NATIONAL FUEL GAS CO - 10-K Annual Report

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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.

For the Fiscal Year Ended September 30, 2004

CONTENTS


		Page


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


		Page


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

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

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.

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.

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.

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.

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.”

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

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.

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.


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.

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



		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

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.


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

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.


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



		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;

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.

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

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

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.

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

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.

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

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

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.

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

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

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.

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,

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,

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

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.

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.

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.

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.*

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

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.

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 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

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.

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.


	*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).

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.

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

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

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

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;

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.


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.

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

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

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

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

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

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.


	*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.

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.

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.

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.

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.

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.

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.

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

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

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.

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.

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.

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.

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

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

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.

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.

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

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.

NATIONAL FUEL GAS COMPANY

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

NATIONAL FUEL GAS COMPANY

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.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

NATIONAL FUEL GAS COMPANY

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%.

NATIONAL FUEL GAS COMPANY

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:

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$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	)

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	%

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.


	(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.

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

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.

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

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.

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

NATIONAL FUEL GAS COMPANY

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

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

NATIONAL FUEL GAS COMPANY

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

NATIONAL FUEL GAS COMPANY

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

NATIONAL FUEL GAS COMPANY

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

NATIONAL FUEL GAS COMPANY

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


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



		Year Ended September 30

		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

NATIONAL FUEL GAS COMPANY

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

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	)

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

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

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

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

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

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.

100


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.

101


*(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)

102


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)

103


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

104


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)

105


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.

106


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.

107

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


	•	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.


(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.


(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.


	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;


	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.


	•	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.


	•	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.


(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.


(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.


(1)	Gigajoules = one billion joules. A joule is a unit of energy.


(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.


(1)	Gas prices are variable based on the NYMEX prices adjusted for basis.


(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.


	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;


	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.


(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.


(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.


(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.


(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.


(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


	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.


	*	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%.


(1)	Amount includes the acquisition of all of the partnership interests in Toro Partners, L.P. and is disclosed in Note J — Acquisitions.


(1)	Revenue is based upon the country in which the sale originates.


(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).


(1)	Includes asset retirement costs of $22.2 million and $18.1 million at September 30, 2004 and 2003, respectively.


(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


(1)	Represents amounts reclassified from regulatory asset and regulatory liability accounts under various rate settlements.

(2)	Amounts represent net accounts receivable written-off.