member or Beneficiary When the Company is Insolvent; Payments to the Company.
      3.1. Except with respect to the revocability of the Trust prior to a Change in Control, no part of the corpus or income of the Trust Fund may be recoverable by the Company, used to provide for borrowing from any lender, or used for any purpose other than for the exclusive purpose of providing payments to Members and Beneficiaries in accordance with the provisions of this Trust Agreement until all payments required by this Trust Agreement have been made. However, nothing in this Section may be deemed to limit or otherwise prevent the
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payment from the Trust Fund of expenses and other charges to the extent provided for in Sections 8 and 17, and the Trust Fund at all times will be subject to the claims of creditors of the Company and its subsidiaries to the extent provided for in Section 3.2.
      3.2. (a) The Trustee must cease payment of benefits to Members and Beneficiaries if the Company is Insolvent. The Company will be considered “Insolvent” if (i) the Company is unable to pay its debts as they become due, or (ii) the Company is subject to a pending proceeding as debtor under the United States Bankruptcy Code.
           (b)  At all times during the continuance of this Trust, as provided in Section 1.1, the principal and income of the Trust will be subject to claims of general creditors of the Company under federal and state law as set forth below.
                (1)  The Board of Directors and the Chief Executive Officer of the Company have the duty to inform the Trustee in writing of Company’s Insolvency. If a person claiming to be a creditor of Company alleges in writing to the Trustee that Company has become Insolvent, the Trustee will determine whether Company is Insolvent and, pending that determination, the Trustee will discontinue payment of benefits to Members and Beneficiaries.
                (2)  Unless the Trustee has actual knowledge of the Company’s Insolvency, or has received notice from Company or a person claiming to be a creditor alleging that Company is Insolvent, the Trustee has no duty to inquire whether the Company is Insolvent. The Trustee may rely on such evidence concerning the Company’s solvency as may be furnished to the Trustee and that provides the Trustee with a reasonable basis for making a determination concerning the Company’s solvency.
                (3)  If at any time the Trustee has determined the Company is Insolvent, the Trustee must discontinue payments to Members and Beneficiaries and will hold the assets of the Trust for the benefit of the Company’s general creditors. Nothing in this Trust Agreement in any way may diminish any rights of Members and Beneficiaries as general creditors of the Company with respect to benefits due under the Plan or otherwise.
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                (4)  The Trustee will resume the payment of benefits to Members and Beneficiaries in accordance with Section 6 only after the Trustee has determined the Company is not Insolvent (or is no longer Insolvent).
           (c)  Provided there are sufficient assets, if the Trustee discontinues the payment of benefits from the Trust pursuant to Section 3.2(b)(3) and subsequently resumes those payments, the first payment following that discontinuance will include the aggregate amount of all payments due to Members and Beneficiaries under the terms of the Plan for the period of that discontinuance, less the aggregate amount of any payments made to Members and Beneficiaries by the Company in lieu of the payments provided for under this Trust Agreement during any such period of discontinuance.
      3.3. Except as provided in Sections 3.1 and 3.2, after the Trust has become irrevocable, the Company will have no right or power to direct the Trustee to return to the Company or to divert any of the Trust assets before all payment of benefits have been made to Members and Beneficiaries pursuant to the terms of the Plan.
      SECTION 4. Duties and Powers of the Trustee with Respect to Investments.
      4.1. The Trustee may not invest in securities (including stock or rights to acquire stock) or obligations issued by the Company, other than a de minimis amount held in common investment vehicles in which the Trustee invests. All rights associated with assets of the Trust will be exercised by the Trustee or the person designated by the Trustee, and in no event will be exercisable by or rest with Members and Beneficiaries.
      4.2. The Company has the right at any time, and from time to time in its sole discretion, to substitute assets of equal fair market value for any asset held by the Trust. The right is exercisable by Company in a non-fiduciary capacity without the approval or consent of any person in a fiduciary capacity.
      4.3. (a) The Company, at any time prior to a Change in Control, may direct the Trustee to, and the Trustee, at any time on or after a Change in Control, may segregate all or
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a specified portion of the Trust Fund into a separate fund (the Directed Fund) and invest it in accordance with the directions of one or more Investment Managers appointed by the Company or the Trustee, as the case may be. Any Investment Manager so appointed must be (1) an investment adviser registered as such under the Investment Advisors Act of 1940, (2) a bank, (3) an insurance company qualified to perform investment management service, under the laws of more than one state of the United States, or (4) any other person acceptable to the Trustee. If the Company appoints an Investment Manager, the Company will deliver to the Trustee a copy of the instruments appointing the Investment Manager and evidencing the Investment Manager’s acceptance of the appointment. The Trustee then will be protected in assuming the appointment of an Investment Manager remains in effect until it is otherwise notified by the Company. All notifications, instructions, and directions under this Section by or from the Company, the Trustee or the Investment Manager must be in writing or they will not be considered as such.
           (b)  The Trustee will invest and reinvest the Directed Fund only to the extent and in the manner directed by the Investment Manager, including an investment in any open-end or closed-end investment company or companies, as defined in the Investment Company Act of 1940. In performing its investment duties, the Investment Manager will have, with respect to the Directed Fund, all of the powers of the Trustee listed in Sections 4 and 5 (other than Sections 5.9 and 5.12). If the Trustee does not receive instructions from an Investment Manager with respect to the Directed Fund, the Trustee, after providing notice to the Investment Manager, will invest those amounts in short-term securities of the United States or any agency or instrumentality of it or in one or more investment companies commonly known as “money market” funds, whether or not managed by the Trustee or its affiliates, and, prior to a Change in Control, with the consent of the Company, in a common fund maintained by the Trustee for short-term investments. If the Investment Manager resigns, is removed, is no longer qualified to serve as an Investment Manager under applicable law, the Trustee will reassume complete investment responsibility for the Directed Fund until, prior to a Change in Control, a new Investment Manager is appointed by the Company, or on and after a Change in Control, a new Investment Manager is appointed by the Trustee. On a Change in Control, the Trustee will notify the Investment Manager either it, the Trustee, is appointing the Investment Manager to
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continue or it, the Trustee, is reassuming complete investment responsibility for the Directed Fund.
           (c)  Any Investment Manager acting may issue orders for the purchase or sale of securities directly to a broker or dealer and the Trustee, on request from the Investment Manager, will execute and deliver appropriate trading authorization. Notification of the issuance of each such order must be given promptly to the Trustee by the Investment Manager, and the execution of each such order will be confirmed by the broker to the Investment Manager and to the Trustee. That notification is authority to the Trustee to receive securities purchased against payment for those securities and to deliver securities sold against receipt of the proceeds from them, as the case may be. Unless the Trustee participates knowingly in, or knowingly undertakes to conceal, an act or omission of the Investment Manager, knowing that act or omission to be a breach of the Investment Manager’s responsibilities with respect to the Trust, the Trustee will not be liable for any act or omission of the Investment Manager and will not be under any obligation to invest or otherwise manage the assets of the Plan that are subject to the management of the Investment Manager, and the Trustee has no liability or responsibility for acting or not acting in accordance with any written direction of the Investment Manager or, subject to Section 4.4(b), failing to act in the absence of any such direction. The Company agrees, to the extent permitted by applicable law, to indemnify the Trustee and hold it harmless from and against any claim or liability that may be asserted against it, other than on account of the Trustee’s own negligence or willful misconduct, by reason of the Trustee’s taking or refraining from taking any action in accordance with this Section, including, any claim or liability that may be asserted against the Trustee on account of failure to receive securities purchased, or failure to deliver securities sold, pursuant to orders issued by the Investment Manager directly to a broker or dealer.
      SECTION 5. Additional Powers and Duties of the Trustee.
     The Trustee has the following additional powers and authority with respect to all property constituting a part of the Trust Fund:
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      5.1. To sell, exchange or transfer any such property at public or private sale for cash or on credit and grant options for the purchase or exchange of it.
      5.2. To participate in any plan or reorganization, consolidation, merger, combination, liquidation or other similar plan relating to any such property, and to consent to or oppose any such plan or any action thereunder or any contract, lease, mortgage, purchase, sale or other action by any corporation or other entity.
      5.3. To deposit any such property with any protective, reorganization or similar committee; to delegate discretionary power to any such committee; and to pay part of the expenses and compensation of any such committee and any assessments levied with respect to any property so deposited.
      5.4. To exercise any conversion privilege or subscription right available in connection with any such property; to oppose or to consent to the reorganization, consolidation, merger or readjustment of the finances of any corporation company or association, or to the sale, mortgage, pledge or lease of the property or any of the securities that at any time may be held in the Trust Fund and to do any act with reference to the property, including the exercise of options, the making of agreements or subscriptions and the payment of expenses, assessments or subscriptions, that may be deemed necessary or advisable in connection with those actions, and to hold and retain any securities or other property that it may so acquire.
      5.5. To commence or defend suits or legal proceedings and to represent the Trust in all suits or legal proceedings; to settle, compromise or submit to arbitration, any claims, debts or damages, due or owing to from the Trust.
      5.6. To exercise, personally or by general or limited power of attorney, any right, including the right to vote, appurtenant to any securities or other such property.
      5.7. To borrow money from any lender in amounts and on terms and conditions as are deemed advisable or proper to carry out the purposes of the Trust and to pledge any securities or other property for the repayment of any such loan.
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      5.8. To hold any mortgage in its own name or in the name of a nominee, with or without the addition of words indicating that the mortgage is held in a fiduciary capacity, and to cause to be formed a corporation, partnership, trust or other entity to hold title to any mortgage with those powers, all on terms and conditions as are deemed advisable; to renew or extend or participate in the renewal or extension of any mortgage, and to agree to a reduction in the rate of interest on any mortgage or to any other modification or change in the terms of any mortgage or of any guarantee pertaining to it, in any manner and of any guarantee pertaining to it, in any manner and to any extent that is deemed advisable for the protection of the Trust or the preservation of any covenant or condition of any mortgage or in the performance of any guarantee, or to enforce any default in the manner and to the extent as is deemed advisable; and to exercise and enforce any and all rights of foreclosure, to bid on any property on foreclosure, to take a deed in lieu of foreclosure with or without paying a consideration for it and in connection with it to release the obligation on the bond secured by that mortgage, and to exercise and enforce in any action, suit or proceeding at law or in equity any rights or remedies in respect of any such mortgage or guarantee.
      5.9. To engage any legal counsel, including counsel to the Company, or any other suitable agents, to consult with that counsel or those agents with respect to the construction of this Trust Agreement, the duties of the Trustee under it, the transactions contemplated by this Trust Agreement or any act the Trustee proposes to take or omit, to rely on the advice of such counsel or agents, and to pay its reasonable fees, expenses and compensation from the Trust, unless paid by the Company.
      5.10. To register any securities held by it in its own name or in the name of any custodian of such property or of its nominee, including the nominee of any system for the central handling of securities, with or without the addition of words indicating that such securities are held in a fiduciary capacity, to deposit or arrange for the deposit of any such securities with such a system and to hold any securities in bearer form.
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      5.11. On the direction of the Company, to enter into or assume any contract or policy with an insurance company or companies for the purpose of investment, insurance coverage or otherwise, to pay from the Trust Fund premiums, assessments, dues, charges and interest, if any, with respect to those contracts or policies, to exercise any and all of the rights, options or privileges (including, but not limited to, the right to borrow) under those contracts or policies, to otherwise take actions that may be available under those contracts or policies. However, the Trustee will be the sole owner of all those contracts held as assets of the Trust Fund. The Trustee will have no power to name a beneficiary of the policy other than the Trust, to assign the policy (as distinct from conversion of the policy to a different form) other than to a successor trustee, or to loan to any person the proceeds of any borrowing against that policy.
      5.12. To make, execute and deliver, as the Trustee, any and all deeds, leases, notes, bonds, guarantees, mortgages, conveyances, contracts, waivers, releases or other instruments in writing necessary or proper for the accomplishment of any of the powers listed above.
      5.13. Notwithstanding any powers granted to the Trustee pursuant to this Trust Agreement or to applicable law, the Trustee may not have any power that could give this Trust the objective of carrying on a business and dividing the gains from it, within the meaning of section 301.7701-2 of the Procedure and Administrative Regulations promulgated pursuant to the Code.
      SECTION 6. Payments by the Trustee.
      6.1. The Company will deliver to the Trustee at least annually a schedule (the Payment Schedule) that indicates the amounts payable in respect of each Member and Beneficiary, that provides a formula or other instructions acceptable to the Trustee for determining the amounts so payable, the form in which that amount is to be paid (as provided for or available under the Plan), and the time of commencement for payment of that amount. Except as otherwise provided in this Trust Agreement, the Trustee will make payments to the Members and Beneficiaries in accordance with the Payment Schedule. On and after a Change in Control,
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the Trustee will make provision for the reporting and withholding of any federal, state or local taxes that may be required to be withheld with respect to the payment of benefits pursuant to the terms of the Plan and will pay amounts withheld to the appropriate taxing authorities or determine that those amounts have been reported, withheld and paid by the Company. Prior to a Change in Control, the Company is responsible for that reporting, withholding and payment.
      6.2. The entitlement of a Member or Beneficiary to benefits under the Plan will be determined by Company or a party it designates under the Plan, and any claim for those benefits will be considered and reviewed under the procedures set out in the Plan.
      6.3. Prior to a Change in Control or, if earlier, until it notifies the Trustee otherwise, the Company will make payment of benefits directly to Members and Beneficiaries as they become due under the terms of the Plan. The Company will notify the Trustee of its decision to not make payment of benefits directly prior to the time amounts are payable to Members and Beneficiaries. In addition, if the principal of the Trust, and any earnings on it, are not sufficient to make payments of benefits in accordance with the terms of the Plan, the Company will make the balance of each such payment as it falls due. The Trustee will notify the Company when principal and earnings are not sufficient.
      6.4. (a) On a Change in Control, the Trustee first must obtain from the Company a current Payment Schedule, and then determine if the Company has paid any of the amounts listed on it. To the extent the Company has not paid any amount due to be paid pursuant to the Payment Schedule, the Trustee will pay the amount specified or determined from the formulas and adjustments, in the then current Payment Schedule, subject to Sections 6.5 and 6.6, to each Member listed as a former employee of the Company or to the Beneficiary in a cash lump sum. The Trustee will file with the Company a written report of that payment within 15 days after making the payment. For all purposes of this Trust Agreement, a Beneficiary is the beneficiary of a deceased Member designated directly to the Trustee, or the beneficiary designated to the Company and reflected on the current Payment Schedule (and substantiated with a copy of the beneficiary designation held by the Company), if it is more recent, or, if there
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is none of either of those or the Trustee cannot reasonably determine the beneficiary designated in either manner, the legal representative of the deceased Member’s estate.
           (b)  At any time following a Change in Control, on termination of the Company’s employment of a Member listed on the Payment Schedule, the amount specified or determined from the formulas and adjustments contained in the then current Payment Schedule, subject to Sections 6.5 and 6.6, will be paid by the Trustee to the Member or Beneficiary in a cash lump sum after the Trustee determines the extent to which the amount has not been paid by the Company. If the Company does not notify the Trustee of the Member’s termination of employment, the Member may deliver to the Trustee two duly executed and notarized Affidavits and Receipts in substantially the form attached as Exhibit A, and, in the case of a deceased Member, the Beneficiary may deliver two copies of the Member’s death certificate. The Trustee will file with the Company a written report of that payment, with one Affidavit and Receipt or one copy of the death certificate, if any, within 15 days after making the payment.
           (c)  If, at any time after a Change in Control the Trust finally is determined by the Internal Revenue Service (the IRS) not to be a “grantor trust” with the result that the income of the Trust Fund is not treated as income of the Company pursuant to Code §§ 671-679, or if a tax is finally determined by the IRS or by counsel to the Trustee to be payable by one or more Members in respect of any right, title or interest in any assets of the Trust Fund prior to termination of employment with the Company, then the amount specified or determined from the formulas and adjustments contained in the then current Payment Schedule, subject to Sections 6.5 and 6.6, will be paid by the Trustee in a cash lump sum as soon as practicable to each Member or Beneficiary, subject to reduction for amounts paid by the Company, regardless of whether that Member’s employment with the Company has terminated and without the necessity of presentation of an Affidavit and Receipt or death certificate.
      6.5. If the Trustee holds life insurance contracts or policies on the life of any Member, the Member may elect, with the consent of the Company prior to a Change in Control and the consent of the Trustee on and after a Change in Control, under procedures adopted by the
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Trustee and subject to Section 6.6, to have those contracts or policies assigned to him or her and distributed to that Member in satisfaction of that portion of the cash lump sum payment to which the Member otherwise would be entitled under the preceding subsections that those contracts or policies represent. The determination of the fair market value of such a contract or policy will be made by the Trustee after consultation with an actuary.
      6.6. On and after a Change in Control, any payment made to a Member or Beneficiary at any time under this Trust Agreement may not exceed the pro rata portion of the assets of the Trust Fund determined to be allocable to that payment, based on the then current Payment Schedule. The Trustee will determine the sufficiency of the Trust Fund at the time of any such payment. If the Trustee determines the Trust Fund is not sufficient to make all payments due at that time and in the future, the Member or Beneficiary, as the case may be, will receive a pro rata payment based on the amount to be paid to the Member or Beneficiary compared to the aggregate amount otherwise payable at that time and in the future to all Members and Beneficiaries. Any amount not paid because of this reduction will be considered as part of the payments to be made subsequently, subject to the same pro rata limitations. The Trustee must engage an actuary to determine the present value of amounts payable in the future and will use reasonable actuarial assumptions as determined by the Trustee, in consultation with the actuary.
      SECTION 7. Third Parties.
      7.1. A third party dealing with the Trustee is not required to make inquiry as to the authority of the Trustee to take any action nor under any obligation to follow the proper application by the Trustee of the proceeds of sale of any property sold by the Trustee or to inquire into the validity or propriety of any act of the Trustee.
      SECTION 8. Taxes, Expenses and Compensation.
      8.1. The Company from time to time will pay taxes of any kind lawfully levied or assessed on or payable in respect of the Trust Fund, the income or any property forming a part
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of it, or any security transaction pertaining to it. To the extent that any taxes lawfully levied or assessed on the Trust Fund are not paid by the Company, the Trustee will pay those taxes out of the Trust Fund. On and after a Change in Control, no taxes (other than applicable withholding taxes and charges pursuant to Section 6.1 and other taxes relating to the Trust Fund for which the Trustee has been assessed by the appropriate federal, state or local taxing authority) may be paid from the Trust Fund. The Trustee will contest the validity of those taxes in any manner deemed appropriate by the Company or its counsel, but at Company expense, or the Company itself may contest the validity of any of those taxes.
      8.2. Any other reasonable expenses incurred by the Trustee in the performance of its duties under this Trust Agreement, including brokerage commissions, will be charged against and paid from the Trust Fund to the extent the Company does not pay those expenses.
      8.3. The Company will pay the Trustee reasonable compensation for its services as may be agreed on in writing from time to time by the Company and the Trustee. That compensation will be charged against and paid from the Trust Fund to the extent the Company does not pay that compensation.
      SECTION 9. Administration and Records.
      9.1. The Trustee will keep or cause to be kept accurate and detailed accounts of any investments, receipts, disbursements and other transactions under this Trust Agreement, and all accounts, books and records relating to that will be open to inspection and audit at all reasonable times by any person designated by the Company and, on and after a Change in Control, by any Member. All those accounts, books and records will be preserved (in original form, or on microfilm, magnetic tape or any other similar process) for the period the Trustee determines, but the Trustee may destroy those accounts, books and records only after first notifying the Company and, on and after a Change in Control, all the Members in writing of its intention to do so and transferring to the Company, with, on and after a Change in Control, a copy to a representative of the Members, any of those accounts, books and records requested.
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      9.2. Within 60 days after the close of each calendar year, and within 60 days after the removal or resignation of the Trustee or the termination of the Trust, the Trustee will file with the Company a written account setting forth all investments, receipts, disbursements and other transactions effected by it during the preceding calendar year or during the period from the close of the preceding calendar year to the date of its removal, resignation or termination, including a description of all investments and securities purchased and sold with the cost or net proceeds of those purchases or sales and showing all cash, securities and other property held at the end of that calendar year or other period. After 90 days from the date of filing that annual or other account, the Trustee will be forever released and discharged from all liability and accountability with respect to the propriety of its acts and transactions shown in that account, except with respect to any acts or transactions as to which the Company, or, on and after a Change in Control, a representative of the Members, within that 90-day period files with the Trustee written objections.
      9.3. The Trustee from time to time must permit an independent public accountant selected by the Company (except one to which the Trustee has reasonable objection) to have access during ordinary business hours to records as may be necessary to audit the Trustee’s accounts.
      9.4. As of the last day of each calendar year, the fair market value of the assets held in the Trust Fund will be determined. The Trustee will file with the Company, and, on and after a Change in Control, a representative of the Members, the written report of the determination of that fair market value.
      9.5. Nothing contained in this Trust Agreement may be construed as depriving the Trustee or the Company of the right to have a judicial settlement of the Trustee’s accounts, and on any proceeding for a judicial settlement of the Trustee’s accounts or for instructions the only necessary parties to it in addition to the Trustee are the Company and, on and after a Change in Control, a representative of the Members.
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      9.6. If the Trustee is removed or resigns, the Trustee will deliver to the successor trustee all records required by the successor trustee to enable it to carry out the provisions of this Trust Agreement.
      9.7. In addition to any returns required of the Trustee by law, the Trustee must prepare and file tax reports and other returns as the Company and the Trustee from time to time agree.
      9.8. The Members at any time may chose a representative to receive information, notices, make objections, and the like under this Section. The Trustee is not required to deal with more than one representative. If more than one representative purports to represent the Members, that person or entity representing the most Members will be considered by the Trustee to be the representative of the Members under this Section.
      9.9. In any case in this Trust Agreement where the Trustee is protected, that protection is to the maximum extent of the law.
      SECTION 10. Removal or Resignation of the Trustee and Designation of Successor Trustee.
      10.1. At any time prior to a Change in Control, the Company may remove the Trustee with or without cause, on at least 60 days’ notice in writing to the Trustee. On and after a Change in Control, the Trustee may not be removed, except by order of a court having competent jurisdiction.
      10.2. The Trustee may resign at any time upon at least 60 days’ notice in writing to the Company and, on and after a Change in Control, the Members.
      10.3. If the Trustee is removed or resigns, the Trustee will duly file with the Company a written account as provided in Section 9.2 for the period since the last previous annual accounting, listing the investments of the Trust Fund and any uninvested cash balance of it, and setting forth all receipts, disbursements, distributions and other transactions respecting the
- 17 -

 

Trust not included in any previous account, and if written objections to that account are not filed as provided in Section 9.2, the Trustee is forever released and discharged from all liability and accountability with respect to the propriety of its acts and transactions shown in that account.
      10.4. Within 60 days after any notice of removal or resignation of the Trustee, the Company will designate a successor trustee qualified to act under this Trust Agreement. However, if a Trustee resigns on or after a Change in Control, then the successor Trustee qualified to act under this Trust Agreement may be only any bank, trust company or other financial institution that may serve as Trustee under applicable law acceptable to at least 50% of the members of the Board immediately prior to the Change in Control then living and readily available and willing to make that decision. If no designation has been made, the Trustee may apply to a court of competent jurisdiction for appointment of a successor or for instructions. All expenses of the Trustee in connection with the proceeding will be allowed as administrative expenses of the Trust. Each successor Trustee, during the period it acts as such, has the powers and duties conferred in this Agreement on an individual Trustee, and the word “Trustee” wherever used in this Agreement, except where the context otherwise requires, is deemed to include any successor Trustee. On designation of a successor Trustee and delivery to the resigned or removed Trustee of written acceptance by the successor Trustee of the designation, the resigned or removed Trustee promptly will assign, transfer, delivery and pay over to that successor Trustee, in conformity with the requirements of applicable law, the funds and properties in its control or possession then consisting the Trust Fund. The transfer will be completed within 30 days after receipt of notice of resignation, removal or transfer.
      SECTION 11. Enforcement of Trust Agreement and Legal Proceedings.
      11.1. The Company has the right to enforce any provision of this Trust Agreement, and, on or after a Change in Control, any Member has the right as a beneficiary of the Trust to enforce any provision of this Trust Agreement that affects the right, title and interest of that Member in the Trust. Except to the extent provided in Section 3.2 or as otherwise required by applicable law, in any actions or proceedings affecting the Trust, the only necessary
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parties are the Company, the Trustee, and, on or after a Change in Control, the Members and, except as otherwise required by applicable law, no other person is entitled to any notice or service of process. Any judgment entered in such an action or proceeding will be binding and conclusive on all persons having or claiming to have any interest in the Trust.
      11.2. If the Trustee receives notification pursuant to Section 3.2 that the Company is Bankrupt or Insolvent, the Trustee promptly will give notice of that in writing to all Members and Beneficiaries listed on the then current Payment Schedule as soon as it is reasonably practicable.
      SECTION 12. Change in Control Defined.
           (a)  A “Change in Control” will be deemed to have occurred if any of the following has occurred:
               (i) either (a) the Company receives a report on Schedule 13D, or an amendment to such a report, filed with the Securities and Exchange Commission (SEC) pursuant to Section 13(d) of the Securities Exchange Act of 1934 (the 1934 Act) disclosing that any person (as that term is used in Section 13(d) of the 1934 Act) (Person), is the beneficial owner, directly or indirectly, of 20% or more of the outstanding stock of the Company or (b) the Company has actual knowledge of facts that 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 20% or more of the outstanding stock of the Company;
               (ii) purchase by any Person, other than the Company or a wholly-owned subsidiary of the Company or an employee benefit plan sponsored or maintained by the Company or a wholly-owned subsidiary of the Company, 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, that
- 19 -

 

Person is the beneficial owner (as defined in Rule 13d-3 under the 1934 Act), directly or indirectly, of 20% 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) 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 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 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 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 2/3 of the directors then still in office who were in office at the beginning of the 24-month period.
      12.2. No Change in Control may be deemed to have occurred for purposes of this Trust Agreement until the Trustee has actual knowledge from a reliable source, not including a Member acting in his or her individual capacity, of that Change in Control. A written notarized statement that a Change in Control has occurred, delivered to the Trustee and signed by at least 50% of the individuals then living who were members of the Board as of any date during the one-year period ending on the date that notice is received by the Trustee will be deemed to be
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actual knowledge from a reliable source, and a report filed with the Securities and Exchange Commission, a public statement issued by the Company, or a periodical of general circulation, including but not limited to The New York Times or The Wall Street Journal , is deemed to be a reliable source, regardless of the manner in which that report of a change in Control is made known to the Trustee.
      SECTION 13. Termination.
      13.1. The Company may terminate this Trust on 30 days’ written notice to the Trustee. On receipt by the Trustee of that notice of termination of the Trust and documentation of the approval of all Members, the Trustee, with reasonable promptness after receipt of any such notice, will arrange for the orderly distribution of the Trust property, or remaining amounts of it, in conformity with the provisions of applicable law.
      13.2. Except as provided in Section 13.1, on and after a Change in Control, the Trust may not terminate until the date on which Members and Beneficiaries are no longer entitled to benefits pursuant to the terms of the Plan.
      13.3. On termination of the Trust, any assets remaining in the Trust will be returned to Company.
      SECTION 14. Amendments.
      14.1. At any time prior to a Change in Control, the Company from time to time may amend or modify, in whole or in part, any or all of the provisions of this Trust Agreement that cannot adversely affect the interests of any Members and that do not conflict with the terms of the Plan. Any such amendment may be made only with notice to all Members, but need not have the consent of any Member.
      14.2. Except as provided in Section 14.1, this Trust Agreement may not be amended by the Company or its successor, except as may be required by applicable law or with the consent of the Trustee and, on and after a Change in Control, all Members.
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      14.3. The Company and the Trustee will execute supplements to, or amendments of, this Trust Agreement necessary to give effect to any amendment or modification.
      SECTION 15. Non-alienation.
      15.1. Benefits payable to Members and Beneficiaries under this Trust Agreement may not be anticipated, assigned (either at law or in equity), alienated, pledged, encumbered or subjected to attachment, garnishment, levy, execution or other legal or equitable process.
      SECTION 16. Communications.
      16.1. All communications of any kind under all provisions of this Trust Agreement, including instructions, elections, notifications, and directions, must be in writing and all communications to parties required under this Agreement must be in writing and (a) delivered in person, (b) mailed by registered or certified mail, return receipt requested, (any mailed notice to be effective four days after the date it is mailed) or (c) sent by facsimile transmission, with confirmation sent by way of one of the above methods, to the party at the address given below for that party (or to such other address as such party designates in a writing complying with this Section, delivered to the other party):
- 22 -

 

 	 	 	
If to the Company:	
 	 	 	
	 	National Fuel Gas Company	
	 	      Prior to October 6, 2003:	
	 	10 Lafayette Square	
	 	Buffalo, New York 14203	
	 	      After October 5, 2003:	
	 	6363 Main Street	
	 	Williamsville, New York 14221	
 	 	 	
	 	Attention: General Counsel	
	 	Telephone: (716) 857-7548	
	 	Fax: (716) 857-7195	
 	 	 	
with a copy to:	
 	 	 	
	 	Hodgson Russ LLP	
	 	One M&T Plaza, Suite 2000	
	 	Buffalo, New York 14203-2391	
	 	Attention: Dianne Bennett	
	 	Telephone: (716) 848-1406	
	 	Fax: (716) 849-0349	
- 23 -

 

 	 	 	
If to the Trustee:	
 	 	 	
	 	HSBC Bank USA	
	 	17 th Floor	
	 	One HSBC Center	
	 	Buffalo, New York 14203	
	 	Attention: Retirement Financial Services	
	 	Telephone: (716) 841-2424	
	 	Fax: (716) 841-4244	
      16.2. All communications of any kind to a Member, Beneficiary or representative of Members must be in writing and delivered as in Section 16.1 and delivered to the address on the Payment Schedule, or a more updated address as specified by the Member, Beneficiary or representative pursuant to Section 16.1.
      16.3. No communication is binding on any entity until received by that entity.
      16.4. Any action of the Company pursuant to this Trust Agreement, including all orders, requests, directions, instructions, approvals and objections of the Company to the Trustee, must be in writing signed on behalf of the Company by any duly authorized officer of the company. The Trustee may rely on, and will be fully protected with respect to, any such action taken or omitted in reliance on, any information, order, request, direction, instruction, approval, objection list and Payment Schedule delivered to the Trustee by the Company or, to the extent applicable under this Trust Agreement, by a Member or the legal representatives of his or her estate.
      SECTION 17. Miscellaneous Provisions.
      17.1. This Trust Agreement is binding on and inures to the benefit of the Company and the Trustee and their respective successors and assigns.
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      17.2. The Company will pay and protect, indemnify and save harmless the Trustee and its officers, employees and agents from and against any and all losses, liabilities (including liabilities for penalties), actions, suits, judgments, demands, damages, costs and expenses (including, without limitation, attorneys’ fees and expenses) of any nature arising from or relating to any action by or any failure to act by the Trustee, its officers, employees and agents or the transactions contemplated by this Trust Agreement, including, but not limited to, any claim made by a Member or his or her Beneficiary with respect to payments made or to be made by the Trustee, any claim made, whether before or after a Change in Control, by the Company or its successor, whether pursuant to a sale of assets, merger, consolidation, liquidation or otherwise, that this Trust Agreement is invalid or ultra vires , except to the extent that any such loss, liability, action, suit, judgment, demand, damage, cost or expense has been determined by final judgment of a court of competent jurisdiction to be the result of the gross negligence or willful misconduct of the Trustee, its officers employees or agents. To the extent the Company has not fulfilled its obligations under this Section, the Trustee will be reimbursed out of the assets of the Trust Fund or may set up reasonable reserves for the payment of those obligations. No personal liability will attach to or be incurred by any employee, officer or director of the Company, as such, under or by reason of the terms or conditions contained in or implied from this Trust Agreement.
      17.3. The Trustee assumes no obligation or responsibility with respect to any action required by this Trust Agreement on the part of the Company.
      17.4. Any corporation into which the Trustee may be merged or with which it may be consolidated, or any corporation resulting from any merger, reorganization or consolidation to which the Trustee may be a party, or any corporation to which all or substantially all the trust business of the Trustee may be transferred is the successor of the Trustee without the execution or filing of any instrument or the performance of any act.
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      17.5. Any provision of this Trust Agreement prohibited by law is ineffective to the extent of any such prohibition, without invalidating the remaining provisions of this Trust Agreement.
      17.6. Titles to the Sections of this Trust Agreement are included for convenience only and do not control the meaning or interpretation of any provision of this Trust Agreement.
      17.7. To the maximum extent consistent with ERISA, this Trust Agreement and the Trust established under it will be governed by and construed, enforced and administered in accordance with the laws of the State of New York, and the Trustee will be liable to account only in the courts of that state.
      17.8. This Trust Agreement may be executed in any number of counterparts, each of which will be deemed to be the original, although the others are not produced.
     IN WITNESS WHEREOF, this Trust Agreement has been duly executed by the parties to it as of the day and year first above written.

	 	 	 	NATIONAL FUEL GAS COMPANY	
 		
	 	 	 	By: /s/ Philip C. Ackerman	
	 	 	 		
	 	 	 	Name: Philip C. Ackerman	
	 	 	 	Title: Chairman, President, CEO	
 	 	 	 	 	
Attest:	 	 	 	 	
 	 	 	 	 	
/s/ Anna Marie Cellino	 	 	 	 	
	 	 	 	 	
Secretary	 	 	 	 	
 	 	 	 	 	
	 	 	 	HSBC BANK USA, AS TRUSTEE	
 		
	 	 	 	By: /s/ Paul L. Morris	
	 	 	 		
	 	 	 	Name: Paul L. Morris	
	 	 	 	Title: Vice President	
 	 	 	 	 	
Attest:	 	 	 	 	
 	 	 	 	 	
/s/ Paul L. Morris	 	 	 	 	

/s/ James S. Buccella	 	 	 	 	
	 	 	 	 	
First Vice President	 	 	 	 	
- 26 -

 

 	 	 	 	 	 	 	
STATE OF NEW YORK	 	 	)	 	 	 	
 	 	 	 	 	 	 	
	 	 	 )	 SS:	 	 	
 	 	 	 	 	 	 	
COUNTY OF ERIE	 	 	)	 	 	 	
     On the 27th day of August , 2003, before me personally came Philip C. Ackerman to me known, who, being by me duly sworn, did depose and say that he /she resides in Erie County, New York , and that he /she is the Chairman/President/CEO of National Fuel Gas Company, one of the corporations described in and which executed the foregoing instrument; and that he/she signed his/her name thereto by order of the Board of Directors of said corporation.

PAULA M. CIPRICH	 	 	 	/s/ Paula M. Ciprich	
Notary Public, State of New York	 	 	 	
 	
Qualified in Erie County
My Commission Expires May 19, 2006	 	 	 	Notary Public	
 	 	 	 	 	 	 	
STATE OF New York	 	 	)	 	 	 	
 	 	 	 	 	 	 	
	 	 	 )	 SS:	 	 	
 	 	 	 	 	 	 	
COUNTY OF Erie	 	 	)	 	 	 	
     On the 27th day of August , 2003, before me personally came Paul L. Morris to be known, who, being by me duly sworn, did depose and say that he /she resides in Hamburg, New York ; that he /she is the Vice President of HSBC Bank USA, one of the corporation described in and which executed the foregoing instrument; and that he/she signed his/her name thereto by order of the Board of Directors of said corporation.

	 	 	 	/s/ Cynthia M. Wylegala	

	 	 	 	Notary Public	
 	 	 	 	 	
CYNTHIA M. WYLEGALA
Notary Public, State of New York
Qualified in Erie County
My Commission Expires July 23, 2006	 	 	 	 	
- 27 -

 

EXHIBIT A
AFFIDAVIT AND RECEIPT
     I,                                         , under penalties of perjury, do hereby solemnly state:
     That I make this Affidavit in order to induce the Trustee of the National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan Trust to pay me $                     pursuant to its terms; and
     That my employment with the National Fuel Gas Company or any of its subsidiaries was terminated on                     .

	 	 	 	
 	
	 	 	 	Member	
 	 	 	 	 	 	 	
STATE OF                    	 	 	)	 	 	 	
 	 	 	 	 	 	 	
	 	 	 ):	 ss.	 	 	
 	 	 	 	 	 	 	
COUNTY OF                    	 	 	)	 	 	 	
     On the                     day of                     , 200                     , before me personally came                                         to me known, who, being by me duly sworn, did depose and say that he/she resides at                                                                                 , and that the statements herein are all materially correct.

	 	 	 	
 	
	 	 	 	Notary Public	

 

Exhibit 10.3
Administrative Rules
of the
Compensation Committee
of the
Board of Directors
of
National Fuel Gas Company
As amended and restated
effective September 9, 2004

 

TABLE OF CONTENTS

I. Meetings	 	 	1	 	
II. Quorum and Voting; Delegation	 	 	1	 	
III. Grants and Awards Under the Plans	 	 	2	 	
A. General Rules Regarding Awards Under the 1997 and 1993 Plans	 	 	3	 	
1. Making of An Award	 	 	3	 	
2. Contemporaneous Awards	 	 	3	 	
3. Stock-Based Awards	 	 	3	 	
a. Source	 	 	3	 	
b. Cash Dividends and Cash Dividend Equivalents	 	 	3	 	
i. Stock Based Awards Other Than Restricted Stock	 	 	3	 	
ii.Restricted Stock Awards	 	 	4	 	
c. Payment	 	 	4	 	
4. Withholding Taxes	 	 	4	 	
5. Deferral of Payment	 	 	5	 	
B. Stock Options Under the 1997 and 1993 Plans	 	 	5	 	
1. Designation	 	 	5	 	
2. Price	 	 	6	 	
3. Exercise Period/Duration	 	 	6	 	
a. Non-Qualified Stock Options Under the 1997 and 1993 Plans	 	 	6	 	
b. Incentive Stock Options Under the 1997 and 1993 Plans	 	 	6	 	
4. Death or Other Termination of Employment	 	 	6	 	
a. Definitions	 	 	6	 	
b. Non-Qualified Stock Options Under the 1997 and 1993 Plans	 	 	7	 	
c. Incentive Stock Options Under the 1997 and 1993 Plans	 	 	7	 	
d. Extension of Incentive Stock Options Under the 1997 and 1993 Plans	 	 	8	 	
5. Mechanics of Exercise	 	 	10	 	
6. Reload Options	 	 	10	 	
C. SARs Under the 1997 Plan	 	 	10	 	
D. Restricted Stock Under the 1997 and 1993 Plans	 	 	11	 	
2

 

 	 	 	 	 	
1. Restrictions on Transferability; Vesting	 	 	11	 	
2. Mechanics of Grant	 	 	11	 	
E. Performance Units and Performance Shares Under The 1997 Plan	 	 	11	 	
IV. Procedures For Exercising Stock Options	 	 	12	 	
A. Authority and Scope	 	 	12	 	
B. Notice of Exercise	 	 	12	 	
1. Form and Delivery	 	 	12	 	
2. Exercise Date	 	 	13	 	
C. Payment of Exercise Price	 	 	13	 	
1. Cash Payment	 	 	13	 	
2. Payment with Existing Company Stock	 	 	14	 	
3. Additional Time to Pay Exercise Price	 	 	14	 	
4. Cashless Exercise	 	 	15	 	
3

 

ADMINISTRATIVE
RULES OF THE
COMPENSATION COMMITTEE
OF THE
BOARD OF DIRECTORS
OF
NATIONAL FUEL GAS COMPANY
As amended and restated
effective September 9, 2004
I. MEETINGS
     Each meeting (“Meeting”) of the Compensation Committee (“Committee”) of the Board of Directors of National Fuel Gas Company (“Company”) shall be held as indicated in a notice made in accordance with these rules. Notice of each Meeting, stating the place, date and hour thereof, shall be given to each member of the Committee (“Member”) by mailing written notice not less than five days before the Meeting to each Member, or by telegraphing, telephoning or delivering oral or written notice to each Member personally not less than one day before the Meeting.
     Any one or more Members of the Committee may participate in a Meeting by means of a conference telephone or similar equipment. Participation by such means shall constitute presence in person at a Meeting.
     The Committee may also take action by unanimous written consent.
II. QUORUM AND VOTING; DELEGATION
     At all Meetings, a quorum shall be required for the transaction of business and shall consist of a majority of the entire Committee. The majority vote of the Members at a Meeting at which a quorum is present shall decide any question that may come before the meeting.
     Consistently with limitations imposed by the Plans, the Committee may delegate in these rules or by resolution any or all of its authority to the Chief Executive Officer, to the Secretary and to any other officer of the Company (individually, “Delegate”), so long as the Delegate has no potential conflict of interest which would cause him or her not to exercise his or her good faith independent

 

business judgment in respect of a delegated matter, and so long as such delegation would not result in the requirement under applicable law that the Delegate’s name appear beneath the Committee’s report required to be included in Company filings with the Securities and Exchange Commission. Subject to such limitations, the Committee hereby delegates the power to implement its decisions to appropriate officers of the Company.
III. GRANTS AND AWARDS UNDER THE PLANS
     The following rules and regulations shall apply with respect to grants and awards of stock options, stock appreciation rights (“SARs”) and shares of restricted stock (“Restricted Stock”) under the Company’s 1997 Award and Option Plan (“1997 Plan”) and 1993 Award and Option Plan (“1993 Plan”) (together, the “Plans”). These rules also address other Awards under the Plans.
     Any capitalized term not defined in these rules shall have the same meaning as in the applicable Plan. The following rules are intended to supplement the Plans and, to the extent that any rule is determined to be inconsistent with any Plan, the Plan shall control.
     These rules may be amended by the Committee at any time and from time to time. Except to the extent otherwise specified in the particular Award Notice or at the time these rules are amended, any grant or award under the Plans shall be subject to these rules as in effect on the date of the grant or award.
2

 

      A.  GENERAL RULES REGARDING AWARDS UNDER THE 1997 AND 1993 PLANS
           1. Making of An Award
               An Award within the meaning of these rules occurs upon the grant by the Committee of any stock option, SAR, Restricted Stock, performance unit, performance share or other incentive award. An Award Notice within the meaning of these rules means a written notice from the Company to a Participant that sets forth the terms and conditions of an Award in addition to those established in the applicable Plan and by the Committee’s exercise of its administrative powers.
           2. Contemporaneous Awards
               An Award of one type granted contemporaneously with an Award of any other type shall be treated as having been granted in combination, and not in the alternative, with the Award of the other type.
           3. Stock-based Awards
                a. Source. Stock-based Awards, to the extent actually paid in Common Stock, shall reduce treasury shares first and thereafter authorized but unissued shares.
                b. Cash Dividends and Cash Dividend Equivalents.
                     (i) Stock-Based Awards Other Than Restricted Stock. No stock-based Award carries with it the entitlement to receive cash dividends or cash dividend equivalents until such stock-based Award is exercised (in the case of a stock option) or earned. If a stock-based Award is exercised or earned prior to or on the record date for determination of stockholders entitled to receive a cash dividend, then such stock-based Award or the securities resulting from the exercise thereof, as the case may be, shall be entitled to receive such cash dividend.
                     (ii) Restricted Stock Awards. Notwithstanding clause (i) of this paragraph (b) or §26 of the 1993 Plan or the 1997 Plan, dividends shall be payable with respect to each
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outstanding Award of Restricted Stock whether or not the restrictions in such Award have been satisfied or have lapsed.
                c. Payment. Payment of stock-based Awards (other than SARs and performance shares, which shall be paid in cash) shall be made with Common Stock.
           4. Withholding Taxes
               At the time a Participant is taxable with respect to Options, SARs or Restricted Stock granted under the Plans, or the exercise or surrender of the same, the Company shall have the right to withhold from amounts payable to the Participant under the Plan or from other compensation payable to the Participant in its sole discretion, or require the Participant to pay to it, an amount sufficient to satisfy all federal, state and/or local withholding tax requirements. A Participant may pay, in whole or in part, such tax withholding amounts by requesting that the Company withhold such amounts of taxes from the amounts owed to the Participant or by delivering as payment to the Company, shares of Common Stock having a Fair Market Value less than or equal to the amount of such required withholding taxes (with the remainder payable in cash).
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           5. Deferral of Payment
               The Committee intends to permit Participants to elect, at any time prior to one year before the date of exercise, to defer the receipt of payment of Awards that are payable in cash; provided, however, that (1) under the then applicable income tax rules the Participant is not in constructive receipt of, and subject to income tax on, the payment prior to its actual receipt, (2) such deferral does not result in any of the Plans being subject to the Employee Retirement Income Security Act of 1974, as amended, and (3) if the Participant is an Executive Officer ( i.e. , is subject to Section 16 of the Securities Exchange Act of 1934, including a retired officer who is, at the relevant time, a director), such election shall comply with Rule 16b-3 promulgated pursuant to the Securities Exchange Act of 1934, as then in effect.
      B.  STOCK OPTIONS UNDER THE 1997 AND 1993 PLANS
           1. Designation
               The Award Notice setting forth the terms and conditions of a grant of a stock option shall indicate the applicable Plan under which the stock option is granted and whether the stock option is an incentive stock option (within the meaning of Section 422 of the Code, an “ISO”) or a non-qualified stock option (“NSO”). The Committee hereby delegates to the President and Chief Executive Officer of the Company the authority to prepare, execute and deliver Award Notices consistent with actions taken by the Committee. The Committee hereby directs that any action taken by the Committee granting stock options without specifying whether the stock options are ISOs be interpreted as follows:
               a. an award of stock options to a Participant who is younger than 60 on the grant date shall be deemed to be an award of ISOs to the maximum extent permitted in accordance with Section 422 of the Internal Revenue Code, with the remainder awarded as NSOs; and
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               b. an award of stock options to a Participant who is 60 or older on the grant date shall be deemed to be awards of NSOs only.
           2. Price
               The price at which Common Stock may be purchased upon exercise of a stock option (the “exercise price”) shall be the Fair Market Value of the Common Stock on the date of the Award.
           3. Exercise Period/Duration
                a. Non-Qualified Stock Options Under the 1997 and 1993 Plans. A non-qualified stock option granted under the 1997 Plan or the 1993 Plan first may be exercised twelve months after the date of grant, or, if earlier, on the date of the optionee’s death.
                b. Incentive Stock Options Under the 1997 and 1993 Plans. An incentive stock option granted under the 1997 Plan or the 1993 Plan first may be exercised twelve months after the date of grant, or, if earlier, on the date of the optionee’s death.
           4. Death or Other Termination of Employment
                a. Definitions. For purposes of these rules, the following terms shall have the following meanings:
                    (i) “Disability” shall mean that the Participant is eligible to receive disability benefits under Article 3 of The National Fuel Gas Company Retirement Plan (“Retirement Plan”), as from time to time amended.
                    (ii) “Principal Subsidiary” shall mean a Subsidiary that has a net income of at least $5,000,000 as of the end of the most recent fiscal year.
                    (iii) “Retirement” shall mean that the Participant has commenced receiving retirement benefits under the Retirement Plan at or after attaining age 65.
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                    (iv) “Subsidiary” shall mean a corporation or other business entity in which the Company directly or indirectly has an ownership interest of eighty percent (80%) or more.
                b. Non-Qualified Stock Options Under the 1997 and 1993 Plans. With respect to the President and Chief Executive Officer of the Company and the Presidents of each Principal Subsidiary, if termination of employment occurs by reason of death, Disability or Retirement, each non-qualified option awarded under the 1997 Plan or the 1993 Plan shall remain exercisable for the balance of its unexpired term. If termination occurs by reason of discharge by the Company for cause or voluntary resignation of the Participant prior to age 60, each such non-qualified option shall lapse unless extended by the Committee in its discretion. If termination of any such officer occurs for any other reason, each such non-qualified option shall remain exercisable for five years from such termination (or in the case of non-qualified options awarded under the 1997 Plan, such greater period as the Committee deems appropriate) or the balance of its unexpired term, whichever is less.
               For all other Participants, if termination of employment occurs by reason of death, Disability or retirement at or after age 60, each non-qualified option awarded under the 1997 Plan or the 1993 Plan shall remain exercisable for five years from such termination or the balance of its unexpired term, whichever is less. If termination occurs for any other reason, each such non-qualified option shall lapse unless extended by the Committee in its discretion.
                c. Incentive Stock Options Under the 1997 and 1993 Plans. Pursuant to §16(a) of the 1997 Plan and the 1993 Plan, the Committee hereby establishes that, with respect to an incentive stock option granted under the 1997 Plan or the 1993 Plan which has not theretofore expired, upon termination of employment by reason of the optionee’s Disability, the optionee may within one year after the date of termination of employment, exercise all or part of the incentive stock option which the optionee was entitled to exercise on the date of termination of employment.
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                d. Extension of Incentive Stock Options Under the 1997 and 1993 Plans.
Pursuant to the last paragraph of §16(b) of the 1997 Plan and the 1993 Plan, the Committee hereby determines that:
     (i) With respect to the President and Chief Executive Officer of the Company and the Presidents of each Principal Subsidiary, if termination of employment occurs by reason of death, Disability or Retirement, another officer of the Company shall, within thirty days of such termination, offer in writing to extend the period during which any incentive stock option granted to such optionee under the 1997 Plan or the 1993 Plan may be exercised to the date on which the incentive stock option would have otherwise expired absent such termination of employment.
          If termination of any such officer’s employment occurs for any other reason, another officer of the Company, if the Committee so authorizes, shall, within thirty days of such termination, offer in writing to extend the period during which any incentive stock option granted to such optionee may be exercised to the date specified in the offer, which shall not be later than the date on which the incentive stock option would have otherwise expired absent such termination of employment;
     (ii) With respect to all Participants other than the President and Chief Executive Officer of the Company and the Presidents of each Principal Subsidiary, if termination of employment occurs by reason of death, Disability or Retirement, an officer of the Company other than such Participant shall, within thirty days of such termination, offer in writing to extend the period during which any incentive stock option granted to such optionee under the 1997 Plan or the 1993 Plan may be exercised,
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to the date which is the earlier of five years from such termination or the balance of the unexpired term of such incentive stock option.
          If termination of such Participant’s employment occurs for any other reason, an officer of the Company other than such Participant, if the Committee so authorizes, shall, within thirty days of such termination, offer to extend the period during which any incentive stock option granted to such optionee may be exercised to the date specified in the offer, which shall not be later than the earlier of five years from such termination of employment or the date on which the incentive stock option would have otherwise expired absent such termination of employment.
     The written offer shall notify the optionee, or the optionee’s estate or the person to whom the optionee’s rights under the incentive stock option are transferred by will or the laws of descent and distribution, of the right to accept the offer by consenting to the extension, in writing, within thirty days of the offer. If such consent is timely received the incentive stock option may be exercised during the period specified in the offer, but not later than the expiration of the exercise period specified in the Award Notice.

5.	 	Mechanics of Exercise	
               To exercise a stock option, the Participant shall provide a signed exercise notice to an appropriate officer or other designee of the Company, which notice shall indicate which options are being exercised, how the exercise price is to be paid and any other appropriate information. Appropriate delivery of a signed notice of exercise binds the Participant to pay the exercise price. Part IV of these Rules contains procedures for exercising stock options.

6.	 	Reload Options	
               No optionee shall be issued a new stock option automatically upon exercise of a stock option. However, if the Award Notice provides for the issuance of such new stock option, the
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new stock option shall have an option price equal to the Fair Market Value of the Common Stock on the date the new stock option is issued and shall otherwise be subject, as nearly as possible, to the same terms and conditions as the exercised stock option.

C.	 	SARs UNDER THE 1997 PLAN	
          All outstanding SARs granted under the 1997 Plan are Independent SARs as described in the Plan. The Plan has been amended to eliminate future awards of SARs.
               The base price of an Independent SAR shall be the Fair Market Value of the Common Stock on the date of the grant of the Independent SAR, and shall otherwise be subject to the terms and conditions imposed by the Award Notice upon the Independent SAR, by the 1997 Plan, and by these Rules upon non-qualified stock options. An Independent SAR shall be outstanding and exercisable during the entire exercise period otherwise applicable to a non-qualified stock option granted on the same day as the Independent SAR (as adjusted in accordance with paragraph III.B.4 above in the event of death or other termination of employment).
               To exercise a SAR, the Participant shall deliver a signed exercise notice to an appropriate officer or other designee of the Company, which notice shall indicate which SARs are being exercised, and any other appropriate information. The Committee hereby delegates to appropriate officers of the Company the authority to establish and revise appropriate procedures with respect to the exercise of SARs.

 	 	D . RESTRICTED STOCK UNDER THE 1997 AND 1993 PLANS	

1.	 	Restrictions on Transferability; Vesting	
               The restrictions on transferability and vesting and all other terms and conditions of Restricted Stock granted under the 1997 and 1993 Plans shall be specified in the Award Notice. All shares of Restricted Stock shall be subject to the Participant’s continued employment with the
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Company or a Subsidiary until vesting. The Committee may accelerate the vesting of Restricted Stock on its own motion as it deems appropriate and in the best interests of the Company.

2.	 	Mechanics of Grant	
               The Committee hereby delegates to appropriate officers of the Company the authority to establish and revise appropriate procedures with respect to the issuance of certificates representing Restricted Stock and the payment of dividends thereon.

E.	 	PERFORMANCE UNITS AND PERFORMANCE SHARES UNDER THE 1997 PLAN	
               The performance period and performance objectives of a performance unit or performance share granted under the 1997 Plan shall be specified in the Award Notice.
          The Committee shall consider any written submission from a Participant, regarding revision of the performance period and/or performance objectives of an Award on the basis of events which may have been unforeseen by the Committee, or circumstances which have changed since the Award, and may consider such matters on its own motion. Upon such consideration, the Committee shall revise such performance period and/or performance objectives when such revision is determined to be in the best interests of the Company and consistent with the purposes of the 1997 Plan or the 1993 Plan.
IV. PROCEDURES FOR EXERCISING STOCK OPTIONS

A.	 	AUTHORITY AND SCOPE	
          Notwithstanding any provision of any award letter issued before 1998, these are the exercise procedures for Incentive Stock Options (“ISOs”) and Non-Qualified Stock Options (“NSOs”) issued under the 1993 Plan, the 1997 Plan, and (unless the Compensation Committee specifically orders otherwise) any other compensation plan which in the future is adopted by the Company.

B.	 	NOTICE OF EXERCISE	

1.	 	Form and Delivery	
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               A Participant holding options granted under any of the Plans elects to exercise options by delivering (by personal delivery or fax) to the office of the Company’s Secretary or Assistant Secretary a Notice of Exercise. A Notice of Exercise is a writing signed by the Participant indicating that the Participant thereby elects to exercise options identified in the Notice (including the quantity and exercise price), and describing the method by which the Participant will pay the exercise price. Appropriate delivery of a Notice of Exercise binds the Participant to pay the exercise price. An optional form of Notice of Exercise is attached to these Rules (see Exhibit A).

2.	 	Exercise Date	
               The effective date of a Notice of Exercise is the “Exercise Date”. An exercise will be effective as of the date the Notice of Exercise is received by the office of the Secretary or Assistant Secretary; provided, however , that:
               (i) a Notice of Exercise received on a business day before trading opens that day on the New York Stock Exchange may validly designate the Exercise Date to be the preceding business day; and
               (ii) a Notice of Exercise may validly designate the Exercise Date to be any date later than the date the Notice of Exercise is received.
               (iii) if the exercise is accomplished through a “cashless exercise” as described in Section IV (C)(4) below, the Exercise Date shall be the date the broker sells Company stock into the market regarding that exercise.

C.	 	Payment of Exercise Price	

1.	 	Cash Payment	
               To pay the exercise price in cash, a Participant must deliver to the Secretary or Assistant Secretary payment in full, in cash or by check payable in immediately available U.S. funds to the Company, within three business days after the Exercise Date (except as additional time may be
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allowed under Section IV (C)(3) below). Payment of the exercise price may be partly in cash and partly in Company stock as described in Section IV (C)(2) below, or may be accomplished through a “cashless exercise” as described in Section IV (C)(4) below.

2.	 	Payment with Existing Company Stock	
               To pay the exercise price in shares of Company stock already owned by a Participant, the Participant must surrender to the Company shares having a total Market Value (as of the Exercise Date) of at least the total exercise price, or pay any shortfall in cash. The Participant must, within three business days after the Exercise Date (except as additional time may be allowed under Section IV (C)(3) below) do one or both of the following:
a. regarding shares in the Company’s Direct Registration System, comply with the Company’s procedures (including signature guarantee requirements) for transferring book-entry shares to the Company; or
b. regarding shares that are evidenced by a paper stock certificate, deliver the certificate to the Secretary or Assistant Secretary. Each certificate delivered must have a guaranteed signature either on the back or on a stock power to be attached. Recommended procedure for mailing certificates is to mail the certificate and signed stock power separately.

3.	 	Additional Time to Pay Exercise Price	
               If, at any time the Participant’s payment of the exercise price would otherwise be required pursuant to Section IV (C)(1) or (2) above, a Participant is either
               a. traveling away from his or her usual place of Company employment, or
               b. “disabled”, as defined in the applicable Plan or these Administrative Rules,
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               then the Participant may pay the exercise price on or before the first business day after the Participant’s return to his or her usual place of NFG employment, but no later than the tenth business day after the Exercise Date. However, the President, Chief Executive Officer, or Treasurer of the Company shall have the authority to grant such additional time to pay the exercise price as is reasonably necessary to accommodate the travel or disability of the Participant.

4.	 	Cashless Exercise	
          The broker-assisted method of exercising options described in this Section IV (C)(4) (“cashless exercise”) requires no cash outlay by the Participant. A Participant wishing to do a cashless exercise must first establish a trading account with a registered securities broker-dealer. Establishing that trading account will likely include the Participant’s commitment to pay the broker as described in their agreement. Upon request by a Participant, the Secretary or Assistant Secretary will provide information that may help the Participant find a broker who has previously done cashless exercises with the Company and/or may be willing to do so at a discounted commission rate. The Participant must provide the Secretary or Assistant Secretary with the Participant’s broker’s name, firm, address, telephone and fax numbers.
          To do a cashless exercise, the Participant must deliver a Notice of Exercise as described in Section IV (B)(1), and notify the Participant’s broker to proceed with the exercise. The Participant’s broker will sell Company stock for the Participant’s account and pay to the Company the exercise price, plus any necessary tax withholding. The Company will have share certificates delivered to the Participant’s broker within three business days after the Exercise Date, unless the Company elects to retain the certificates pending receipt of the exercise price. The Participant will be required to pay the Participant’s broker according to the agreement between them, typically a few days’ interest on the exercise price plus a commission on the shares sold.
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Exhibit 10.4
RETIREMENT AND CONSULTING AGREEMENT
     This Retirement and Consulting Agreement (“Agreement”) is entered into by and between Bernard J. Kennedy, an individual residing at 33 Ruskin Road, Amherst, New York, 14226, (hereinafter “Kennedy”) and National Fuel Gas Company (“National Fuel”), a New Jersey corporation, on September 5, 2001. For purposes of this Agreement, as appropriate, the term “National Fuel” refers, collectively, to National Fuel Gas Company and its subsidiaries and other affiliates.
RECITALS
     WHEREAS, Kennedy is employed by National Fuel pursuant to an employment agreement dated September 17, 1981, as amended, and currently extended to September 1, 2002 (the “Employment Agreement”), which affords him the minimum base salary hereinafter set forth, and (during as well as after the term thereof) participation in all National Fuel benefits, plans and programs (including improvements therein) on at least a par with other executive officers of National Fuel;
     WHEREAS, Kennedy has agreed to waive his rights to any automatic extension of the term of the Employment Agreement and to certain payments and benefits to which he otherwise would be entitled under the Employment Agreement during the usual automatic extension thereof and following termination of employment;
     WHEREAS, National Fuel wishes to secure for itself the availability of Kennedy so that it might benefit from Kennedy’s experience, knowledge, talents, reputation and prominence in the energy industry, and desires that Kennedy continue to advise National Fuel on issues relating to expansions, mergers, acquisitions, dispositions and other important matters;
     WHEREAS, Kennedy has agreed to cooperate with National Fuel in connection with National Fuel’s request on the timing of payments under the Executive Retirement Plan, and, in connection therewith, Kennedy has agreed to certain adjustments in Pension Benefit Guarantee Corporation rates, and to certain other assumptions and interest rates;
     WHEREAS, Kennedy’s employment at the request of National Fuel with National Fuel after age 65 has reduced the value of benefits he accrued through that date under National Fuel’s pension plans;
     WHEREAS, in lieu of seeking other opportunities, Kennedy has agree to remain available and to continue to provide services to National Fuel, to serve as a “bridge” in the event his successor should become incapacitated, and not to compete with National Fuel after the termination of his employment;

 

     WHEREAS, Kennedy recognizes that National Fuel’s business and goodwill are dependent upon National Fuel’s trade secrets and confidential and proprietary information and that National Fuel will sustain great loss and damage if Kennedy discloses, utilizes or causes to be disclosed or utilized National Fuel’s trade secrets and/or confidential and proprietary information to third parties or for Kennedy’s own benefit, and Kennedy has agreed that he will not disclose, utilize or cause to be disclosed or utilized any such trade secrets and/or confidential and proprietary information;
     WHEREAS, Kennedy is not otherwise entitled to the total sums being paid under this Agreement, except as provided herein;
     NOW, THEREFORE, in consideration of the mutual promises, terms, covenants and conditions described above and set forth below, the parties to this Agreement agree as follows:
     1.    Effective Date of Agreement . This Agreement shall become effective as of the date first above written.
     2.    Employment .

(a)	 	Kennedy shall, and Kennedy agrees to, relinquish his current position of chief executive officer of National Fuel effective October 1, 2001; provided, however, National Fuel requests that Kennedy commit to continue to serve on the Board of Directors of National Fuel (the “Board”) after October 1, 2001. Kennedy agrees to resign as a member of the Board following the first annual meeting of stockholders following his 72nd birthday consistent with the director tenure policy to be proposed by Kennedy to the Board at its scheduled September 13, 2001 meeting.	
 	
(b)	 	Kennedy shall remain an employee of National Fuel and Chairman of the Board through January 2, 2002 at which time Kennedy will terminate his employment with National Fuel and relinquish his position as Chairman of the Board.	
 	
(c)	 	Kennedy shall (i) receive his regular monthly base salary of $70,679.16, payable by National Fuel and its affiliated corporations in accordance with their customary practices through January 2, 2002; (ii) remain a participant in National Fuel’s Annual At Risk Compensation Incentive Program (the “AARCIP”) through September 30, 2001, and be paid, in a manner consistent with past practice, during calendar 2001 and as soon as practicable following the award thereof, a bonus for fiscal 2001 as shall be determined by the Board’s Compensation Committee; and (iii) for the months of October, November and December 2001 be paid (in lieu of all other bonuses otherwise available to him under the Employment Agreement or otherwise) a monthly bonus of $149,320.84.	
 	
(d)	 	Upon termination of Kennedy’s employment on January 2, 2002, Kennedy shall, in addition to the payments and benefits provided herein (including, but not by way of limitation, the benefits provided pursuant to section 4(c)), be	
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 	 	eligible for and entitled to (i) retiree medical benefit coverage, subject to the terms and conditions of the respective benefit plan(s) and/or program(s); (ii) life insurance benefits pursuant to, and as limited by, the Amended and Restated Split Dollar Insurance Agreement dated August 28, 1991, as last amended effective as of June 15, 2000 (“Life Insurance Agreement”); (iii) retirement benefits pursuant to the National Fuel Gas Company Retirement Plan; (iv) annuity payments pursuant to National Fuel Gas Company Deferred Compensation Plan (the “DCP”) Cycles I, II-A, III and III-A; (v) a Distribution of Savings Account pursuant to DCP Cycle V; (vi) “Tophat” benefits pursuant to the National Fuel Gas Company Top Hat Plan; and (vii) unexercised stock options and SARs granted under the National Fuel Gas Company 1997 Award and Option Plan and the predecessors thereof.	

(e)	 	Except insofar as is necessary to accommodate the express provision of Section 2(a), 2(b) and 2(c) of this Agreement, the Employment Agreement shall remain in full force and effect through January 2, 2002, at which time it shall terminate, provided however such termination shall not limit or impact Kennedy’s receipt of the benefits and entitlements identified in clauses (i) through (vii) of Section 2(d) of this Agreement which benefits for purposes of Section 4 of the Pension Settlement Agreement shall be deemed to be “payable to Kennedy pursuant to the terms of” this Agreement.	
     3.    Consulting Services .

(a)	 	From January 2, 2002 until June 30, 2004 (the “Consulting Period”), Kennedy shall, subject to the terms and conditions hereof, make himself available to render consultation services as requested by the Chief Executive Officer of National Fuel, for which he shall receive a non-refundable monthly retainer of $20,833.33 payable on or before January 2, 2002, and on the 1st day of each succeeding month during the Consulting Period. The retainer specified in this section 3(a) shall entitle National Fuel to Kennedy’s consultation services for up to 48 days during any 16 month period in the Consulting Period. In the event Kennedy performs consulting services for National Fuel for more than 48 days during any 16 month period in the Consulting Period or for more than 4 days during any calendar month during such period, National Fuel shall, upon receipt of an appropriate invoice, compensate Kennedy for such additional days at the rate of $3,500 per day. For purposes of this section 3(a), a “day” of consulting services shall mean any calendar day or part thereof during which Kennedy renders consulting services (including any days during which Kennedy is required to travel on consultation related business).	
 	
(b)	 	As needed during the Consulting Period at the request of the chief executive officer of National Fuel from time to time (and subject to the limitations provided in section 3(a) above), Kennedy shall advise and assist National Fuel concerning mergers and acquisitions, regulatory matters, marketing and customer relations, business strategy and such other matters as may arise that	
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 	 	the Chief Executive Officer of National Fuel determines, from time to time, require Kennedy’s experience and knowledge. In addition, Kennedy shall represent National Fuel with trade or business associations as selected by the chief executive officer of National Fuel from time to time. Service for or in connection with AEGIS, shall not be considered consultation service for National Fuel for purposes of this Agreement.	

(c)	 	During the Consulting Period, Kennedy shall be an independent contractor and, as such, shall control the detail, manner and means of providing consulting services pursuant to this Agreement. Accordingly, Kennedy shall not be required to work any particular schedule, but shall use his best efforts to meet National Fuel’s deadlines. Further, Kennedy shall not, within reason, be required to work at any particular location; however, during the Consulting Period, National Fuel shall provide reasonable and sufficient executive office space and executive secretarial assistance, telephone, fax service, computer, other customary office equipment and support, together with a garage space and related support when Kennedy’s presence is required at National Fuel offices. Subject to the approval of the chief executive officer of National Fuel or his or her designee, and upon receipt of proper documentation, National Fuel shall reimburse Kennedy for any reasonable expenses incurred in connection with the performance of consulting services under this Agreement. Kennedy shall be entitled to utilize first class commercial air travel, the company plane or jet service, or comparable facility.	

(d)	 	During the Consulting Period, National Fuel shall provide such other support and facilities as the chief executive officer of National Fuel shall decide facilitates Kennedy’s business and industry related exposure and contacts that Kennedy has cultivated, and will cultivate, for National Fuel.	

(e)	 	In view of the success the Company has enjoyed under his leadership and the record performance it has achieved in recent years, Kennedy shall, if requested by the Board during the three years following his retirement, serve on any committee of the Board established to review any transaction which, if consummated, would constitute a “Change in Control” under the National Fuel Gas Company 1997 Award and Option Plan. Such service shall not reduce, or be considered a part of, the consultation obligation of Section 3(a) or entitle Kennedy to any compensation pursuant to Section 3(a). Upon the occurrence of any such “Change in Control” transaction prior to January 1, 2005 (or thereafter, if the transaction was publicly announced prior to January 1, 2005), in recognition of the success of Kennedy’s efforts in bringing the Company to its current position and taking into account the additional value shareholders receive through consummation of such “Change in Control” transaction, the Compensation Committee shall consider and recommend to the Board, and the Board shall make, an award of National Fuel common	
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 	 	stock to Kennedy in such amount(s), as the Compensation Committee and the Board, respectively, shall equitably determine in the exercise of their discretion.	

4.	 	Retirement . In addition to the compensation and benefits provided pursuant to sections 2 and 3 of this Agreement and the compensation and benefits to which Kennedy is entitled under the terms of National Fuel’s compensation and benefit plans and policies for directors, Kennedy shall be entitled to the following compensation and benefits, except as otherwise provided in Section 4(d), upon termination of his employment by National Fuel:	

(a)	 	Kennedy shall receive such support and benefits provided to a retired chief executive officer and chairman of the Board, commensurate with National Fuel’s past practice; as outlined to Kennedy in a letter of even date herewith from the Chairman of the Board’s Compensation Committee (the “Letter”) and any other support or benefits as may be approved by National Fuel’s chief executive officer;	

(b)	 	All of Kennedy’s stock options and SARs, whether granted before or after the effective date of this Agreement, shall remain exercisable for their remaining terms (disregarding, for purposes of determining the terms of such options and SARs, the termination of Kennedy’s employment);	

(c)	 	To the extent not provided under the Company’s retiree welfare benefits plans and programs (pursuant to Section 2(d) herein), for the rest of Kennedy’s life, he and, as applicable, his spouse and his daughter Maureen shall be entitled to all medical, health care and dental benefits under National Fuel’s medical, health care and dental plans and/or programs as if Kennedy were still employed, at the same level of benefits and at the same net dollar cost to Kennedy as is available to all of National Fuel’s senior executives generally or, if greater, at the same level of benefits and at the same dollar cost to Kennedy as Kennedy was receiving or was eligible to receive prior to his retirement on January 2, 2002; provided, however, that if National Fuel cannot provide such benefits under its existing plan(s) and/or program(s) because of limitations under applicable law, National Fuel shall provide equivalent benefits on an individual basis; provided, further, that following Kennedy’s death, Kennedy’s spouse and his daughter Maureen shall (at their expense, to the extent not paid for by National Fuel pursuant to National Fuel’s retiree welfare benefit plan(s) or program(s) pursuant to Section 2(d) of this Agreement) remain eligible to participate for their lives in the medical and dental benefit plan(s) and/or program(s) that Kennedy and/or his spouse and his daughter Maureen were participating in prior to Kennedy’s death; and	

(d)	 	As consideration for past services, Kennedy’s agreement to waive the compensation and other benefits he would otherwise be entitled to receive	
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 	 	under his Employment Agreement through the remaining term thereof and Kennedy’s agreement to be bound by the non-competition covenants contained in section 8 hereof, the following:	

(i)	 	An award effective October 1, 2001 of (or awards aggregating) 50,000 shares of stock (such number being adjusted to reflect a stock split, stock dividend or consolidation after the date of this Agreement, but prior to October 1, 2001).	
 	
(ii)	 	The payments set forth in the Pension Settlement Agreement by and between National Fuel and Kennedy to be executed contemporaneously with this Agreement (the “Pension Settlement Agreement”).	

5.	 	Death or Disability . In the event of Kennedy’s death or total disability prior to termination during the term of employment described in Section 2(b), National Fuel’s obligation to pay base salary and any unearned bonuses as described in section 2(c) shall end with its prorated payment thereof for the pay period during which such death or disability occurs. In the event of Kennedy’s death or total disability during the Consulting Period, National Fuel’s obligation to pay the monthly retainer described in section 3(a) shall end with its payment thereof for the month during which such death or disability occurs.	
 	
6.	 	Non-Disclosure Agreement .	

(a)	 	As part of the consideration for the compensation provided in this Agreement and for the other covenants made by National Fuel in this Agreement, Kennedy shall hold in a fiduciary capacity, for the benefit of National Fuel, all of National Fuel’s trade secrets and confidential and proprietary information. Kennedy shall not, without the prior written consent of National Fuel, at any time following the termination of Kennedy’s employment with National Fuel, utilize, communicate or divulge to anyone other than National Fuel or those designated by it any of National Fuel’s trade secrets or confidential and proprietary information. Kennedy shall provide National Fuel with prompt notice of any subsequent employment, including, but not limited to, the name and address of any subsequent employer and the title and duties of Kennedy’s position therewith so that National Fuel can take whatever steps it deems appropriate in order to protect its interests under this Agreement. Kennedy understands that, under appropriate circumstances, National Fuel can sue Kennedy and/or any of Kennedy’s future employers for tortious interference with National Fuel’s contracts, interference with National Fuel’s prospective business relations, and/or misappropriation of National Fuel’s trade secrets or confidential and proprietary information. Except with respect to the monthly retainer described in section 3(a), in no event shall an asserted violation of the provisions of this section 6 constitute	
6

 

 	 	a basis for deferring or withholding any amounts otherwise payable or provided to Kennedy under this Agreement or the Pension Settlement Agreement.	

(b)	 	The prohibition against Kennedy’s use of National Fuel’s trade secrets and confidential and proprietary information, other than for the benefit of National Fuel, includes, but is not limited to, (i) the exploitation of any products or services that embody or are derived from National Fuel’s trade secrets or confidential and proprietary information, and (ii) the exercise of judgment or the performance of analysis based upon knowledge of National Fuel’s trade secrets and confidential and proprietary information. Kennedy represents, warrants and agrees that he has no proprietary or ownership rights or title to any of National Fuel’s trade secrets or confidential and proprietary information and no legal right to use, disclose, disseminate, or publish any of National Fuel’s trade secrets or confidential and proprietary information in any locality.	

7.	 	Definition of Confidential Material . National Fuel’s “trade secrets” and “confidential and proprietary information” include, but are not limited to, any and all memoranda, software, data bases, computer programs, interface systems, pricing and client information, and records pertaining to National Fuel’s methods or practices of doing business and marketing its services and products, whether or not developed or prepared by Kennedy during the term of his employment with National Fuel or in connection with his providing consulting service to National Fuel. National Fuel’s trade secrets and confidential and proprietary information also include “writing” or “writings,” which shall mean and include all works, expressed in words, numbers or other verbal or numerical symbols, regardless of the physical manner in which they are embodied, including, but not limited to, books, articles, manuscripts, memoranda, computer programs, computer software systems, maps, charts, diagrams, technical drawings, manuals, video and audio tape recordings, and photographs, whether or not developed or prepared by Kennedy during the term of his employment with National Fuel or in connection with his providing consulting services to National Fuel. National Fuel’s trade secrets and confidential and proprietary information shall include any information or material not generally known to the public (other than by act of Kennedy or his representatives in breach of this Agreement) which gives the holder thereof an opportunity to obtain an advantage over competitors without knowledge of such information, as well as any information received from third parties under confidential conditions and information subject to National Fuel’s attorney-client or work-product privilege, the use or disclosure of which might reasonably be construed to be contrary to National Fuel’s interests.	
 	
8.	 	Non-Compete Covenants .	

(a)	 	In order to protect and safeguard National Fuel’s trade secrets and confidential and proprietary information, and also National Fuel’s goodwill	
7

 

 	 	with its customers, during the period beginning on the date of this Agreement and ending January 2, 2005, Kennedy will not, within any state in which National Fuel does business at any time during such period, directly or indirectly and without the prior written consent of National Fuel engage in or be interested in (as owner, partner, shareholder, employee, director, agent, consultant or otherwise), any business that is a competitor of National Fuel, as hereafter defined, or any business that is such a customer. For purposes of this Agreement, a “competitor” of National Fuel is any entity including, without limitation, a 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, during such period or the immediately preceding fiscal year of such entity, was engaged in (i) the exploration for or production, transportation, purchase, brokering, marketing, distribution or trading of natural gas or other energy products or services or (ii) the timber business.	

(b)	 	Anything contained herein to the contrary notwithstanding, nothing in section 8(a) shall be interpreted to prohibit (i) Kennedy’s present or future investments in the securities of competing companies listed on a national securities exchange or traded on the over-the-counter market to the extent such investments do not exceed 5% of the total outstanding shares of such company, (ii) Kennedy’s employment with a competitor of National Fuel provided such employment is limited to areas unrelated to the exploration for or production, transportation, purchase, brokering, marketing, distribution or trading of natural gas or other energy products or services or the timber business, (iii) continuation of business and professional relationships with the entities identified on Exhibit A to the Employment Agreement, or (iv) Kennedy’s engagement in or interest in any business after obtaining the prior written consent of National Fuel.	
 	
(c)	 	For the period beginning on the date hereof and ending on January 2, 2004 (the second anniversary of Kennedy’s retirement on January 2, 2002), Kennedy shall not induce or otherwise entice any employee of National Fuel to leave National Fuel, nor shall Kennedy attempt to hire any of National Fuel’s employees.	
 	
(d)	 	The foregoing restrictions contain reasonable limitations as to the time, geographic area, and scope of activity to be restrained and these restrictions do not impose any greater restraint than is necessary to protect the goodwill and other legitimate business interests of National Fuel. If and to the extent a court of competent jurisdiction finds one or more restriction contained in this section 8 to be unreasonable in terms of geographic scope, time limitation, or otherwise, the restriction(s) found to be unreasonable shall be deemed modified to the extent necessary so that the provisions of this section 8 are enforceable to the greatest extent possible.	
8

 

9.	 	Obligations, Enforcement . Except as otherwise provided in section 6 of this Agreement, National Fuel’s obligation to make the payments provided for in this Agreement or the Pension Settlement Agreement shall not be affected by any set-off, counter-claim, recoupment, defense or other claim, right or action National Fuel may have against Kennedy or others. In no event shall Kennedy be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to him under any of the provisions of this Agreement. National Fuel shall pay, or on an ongoing basis promptly reimburse Kennedy, for all legal fees and expenses reasonably incurred by Kennedy in connection with Kennedy’s enforcement of his rights under this Agreement.	
 	
10.	 	Binding Consideration . Kennedy understands, represents, warrants and agrees that National Fuel has no contractual obligation or legal duty to pay Kennedy severance compensation or wages in lieu of notice of termination.	
 	
11.	 	Binding Agreement . This Agreement is and shall be binding upon and inure to the benefit of the parties hereto and their respective successors (including any and all successors of National Fuel or to all or substantially all of its assets, whether by way of merger, acquisition, consolidation, share exchange or other business combination), heirs, executors, administrators and assigns. Kennedy represents, warrants and agrees that he has read, understands and intends to be bound by this Agreement and its recitals, terms, conditions and representations.	
 	
12.	 	Miscellaneous .	

(a)	 	This Agreement, the Pension Settlement Agreement and the Letter (the “Documents”) contain and state the entire agreement of the parties hereto with respect to the subject matters of the Documents and, except as otherwise expressly provided in the Documents, supersede and cancel all prior written and oral agreements and understandings with respect to the subject matter of the Documents; provided, however, that notwithstanding the foregoing, this Agreement shall have no effect upon (i) the Employment Agreement, prior to its termination on January 2, 2002 except as insofar as is necessary to accommodate the express provision of Sections 2(a), 2(b) and 2(c) of this Agreement, and (ii) Kennedy’s rights under the Life Insurance Agreement. Except for awards or payouts to be made prior to Kennedy’s termination of employment as provided herein, no payments shall be made after January 31, 2002, hereunder unless and until the release required in Section 8 of the Pension Settlement Agreement is received by National Fuel and may not be revoked by Kennedy.	

(b)	 	The term “affiliate” as used in this Agreement with respect to a party, means any individual or entity that owns or controls, is owned or controlled by, or is under common ownership or control with, such party.	
9

 

(c)	 	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 Kennedy:
Bernard J. Kennedy
33 Ruskin Road
Amherst, New York 14226	
 	
 	 	If to National Fuel:
National Fuel Gas Company
10 Lafayette Square
Buffalo, New York 14203
Attention: Corporate Secretary	
 	
 	 	or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notices and communications shall be effective when actually received by the addressee	
 	
(d)	 	This Agreement shall be governed by the laws of the State of New York and may be amended or modified only by written agreement signed by both parties.	
 	
(e)	 	Notwithstanding any other provision of this Agreement, National Fuel may withhold from amounts payable under this Agreement all federal, state, local and foreign taxes that are required to be withheld by applicable laws or regulations; provided, however, without prior approval of Kennedy, shall not withhold more than the minimum amount National Fuel reasonably determines is required to be withheld under such laws or regulations.	
 	
(f)	 	The obligations of Kennedy hereunder are personal and cannot be assigned.	
 	
(g)	 	If any term or other provision of this Agreement shall be declared to be invalid, illegal, or incapable of being enforced by any rule of law or public policy, all other terms, provisions and conditions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner materially adverse to any party to this Agreement. Upon any binding determination that any term or other provision of this Agreement is invalid, illegal or incapable of being enforced, the parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties to this Agreement as closely as possible in an acceptable and legally enforceable manner, to the end that the transactions contemplated hereby may be effected to the full extent possible.	
10

 

(h)	 	The headings in this Agreement are not part of the provisions hereof and shall have no force or effect.	
 	
(i)	 	Except as otherwise provided herein, this Agreement shall terminate upon satisfaction of each party’s obligations hereunder.	
     IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first above written.

BERNARD J. KENNEDY	 	NATIONAL FUEL GAS COMPANY	
 	 	 	 	 	
/s/ Bernard J. Kennedy
	 	By:	 	/s/ G. L. Mazanec

 	 	
 	
	 	Its:	 	Chairman of the Compensation Committee of the Board of Directors	
11

 

The following page is the letter referenced in Section 4(a) of the
Retirement and Consulting Agreement, dated September 5, 2001,
between National Fuel Gas Company and Bernard J. Kennedy

 

GEORGE L. MAZANEC
302 Fall River Court
Houston, TX 77024
713-627-4623
Bernard J. Kennedy
National Fuel Gas Company
10 LaFayette Square
Buffalo, NY 14203
Dear Bernie:
     In connection with your proposed retirement, you have asked for National Fuel Gas Company’s (“National Fuel”) current policy and past practice regarding provision of support and benefits to a retired CEO and Chairman of the Board.
     For a period of five years beginning on the date of your termination of employment with National Fuel, and such additional period as determined in the sole discretion of National Fuel’s CEO, that support and benefits include the following:

1.	 	Exclusive use of an executive office in National Fuel’s headquarters office building, or such other location as the parties may mutually agree upon, including an executive secretary, telephone, fax service, computer, and other customary office equipment and support, together with a garage space and related support.	
 	
2.	 	Continued provision of tax consultation, planning and preparation assistance, paid for by National Fuel under the same terms and conditions as received prior to retirement.	
 	
3.	 	Reimbursement for relocation-related expenses and other relocation benefits pursuant to National Fuel’s relocation policy for executive officers.	
     In addition, since it is proposed that you will provide consulting services following retirement, National Fuel will continue to provide during the consulting period payment for business club dues and related expenses at certain clubs to which the executive was a member prior to retirement and with respect to which the executive’s continued membership in, and attendance at functions of, such clubs would be a continuing benefit to National Fuel.

	 	Very truly yours,	
 	 	 	
	 	/s/ George L. Mazanec	
	 	George L. Mazanec	
	 	Chairman of the Compensation Committee
of the Board of Directors of National Fuel Gas Company	
	 	Dated: September 5, 2001	
13

EXHIBIT 12

 	 	 	 	 	 	COMPUTATION OF RATIO OF	
 	 	 	 	 	 	EARNINGS TO FIXED CHARGES	
 	 	 	 	 	 	UNAUDITED	
 	 	 	 	 	 	Fiscal Year Ended September 30
	
 	 	For the Twelve	 	 	 	 	 	 	 	 	 	 	
 	 	Months Ended	 	 	 	 	 	 	 	 	 	 	
 	 	September 30, 2004
	 	2003
	 	2002
	 	2001
	 	2000
	 	1999
	
EARNINGS:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Cumulative Effect of Changes in Accounting	 	$	166,586	 	 	$	187,836	 	 	$	117,682	 	 	$	65,499	 	 	$	127,207	 	 	$	115,037	 	
Plus Minority Interest in Foreign Subsidiaries	 	 	1,933	 	 	 	785	 	 	 	730	 	 	 	1,342	 	 	 	1,384	 	 	 	1,616	 	
Plus Income Tax Expense	 	 	92,737	 	 	 	128,161	 	 	 	72,034	 	 	 	37,106	 	 	 	77,068	 	 	 	64,829	 	
Less Investment Tax Credit (1)	 	 	(697	)	 	 	(693	)	 	 	(702	)	 	 	(353	)	 	 	(1,051	)	 	 	(729	)	
(Less Income) Plus Loss from Unconsolidated Subsidiaries (3)	 	 	(805	)	 	 	(535	)	 	 	14,943	 	 	 	(1,794	)	 	 	(1,669	)	 	 	(999	)	
Plus Distributions from Unconsolidated Subsidiaries	 	 	785	 	 	 	1,238	 	 	 	585	 	 	 	595	 	 	 	229	 	 	 	—	 	
Plus Interest Expense on Long-Term Debt	 	 	83,826	 	 	 	92,766	 	 	 	90,543	 	 	 	81,851	 	 	 	67,195	 	 	 	65,402	 	
Plus Other Interest Expense	 	 	6,763	 	 	 	12,290	 	 	 	15,109	 	 	 	25,294	 	 	 	32,890	 	 	 	22,296	 	
Less Amortization of Loss on Reacquired Debt	 	 	(1,350	)	 	 	(2,078	)	 	 	(1,927	)	 	 	(1,927	)	 	 	(1,979	)	 	 	(1,839	)	
Plus (Less) Allowance for Borrowed Funds Used in Construction	 	 	298	 	 	 	(102	)	 	 	446	 	 	 	438	 	 	 	424	 	 	 	303	 	
Plus Rentals (2)	 	 	4,286	 	 	 	4,573	 	 	 	4,906	 	 	 	4,893	 	 	 	4,561	 	 	 	4,281	 	

 	 	 	 	

 	 	 	 	
 	 	
 	 	$	354,362	 	 	$	424,241	 	 	$	314,349	 	 	$	212,944	 	 	$	306,259	 	 	$	270,197	 	

 	 	 	 	

 	 	 	 	
 	 	
FIXED CHARGES:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest & Amortization of Premium and Discount of Funded Debt	 	$	83,826	 	 	$	92,766	 	 	$	90,543	 	 	$	81,851	 	 	$	67,195	 	 	$	65,402	 	
Plus Other Interest Expense	 	 	6,763	 	 	 	12,290	 	 	 	15,109	 	 	 	25,294	 	 	 	32,890	 	 	 	22,296	 	
Less Amortization of Loss on Reacquired Debt	 	 	(1,350	)	 	 	(2,078	)	 	 	(1,927	)	 	 	(1,927	)	 	 	(1,979	)	 	 	(1,839	)	
Plus (Less) Allowance for Borrowed Funds Used in Construction	 	 	298	 	 	 	(102	)	 	 	446	 	 	 	438	 	 	 	424	 	 	 	303	 	
Plus Rentals (2)	 	 	4,286	 	 	 	4,573	 	 	 	4,906	 	 	 	4,893	 	 	 	4,561	 	 	 	4,281	 	

 	 	 	 	

 	 	 	 	
 	 	
 	 	$	93,823	 	 	$	107,449	 	 	$	109,077	 	 	$	110,549	 	 	$	103,091	 	 	$	90,443	 	

 	 	 	 	

 	 	 	 	
 	 	
RATIO OF EARNINGS TO FIXED CHARGES	 	 	3.78	 	 	 	3.95	 	 	 	2.88	 	 	 	1.93	 	 	 	2.97	 	 	 	2.99	 	

(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 2002 includes the Impairment of Investment in Partnership of $15,167.	

 

Exhibit 23.1 
CONSENT OF ENGINEER
     We hereby consent to the reproduction of our audit report for Seneca Resources Corporation dated October 15, 2004, and to the reference to our estimate dated September 30, 2004, appearing in this National Fuel Gas Company Annual Report on Form 10-K.
     We also consent to the incorporation by reference in (i) the Registration Statement (Form S-8, No. 2-94539), as amended, relating to the National Fuel Gas Company 1983 Incentive Stock Option Plan and the National Fuel Gas Company 1984 Stock Plan, and in the related Prospectuses, (ii) the Registration Statements (Form S-8, Nos. 33-28037, 333-3055 and 333-102220, and Nos. 2-97641, 33-17341, 333-03057 and 333-102211), as amended, relating to the National Fuel Gas Company Tax-Deferred Savings Plan and the National Fuel Gas Company Tax-Deferred Savings Plan for Non-Union Employees, respectively, and in the related Prospectuses, (iii) the Registration Statement (Form S-3, No. 333-03803), as amended, relating to $500,000,000 of National Fuel Gas Company debentures and/or medium term notes and, in the related Prospectus, (iv) the Registration Statements (Form S-3, No. 33-51881 and Form S-3D, No. 333-51769), as amended, relating to the National Fuel Gas Company Dividend Reinvestment and Stock Purchase Plan, and in the related Prospectuses, (v) the Registration Statement (Form S-3, No. 33-36868), as amended, relating to the National Fuel Gas Company Customer Stock Purchase Plan, and in the related Prospectus, (vi) the Registration Statements (Form S-8, Nos. 33-49693 and 333-117132), as amended, relating to the National Fuel Gas Company 1993 Award and Option Plan, and in the related Prospectus, (vii) the Registration Statements (Form S-8, Nos. 333-51595, 333-55124 and 333-117131), relating to the National Fuel Gas Company 1997 Award and Option Plan, and in the related Prospectus, (viii) the Registration Statement (Form S-3, No. 333-83497), as amended, relating to $625,000,000 of National Fuel Gas Company debentures and/or common stock, and in the related Prospectus, (ix) the Registration Statement (Form S-3, No. 333-102200), as amended, relating to $800,000,000 of National Fuel Gas Company debt securities, common stock, stock purchase contracts and stock purchase units, and in the related Prospectus, and (x) the Registration Statement (Form S-3, No. 333-85711), as amended, relating to the National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan, and in the related Prospectus, of the reproduction of our report dated October 15, 2004, appearing in this National Fuel Gas Company Annual Report on Form 10-K.

 	RALPH E. DAVIS ASSOCIATES, INC.
 	 	
 	/s/ Allen C. Barron, P.E.  	 	
 	Allen C. Barron, P.E. 	 	
 	President 	 	
 	
Houston, Texas
October 22, 2004

 

Exhibit 23.2 
CONSENT OF ENGINEER
     We hereby consent to the reproduction of our audit report for Seneca Energy Canada, Inc. dated October 15, 2004, and to the reference to our estimate dated September 30, 2004, appearing in this National Fuel Gas Company Annual Report on Form 10-K.
     We also consent to the incorporation by reference in (i) the Registration Statement (Form S-8, No. 2-94539), as amended, relating to the National Fuel Gas Company 1983 Incentive Stock Option Plan and the National Fuel Gas Company 1984 Stock Plan, and in the related Prospectuses, (ii) the Registration Statements (Form S-8, Nos. 33-28037, 333-3055 and 333-102220, and Nos. 2-97641, 33-17341, 333-03057 and 333-102211), as amended, relating to the National Fuel Gas Company Tax-Deferred Savings Plan and the National Fuel Gas Company Tax-Deferred Savings Plan for Non-Union Employees, respectively, and in the related Prospectuses, (iii) the Registration Statement (Form S-3, No. 333-03803), as amended, relating to $500,000,000 of National Fuel Gas Company debentures and/or medium term notes and, in the related Prospectus, (iv) the Registration Statements (Form S-3, No. 33-51881 and Form S-3D, No. 333-51769), as amended, relating to the National Fuel Gas Company Dividend Reinvestment and Stock Purchase Plan, and in the related Prospectuses, (v) the Registration Statement (Form S-3, No. 33-36868), as amended, relating to the National Fuel Gas Company Customer Stock Purchase Plan, and in the related Prospectus, (vi) the Registration Statements (Form S-8, Nos. 33-49693 and 333-117132), as amended, relating to the National Fuel Gas Company 1993 Award and Option Plan, and in the related Prospectus, (vii) the Registration Statements (Form S-8, Nos. 333-51595, 333-55124 and 333-117131), relating to the National Fuel Gas Company 1997 Award and Option Plan, and in the related Prospectus, (viii) the Registration Statement (Form S-3, No. 333-83497), as amended, relating to $625,000,000 of National Fuel Gas Company debentures and/or common stock, and in the related Prospectus, (ix) the Registration Statement (Form S-3, No. 333-102200), as amended, relating to $800,000,000 of National Fuel Gas Company debt securities, common stock, stock purchase contracts and stock purchase units, and in the related Prospectus, and (x) the Registration Statement (Form S-3, No. 333-85711), as amended, relating to the National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan, and in the related Prospectus, of the reproduction of our report dated October 15, 2004, appearing in this National Fuel Gas Company Annual Report on Form 10-K.

 	RALPH E. DAVIS ASSOCIATES, INC.
 	 	
 	/s/ Allen C. Barron, P.E.  	 	
 	Allen C. Barron, P.E. 	 	
 	President 	 	
 	
Houston, Texas
October 22, 2004

 

Exhibit 23.3 
CONSENT OF INDEPENDENT PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Forms S-3 (Nos. 333-85711, and 333-102200) and Forms S-8 (Nos. 2-94539, 33-49693, 333-03055, 333-51595, 333-55124, 333-102211, 333-102220, 333-117131 and 333-117132) of National Fuel Gas Company of our report dated December 9, 2004 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Buffalo, New York
December 14, 2004

 

Exhibit 31.1 
CERTIFICATION
     I, P. C. Ackerman, certify that:
     1. I have reviewed this annual report on Form 10-K of National Fuel Gas Company;
     2. Based on my knowledge, this annual 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 annual report;
     3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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)) 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 annual report is being prepared;
     (b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this annual report based on such evaluation; and
     (c) Disclosed in this annual 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: December 9, 2004
/s/ P. C. Ackerman

P. C. Ackerman
Chairman of the Board, 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 annual 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 annual report;
     3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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)) 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 annual report is being prepared;
     (b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this annual report based on such evaluation; and
     (c) Disclosed in this annual 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: December 9, 2004
/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, P. C. ACKERMAN, the Chairman of the Board, 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, 2004 (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 9th day of December, 2004.

 	 	 	
 	/s/ P. C. Ackerman  	 	
 	Chairman of the Board, President and 	 	
 	Chief Executive Officer 	 	

 	 	 	
 	/s/ R. J. Tanski  	 	
 	Treasurer and Principal Financial Officer 	 	

  

Exhibit 99.1

October 15, 2004
Seneca Resources Corporation
1201 Louisiana, Suite 400
Houston, Texas 77002

		
Attention: 	Mr. James A. Beck
President	

			
 	                    Re: 	Oil, Condensate and Natural Gas Reserves,
Seneca Resources Corporation
As of September 30, 2004	
Gentlemen:
At your request, the firm of Ralph E. Davis Associates, Inc. has audited an evaluation of the proved oil, condensate and natural gas reserves on leaseholds in which Seneca Resources Corporation has certain interests. This report presents a summary of the Proved Developed (producing and non-producing) and Proved Undeveloped reserves anticipated to be produced from Seneca Resources’ interest.
The reserves associated with these estimates have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Rule 4-10(a) of regulation S-X of the Securities Exchange Act of 1934. We have also estimated the future net revenue and discounted present value associated with these reserves as of September 30, 2004, utilizing a scenario of non escalated product prices as well as non escalated costs of operations, i.e., prices and costs were not escalated above
Consultants to the Petroleum and Natural Gas Industries Since the 1920’s

 

RALPH E. DAVIS ASSOCIATES, INC.

Seneca Resources Corporation
Oil, Condensate and Natural Gas Reserves
Mr. James A. Beck	 	October 15, 2004
Page 2	
current values as detailed later in this report. The present value is presented for your information and should not be construed as an estimate of the fair market value.
The summarized results of the reserve audit are as follows: 
Estimated Proved Reserves
Net to Seneca Resources Corporation
As of September 30, 2004

 	 	Proved Developed
	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Proved	 	 	
Division:
	 	Producing
	 	Non Producing
	 	Undeveloped
	 	Total Proved
	
EAST COAST:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil/Condensate: MBbls	 	 	147.4	 	 	 	0.0	 	 	 	0.0	 	 	 	147.4	 	
Gas: MMcf	 	 	78,741.2	 	 	 	19.2	 	 	 	0.0	 	 	 	78,760.4	 	
GULF COAST:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil/Condensate: MBbls	 	 	1,813.4	 	 	 	247.9	 	 	 	19.1	 	 	 	2,080.4	 	
Gas: MMcf	 	 	11,817.1	 	 	 	14,009.3	 	 	 	1,907.7	 	 	 	27,734.1	 	
WEST COAST:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil/Condensate: MBbls	 	 	38,475.4	 	 	 	155.8	 	 	 	22,250.4	 	 	 	60,881.6	 	
Gas: MMcf	 	 	52,633.2	 	 	 	402.1	 	 	 	14,408.1	 	 	 	67,443.4	 	
TOTAL COMPANY:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil/Condensate: MBbls	 	 	40,436.2	 	 	 	403.7	 	 	 	22,269.5	 	 	 	63,109.4	 	
Gas: MMcf	 	 	143,191.5	 	 	 	14,430.6	 	 	 	16,315.8	 	 	 	173,937.9	 	
Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil. Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the official temperature and pressure bases of the areas wherein the gas reserves are located.

 

RALPH E. DAVIS ASSOCIATES, INC.
Seneca Resources Corporation
Oil, Condensate and Natural Gas Reserves
Mr. James A. Beck
October 15, 2004
Page 3
DISCUSSION:
The scope of this study was to audit the proved reserves attributable to the interests of Seneca Resources Corporation. Reserve estimates were prepared by Seneca using acceptable evaluation principals for each source. The quantities presented herein are estimated reserves of oil, condensate and natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under existing economic conditions with reasonable certainty.
Ralph E. Davis Associates, Inc. has audited the reserve estimates, the data incorporated into preparing the estimates and the methodology used to evaluate the reserves. In each of Seneca’s producing divisions all current year additions and those properties of significant value were reviewed by Ralph E. Davis. Reserve estimates of current producing zones, productive zones behind pipe and undrilled well locations were reviewed in detail. Certain changes to either individual reserve estimates or the categorization of reserves were suggested by Ralph E. Davis Associates, Inc. and accepted by Seneca Resources. It is our opinion that the reserves presented herein meet all the criteria of Proved Reserves.
Neither Ralph E. Davis Associates, Inc. nor any of its employees have any significant interest in Seneca Resources Corporation or the properties reported herein. The employment and compensation to make this study are not contingent on our estimate of reserves.
We appreciate the opportunity to be of service to you in this matter and will be glad to address any questions or inquiries you may have.
Very truly yours,
RALPH E. DAVIS ASSOCIATES, INC.

Allen C. Barron, P. E.
President

 

RALPH E. DAVIS ASSOCIATES, INC.
CLASSIFICATION OF RESERVES
Proved Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

 	1.	 	           Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.	
 	
 	2.	 	           Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.	
 	
 	3.	 	           Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.	
Proved Developed Oil and Gas Reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved Undeveloped Reserves
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
(Classification of reserves as found in Rule 4-10(a) of Regulation S-X of the per Securities and Exchange Act)

 

Exhibit 99.2

October 15, 2004
Seneca Energy Canada, Inc.
550 6 th Avenue SW
Suite 1000
Calgary, Alberta T2P O2S

		
Attention:       	Mr. Darrell Ibach
President	

		
Re:       	Oil, Condensate and Natural Gas Reserves,
Seneca Energy Canada, Inc.
As of September 30, 2004	
Gentlemen:
At your request, the firm of Ralph E. Davis Associates, Inc. has audited an evaluation of the proved oil, condensate and natural gas reserves on leaseholds in which Seneca Energy Canada, Inc. has certain interests. This report presents a summary of the Proved Developed (producing and non-producing) and Proved Undeveloped reserves anticipated to be produced from Seneca Energy Canada’s interest.
The reserves associated with these estimates have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Rule 4-10(a) of regulation S-X of the Securities Exchange Act of 1934. We have also estimated the future net revenue and discounted present value associated with these reserves as of September 30, 2004, utilizing a scenario of non escalated product prices as well as non escalated costs of operations, i.e., prices and costs were not
Consultants to the Petroleum and Natural Gas Industries Since the 1920’s

 

RALPH E. DAVIS ASSOCIATES, INC.

Seneca Energy Canada, Inc.	 	
Oil, Condensate and Natural Gas Reserves	October 15, 2004	
Mr. Darrell Ibach	Page 2	
escalated above current values as detailed later in this report. The present value is presented for your information and should not be construed as an estimate of the fair market value.
Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil. Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the official temperature and pressure bases of the areas wherein the gas reserves are located.
The summarized results of the reserve audit are as follows: 
Estimated Proved Reserves
Net to Seneca Energy Canada, Inc.
As of September 30, 2004

 	 	Proved Developed
	 	 	 	 	
 	 	Producing
	 	Non Producing
	 	Undeveloped
	 	Total Proved
	
TOTAL COMPANY	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil: MBbls	 	 	1,820.5	 	 	 	81.7	 	 	 	0.0	 	 	 	1,902.2	 	
NGL/Condensate: MBbls	 	 	153.4	 	 	 	48.3	 	 	 	0.0	 	 	 	201.7	 	
Gas: MMcf	 	 	32,580.5	 	 	 	13,642.2	 	 	 	4,623.0	 	 	 	50,845.7	 	
DISCUSSION:
The scope of this study was to audit the proved reserves attributable to the interests of Seneca Energy Canada, Inc. Reserve estimates were prepared by Seneca Energy Canada using acceptable evaluation principals for each source. The quantities presented herein are estimated reserves of oil, condensate and natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under existing economic conditions with reasonable certainty.

 

RALPH E. DAVIS ASSOCIATES, INC.
Seneca Energy Canada, Inc.
Oil, Condensate and Natural Gas Reserves
Mr. Darrell Ibach
October 15, 2004
Page 3
Ralph E. Davis Associates, Inc. has audited the reserve estimates, the data incorporated into preparing the estimates and the methodology used to evaluate the reserves. In each of Seneca Energy Canada’s producing areas all current year additions and those properties of significant value were reviewed by Ralph E. Davis. Reserve estimates of current producing zones, productive zones behind pipe and undrilled well locations were reviewed in detail. Certain changes to either individual reserve estimates or the categorization of reserves were suggested by Ralph E. Davis Associates, Inc. and accepted by Seneca Energy Canada. It is our opinion that the reserves presented herein meet all the criteria of Proved Reserves.
Neither Ralph E. Davis Associates, Inc. nor any of its employees have any significant interest in Seneca Energy Canada, Inc. or Seneca Resources Corporation or the properties reported herein. The employment and compensation to make this study are not contingent on our estimate of reserves.
We appreciate the opportunity to be of service to you in this matter and will be glad to address any questions or inquiries you may have.
Very truly yours,
RALPH E. DAVIS ASSOCIATES, INC.

Allen C. Barron, P. E.
President

 

RALPH E. DAVIS ASSOCIATES, INC.
CLASSIFICATION OF RESERVES
Proved Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

 	1.	 	           Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.	
 	
 	2.	 	           Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.	
 	
 	3.	 	           Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.	
Proved Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved Undeveloped Reserves
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
(Classification of reserves as found in Rule 4-10(a) of Regulation S-X of the per Securities and Exchange Act)

 

Exhibit 99.3