United States
Securities and Exchange Commission
Washington, D.C. 20549

Amendment No. 1
Form 10-K10-K/A
Annual Report Pursuant to SectionANNUAL REPORT PURSUANT TO SECTION 13 orOR 15(d) of
The Securities Exchange Act ofOF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended September 30, 20002001

Commission File Number 1-3880

National Fuel Gas Company
(Exact name of registrant as specified in its charter)

New Jersey13-1086010
(State or other jurisdiction of(I.R.S. Employer
incorporation or organization)Identification No.)
  
10 Lafayette Square14203
Buffalo, New York(Zip Code)

(Address of principal executive offices)

(716) 857-7000
Registrant's telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:Act.

Title of each className of each exchange on which registered
Common Stock, $1 Par Value, andNew York Stock Exchange
Common Stock Purchase Rights     

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    X   NO        

      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. [   X   ]

      The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $2,207,381,000$1,759,487,000 as of November 30, 2000.2001.

      Common Stock, $1 Par Value, outstanding as of November 30, 2000: 39,384,9502001: 79,480,675 shares.

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the registrant's Annual Report to Shareholders for 20002001 are incorporated by reference into Part I of this report. Portions of the registrant's definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 15, 200121, 2002 are incorporated by reference into Part III of this report.

For the Fiscal Year Ended September 30, 2000

Contents

Part I

ITEM 1     BUSINESS

THE COMPANY AND ITS SUBSIDIARIES
RATES AND REGULATION
THE UTILITY SEGMENT
THE PIPELINE AND STORAGE SEGMENT
THE EXPLORATION AND PRODUCTION SEGMENT
THE INTERNATIONAL SEGMENT
THE ENERGY MARKETING SEGMENT
THE TIMBER SEGMENT
SOURCES AND AVAILABILITY OF RAW MATERIALS
COMPETITION
SEASONALITY
CAPITAL EXPENDITURES
ENVIRONMENTAL MATTERS
MISCELLANEOUS
EXECUTIVE OFFICERS OF THE COMPANY


ITEM 2    PROPERTIES

GENERAL INFORMATION ON FACILITIES
EXPLORATION AND PRODUCTION ACTIVITIES


ITEM 3    LEGAL PROCEEDINGS

ITEM 4     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Part II

ITEM 5     MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS

ITEM 6     SELECTED FINANCIAL DATA

ITEM 7     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ITEM 7A     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 8     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ITEM 9     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Part III

ITEM 10     DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

ITEM 11     EXECUTIVE COMPENSATION

ITEM 12     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Part IV

ITEM 14     EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

SIGNATURES

This combined Annual Report to Shareholders/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 combined Annual Report to Shareholders/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 a "*" 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
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The Company and its Subsidiaries
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National Fuel Gas Company (the Company or Registrant), a registered holding company 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. The Company is engaged in the business of owning and holding securities issued by its twelve directly owned subsidiary companies. Except as otherwise indicated below, the Company 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 735,000 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 by Seneca Independence Pipeline Company (SIP), a Delaware corporation. 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. SIP holds a one-third general partnership interest in Independence Pipeline Company (Independence), a Delaware general partnership. Independence, upon securing sufficient customer interest, plans to construct and operate the Independence Pipeline, a 400-mile interstate pipeline system expected to transport about 916 thousand dekatherms (MDth) per day of natural gas from Defiance, Ohio to Leidy, Pennsylvania.*

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 the Gulf Coast region of Texas and Louisiana, in California, in Wyoming, and in the Appalachian region of the United States. Also, exploration and production operations are conducted in the provinces of Manitoba, Alberta and Saskatchewan in Canada by Seneca's wholly-owned subsidiary, National Fuel Exploration Corp. (NFE), an Alberta, Canada corporation.

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 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 assets are majority ownership of (i) United Energy, a.s. (UE), a wholesale power and district heating company located in the northern part of the Czech Republic, which was formed from the merger of Severoceske teplarny, a.s. and Prvni severozapadni teplarenska, a.s., and (ii) Teplarna Kromeriz, a.s. (TK), a district heating company located in the southeast region of the Czech Republic.

5.    The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation engaged in the marketing and brokerage of natural gas and electricity and the performance of energy management services for industrial, commercial, public authority and residential end-users in the northeast United States.

6.    The Timber segment operations are carried out by Highland Forest Resources, Inc. (Highland), a Pennsylvania corporation (formerly known as Highland Land & Minerals, Inc.), and by a division of Seneca known as its Northeast Division. This segment markets timber from its New York and Pennsylvania land holdings, owns four sawmill operations in northwestern Pennsylvania and processes timber consisting primarily of high quality hardwoods.

     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 I - Business Segment Information.

     The Company's other wholly-owned subsidiaries are not included in any of the six reportable business segments and consist of the following:

     No single customer, or group of customers under common control, accounted for more than 10% of the Company's consolidated revenues in 2000.

Rates and Regulation
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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. The SEC and some members of Congress have advocated, on either a stand-alone basis or in conjunction with legislation which would deregulate the electric industry, the repeal of the Holding Company Act. Thus far, the proposed legislation would transfer certain oversight responsibilities to the various state public utility regulatory commissions and the Federal Energy Regulatory Commission (FERC) and would expand the access of these bodies to the books and records of companies in a holding company system and could increase regulation, especially at the state level.* By contrast, previous SEC rule changes have reduced the number of applications required to be filed under the Holding Company Act, exempted some routine financings and expanded diversification opportunities. The Company is unable to predict at this time what the ultimate outcome of legislative or regulatory changes will be and, therefore, what impact such efforts 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 are regulated by the FERC. SIP is not itself regulated by the FERC, but its sole business is the ownership of an interest in Independence, whose construction, rates, services and other matters are or will be regulated by the FERC. 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 regulations on various subjects as other companies doing similar business in the same locations.

The Utility Segment
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The Utility segment contributed approximately 45.3% of the Company's net income available for common stock in 2000.

     During 2000, Distribution reached agreement with the Staff of the New York Department of Public Service, the New York State Consumer Protection Board, and Multiple Intervenors (an advocate for large commercial and industrial customers), that settles rates for a three year period beginning with 2001.

     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
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The Pipeline and Storage segment contributed approximately 24.9% of the Company's net income available for common stock in 2000.

     Supply Corporation currently has service agreements for substantially all of its firm transportation capacity which totals approximately 1,839 MDth per day. The Utility segment has contracted for approximately 1,149 MDth per day or 62.5% of that capacity until 2003 and continuing year-to-year thereafter. An additional 536 MDth per day or 29.1% of Supply Corporation's firm transportation capacity is subject to firm contracts with nonaffiliated customers until 2003 or later.

     Supply Corporation has available for sale to customers approximately 67,409 MDth of firm storage capacity. The Utility segment has contracted for 28,248 MDth or 41.9% of that capacity. Of that, 26,581 MDth or 39.4% of total storage capacity is contracted by the Utility segment under agreements with remaining initial terms expiring in 2003 or later. Other customers, both affiliated and nonaffiliated, have contracted for the remaining 39,161 MDth or 58.1% of firm storage capacity, and 15,276 MDth or 22.7% of total storage capacity is contracted by nonaffiliated customers until 2003 or later. 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.*

     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
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The Exploration and Production segment contributed approximately 27.4% of the Company's net income available for common stock in 2000.

     In June 2000, Seneca, through its wholly-owned subsidiary, NFE, acquired the stock of Tri Link Resources Ltd., a Calgary, Alberta-based exploration and production company for approximately $123.8 million (and another $99.2 million in assumed debt which has been redeemed). Upon completing this acquisition, Tri Link was amalgamated into NFE. This acquisition increased Seneca's total reserve base to approximately one trillion cubic feet equivalent.*

     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
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The International segment contributed approximately 2.6% of the Company's net income available for common stock in 2000.

     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
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The Energy Marketing segment incurred a net loss in 2000. The impact of this segment's net loss in relation to total net income for the Company was negative 6.1%.

     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
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The Timber segment contributed approximately 4.8% of the Company's net income available for common stock in 2000.

     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.

Sources and Availability of Raw Materials
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Natural gas is the principal raw material for the Utility segment. In 2000, the Utility segment purchased 104.0 billion cubic feet (Bcf) of gas. Gas purchases from various producers and marketers in the southwestern United States and Canada under long-term (two years or longer) contracts accounted for 71% of these purchases. Purchases of gas on the spot market (contracts of less than a year) accounted for 28% of the Utility segment's 2000 gas purchases. Gas purchases from Dynegy Marketing and Trade and BP Energy Co. (both providing gas from the southwestern United States under long-term contracts) represented 28% and 20%, respectively, of total 2000 gas purchases by the Utility segment. No other producer or marketer provided the Utility segment with 10% or more of its gas requirements in 2000.

     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. SIP, through Independence, proposes to transport natural gas produced in Canada and in the continental United States.

     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 I-Business Segment Information and M - Supplementary Information for Oil and Gas Producing Activities.

     Coal is the principal raw material for the International segment, constituting 45% of the cost of raw materials needed to operate the boilers which produce steam or hot water. Natural gas, oil, limestone and water combined account for the remaining 55% of such materials. Coal is purchased and delivered directly from the Mostecka Uhelna Spolecnost, a.s. mine for Horizon's largest coal-fired plant under a contract where price and quantity are the subject of negotiation each year. Based on the current extraction rate, this mine has proven reserves through 2030. Natural gas is imported by the Czech Republic government from Russia and the North Sea and is transported through the Transgas pipeline system which is majority owned by the Czech government and purchased by the International segment from two of the eight regional gas distribution companies. Oil is also imported. This segment purchases oil from domestic and foreign refineries.

     With respect to the Timber segment, Highland requires an adequate supply of timber to process. Highland, however, mainly processes timber which is located on land owned by Seneca, and, therefore, the source and availability of this segment's primary raw material are generally known in advance.

     The Energy Marketing segment depends on an adequate supply of natural gas and electricity. In 2000, this segment purchased 35.5 Bcf of natural gas and approximately 57,000 megawatt hours of electricity.

Competition
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Competition in the natural gas industry exists among providers of natural gas, as well as between natural gas and other sources of energy. The continuing deregulation of the natural gas industry should enhance the competitive position of natural gas relative to other energy sources, such as fuel oil or electricity, by removing some of the regulatory impediments to adding customers and responding to market forces.* In addition, the environmental advantages of natural gas compared with other fuels should increase the role of natural gas as an energy source.* Moreover, while demand for natural gas is increasing, the production of natural gas also continues to increase making it a dependable alternative to imported oil.*

     The electric industry is 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 is unclear at this point what impact this restructuring will have on the Company.*

     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 are redefining the roles of the gas utility industry and the state regulatory commissions. Regulators in both New York and Pennsylvania have adopted retail competition for natural gas supply purchases. However, the Utility segment's traditional distribution function remains largely unchanged. For further discussion of state restructuring initiatives refer to Item 7, MD&A under the heading "Rate Matters."

     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 is now better able to compete, 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 northeastern 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.*

     SIP, through Independence, is competing for customers with other proposed pipeline projects which would bring natural gas from the Chicago area to the growing markets in the northeast and mid-Atlantic regions of the United States. In combination with expansion projects of Transcontinental Gas Pipe Line Corporation and ANR Pipeline Company, Independence intends to provide the least-cost path for this service and will access the storage and market hub at Leidy, Pennsylvania.* It is likely that not all of the proposed pipelines will go forward, and that the first project built will have an advantage over other proposed projects.* Independence is the first of the proposed projects to be approved by the FERC. If completed, the Independence pipeline would likely create opportunities for increased transportation and storage services by Supply Corporation.*

Competition: The Exploration and Production Segment
The Exploration and Production segment competes with other gas and oil producers and marketers with respect to its sales of oil and gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other oil and natural gas exploration and production companies of various sizes for leases and drilling rights for exploration and development prospects.

     To compete in this environment, Seneca and its wholly-owned subsidiary, NFE, each originate and act as operator on most prospects, minimize 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 its size, operating expertise and financial criteria.

Competition: The International Segment
Horizon competes with other entities seeking to develop foreign and domestic energy projects. Horizon, through UE, faces competition in the sale of thermal energy to large industrial customers. Currently, electric energy sales are made to the regional electric distribution company. The Czech cabinet approved a plan put forward by the Ministry of Industry and Trade to privatize the Czech Republic's dominant energy producer and six regional electric distributors. It is unclear at this point what impact this privatization will have on the wholesale electric energy market.* UE sells electricity at the wholesale level.

Competition: The Energy Marketing Segment
The Energy Marketing segment competes with other marketers of electricity and natural gas and with other providers of energy management services. Although the deregulation of electric and natural gas utilities is a relatively new occurrence, the competition in this area is well developed with regard to price and services and derives 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. 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, saw logs or export logs ultimately used in the production of high-end furniture, cabinetry and flooring. The Timber segment markets its products both nationally and internationally.

Seasonality
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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 on the Utility segment 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. In the International segment, district heating operations in the Czech Republic are also subject to the seasonality of weather.

     Volumes transported and stored by Supply Corporation may vary materially depending on weather, without materially affecting its earnings. Supply Corporation's rates are based on a straight fixed-variable rate design which allows recovery of all fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed only to reimburse the variable costs caused by actual transportation or storage of gas.

     Variations in weather conditions can materially affect the volume of gas and electricity consumed by customers of the Energy Marketing segment.

     The activities of the Timber segment vary on a seasonal basis and are subject to weather constraints. The timber harvesting and processing season occurs when timber growth is dormant and runs from approximately September to March. The operations conducted in the summer months focus on pulpwood and on thinning out lower-grade species from the timber stands to encourage the growth of higher-grade species.

Capital Expenditures
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A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading "Investing Cash Flow."

Environmental Matters
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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 H-Commitments and Contingencies.

Miscellaneous
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The Company and its wholly-owned subsidiaries had a total of 3,597 full-time employees at September 30, 2000, 2,396 employees in all of its U.S. operations and 1,201 employees in its International segment. This is a decrease of 5.5% from the 3,807 total employed at September 30, 1999.

     Agreements covering employees in collective bargaining units in New York were renegotiated in November 2000, effective beginning on November 26, 2000, and are scheduled to expire in February 2006. Agreements covering most employees in collective bargaining units in Pennsylvania were renegotiated, effective November 1998, and are scheduled to expire in April and May 2003.

     The Company 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 Company renews such franchises.

Executive Officers of the Company as of November 15, 2000(1)
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Name and Age(2)          Current Company Positions and Other Material
                         Business Experience During Past 5 Years(3)
- ----------------------- --------------------------------------------------------

Bernard J. Kennedy      Chairman of the Board of  Directors  since March 1989
(69)                    and Chief Executive  Officer  since August 1988.
                        Mr.  Kennedy has served as a Director since March 1978
                        and previously  served as President from January 1987
                        to July 1999.

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Philip C. Ackerman      President  since July 1999,  Executive Vice President of
(56)                    Supply Corporation  since  October 1994 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.

- ----------------------- --------------------------------------------------------

Dennis J. Seeley        President of Supply  Corporation  since March 2000.
(57)                    Mr. Seeley has served as Vice  President  of the Company
                        from January 2000 to April 2000,  Senior Vice  President
                        of  Distribution Corporation  from February 1997 to
                        March 2000 and Senior Vice President of Supply
                        Corporation  from January 1993 to February 1997.

- ----------------------- --------------------------------------------------------

David F. Smith          President of  Distribution Corporation since July 1999.
(47)                    Mr. Smith  served  as  Senior  Vice   President of
                        Distribution Corporation from January 1993 to July 1999.

- ----------------------- --------------------------------------------------------

James A. Beck           President  of  Seneca  since  October  1996  and
(53)                    President  of Highland since March 1998. Mr. Beck
                        previously  served as Vice President  of Seneca from
                        January 1994 to April 1995 and Executive  Vice President
                        of  Seneca  from May 1995 to September 1996.

- ----------------------- --------------------------------------------------------

Joseph P. Pawlowski     Treasurer since December 1980; Senior Vice President of
(59)                    Distribution  Corporation  since February 1992 and
                        Treasurer of Distribution Corporation since January
                        1981;  Treasurer of Supply  Corporation  since June 1985
                        and Secretary of Supply Corporation since October 1995.

- ----------------------- --------------------------------------------------------

Gerald T. Wehrlin       Controller since December 1980; Senior Vice President of
(62)                    Distribution Corporation since April 1991; Controller of
                        Seneca since  September  1981;  Vice President of
                        Horizon since February 1997. Mr. Wehrlin  previously
                        served as Secretary and Treasurer of Horizon from
                        September 1995 to February 1997.

- ----------------------- --------------------------------------------------------





- ----------------------- --------------------------------------------------------

Name and Age(2)          Current Company Positions and Other Material
                         Business Experience During Past 5 Years(3)

- ----------------------- --------------------------------------------------------

Walter E. DeForest      Senior Vice President of Distribution Corporation since
(59)                    August 1993.

- ----------------------- --------------------------------------------------------

Bruce H. Hale           Senior Vice  President  of Supply  Corporation  since
(51)                    February 1997 and Vice  President of Horizon since
                        September  1995. Mr. Hale  previously  served as  Senior
                        Vice  President  of Distribution  Corporation  from
                        January 1993 to February 1997.

- ----------------------- --------------------------------------------------------

(1)

The Company has been advised that there are no family relationships among any of the officers listed, and that there is no arrangement or understanding among any one of them and any other persons pursuant to which he was elected as an officer. The executive officers serve at the pleasure of the Board of Directors.

(2)

Ages are as of September 30, 2000.

(3)

The information provided relates to the principal subsidiaries of the Company. Many of the executive officers have in the past or currently serve as officers or directors for other subsidiaries of the Company.


ITEM 2 Properties
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General Information on Facilities
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The investment of the Company in net property, plant and equipment was $2.7 billion at September 30, 2000. Approximately 53% of this investment is in the Utility and Pipeline and Storage segments, which are primarily located in western New York and western Pennsylvania. The Exploration and Production segment represents the next largest investment in net property, plant and equipment (37%) and is primarily located in the Gulf Coast region of Texas and Louisiana, in California, in Wyoming, in the Appalachian region of the United States and in the provinces of Manitoba, Alberta and Saskatchewan in Canada. The remaining investment in net property, plant and equipment consists primarily of the International segment (6%) which is located in the Czech Republic and the Timber segment (4%) which is located primarily in northwestern Pennsylvania. During the past five years, the Company has made significant additions to property, plant and equipment in order to expand and improve transmission and distribution facilities for both retail and transportation customers, to augment the reserve base of oil and gas in the United States and Canada, and to purchase district heating and power generation facilities in the Czech Republic. Net property, plant and equipment has increased $1.034 billion, or 63%, since 1995.

     The Utility segment has a net investment in property, plant and equipment of $939.8 million at September 30, 2000. The net investment in its gas distribution network (including 14,769 miles of distribution pipeline) and its services represent approximately 57% and 29%, respectively, of the Utility segment's net investment in property, plant and equipment at September 30, 2000.

     The Pipeline and Storage segment represents a net investment of $475 million in property, plant and equipment at September 30, 2000. Transmission pipeline, with a net cost of $131.1 million, represents 28% of this segment's total net investment and includes 2,556 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 478 miles of pipeline. Net investment in storage facilities includes $81.1 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 74,671 installed compressor horsepower.

     The Exploration and Production segment had a net investment in property, plant and equipment amounting to $998.9 million at September 30, 2000. Of this amount, $750.1 million relates to properties located in the United States. The remaining net investment of $248.8 million relates to properties located in Canada.

     The International segment had a net investment in property, plant and equipment amounting to $172.6 million at September 30, 2000. UE's net investment in district heating and electric generation facilities was $171.8 million; and TK's net investment in district heating facilities was approximately $0.7 million.

     The Timber segment had a net investment in property, plant and equipment of $95.6 million at September 30, 2000. Located primarily in northwestern Pennsylvania, the net investment includes four sawmills and approximately 150,000 acres of timber.

     The Utility and Pipeline and Storage segments' facilities provided the capacity to meet its 2000 peak day sendout, including transportation service, of 1,779 million cubic feet (MMcf), which occurred on January 17, 2000. Withdrawals from storage of 779.5 MMcf provided approximately 43.8% of the requirements on that day.

     Company maps are included throughout pages 3 through 16 of the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K and are narratively described in the Apendix to this electronic filing and are incorporated herein by reference.

Exploration and Production Activities
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The information that follows is disclosed in accordance with SEC regulations, and relates to the Company's oil and gas producing activities. A further discussion of oil and gas producing activities is included in Item 8, Note M-Supplementary Information for Oil and Gas Producing Activities. Note M sets forth proved developed and undeveloped reserve information for Seneca. Seneca's oil and gas reserves reported in Note M as of September 30, 2000 were estimated by Seneca's qualified geologists and engineers and were audited by independent petroleum engineers from Ralph E. Davis Associates, Inc. and McDaniel and Associates Consultants, Ltd. Seneca reports its oil and gas reserve information on an annual basis to the Energy Information Administration (EIA). The basis of reporting Seneca's reserves to the EIA is identical to that reported in Note M.

     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                2000        1999       1998
- --------------------------------------- ------------- ----------- ----------

United States
Average Sales Price per Mcf of Gas(1)         $3.31       $2.20      $2.45
Average Sales Price per Barrel of Oil(1)     $25.34      $12.85     $12.15
Average Production (Lifting) Cost per Mcf
  Equivalent of Gas and Oil Produced          $0.51       $0.46      $0.45
- --------------------------------------- ------------- ----------- ---------
Canada
Average Sales Price per Mcf of Gas(1)         $2.52           -          -
Average Sales Price per Barrel of Oil(1)     $29.28           -          -
Average Production (Lifting) Cost per Mcf
  Equivalent of Gas and Oil Produced          $1.41           -          -
- ---------------------------------------- ------------- ----------- ---------
Total
Average Sales Price per Mcf of Gas(1)         $3.31       $2.20      $2.45
Average Sales Price per Barrel of Oil(1)     $26.03      $12.85     $12.15
Average Production (Lifting) Cost per Mcf
  Equivalent of Gas and Oil Produced          $0.58       $0.46      $0.45
- ---------------------------------------- ------------- ----------- ---------

(1) Prices do not reflect gains or losses from hedging activities.

Productive Wells

- --------------------------- ------------------ --------------- -----------------
At September 30, 2000         United States         Canada             Total
- --------------------------- ------------------ --------------- -----------------
                            Gas       Oil        Gas     Oil       Gas       Oil

Productive Wells  - gross   1,924     860         8      471     1,932     1,331
                  - net     1,782     782         3      427     1,785     1,209
- ----------------- --------- ------ ---------- ------- -------- --------- -------
Developed and Undeveloped Acreage

- ----------------------- ------------- ------------- -------------- -------------
At September 30, 2000                    United        Canada         Total
                                         States
- ----------------------- ------------- ------------- -------------- -------------


Developed Acreage       - gross          641,535         68,917       710,452
                        - net            552,275         53,160       605,435

Undeveloped Acreage     - gross          997,031      1,839,706     2,836,737
                        - net            716,759      1,827,910     2,544,669
- ----------------------- ------------- ------------- -------------- -------------
Drilling Activity

- --------------------------------------------------------------------------------
                                    Productive                     Dry
                             ---------------------------------------------------
For the Year Ended September    2000    1999     1998     2000    1999    1998
30
                             ---------------------------------------------------
United States
Net Wells
Completed   - Exploratory     13.89   12.95    10.72     6.53    5.64    4.97
            - Development     82.82   95.26    14.11     1.00    4.75    2.00
- --------------------------------------------------------------------------------
Canada
Net Wells
Completed   - Exploratory      1.00       -        -        -       -       -
            - Development     21.50       -        -     4.00       -       -
- --------------------------------------------------------------------------------
Total
Net Wells
Completed   - Exploratory     15.89   12.95    10.72     6.53    5.64    4.97
            - Development    103.32   95.26    14.11     5.00    4.75    2.00
- --------------------------------------------------------------------------------
Present Activities

- ------------------------------- ---------- ------------ ---------- -----------
At September 30, 2000                         United     Canada       Total
                                              States
- ------------------------------- ---------- ------------ ---------- -----------

Wells in Process of Drilling    - gross       30.00       2.00        32.00
                                - net         25.78       2.00        27.78
- ------------------------------- ---------- ------------ ---------- -----------
South Lost Hills Waterflood Program
In Seneca's South Lost Hills Field, a waterflood project was initiated in 1996 on the Ellis lease in the Diatomite reservoir for pressure maintenance and recovery enhancement purposes. Currently there are 26 injection wells and 91 production wells in the program. The total injection and production from this waterflood project are 6,400 barrels of water per day and 300 barrels of oil per day, respectively.

ITEM 3 Legal Proceedings
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For a discussion of various environmental matters, refer to Item 7, MD&A under the heading "Other Matters" and to Item 8 at Note H-Commitments and Contingencies.

ITEM 4 Submission of Matters to a Vote of Security Holders
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No matter was submitted to a vote of security holders during the fourth quarter of 2000.

PART II

ITEM 5 Market for the Registrant's Common Stock and Related Shareholder Matters
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Information regarding the market for the Company's common stock and related shareholder matters appears under Item 8 at Note D-Capitalization and Note L-Market for Common Stock and Related Shareholder Matters (unaudited).

     On July 1, 2000, the Company issued 840 unregistered shares of Company common stock to the seven non-employee directors of the Company, 120 shares to each such director. These shares were issued as partial consideration for the directors' service as directors during the quarter ended September 30, 2000, 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 amended, as transactions not involving any public offering.

ITEM 6 Selected Financial Data
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- -----------------------------------------------------------------------------------------------
Year Ended September 30         2000        1999         1998        1997        1996
- -----------------------------------------------------------------------------------------------
Summary of Operations (Thousands)
Operating Revenues             $1,425,277 $1,263,274  $1,248,000  $1,265,812 $1,208,017
- -----------------------------------------------------------------------------------------------
Operating Expenses:
  Purchased Gas                   503,617    405,925     441,746     528,610    477,357
  Fuel Used in Heat and
  Electric Generation              54,893     55,788      37,837       1,489          -
  Operation and Maintenance       350,383    328,800     321,411     286,537    309,206
  Property, Franchise and
    Other Taxes                    78,878     91,146      92,817     100,549     99,456
  Depreciation, Depletion and
    Amortization                  142,170    124,778     117,238     111,650     98,231
  Impairment of Oil and Gas
    Producing Properties                -          -     128,996           -          -
  Income Taxes                     77,068     64,829      24,024      68,674     66,321
- -----------------------------------------------------------------------------------------------
                                1,207,009  1,071,266   1,164,069   1,097,509  1,050,571
- -----------------------------------------------------------------------------------------------
Operating Income                  218,268    192,008      83,931     168,303    157,446
Other Income                       10,408     12,343      35,870       3,196      3,869
- -----------------------------------------------------------------------------------------------
Income Before Interest Charges and
 Minority Interest in
   Foreign Subsidiaries           228,676    204,351     119,801     171,499    161,315
Interest Charges                  100,085     87,698      85,284      56,811     56,644
- -----------------------------------------------------------------------------------------------
Minority Interest in
   Foreign Subsidiaries            (1,384)    (1,616)     (2,213)          -          -
- -----------------------------------------------------------------------------------------------
Income Before Cumulative Effect   127,207    115,037      32,304     114,688    104,671
Cumulative Effect of Change in
  Accounting                            -          -      (9,116)          -          -
- -----------------------------------------------------------------------------------------------
Net Income Available for Common
  Stock                          $127,207   $115,037     $23,188    $114,688   $104,671
- -----------------------------------------------------------------------------------------------
Per Common Share Data
  Basic Earnings per Common Share   $3.25      $2.98       $0.61(1)    $3.01      $2.78
  Diluted Earnings per Common Share $3.21      $2.95       $0.60(1)    $2.98      $2.77
  Dividends Declared                $1.89      $1.83       $1.77       $1.71      $1.65
  Dividends Paid                    $1.88      $1.82       $1.76       $1.70      $1.64
  Dividend Rate at Year-End         $1.92      $1.86       $1.80       $1.74      $1.68
At September 30:
Number of Common Shareholders      21,164     22,336      23,743      20,267     21,640
- -----------------------------------------------------------------------------------------------
Net Property, Plant and Equipment(Thousands)
  Utility                        $939,753   $919,642    $906,754    $889,216   $855,161
  Pipeline and Storage            474,972    466,524     460,952     450,865    452,305
  Exploration and Production      998,852    674,813     638,886     443,164    375,958
  International                   172,602    210,920     202,590         942      1,274
  Energy Marketing                    360        489         353         123         41
  Timber                           95,607     88,623      38,593      34,872     24,680
  All Other                         1,241        214           -         173        172
  Corporate                             4          7           9          11         15
- -----------------------------------------------------------------------------------------------
Total Net Plant                $2,683,391 $2,361,232  $2,248,137  $1,819,366 $1,709,606
- -----------------------------------------------------------------------------------------------
Total Assets(Thousands)$3,236,888 $2,842,586  $2,684,459  $2,267,331 $2,149,772
- -----------------------------------------------------------------------------------------------
Capitalization(Thousands)
Common Stock Equity             $ 987,437  $ 939,293   $ 890,085   $ 913,704  $ 855,998
Long-Term Debt, Net of
   Current Portion                953,622    822,743     693,021     581,640    574,000
Total Capitalization           $1,941,059 $1,762,036   1,583,106  $1,495,344 $1,429,998
- -----------------------------------------------------------------------------------------------

(1) 1998 includes oil and gas asset impairment of ($2.06) basic, ($2.04) diluted and cumulative effect of a change in depletion methods of ($0.24) basic and diluted. Refer to further discussion of these items in Notes to Financial Statements, Note A - Summary of Significant Accounting Policies.


ITEM 7 Management's Discussion and Analysis of Financial Condition and Results of Operations
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Results of Operations

2000 Compared with 1999
The Company's earnings were $127.2 million, or $3.25 per common share ($3.21 per common share on a diluted basis) in 2000. This compares with 1999 earnings of $115.0 million, or $2.98 per common share ($2.95 per common share on a diluted basis). The increase in earnings of $12.2 million was the result of higher earnings in the Exploration and Production, Utility, Timber and International segments. These were offset in part by lower earnings in the Pipeline and Storage segment, the Energy Marketing segment (which had a loss for the year) and in Corporate operations. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.

1999 Compared with 1998
The Company's earnings were $115.0 million, or $2.98 per common share ($2.95 per common share on a diluted basis), in 1999. This compares with 1998 earnings of $23.2 million, or $0.61 per common share ($0.60 per common share on a diluted basis). Earnings for 1998 included a $79.1 million (after tax) non-cash impairment of the Exploration and Production segment's oil and gas assets and the non-cash cumulative effect of a change in accounting. The 1998 accounting change, which was a change in depletion methods for the Exploration and Production segment's oil and gas assets, had a negative $9.1 million (after tax), or $0.24 per common share, non-cash cumulative effect through 1997, which was recorded in the first quarter of 1998. Excluding these two non-cash special items, earnings for 1998 would have been $111.4 million, or $2.91 per common share ($2.88 per common share on a diluted basis).

     The increase in 1999 earnings of $3.6 million (exclusive of the two non-cash special items in 1998) was the result of higher earnings in the Utility, Timber, Energy Marketing and International segments and in Corporate operations. These higher earnings were offset in part by reduced earnings in the Exploration and Production segment. The Pipeline and Storage segment's earnings remained level with the prior year. 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 (Thousands)2000         1999        1998
- ---------------------------------- ------------- -------------- -------------

Utility                                $57,662      $56,875     $51,788
Pipeline and Storage                    31,614       39,765      39,852
Exploration and Production (1)          34,877        7,127     (64,110)
International                            3,282        2,276       1,279
Energy Marketing                        (7,790)       2,054         787
Timber                                   6,133        4,769       1,904
- ---------------------------------- ------------- ------------ -----------
   Total Reportable Segments           125,778      112,866      31,500
All Other                                 (371)        (162)        143
Corporate                                1,800        2,333         661
- ---------------------------------- ------------- ------------ -----------
   Total Consolidated (1)             $127,207     $115,037     $32,304
- ---------------------------------- ------------- ------------ -----------

(1) Before Cumulative Effect of a Change in Accounting in 1998. Exclusive of the non-cash asset impairment, 1998 earnings for the Exploration and Production segment and Total Consolidated would have been $15,004 and $111,418, respectively.

Utility

Revenues

Utility Operating Revenues

- ------------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands) 2000         1999        1998
- ------------------------------------------ ------------- -------------- -------------

  Retail Revenues:
    Residential                          $584,618     $581,022    $612,647
    Commercial                             93,914      101,482     123,807
    Industrial                             21,543       15,903      18,068
- ------------------------------------- ------------- ------------ -----------
                                          700,075      698,407     754,522
- ------------------------------------- ------------- ------------ -----------
  Off-System Sales                         47,962       29,214      44,479
  Transportation                          104,534       77,600      62,844
  Other                                    (6,112)       2,134       9,335
- ------------------------------------- ------------- ------------ -----------
                                         $846,459     $807,355    $871,180
- ------------------------------------- ------------- ------------ -----------
Utility Throughput - (MMcf)

- -------------------------------- ------------- -------------- -------------
Year Ended September 30             2000           1999          1998
- -------------------------------- ------------- -------------- -------------
  Retail Sales:
    Residential                       68,196         71,177        71,704
    Commercial                        12,312         13,885        16,405
    Industrial                         4,276          4,144         4,298
- -------------------------------- ------------- -------------- -------------
                                      84,784         89,206        92,407
- -------------------------------- ------------- -------------- -------------
  Off-System Sales                    12,833         12,469        16,192
  Transportation                      71,862         64,086        60,080
- -------------------------------- ------------- -------------- -------------
                                     169,479        165,761       168,679
- -------------------------------- ------------- -------------- -------------
2000 Compared with 1999
Operating revenues for the Utility segment increased $39.1 million in 2000 compared with 1999. This resulted from an increase in retail, off-system, and transportation gas sales revenues of $1.7 million, $18.7 million, and $26.9 million, respectively. These increases were partly offset by a decrease in other operating revenues of $8.2 million.

     The increase in retail gas revenues for the Utility segment was primarily due to the recovery of higher gas costs, offset by a decrease in the volumes sold. The recovery of higher gas costs (gas costs are recovered dollar for dollar in revenues) resulted from a much higher cost of purchased gas. See further discussion of purchased gas below under the heading "Purchased Gas." The decrease in retail sales volumes was primarily the result of the migration of residential and small commercial customers to transportation service in both the New York and Pennsylvania jurisdictions, offset slightly by the impact of colder weather. The migration from gas sales to transportation is the result of customers turning to marketers for their gas supplies while using the Utility for their gas transportation service. Restructuring in the Utility segment's service territory is further discussed in the "Rate Matters" section that follows. Transportation revenues increased and volumes were up 7.8 billion cubic feet (Bcf) as a result of the migration noted above as well as the slightly colder weather. Off-system sales revenues increased largely due to increased gas prices and slightly higher volumes. However, due to profit sharing with retail customers, the margins resulting from off-system sales are minimal.

     The decrease in other operating revenues of $8.2 million was due primarily to a $9.7 million reduction in refund pool revenue, as discussed below, and an $8.5 million reduction in revenue for various adjustments (including a provision for refund) related to the September 30, 2000 conclusion of the two year rate settlement approved by the State of New York Public Service Commission (NYPSC). Partly offsetting these decreases were two items that reduced revenue in 1999 that did not recur in 2000. The more significant item was the gas restructuring reserve which reduced revenues by $7.2 million in 1999. This special reserve put aside dollars to be applied against incremental costs that could result from the NYPSC's gas restructuring efforts and was required in 1999 by the terms of the rate settlement with the NYPSC. The NYPSC's gas restructuring efforts are further discussed in the "Rate Matters" section that follows. The second item that reduced 1999 revenues was a $0.4 million adjustment related to the final settlement of Internal Revenue Service (IRS) audits. Also offsetting the decreases noted above, 2000 revenue includes $0.7 million accrued to offset additional state income taxes that resulted from the enactment of tax changes in New York State. The revenue and related regulatory asset were recorded as the New York Department of Public Service has provided the opportunity of rate recovery by New York State utilities of such additional taxes. All of these items are included in the "Other" category of the Utility Operating Revenue table above.

     As part of its 1998 two year rate settlement approved by the NYPSC, Distribution Corporation was allowed to utilize certain refunds from upstream pipeline companies and certain other credits (referred to as the "refund pool") to offset certain specific expense items. When dollars from the refund pool are utilized, revenue is recorded and an equal amount of operation and maintenance (O&M) expense is also recorded (thus there is no earnings impact). The amount of refund pool revenue, and related O&M expense, recognized in 2000 was $9.7 million less than in 1999.

1999 Compared with 1998
Operating revenues for the Utility segment decreased $63.8 million in 1999 compared with 1998. This resulted from a reduction in retail and off-system gas sales revenue of $56.1 million and $15.3 million, respectively, and a reduction in other operating revenue of $7.2 million. These decreases were partly offset by an increase in transportation revenue of $14.8 million.

     The recovery of lower gas costs and the general base rate decrease in the New York jurisdiction effective October 1, 1998, caused the decrease in retail gas revenue. The recovery of lower gas costs resulted from both lower retail volumes sold of 3.2 Bcf and a lower average cost of purchased gas (see discussion of purchased gas below under the heading "Purchased Gas"). Despite weather that was colder than 1998, retail volumes sold decreased, mainly due to the migration of residential and small commercial retail customers to transportation service. Transportation revenue increased and volumes are up 3.9 Bcf as a result of the migration and because of colder weather. Off-system revenue is down due to lower volumes sold of 3.7 Bcf.

     The decrease in other operating revenue of $7.2 million is due primarily to a $7.2 million gas restructuring reserve, as discussed above, reducing revenue in 1999, $6.0 million of revenue recorded in 1998 as a result of IRS audits and $0.4 million of a revenue reduction in 1999 due to a final IRS audit settlement. These items were offset in part by a $7.1 million lower refund provision recorded in 1999 as compared with the 1998 refund provision. The revenue related to the IRS audits represents the rate recovery of interest expense as allowed by the New York rate settlement of 1996. The refund provision represents the 50% sharing with customers of earnings over a predetermined amount in accordance with the New York rate settlements of 1996 and 1998. All of these items are included in the "Other" category of the Utility Operating Revenue table above.

Earnings

2000 Compared with 1999
In the Utility segment, 2000 earnings were $57.7 million, up $0.8 million from the prior year. The increase in earnings resulted primarily from two items in the prior year (expenses related to an early retirement offer of $3.7 million (after tax) and a special reserve for gas restructuring of $4.7 million (after tax) which did not recur in the current year). These items were offset by higher stock appreciation rights (SARs) expense of $2.9 million (after tax), as discussed below, and revenue adjustments of $5.5 million (after tax), as discussed in the revenue section above.

     The increase in the market price of the Company's common stock, while benefiting shareholders, carried with it the required recognition of expense for SARs. This expense is spread across all segments, with the greatest impact on Pipeline and Storage, Utility and Exploration and Production segments. For 2000, total expense related to SARs for all segments was $9.2 million (after tax), and reflects the stock price increase from September 30, 1999 ($47.19 per common share) to September 30, 2000 ($56.06 per common share).

     The impact of weather on Distribution Corporation's New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits Distribution Corporation's New York customers. In 2000, the WNC in New York preserved earnings of approximately $8.1 million (after tax) as weather, overall in the New York service territory, was warmer than normal for the period from October 1999 through May 2000. Since the Pennsylvania rate jurisdiction does not have a WNC, uncontrollable weather variations directly impact earnings. In the Pennsylvania service territory, since 2000 weather was only 0.9% colder than 1999, no significant earnings variances occurred.

1999 Compared with 1998
In the Utility segment, 1999 earnings were $56.9 million, up $5.1 million from the prior year. This was largely because the settlement of the primary issues of IRS audits of years 1977-1994 had a negative impact on earnings in 1998. In addition, adjustments made relating to the final settlement of these audits had a positive impact to earnings in 1999. Absent the IRS audit items, earnings of the Utility segment were up $0.6 million from the prior year.

     Lower O&M and interest expenses, a lower refund provision in 1999 (as noted in the revenue discussion above), positive adjustments for lost and unaccounted-for gas related to 1998 and 1999 and slightly colder weather (which mainly benefits the Pennsylvania jurisdiction), were the positive contributors to earnings in 1999. These items offset the costs associated with the 1999 early retirement offers, as well as the effects of a rate settlement that included a $7.2 million rate reduction in New York that became effective October 1, 1998 and the previously discussed special gas restructuring reserve.

     In 1999, the WNC in New York preserved earnings of approximately $6.3 million (after tax) as weather, overall in the New York service territory, was warmer than normal for the period from October 1998 through May 1999. In the Pennsylvania service territory, weather that was 4.0% colder than 1998 increased earnings by approximately $0.5 million (after tax).

Degree Days

- ------------ ----------- ------------ ---------------- --------------------------
                                                         Percent (Warmer)
                                                            Colder Than
                                                      --------------------------
Year Ended September 30    Normal       Actual          Normal        Prior Year
- ------------- ----------- ------------ --------------- ------------- ------------
  2000:       Buffalo     6,932        6,312           (8.9%)        2.1%
              Erie        6,230        5,657           (9.2%)        0.9%
- ------------- ----------- ------------ --------------- ------------- ------------
  1999:       Buffalo     6,848        6,179           (9.8%)        4.5%
              Erie        6,223        5,607           (9.9%)        4.0%
- ------------- ----------- ------------ --------------- ------------- ------------
  1998:       Buffalo     6,689        5,914           (11.6%)       (12.9%)
              Erie        6,223        5,389           (13.4%)       (15.7%)
- ------------- ----------- ------------ --------------- ------------- ------------
Purchased Gas
The cost of purchased gas is currently the Company's single largest operating expense. Annual variations in purchased gas costs can be 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 can satisfy 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 $4.93 per thousand cubic feet (Mcf) in 2000, an increase of 29% from the average cost of $3.82 per Mcf in 1999. The average cost of purchased gas in 1999 was 7.5% lower than the $4.13 per Mcf in 1998.

Pipeline and Storage

Revenues

Pipeline and Storage Operating Revenues

- ------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands)2000           1999          1998
- ------------------------------------- ------------- -------------- -------------
Firm Transportation                    $92,305        $91,279       $93,362
Interruptible Transportation             1,578            856           985
- ---------------------------------- ------------- -------------- -------------
                                        93,883         92,135        94,347
- ---------------------------------- ------------- -------------- -------------
Firm Storage Service                    62,899         63,655        62,850
Interruptible Storage Service              287            173           655
- ---------------------------------- ------------- -------------- -------------
                                        63,186         63,828        63,505
- ---------------------------------- ------------- -------------- -------------
Other                                   12,590         12,820        13,131
- ---------------------------------- ------------- -------------- -------------
                                      $169,659       $168,783      $170,983
- ---------------------------------- ------------- -------------- -------------
Pipeline and Storage Throughput - (MMcf)

- --------------------------------- ------------- -------------- -------------
Year Ended September 30              2000           1999          1998
- --------------------------------- ------------- -------------- -------------
Firm Transportation                   291,818        300,242       298,738
Interruptible Transportation           21,730          8,061        14,310
- --------------------------------- ------------- -------------- -------------
                                      313,548        308,303       313,048
- --------------------------------- ------------- -------------- -------------
2000 Compared with 1999
Operating revenues increased $0.9 million in 2000 compared with 1999. The increase resulted primarily from higher firm transportation revenue of $1.0 million, higher interruptible transportation and interruptible storage service revenues of $0.8 million, offset by lower firm storage service revenue of $0.8 million. The increase in firm transportation revenues resulted primarily from a $1.3 million "pass-through" type item (which did not recur in 2000) that reduced revenues in the prior year and correspondingly reduced O&M expense in the prior year, thus having no earnings impact. The increase in interruptible transportation and interruptible storage service revenues is principally the result of higher throughput volumes. The decrease in firm storage service revenue was the result of discounted storage service rates, as well as the loss of certain storage service customers. However, for the 2001 winter heating season, all firm storage capacity has been subscribed.

     Transportation volumes in this segment increased 5.2 Bcf. Generally, volume fluctuations do not have a significant impact on revenues as a result of Supply Corporation's straight fixed-variable (SFV) rate design. However, as mentioned above, the higher interruptible volumes did add to revenues in 2000.

1999 Compared with 1998
Operating revenues decreased $2.2 million in 1999 compared with 1998. The decrease resulted primarily from lower firm transportation revenue of $2.1 million, lower interruptible transportation and interruptible storage service revenue of $0.6 million, offset in part by higher firm storage service revenue of $0.8 million. Approximately $1.0 million of the decrease in the firm transportation revenue related to a "pass- through" type item (mentioned above) that correspondingly reduced O&M expense, thus having no bottom line earnings impact. Interruptible transportation and interruptible storage service revenue decreased (and interruptible volumes transported decreased 6.2 Bcf) as a result of full storages at the beginning of the 1998-99 heating season and a warmer than normal winter in 1998-99; thus Supply Corporation lacked available storage space to service interruptible customers. Lower interruptible storage service generally results in lower interruptible transportation.

     Transportation volumes in this segment decreased 4.7 Bcf. Generally, volume fluctuations do not have a significant impact on revenues as a result of Supply Corporation's SFV rate design. However, as mentioned above, lower interruptible transportation volumes did negatively impact revenue for 1999.

Earnings

2000 Compared with 1999
Earnings in the Pipeline and Storage segment decreased $8.2 million in 2000 compared with 1999. In the current year increased SARs expense of $4.6 million (after tax) and the addition of $1.1 million of New York State income tax, resulting from recently enacted tax law changes in New York State, contributed to the decrease in earnings. The Federal Energy Regulatory Commission (FERC), which regulates this segment, has not provided for the recovery of additional taxes as has the New York Department of Public Service. Several items in the prior year, which did not recur in the current year, also contributed to 2000 earnings being less than 1999 earnings. The prior year's earnings included interest income of $1.2 million (after tax) and a reduction in income tax of $1.7 million related to the final settlement of IRS audits of years 1977-1994. In addition, 1999 included the recovery of $0.5 million (after tax) of costs related to a gathering project that had been previously reserved for and the recovery, through insurance, of $0.4 million (after tax) of a previously expensed base gas loss. These items were offset in part by a charge in 1999 for an early retirement of $0.9 million (after tax).

1999 Compared with 1998
Earnings in the Pipeline and Storage segment remained at $39.8 million for 1999 and 1998. Lower revenues, as discussed above, and nonrecurring income in 1998 from a buyout of a firm transportation agreement by a customer in the amount of $1.6 million (after tax), were offset by lower O&M and interest expenses in 1999. Items causing lower O&M expense in 1999 when compared to 1998 include the establishment of reserves in 1998 for preliminary survey and investigation costs associated with a proposed incremental expansion project and a natural gas gathering project (mainly due to lack of interest in furthering these projects). In addition, Supply Corporation recognized a base gas loss at its Zoar Storage Field in 1998. In total, these three items amounted to $2.4 million of after tax expense in 1998. In 1999, Supply Corporation reversed $0.5 million (after tax) of the gathering project reserve, and recovered, through insurance, $0.4 million (after tax) related to the Zoar base gas loss. Several significant items also increased O&M expense in 1999 when compared to 1998, including $0.9 million of after tax charges for early retirement offers in 1999 and the 1998 reversal of a portion of a reserve set up in a prior period for a storage project. Supply Corporation was able to recover approximately $0.7 million (after tax) by selling preliminary engineering, survey, environmental and archeological information from this storage project to the Independence Pipeline Company.

Exploration and Production

Revenues

Exploration and Production Operating Revenues

- -------------------------- ------------- -------------- -------------
Year Ended September 30
 (Thousands)2000           1999          1998
- -------------------------- ------------- -------------- -------------
  Gas (after Hedging)        $108,832        $83,229       $82,910
  Oil (after Hedging)         117,606         52,050        34,069
  Gas Processing Plant         17,666         11,751         4,937
  Other                        (6,034)           (36)        2,356
- -------------------------- ------------- -------------- -------------
                             $238,070       $146,994      $124,272
- -------------------------- ------------- -------------- -------------
Production Volumes

- -------------------------------------------- ------------- --------- ----------
Year Ended September 30                            2000      1999       1998
- -------------------------------------------- ------------- --------- ----------
Gas Production (million cubic feet)
  Gulf Coast                                     32,760    28,758     29,461
  West Coast                                      4,374     3,977      2,146
  Appalachia                                      4,344     4,431      4,867
  Canada                                            192         -          -
- -------------------------------------------- ------------- --------- ----------
                                                 41,670    37,166     36,474
- -------------------------------------------- ------------- --------- ----------
Oil Production (thousands of barrels)
  Gulf Coast                                      1,415     1,373      1,228
  West Coast                                      2,824     2,633      1,376
  Appalachia                                          9        10         10
  Canada                                            899         -          -
- -------------------------------------------- ------------- --------- ----------
                                                  5,147     4,016      2,614
- -------------------------------------------- ------------- --------- ----------
Average Prices

- ------------------------------------ ----------- ------------ -----------
Year Ended September 30                   2000         1999        1998
- ------------------------------------ ----------- ------------ -----------
Average Gas Price/Mcf
  Gulf Coast                             $3.29        $2.15       $2.40
  West Coast                             $3.62        $2.28       $2.14
  Appalachia                             $3.16        $2.44       $2.88
  Canada                                 $2.52            -           -
  Weighted Average                       $3.31        $2.20       $2.45
  Weighted Average After Hedging(1)      $2.61        $2.24       $2.27

Average Oil Price/bbl
  Gulf Coast                            $28.27       $15.18      $14.69
  West Coast(2)                         $23.87       $11.62       $9.85
  Appalachia                            $25.12       $14.73      $16.80
  Canada                                $29.28            -           -
  Weighted Average                      $26.03       $12.85      $12.15
  Weighted Average After Hedging(1)     $22.85       $12.96      $13.03
- ------------------------------------ ------------- ------------ -----------

(1) Refer to further discussion of hedging activities below under "Market Risk Sensitive Instruments" and in Note F - Financial Instruments in Item 8 of this report.

(2) Includes low gravity oil which generally sells for a lower price.

2000 Compared with 1999
Operating revenues increased $91.1 million in 2000 compared with 1999. Oil production revenues, net of hedging activities, increased $65.6 million as the weighted average price of oil after hedging increased 76% and production increased 28%, from the prior year. Oil production from Canadian wells acquired as part of the June 2000 acquisition of Tri Link Resources, Ltd. (Tri Link) now known as National Fuel Exploration Corp. (NFE), added $26.3 million to oil revenues. Gas production revenues, net of hedging activities, increased $25.6 million as production increased 12% and the weighted average price of gas after hedging increased 17%. Revenue from Seneca's gas processing plant was up $5.9 million. These items were partly offset by a $6.0 million decrease in other revenues resulting primarily from mark-to-market and other revenue adjustments related to written options. Refer to further discussion of these and other derivative financial instruments in the "Market Risk Sensitive Instruments" section that follows and in Note F - Financial Instruments in Item 8 of this report.

1999 Compared with 1998
Operating revenues increased $22.7 million in 1999 compared with 1998. Oil production revenues, net of hedging activities, increased $18.0 million as production increased 54% (mainly the result of West Coast production from the properties acquired in 1998). Gas production revenue, net of hedging activities, increased $0.3 million due to higher production (also mainly the result of West Coast production from the properties acquired in 1998). Revenue from Seneca's gas processing plant was up $6.8 million. These items were partly offset by a negative mark-to-market revenue adjustment of $1.3 million related to written options.

Earnings

2000 Compared with 1999
In the Exploration and Production segment, 2000 earnings of $34.9 million were up $27.8 million when compared with 1999. NFE added $6.4 million to 2000 earnings. As discussed above, significant improvement in oil and gas pricing, combined with an increase in production, were the main reasons for higher earnings. Partly offsetting higher revenues was an increase in production related expenses, including higher depletion, an increase in lease operating costs, and higher production taxes. In addition, general and administrative expenses were up as a result of higher costs associated with labor and benefits (including SARs expense), and interest expense increased due to higher borrowings related to the acquisition of Tri Link. The increase in the gas processing plant revenue of $5.9 million was offset by an equal amount of related expense increase.

1999 Compared with 1998
In the Exploration and Production segment, 1999 earnings of $7.1 million were down $7.9 million (exclusive of the two non-cash special items in 1998) when compared with 1998. This is largely because the settlement of the primary issues of IRS audits of years 1977-1994 had a positive impact on earnings in 1998. Absent the IRS audit items, earnings of the Exploration and Production segment were down $1.4 million from 1998. Depressed oil and gas prices for much of 1999 were the main reason for these lower earnings. Higher oil and gas production revenue, as noted in the revenue section above, was offset by increases in lease operating, depletion and interest expense related mainly to Seneca's acquisition activity in 1998. The increase in the gas processing plant revenue of $6.8 million was largely offset by an increase in related expenses of $6.2 million.

International

Revenues

International Operating Revenues

- ----------------------------- ------------- -------------- -------------
Year Ended September 30
(Thousands) 2000           1999          1998
- ----------------------------- ------------- -------------- -------------

   Heating                         $69,387        $71,974       $49,560
   Electricity                      31,426         34,158        22,774
   Other                             3,923            913         3,925
- ----------------------------- ------------- -------------- -------------
                                  $104,736       $107,045       $76,259
- ----------------------------- ------------- -------------- -------------
International Heating and Electric Volumes

- ------------------------------------- ------------- ------------ -----------
Year Ended September 30                       2000         1999        1998
- ------------------------------------- ------------- ------------ -----------


   Heating Sales (Gigajoules) (1)      10,222,024   10,047,042   7,116,776
   Electricity Sales (megawatt hours)   1,147,303    1,138,980     763,848

- ------------------------------------- ------------- ------------ -----------

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


2000 Compared with 1999
Operating revenues decreased $2.3 million in 2000 compared with 1999. The decrease in revenues is largely due to the decrease in value of the Czech koruna (CZK) as compared to the U.S. dollar. While higher heating and electricity sales contributed to higher operating revenues (in CZK), the decrease in value of the CZK caused an overall decrease in revenues when translated into U.S. dollars.

1999 Compared with 1998
Operating revenues increased $30.8 million in 1999 compared with 1998. The increase in revenues as well as the increase in heat and electric volumes, as shown in the tables above, reflects the fact that 1999 was the first year in which a full twelve months of sales and revenues are included for PSZT (now part of the combined company known as UE). Sales and revenues for 1998 include only eight months of activity as PSZT was acquired in February 1998.

Earnings

2000 Compared with 1999
The International segment's 2000 earnings were $3.3 million, or $1.0 million higher than 1999 earnings. This increase can be attributed to lower O&M expense, an income tax adjustment that benefited earnings in 2000, and additional consideration received in 2000 on the sale of a previously written-off project. These were partly offset by a decrease in margin and the negative impact of the decline in the exchange rate, as discussed above.

1999 Compared with 1998
The International segment's 1999 earnings were $2.3 million, or $1.0 million higher than 1998 earnings. Earnings for 1999 reflect a full twelve months of results from PSZT, while 1998 only included eight months of earnings. The contribution from these additional months in 1999 was offset in part by higher interest expense during 1999. In addition, 1998 earnings included a $2.7 million (after tax) net gain associated with U.S. dollar denominated debt, which did not recur in 1999. This debt was converted to a Czech koruna denominated loan in December 1998.

Energy Marketing

Revenues

Energy Marketing Operating Revenues

- ----------------------------------- -------------- --------------- ------------
Year Ended September 30
(Thousands)2000           1999          1998
- ----------------------------------- -------------- --------------- ------------

Natural Gas (after Hedging)             $139,614        $97,514      $86,877
Electricity                                1,941          1,551          253
Other                                     (7,626)            23           57
- ----------------------------------- -------------- -------------- ------------
                                        $133,929        $99,088      $87,187
- ----------------------------------- -------------- -------------- ------------
Energy Marketing Volumes

- ----------------------------------- ------------- -------------- -----------
Year Ended September 30                    2000           1999        1998
- ----------------------------------- ------------- -------------- -----------

Natural Gas - (MMcf)                     35,465         34,454      26,453
- ----------------------------------- ------------- -------------- -----------
2000 Compared with 1999
Operating revenues increased $34.8 million in 2000 compared with 1999. The primary reason for this increase is the higher gas costs that are reflected in the natural gas marketing revenues. In addition, higher marketing volumes reflect an increase in NFR customers from 17,480 at September 30, 1999 to 33,115 at September 30, 2000. Almost 89% of the increase in customers were residential customers. These higher revenues were offset in part by a negative $8.6 million mark-to-market adjustment related to certain derivative financial instruments (included in "Other" on the table above). See further discussion of NFR's use of derivatives in the "Market Risk Sensitive Instruments" section that follows and in Note F - Financial Instruments in Item 8 of this report.

1999 Compared with 1998
Operating revenues increased $11.9 million in 1999 compared with 1998. This increase reflected higher marketing volumes as NFR customers increased from 5,476 at September 30, 1998 to 17,480 at September 30, 1999. Over 75% of the increase in customers were residential customers.

Earnings

2000 Compared with 1999
The Energy Marketing segment incurred a loss for 2000 of $7.8 million, a decrease of approximately $9.9 million over 1999 earnings of $2.1 million. The most significant reasons for the decrease were mark-to-market losses related to certain derivative financial instruments of $5.6 million (after tax), the accrual of a $1.6 million (after tax) loss contingency on the unhedged portion of this segment's fixed price sales contracts for sale of natural gas to customers in 2001, and higher expenses including interest.

1999 Compared with 1998
The Energy Marketing segment's 1999 earnings were $2.1 million, an increase of $1.3 million over 1998 earnings. Volumes of natural gas marketed increased 30% to 34.5 Bcf in 1999 from 26.5 Bcf in 1998 and margins were also up from 1998. These positive contributions to earnings were partly offset by higher expenses for labor, office expense and advertising.

Timber

Revenues

Timber Operating Revenues

- -------------------------- --------------- ---------------- -------------
Year Ended September 30
(Thousands)2000             1999          1998
- -------------------------- --------------- ---------------- -------------

Log Sales                        $24,091          $18,276        $9,157
Green Lumber Sales                 4,397            4,018         4,119
Kiln Dry Lumber Sales             10,152            8,197         3,991
Other                                532              626           538
- -------------------------- --------------- ---------------- -------------
                                 $39,172          $31,117       $17,805
- -------------------------- --------------- ---------------- -------------
Timber Board Feet

- --------------------------- --------------- ---------------- -------------
Year Ended September 30
(Thousands)2000             1999          1998
- --------------------------- --------------- ---------------- -------------

Log Sales                           9,370            6,902         2,794
Green Lumber Sales                  8,193            8,541         7,634
Kiln Dry Lumber Sales               6,987            5,711         2,710
- --------------------------- --------------- ---------------- -------------
                                   24,550           21,154        13,138
- --------------------------- --------------- ---------------- -------------
2000 Compared with 1999
Operating revenues for the Timber segment increased $8.1 million. This increase was primarily the result of higher log sales and kiln dry lumber sales. Log sales are up due mainly to higher board feet of cherry veneer and export logs sold and higher average prices. The increase in kiln dry lumber sales is due to the operating of additional kilns brought on line in 1999 that were operational for a full 12 months in 2000 and the addition of two more kilns brought on line in August 2000.

1999 Compared with 1998
Operating revenues for the Timber segment increased $13.3 million. This increase was primarily the result of higher log sales and kiln dry lumber sales. Revenue growth reflects the increased investment by this segment in timber and sawmills.

Earnings

2000 Compared with 1999
Timber segment earnings of $6.1 million in 2000 were up $1.4 million when compared with 1999. The increase was due to higher operating revenues, as mentioned above, and an after tax gain on the sale of land and standing timber of $1.5 million. These items were partly offset by higher interest expense resulting from higher debt related to the PennzEnergy Company acquisition in July 1999 and by higher operating expenses.

1999 Compared with 1998
Timber segment earnings of $4.8 million in 1999 were up $2.9 million when compared with 1998. As noted above, timber revenues increased by 75% in 1999. These higher revenues were partly offset by higher O&M and interest expenses. Earnings growth reflects the increased investment by this segment in timber and sawmills.

Other Income and Interest Charges
Although most of the variances in Other Income items and Interest Charges are discussed in the earnings discussion by segment above, following is a summary on a consolidated basis:

Other Income
Other income decreased $1.9 million in 2000 compared with 1999. This decrease resulted from $3.2 million of interest income related to the final settlement of IRS audits for years 1977-1994 which was recorded during 1999, as well as a $2.4 million gain recorded in 1999 which resulted from the demutualization of an insurance company. As a policyholder, the Company received stock of the insurance company as part of its initial public offering. Neither of these items recurred in 2000. Partly offsetting this decrease was a $2.6 million gain on the sale of land and standing timber in 2000, as well as $0.5 million of additional consideration received in 2000 on the sale of a previously written-off project in the International segment.

     Other income decreased $23.5 million in 1999 compared with 1998. This decrease was primarily due to a decrease in interest income related to the settlement of IRS audits. In 1999 and 1998, $3.1 million and $18.5 million, respectively, of interest income was recognized related to these audits. Lower other income in 1999 also reflects two items recorded in 1998: a net gain of $5.1 million associated with U.S. dollar denominated debt in the International segment and a buyout of a firm transportation agreement by a Pipeline and Storage segment customer in the amount of $2.5 million. Partly offsetting these items was a $2.4 million gain recorded in 1999 resulting from the demutualization of an insurance company.

Interest Charges
Interest on long-term debt increased $1.8 million in 2000 and $12.2 million in 1999. The increase in both years can be attributed mainly to a higher average amount of long-term debt outstanding. Long-term debt balances have grown significantly over the past several years primarily as a result of acquisition activity in the Exploration and Production and International segments.

     Other interest charges increased $10.6 million in 2000 and decreased $9.8 million in 1999. The increase in 2000 was primarily the result of higher weighted average interest rates and higher average amounts of short-term debt outstanding. As discussed in "Financing Cash Flow" below, the acquisition of Tri Link was financed with short-term debt. The decrease in 1999 compared to 1998 resulted primarily from $11.7 million of interest expense recorded in 1998 related to the settlement of IRS audits. Partly offsetting this decrease in 1999, interest on short-term debt increased mainly as a result of higher average amounts of debt outstanding.

Outlook for 2001*
This outlook for 2001 section contains forward-looking statements, all of which are based on current expectations. There is no assurance that the Company's projections will in fact be achieved and these projections do not reflect any acquisitions or divestitures which may occur in 2001. Reference should be made to the various important factors listed under the heading "Safe Harbor for Forward-Looking Statements" that could cause actual future results to differ materially.

     The Company expects that earnings for 2001 will fall within the range of $168 million to $172 million, or $4.25 per basic common share to $4.35 per basic common share.* Higher earnings in the Exploration and Production segment is the main driver of the expected increase in earnings for 2001 as compared with actual earnings for 2000.* Production estimates for 2001 are in the range of 95 to 100 Bcfe (with oil representing 54% of that production).* Spot price assumptions for 2001 are $3.98 per Mcf for natural gas and $25.51 per bbl for crude oil.* Information on the Exploration and Production segment's hedging program is provided in the "Market Risk Sensitive Instruments" section that follows.

     In the Utility segment, earnings are expected to be down in 2001 as compared with 2000.* The overall rate of return (operating income after income tax) is expected to be about 9% on an average rate base for 2001 of $623 million for the New York jurisdiction and about 9.5% on an average rate base for 2001 of $242 million in the Pennsylvania jurisdiction.* These figures compare to 2000's actual return on rate base of 10.1% in New York and 9.9% in Pennsylvania. The expected decrease in New York reflects the recent rate settlement with the NYPSC whereby rates in the New York jurisdiction are reduced by $10 million for 2001. In addition, the rate settlement reduced the targeted return on equity, above which earnings are shared 50% with rate payers, from 12% to 11.5%.

     In the Pipeline and Storage segment, 2001 earnings are expected to increase as the overall rate of return on rate base should increase from 10.6% in 2000 to about 12 to 12.5% in 2001 on an average rate base in 2001 of $407 million.* Anticipated O&M savings is a significant reason for this increase.* In the International segment, earnings for 2001 are anticipated to be close to 2000 earnings after a reduction for the non-recurring income tax adjustment of $1.8 million that is included in 2000 earnings.*

     In the Energy Marketing segment, 2001 earnings are expected to be at break even or a slight loss.* In the Timber segment, earnings for 2001 should be flat to slightly up as compared with 2000 earnings.* Earnings for all other, including Corporate, are expected to be flat to down slightly as compared with 2000 earnings.*

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
(Millions)2000          1999       1998
- ---------------------------------- ----------------- ------------- -------------

Provided by Operating Activities             $238.2        $267.5    $249.9
Capital Expenditures                         (269.4)       (256.1)   (390.1)
Investment in Subsidiaries,
  Net of Cash Acquired                       (123.8)         (5.8)   (112.0)
Investment in Partnerships                     (4.4)         (3.6)     (5.5)
Other Investing Activities                     13.3           6.7       7.6
Short-Term Debt, Net Change                   226.5          67.2     229.4
Long-Term Debt, Net Change                    (18.1)        (15.6)     94.9
Issuance of Common Stock                       14.3          10.7       7.9
Dividends Paid on Common Stock                (73.0)        (69.9)    (67.0)
Dividends Paid to Minority
  Interest                                     (0.2)         (0.2)     (0.3)
Effect of Exchange Rates on Cash               (0.5)         (2.1)      1.6
- ---------------------------------- ----------------- ------------- ----------
Net Increase (Decrease) in Cash
  and Temporary Cash Investments               $2.9         $(1.2)   $16.4
- ---------------------------------- ----------------- ------------- ----------
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, deferred income taxes, minority interest in foreign subsidiaries, the cumulative effect of a change in accounting for depletion (1998) and the impairment of oil and gas producing properties (1998).

     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 SFV rate design.

     Net cash provided by operating activities totaled $238.2 million in 2000, a decrease of $29.3 million compared with the $267.5 million provided by operating activities in 1999. The decrease is attributable primarily to higher gas costs in the Utility and Energy Marketing segments stemming from rising natural gas prices. In the Utility segment, any unrecovered gas costs are deferred for future recovery. Partially offsetting this negative impact to cash provided by operating activities, the Exploration and Production segment experienced an increase in cash provided by operating activities. Higher cash receipts from the sale of oil and gas production resulted from higher production and significantly higher prices.

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 $398.8 million in 2000. The table below presents these expenditures by business segment:


- ----------------------------------------- ---------------- ---------------- -------------
                                                                           Total
                                                       Investments   Expenditures
                                          Capital               in           For
                                                      Corporations         Long-
Year Ended September 30, 2000
(Millions)                           Expenditures               or         Lived
                                                      Partnerships        Assets
- ---------------------------------- ---------------- ---------------- -------------
Utility                                    $55.8             $  -         $55.8
Pipeline and Storage                        34.0(1)            1.8         35.8
Exploration and Production                 156.2             123.8        280.0
International                                9.8                -           9.8
Energy Marketing                             0.1                -           0.1
Timber                                      13.6                -          13.6
All Other                                    1.1               2.6          3.7
- ---------------------------------- ---------------- ---------------- -------------
                                          $270.6(1)         $128.2       $398.8
- ---------------------------------- ---------------- ---------------- -------------

(1) Includes non-cash acquisition of $1.2 million in a stock-for-asset swap.

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 capital expenditures were made for additions, improvements, and replacements to this segment's transmission and storage systems. Of the total capital expenditures, $9.2 million was related to the acquisition of another company's interest in the Niagara Spur Loop Line and the Ellisburg-Leidy pipeline in January 2000. This acquisition was financed with short-term borrowings. The capital expenditures also include approximately $1.2 million for natural gas wells and related pipelines as well as some undeveloped timber property acquired from Cunningham Natural Gas Corporation (Cunningham) in November 1999. These assets were acquired through the issuance of 54,674 shares of the Company's common stock. In addition to the assets identified above, the Company received Cunningham's temporary cash investments in exchange for the shares of Company common stock.

     During 2000, SIP made a $1.8 million investment in Independence Pipeline Company, a Delaware general partnership (Independence), and had an aggregate investment balance of $13.7 million at September 30, 2000. This investment represents a one-third partnership interest. The investment has been financed with short-term borrowings. Independence intends to build a 400-mile natural gas pipeline (the Independence Pipeline) from Defiance, Ohio to Leidy, Pennsylvania at an estimated cost of $680 million.* If construction never begins on the Independence Pipeline project, the Company's share of the development costs (including SIP's investment in Independence) is estimated not to exceed $15.0 million.*

     On July 12, 2000, the FERC issued a Certificate of Public Convenience and Necessity (the Certificate) authorizing, among other things, the construction and operation of the Independence Pipeline, subject to satisfaction of various conditions spelled out in the Certificate and in previous FERC orders. Among those conditions is the requirement that, before construction may commence, Independence must file at FERC executed, firm transportation agreements with "no out" clauses for at least 68.2% of its capacity. (Independence already filed, on June 26 and July 6, 2000, precedent agreements for firm transportation amounting to about 38% of the capacity of the Independence Pipeline, thereby satisfying a FERC requirement previously imposed as a precondition to FERC's issuance of the Certificate.) The Independence Pipeline partners are working on obtaining the required customer commitments. The Certificate also requires that the Independence Pipeline be constructed and placed in service by July 12, 2003. Assuming contracts are in place in quantities satisfactory to the partners, the Independence Pipeline's planned in service date is November 1, 2002.*

     The Certificate also includes an environmental condition that Independence file an "implementation plan" within 60 days after Independence accepted the Certificate. In October and November 2000, Independence timely filed a preliminary implementation plan which included a request for an extension of time to provide certain technical information, in order to allow the remaining field surveys (for example, for endangered species) to be commenced in spring 2001. This timing would be consistent with Independence's planned in service date of November 1, 2002, and the Certificate's deadline of July 12, 2003 to complete construction. On November 20, 2000, a FERC official issued a letter requiring Independence to file a full implementation plan, including the necessary technical information, by May 1, 2001, and warning that if Independence cannot comply with these terms, its Certificate authority could be in jeopardy. This letter also requires Independence to file monthly status reports on environmental permitting and land acquisition activities. It is possible that Independence will be unable to file timely an implementation plan which meets the requirements set out in the November 20 letter, and that Independence's application could be dismissed.*

Exploration and Production
The Exploration and Production segment capital expenditures included approximately $113.6 million for the Company's offshore program in the Gulf of Mexico, including offshore drilling expenditures, offshore construction, lease acquisition costs and geological and geophysical expenditures. The remaining $42.6 million of capital expenditures included onshore drilling, construction and recompletion costs for wells located in Louisiana, Texas, California and Canada as well as onshore geological and geophysical costs, including the purchase of certain 3-D seismic data and fixed asset purchases.

     In June 2000, the Company acquired the outstanding shares of Tri Link, a Calgary, Alberta based oil and gas exploration and production company. This acquisition built the Company's total reserve base to approximately one trillion cubic feet equivalent.* The cost of acquiring the outstanding shares of Tri Link was approximately $123.8 million. The acquisition was financed with short-term borrowings. Refer to "Financing Cash Flow" for a discussion of the redemption of the debt that was assumed as part of the Tri Link acquisition.

International
The majority of the International segment capital expenditures were concentrated in the areas of improvements and replacements within the district heating and power generation plants in the Czech Republic.

Energy Marketing
The Energy Marketing capital expenditures consisted primarily of furniture, equipment and computer hardware and software.

Timber
The majority of the Timber segment's capital expenditures consisted of the purchase of land and timber in Pennsylvania, and the construction or purchase of new facilities and equipment for this segment's sawmill and kiln operations.

All Other
Expenditures for Long-Lived Assets for all other subsidiaries consisted of the purchase of a 50% interest in a gas processing facility and the purchase of a 50% partnership interest in Seneca Energy II, LLC which generates and sells electricity to a public utility by using methane gas obtained from a landfill owned by an outside party.

Other Investing Activities
Other cash provided by or used in investing activities primarily reflects cash received on the sale of investments in property, plant and equipment.

Estimated Capital Expenditures
The Company's estimated capital expenditures for the next three years are:*


- ------------------------------------------- ------------ ------------ ------------
Year Ended September 30 (Millions)                2001         2002         2003
- ------------------------------------------- ------------ ------------ ------------
Utility                                          $49.8        $48.1        $47.1
Pipeline and Storage                              38.2         26.6         19.9
Exploration and Production                       164.9        180.8        202.1
International                                     15.5          2.5          2.5
Timber                                             5.0          5.0          5.0
- ------------------------------------------- ------------ ------------ ------------
                                                $273.4       $263.0       $276.6
- ------------------------------------------- ------------ ------------ ------------

     Estimated capital expenditures for the Utility segment in 2001 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 2001 will be concentrated in the reconditioning of storage wells and the replacement of storage and transmission lines.* The estimated capital expenditures also include $5.0 million for an increase in horsepower at the Ellisburg, Pennsylvania compressor station.* In addition, $8.1 million has been budgeted for the construction of a transmission line from Lamont, Pennsylvania to Roystone, Pennsylvania.*

     Estimated capital expenditures in 2001 for the Exploration and Production segment include approximately $105.4 million for the onshore program ($59.6 million in Canada).* Of this amount, approximately $59.9 million ($46.0 million in Canada) is intended to be spent on exploratory and development drilling.* The estimated expenditures also include approximately $59.5 million for the offshore program in the Gulf of Mexico.* Of this amount, approximately $49.9 million is intended to be spent on exploratory and development drilling.*

     The estimated capital expenditures for the International segment in 2001 include approximately $13.0 million for the construction of a boiler at a district heating and power generation plant in the Czech Republic.* The new boiler will replace an existing boiler. Other capital expenditures will be concentrated on smaller improvements and replacements within the district heating and power generation plants.*

     Estimated capital expenditures in the Timber segment will be concentrated in the purchase of land and timber as well as the construction or purchase of new facilities and equipment for this segment's sawmill and kiln operations.*

     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 storage facilities and the expansion of transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company's other business segments depends, to a large degree, upon market conditions.*

Financing Cash Flow

Consolidated short-term debt increased $226.5 million during 2000. The Company continues to consider short-term debt an important source of cash for temporarily financing capital expenditures and investments in corporations 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.

     In June 2000, the Company paid approximately $99.2 million to redeem the bank loans and convertible debentures of Tri Link. These redemptions were financed with short-term debt.

     In February 2000, the Company issued $150.0 million of 7.30% medium-term notes due in February 2003. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $149.3 million. The proceeds of this debt issuance were used to redeem $50.0 million of 6.60% medium-term notes which matured in February 2000 and to reduce short-term debt.

     The Company's present liquidity position is believed to be adequate to satisfy known demands.* Under the Company's existing indenture covenants, at September 30, 2000, the Company would have been permitted to issue up to a maximum of $487.0 million in additional long-term unsecured indebtedness at projected market interest rates. In addition, at September 30, 2000, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $130.5 million of short-term debt.

     The Company's embedded cost of long-term debt was 7.0% at both September 30, 2000 and 1999, respectively.

     In March 1998, the Company obtained authorization from the Securities and Exchange Commission (SEC), under the Holding Company Act, to issue long-term debt securities and equity securities in amounts not exceeding $2.0 billion at any one time outstanding during the order's authorization period, which extends to December 31, 2002. In August 1999, the Company registered $625.0 million of debt and equity securities under the Securities Act of 1933. After the November 2000 medium-term note issuance discussed below, the Company currently has $275.0 million of debt and equity securities registered under the Securities Act of 1933.

     In November 2000, the Company issued $200.0 million of 7.50% medium-term notes due in November 2010. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $197.3 million. The proceeds of this debt issuance were used to reduce short-term debt.

     The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, regulatory authorizations, and the requirements of the Company.

     The Company is involved in litigation arising in the normal course of business. The Company is involved in regulatory matters arising in the normal course of business that involve 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 year 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.*

Market Risk Sensitive Instruments

Energy Commodity Price Risk
The Company, primarily in its Exploration and Production and Energy Marketing segments, 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 have to pay the respective counterparties at September 30, 2000 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 Company may be exposed to credit risk on some of these derivatives. 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.

     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 prices as of September 30, 2000. At September 30, 2000, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2003.

Natural Gas Price Swap Agreements


- ---------------------------------------- ----------------------------------------
                                                  Expected Maturity Dates
                                         ----------------------------------------
                                             2001      2002       2003     Total
- ---------------------------------------- ---------- --------- ---------- ---------

Notional Quantities (Equivalent Bcf)         17.9      25.8        1.2      44.9
Weighted Average Fixed Rate (per Mcf)       $2.79     $3.75      $2.78     $3.34
Weighted Average Variable Rate (per Mcf)    $4.79     $4.80      $4.76     $4.79
- ---------------------------------------- ---------- --------- ---------- ---------

Crude Oil Price Swap Agreements


- ---------------------------------------- --------------------------------------------------
                                                       Expected Maturity Dates
                                         --------------------------------------------------
                                              2001         2002         2003        Total
- ---------------------------------------- ----------- ------------ ------------ ------------

Notional Quantities (Equivalent bbls)    3,717,915    4,840,980    1,803,000   10,361,895
Weighted Average Fixed Rate (per bbl)       $21.04       $22.98       $19.93       $21.75
Weighted Average Variable Rate (per bbl)    $33.87       $33.87       $33.87       $33.87
- ---------------------------------------- ----------- ------------ ------------ ------------

     At September 30, 2000, the Company would have had to pay the respective counterparties an aggregate of approximately $54.8 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have had to pay an aggregate of approximately $51.4 million to the counterparties to terminate the crude oil price swap agreements outstanding at September 30, 2000.

     At September 30, 1999, the Company had natural gas price swap agreements covering 40.2 Bcf at a weighted average fixed rate of $2.69 per Mcf. The Company also had crude oil price swap agreements covering 2,296,000 bbls at a weighted average fixed rate of $19.00 per bbl. As can be seen from the September 30, 2000 tables above, the Company has significantly increased its use of crude oil price swap agreements, which is primarily attributable to the increase in crude oil production that will be experienced as a result of the Tri Link acquisition in 2000. Tri Link (or NFE, as it is now known), primarily produces crude oil.

     The following tables disclose 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, 2000, the Company had not entered into any natural gas or crude oil no cost collars extending beyond 2004.

No Cost Collars



- ------------------------------------------------------------------------------
                                              Expected Maturity Dates
                                    -----------------------------------------
                                      2001      2002      2003     2004      Total
- --------------------------------------------- --------- --------- ------- ---------
Crude Oil
   Notional Quantities (Equivalent  1,995,000 1,335,000 1,125,000 270,000 4,725,000
   bbls)
   Weighted Average Ceiling Price      $30.07    $28.26    $26.41  $25.80    $28.44
  (per bbl)
   Weighted Average Floor Price (per   $23.24    $21.91    $21.96  $22.00    $22.49
   bbl)
Natural Gas
   Notional Quantities (Equivalent        6.6         -         -       -       6.6
   Bcf)
   Weighted Average Ceiling Price       $5.75         -         -       -     $5.75
   (per Mcf)
   Weighted Average Floor Price (per    $3.83         -         -       -     $3.83
   Mcf)
- --------------------------------------------- --------- --------- ------- ---------

     At September 30, 2000, the Company would have had to pay the respective counterparties an aggregate of approximately $0.9 million to terminate the natural gas no cost collars outstanding at that date. The Company would have had to pay an aggregate of approximately $4.9 million to terminate the crude oil no cost collars outstanding at that date.

     At September 30, 1999, the Company did not have any no cost collars outstanding. During 2000, the Company began entering into no cost collars on the basis of obtaining better value for its crude oil and natural gas production than could be experienced through the use of price swap agreements only. The concentration of the no cost collars in crude oil is attributable to the crude oil production from NFE, as discussed above.

     The following table discloses the net notional quantities, 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, 2000, the Company held no futures contracts with maturity dates extending beyond 2002.

Futures Contracts



- ----------------------------------------------------------------------------------
                                                        Expected Maturity Dates
                                                   -------------------------------
                                                       2001       2002     Total
- -------------------------------------------------- ---------- ---------- ---------

Contract Volumes Purchased (Sold) (Equivalent Bcf)    (3.9)       -(1)     (3.9)
Weighted Average Contract Price (per Mcf)             $4.23    $3.57       $4.20
Weighted Average Settlement Price (per Mcf)           $5.28    $4.77       $5.25
- -------------------------------------------------- ---------- ---------- ---------

(1) Volumes purchased amount to approximately 38,000 Mcf.

     At September 30, 2000, the Company would have had to pay $5.5 million to terminate these futures contracts.

     At September 30, 1999, the Company had futures contracts covering 1.2 Bcf (net long position) at a weighted average contract price of $2.76 per Mcf.

     The following table discloses the notional quantities and weighted average strike prices by expected maturity dates for options used by the Company to manage natural gas and crude oil price risk. At September 30, 2000, the Company held no options with maturity dates extending beyond 2001.

Options Purchased



- ------------------------------------------- ----------------------------------
                                               Expected Maturity Date - 2001
- ------------------------------------------- ----------------------------------
Natural Gas
   Notional Quantities (Equivalent Bcf)                       31.1
   Weighted Average Strike Price (per Mcf)                   $4.76
- ------------------------------------------- ----------- ----------------------

Options Sold


- ------------------------------------------- ----------------------------------
                                               Expected Maturity Date - 2001
- ------------------------------------------- ----------------------------------
Natural Gas
   Notional Quantities (Equivalent Bcf)                           37.9
   Weighted Average Strike Price (per Mcf)                       $4.76
- ------------------------------------------- ----------- ---------------- -----
Crude Oil
   Notional Quantities (Equivalent bbls)                       368,000
   Weighted Average Strike Price (per bbl)                      $15.25
- ------------------------------------------- ----------- ---------------- -----

     At September 30, 2000, the Company would have had to pay $9.8 million to terminate these options.

     At September 30, 1999, the Company had purchased crude oil options outstanding covering 1,464,000 bbls at a weighted average strike price of $20.00 per bbl. The Company also had purchased natural gas options outstanding at September 30, 1999 covering 9.0 Bcf at a weighted average strike price of $2.72 per Mcf. The Company had sold crude oil options outstanding at September 30, 1999 covering 1,832,000 bbls at a weighted average strike price of $15.25 per bbl. The Company also had sold natural gas options outstanding at September 30, 1999 covering 31.0 Bcf at a weighted average strike price of $2.84 per Mcf.

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. During 2000, the Czech koruna decreased in value in relation to the U.S. dollar resulting in a $23.1 million negative adjustment to the Cumulative Foreign Currency Translation Adjustment (CTA) (a component of Accumulated Other Comprehensive Income). The Canadian dollar decreased in value in relation to the U.S. dollar resulting in a $4.3 million negative adjustment to the CTA. Further valuation changes to the Czech koruna and Canadian dollar would result in corresponding positive or negative adjustments to the CTA. Management cannot predict whether the Czech koruna or Canadian dollar will increase or decrease in value against the U.S. dollar.*

Interest Rate Risk
The Company's exposure to interest rate risk primarily consists of short-term debt instruments. At September 30, 2000, these instruments included short-term bank loans and commercial paper totaling $601.2 million (domestically). The interest rate on these short-term bank loans and commercial paper approximated 6.7%. The Company's short-term debt instruments also included $18.3 million of short-term bank loans in the Czech Republic at September 30, 2000. The interest rate on the Czech Republic loans approximated 5.7%.

     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 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, 2000:


- ------------------------------------------------------------------------------------- --------
                                 Principal Amounts by Expected Maturity Dates
                                ---------------------------------------------

(Millions of Dollars)          2001   2002  2003   2004  2005  Thereafter  Total
- ------------------------------------------------------------------------------

National Fuel Gas Company
Long-Term Fixed Rate Debt         $-    $-  $150  $225    $-    $549      $924
Weighted Average Interest
   Rate Paid                      -%    -%  7.3%  7.3%    -%    6.6%      6.9%
Fair Value =  $887.2 million
- ----------------------------------------------------------------------------

Other Notes

Long-Term Debt(1)              $11.3  $8.5  $8.6  $8.7  $2.7    $1.1     $40.9
Weighted Average Interest
  Rate Paid                     6.0%  5.9%  5.9%  5.9%  5.9%    6.0%      5.9%
Fair Value = $40.9 million
- ----------------------------------------------------------------------------

(1) $37.8 million is variable rate debt; $3.1 million is fixed rate debt.

     The Company utilizes an interest rate swap to eliminate interest rate fluctuations on its CZK 1,356,534,000 term loan ($33.7 million at September 30, 2000), which carries a variable interest rate of six month Prague Interbank Offered Rate (PRIBOR) plus 0.475%. Under the terms of the interest rate swap, which extends until 2002, the Company pays a fixed rate of 8.31% and receives a floating rate of six month PRIBOR. The Company would have paid approximately $1.4 million to settle the interest rate swap at September 30, 2000.

RATE MATTERS

Utility Operation

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) that establishes rates for a three-year period beginning October 1, 2000. The Agreement provides that customers will receive a bill credit of $17.6 million in the first year, of which $7.6 million relates to customers' share of earnings accumulated under previous settlements. The credit will be reduced to $5.0 million in the second year, and in the third and subsequent years the credit will remain at $5.0 million unless the Company can demonstrate that it is no longer justified. Also, earnings beyond a target level of 11.5% return on equity will be shared equally between shareholders and ratepayers. The Agreement provides further that the Company and interested parties will resume discussions to address the NYPSC's competition initiatives, including changes to "customer choice" transportation services, among other things. Those discussions are currently under way.

     On November 3, 1998, the NYPSC issued its Policy Statement Concerning the Future of the Natural Gas Industry in New York State and Order Terminating Capacity Assignment (Policy Statement). The Policy Statement sets forth the NYPSC's "vision" on "how best to ensure a competitive market for natural gas in New York." That vision includes the following goals:

  1. Effective competition in the gas supply market for retail customers;
  2. Downward pressure on customer gas prices;
  3. Increased customer choice of gas suppliers and service options;
  4. A provider of last resort (not necessarily the utility);
  5. Continuation of reliable service and maintenance of operations procedures that treat all participants fairly;
  6. Sufficient and accurate information for customers to use in making informed decisions;
  7. The availability of information that permits adequate oversight of the market to ensure fair competition; and
  8. Coordination of Federal and State policies affecting gas supply and distribution in New York State.

     The Policy Statement provides that the most effective way to establish a competitive market in gas supply is "for local distribution companies to cease selling gas." The NYPSC indicated in its order that it hopes to accomplish that objective over a three-to-seven year transition period from the date the Policy Statement was issued, taking into account "statutory requirements" and the individual needs of each local distribution company (LDC).* The Policy Statement directs Staff to schedule "discussions" with each LDC on an "individualized plan that would effectuate our vision." In preparation for negotiations, LDCs will be required to address issues such as a strategy to hold new capacity contracts to a minimum, a long-term rate plan with a goal of reducing or freezing rates, and a plan for further unbundling. In addition, Staff was instructed to hold collaborative sessions with multiple parties to discuss generic issues including reliability and market power regulation. Distribution Corporation has participated in the collaborative sessions. These collaborative sessions have not yet produced a consensus document on all issues before the NYPSC. Distribution Corporation will continue to participate in all future collaborative sessions.*

     On March 22, 2000, the NYPSC issued an order directing electric and gas utilities to file tariff amendments "to accommodate the wishes of retail access customers who prefer to receive combined, single bills from either their utility company or their [marketer]" (Billing Order). The tariff amendments will provide for marketer single-bill or utility single-bill services, thereby allowing a customer to choose a billing preference through the customer's choice of suppliers - utility or marketer. Distribution Corporation has permitted marketer single billing since 1996.

     On November 1, 2000, Distribution Corporation filed tariff amendments in compliance with the Billing Order (and a subsequent order on rehearing of the Billing Order). Consistent with the provisions of the Billing Order, Distribution Corporation's filing proposes to maintain its long-standing marketer single-bill model and add a permanent version of a utility-provided competitive single-bill service that has been available since May 2000. In addition, the filing proposes a credit (called a "backout credit"), available to marketers that issue single retail bills, equal to the long-run marginal cost of billing services avoided by Distribution Corporation. Based on the methodology set forth in the Billing Order, Distribution Corporation calculated a backout credit of $0.66 per bill avoided. The charge for Distribution Corporation's competitive billing service was set at $0.71 (with a backout credit). The company's filing proposed an effective date of February 1, 2001 and is subject to review and approval by the NYPSC. At this time, Distribution Corporation is unable to ascertain the outcome of this proceeding.*

     On March 30, 2000, a collaborative was convened to address the NYPSC's Order Instituting Proceeding in the so-called "Provider of Last Resort" (POLR) case. The collaborative was charged with the task of helping the NYPSC to "refine our concept of the mature competitive retail energy markets (especially the future role of the regulated utilities) and to identify and remove obstacles to its achievement." The parties in this case are addressing, among other things, issues arising from utilities exiting the merchant function. The proceeding is also focusing on utilities' responsibility to provide low-income assistance programs. Currently the parties are collaborating on a periodic basis and are in the process of identifying issues for further review. At this time, Distribution Corporation is unable to ascertain the outcome of the POLR proceeding.*

     On April 12, 2000, the NYPSC issued an order setting forth procedures for implementation of electronic data interchange (EDI) for electronic exchange of retail access data in New York (EDI Order). As described by the NYPSC, EDI is the computer-to-computer exchange of routine business information in a standard form. The NYPSC believes that EDI is necessary to develop uniform data exchange protocol for the state's customer choice initiatives. The EDI Order adopts provisions of a report prepared after an EDI collaborative involving utilities, marketers and other interests. Distribution Corporation submitted its EDI implementation plans on May 31, 2000. Implementation of EDI is expected to begin on a limited, test-only basis during the fourth quarter of calendar 2000. At this time, Distribution Corporation is unable to ascertain the outcome of the EDI proceeding.*

     The NYPSC continues to address, through various proceedings and "collaboratives," upstream pipeline capacity issues arising from the restructuring. At this point, Distribution Corporation remains authorized to release upstream intermediate capacity to marketers serving former sales customers. Costs relating to retained upstream transmission capacity are recovered through a transition cost surcharge. At this time, Distribution Corporation does not foresee any material changes to upstream capacity requirements in the near term.*

     On May 15, 2000, the New York State tax law was amended to phase out the long-running tax on utility gross revenues beginning January 1, 2001. Offsetting the scheduled reductions, however, is the imposition of a net income based tax on the same utilities. In a report issued on October 13, 2000, the New York Department of Public Service recommended, among other things, that utilities be kept whole for any tax increases resulting from implementation of the changes. Toward that end, the report proposes that the mechanism in rates currently used for recovery of the gross revenue tax be utilized to collect the new income tax. To the extent a utility's income tax liability exceeds the amount collectible through the existing gross revenue tax recovery mechanism, deferral accounting would be authorized. The New York Department of Public Service's report is subject to review and approval by the NYPSC after the close of the public comment period on December 18, 2000. Distribution Corporation plans to file tariff amendments revising its tax recovery mechanism consistent with the New York Department of Public Service's recommendations. At this time, Distribution Corporation is unable to ascertain the outcome of this proceeding.*

Pennsylvania Jurisdiction

Distribution Corporation currently does not have a rate case on file with the Pennsylvania Public Utility Commission (PaPUC). Management will continue to monitor its financial position in the Pennsylvania jurisdiction to determine the necessity of filing a rate case in the future.

     A natural gas restructuring bill was signed into law on June 22, 1999. Entitled the Natural Gas Choice and Competition Act (Act), the new law requires all Pennsylvania LDCs to file tariffs designed to provide retail customers with direct access to competitive gas markets. Distribution Corporation submitted its compliance filing on October 1, 1999 for an effective date on or about July 1, 2000. The filing largely mirrored Distribution Corporation's System Wide Energy Select program previously in effect, which substantially complied with the Act's requirements. After negotiations with PaPUC Staff and intervenors, a settlement was reached with all parties except for the Pennsylvania Office of Consumer Advocate (OCA). The settlement parties generally agreed that Distribution Corporation's proposal needed only modest changes to meet the requirements of the Act. Hearings were held and briefs filed on OCA's open issues. In a Recommended Decision issued on March 31, 2000, the Administrative Law Judge rejected the OCA's arguments and recommended approval of the settlement agreement. On June 29, 2000, the PaPUC entered an Opinion and Order adopting the settlement, with immaterial changes. Distribution Corporation's restructured rates and services became effective on July 1, 2000.

     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.

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.

Other Matters

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 in the range of $6.4 million to $7.6 million.* The minimum liability of $6.4 million has been recorded on the Consolidated Balance Sheet at September 30, 2000. Other than discussed in Note H (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 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 Note H - Commitments and Contingencies under the heading "Environmental Matters" in Item 8 of this report.

New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). This statement was subsequently amended by SFAS 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133," and by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of Statement 133." For a discussion of the impact on the Company, see disclosure in Note A - Summary of Significant Accounting Policies in Item 8 of this report.

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 combined Annual Report to Shareholders/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 herein, including those which are designated with a "*", are forward-looking statements 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 statement:

  1. Changes in economic conditions, demographic patterns and weather conditions;
  2. Changes in the availability or price of natural gas and oil;
  3. Inability to obtain new customers or retain existing ones;
  4. Significant changes in competitive factors affecting the Company;
  5. Governmental/regulatory actions and initiatives, including those affecting acquisitions, financings, allowed rates of return, industry and rate structure, franchise renewal, and environmental/safety requirements;
  6. Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;
  7. Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs;
  8. The nature and projected profitability of pending and potential projects and other investments;
  9. Occurrences affecting the Company's ability to obtain funds from operations, debt or equity to finance needed capital expenditures and other investments;
  10. Uncertainty of oil and gas reserve estimates;
  11. Ability to successfully identify and finance oil and gas property acquisitions and ability to operate and integrate existing and any subsequently acquired business or properties;
  12. Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves;
  13. Changes in the availability or price of derivative financial instruments;
  14. Changes in the price of natural gas or oil and the related effect given the accounting treatment or valuation of these financial instruments;
  15. Inability of the various counterparties to meet their obligations with respect to the Company's financial instruments;
  16. Regarding foreign operations - changes in foreign trade and monetary policies, laws and regulations related to foreign operations, political and governmental changes, inflation and exchange rates, taxes and operating conditions;
  17. Significant changes in tax rates or policies or in rates of inflation or interest;
  18. Significant changes in the Company's relationship with its employees and the potential adverse effects if labor disputes or grievances were to occur; or
  19. Changes in accounting principles or the application of such principles to the Company.
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

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Refer to the "Market Risk Sensitive Instruments" section in Item 7, MD&A.

ITEM 8 Financial Statements and Supplementary Data

Back to Table of Contents

Index to Financial Statements

Financial Statements:

Report of Independent Accountants

Consolidated Statements of Income and Earnings Reinvested in the Business, three years ended September 30, 2000

Consolidated Balance Sheets at September 30, 2000 and 1999

Consolidated Statement of Cash Flows, three years ended September 30, 2000

Consolidated Statement of Comprehensive Income, three years ended September 30, 2000

Notes to Consolidated Financial Statements

     Financial Statement Schedules:
       For the three years ended September 30, 2000

II-Valuation and Qualifying Accounts

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 K - Quarterly Financial Data (unaudited) and Note M - Supplementary Information for Oil and Gas Producing Activities, appears under this Item, and reference is made thereto.

Report of Management

Management is responsible for the preparation and integrity of the Company's financial statements. The financial statements have been prepared in accordance with generally accepted accounting principles and necessarily include some amounts that are based on management's best estimates and judgment.

     The Company maintains a system of internal accounting and administrative controls and an ongoing program of internal audits that management believes provide reasonable assurance that assets are safeguarded and that transactions are properly recorded and executed in accordance with management's authorization. The Company's financial statements have been examined by our independent accountants, PricewaterhouseCoopers LLP, which also conducts a review of internal controls to the extent required by generally accepted auditing standards.

     The Audit Committee of the Board of Directors, composed solely of outside directors, meets with management, internal auditors and PricewaterhouseCoopers LLP to review planned audit scope and results and to discuss other matters affecting internal accounting controls and financial reporting. The independent accountants have direct access to the Audit Committee and periodically meet with it without management representatives present.

Report of Independent Accountants

Back to Index of Financial Statements

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, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2000, 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 auditing standards generally accepted in the United States of America, which 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.





PricewaterhouseCoopers LLP


Buffalo, New York
October 23, 2000

National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business


- ------------------------------------------------- -------------- ------------- --------------
Year Ended September 30 (Thousands of Dollars,
  Except Per Common Share Amounts)2000           1999          1998
- ------------------------------------------------- -------------- ------------- --------------
IncomeOperating Revenues$1,425,277    $1,263,274     $1,248,000
- ------------------------------------------------- -------------- ------------- --------------
Operating Expenses
   Purchased Gas                                       503,617       405,925        441,746
   Fuel Used in Heat and Electric Generation            54,893        55,788         37,837
   Operation                                           326,933       304,919        295,618
   Maintenance                                          23,450        23,881         25,793
   Property, Franchise and Other Taxes                  78,878        91,146         92,817
   Depreciation, Depletion and Amortization            142,170       124,778        117,238
   Impairment of Oil and Gas Producing
     Properties                                              -             -        128,996
   Income Taxes                                         77,068        64,829
                                                                                     24,024
- ------------------------------------------------- -------------- ------------- --------------
                                                     1,207,009     1,071,266      1,164,069
- ------------------------------------------------- -------------- ------------- --------------
Operating Income  218,268       192,008         83,931
Other Income   10,408        12,343
                                                                                     35,870
- ------------------------------------------------- -------------- ------------- --------------
Income Before Interest Charges and
  Minority Interest in Foreign Subsidiaries  228,676       204,351        119,801
- ------------------------------------------------- -------------- ------------- --------------
Interest Charges
   Interest on Long-Term Debt                           67,195        65,402         53,154
   Other Interest                                       32,890        22,296
                                                                                     32,130
- ------------------------------------------------- -------------- ------------- --------------
                                                       100,085        87,698
                                                                                     85,284
- ------------------------------------------------- -------------- ------------- --------------
Minority Interest in Foreign Subsidiaries   (1,384)       (1,616)
                                                                                     (2,213)
- ------------------------------------------------- -------------- ------------- --------------
Income Before Cumulative Effect  127,207       115,037         32,304
Cumulative Effect of Change in
     Accounting for Depletion                                -             -
                                                                                     (9,116)
- ------------------------------------------------- -------------- ------------- --------------
 Net Income Available for Common Stock                 127,207       115,037         23,188
- ------------------------------------------------- -------------- ------------- --------------
Earnings Reinvested in the Business
Balance at Beginning of Year                           472,517       428,112        472,595
- ------------------------------------------------- -------------- ------------- --------------
                                                       599,724       543,149        495,783
Dividends on Common Stock                               73,877        70,632
                                                                                     67,671
- ------------------------------------------------- -------------- ------------- --------------
Balance at End of Year $525,847      $472,517       $428,112
- ------------------------------------------------- -------------- ------------- --------------
Basic Earnings Per Common Share:
  Income Before Cumulative Effect                        $3.25         $2.98          $0.85
  Cumulative Effect of Change in Accounting
    For Depletion                                            -             -          (0.24)
- ------------------------------------------------- -------------- ------------- --------------
  Net Income Available for Common Stock                  $3.25         $2.98          $0.61
- ------------------------------------------------- -------------- ------------- --------------
Diluted Earnings Per Common Share:
  Income Before Cumulative Effect                        $3.21         $2.95          $0.84
  Cumulative Effect of Change in Accounting
    For Depletion                                            -             -          (0.24)
- ------------------------------------------------- -------------- ------------- --------------
  Net Income Available for Common Stock                  $3.21         $2.95          $0.60
- ------------------------------------------------- -------------- ------------- --------------
Weighted Average Common Shares Outstanding:
  Used in Basic Calculation                         39,116,921    38,663,981     38,316,397
  Used in Diluted Calculation                       39,583,100    39,041,728     38,703,526
- ------------------------------------------------- -------------- ------------- --------------

See Notes to Consolidated Financial Statements

Back to Index of Financial Statements

National Fuel Gas Company
Consolidated Balance Sheets



- ------------------------------------------------- --------------- ---------------

At September 30 (Thousands of Dollars)2000            1999
- ------------------------------------------------- --------------- ---------------

AssetsProperty, Plant and Equipment$3,829,637      $3,390,875
  Less - Accumulated Depreciation,
    Depletion and Amortization                        1,146,246       1,029,643
- ------------------------------------------------- --------------- ---------------
                                                      2,683,391       2,361,232
- ------------------------------------------------- --------------- ---------------

Current Assets
  Cash and Temporary Cash Investments                    32,125          29,222
  Receivables - Net                                     122,127          97,828
  Unbilled Utility Revenue                               27,105          18,674
  Gas Stored Underground                                 55,795          41,099
  Materials and Supplies - at average cost               25,145          23,631
  Unrecovered Purchased Gas Costs                        29,681           4,576
  Prepayments                                            32,293          35,072
- ------------------------------------------------- --------------- ---------------
                                                        324,271         250,102
- ------------------------------------------------- --------------- ---------------

Other Assets
  Recoverable Future Taxes                               84,199          87,724
  Unamortized Debt Expense                               19,841          21,717
  Other Regulatory Assets                                17,518          25,214
  Deferred Charges                                       12,497          14,266
  Other                                                  95,171          82,331
- ------------------------------------------------- --------------- ---------------
                                                        229,226         231,252
- ------------------------------------------------- --------------- ---------------
                                                     $3,236,888      $2,842,586
- ------------------------------------------------- --------------- ---------------

See Notes to Consolidated Financial Statements

Back to Index of Financial Statements

National Fuel Gas Company
Consolidated Balance Sheets


- -------------------------------------------------- ------------- -------------

At September 30 (Thousands of Dollars)2000          1999
- -------------------------------------------------- ------------- -------------
Capitalization and LiabilitiesCapitalization:Common Stock Equity
  Common Stock, $1 Par Value
    Authorized  - 200,000,000 Shares; Issued and
    Outstanding - 39,329,803 Shares and 38,837,499
    Shares, Respectively                             $  39,330     $  38,837
  Paid In Capital                                      452,217       431,952
  Earnings Reinvested in the Business                  525,847       472,517
  Accumulated Other Comprehensive Income               (29,957)       (4,013)
- -------------------------------------------------- ------------- -------------
Total Common Stock Equity987,437       939,293
Long-Term Debt, Net of Current Portion953,622       822,743
- -------------------------------------------------- ------------- -------------
Total Capitalization1,941,059     1,762,036
- -------------------------------------------------- ------------- -------------
Minority Interest in Foreign Subsidiaries23,031        27,589
- -------------------------------------------------- ------------- -------------
Current and Accrued Liabilities
  Notes Payable to Banks and
    Commercial Paper                                   619,502       393,495
  Current Portion of Long-Term Debt                     11,262        69,608
  Accounts Payable                                      88,970        82,747
  Amounts Payable to Customers                           9,583         5,934
  Other Accruals and Current Liabilities                84,961        87,310
- -------------------------------------------------- ------------- -------------
                                                       814,278       639,094
- -------------------------------------------------- ------------- -------------
Deferred Credits
  Accumulated Deferred Income Taxes                    326,994       275,008
  Taxes Refundable to Customers                         14,410        14,814
  Unamortized Investment Tax Credit                      9,951        11,007
  Other Deferred Credits                               107,165       113,038
- -------------------------------------------------- ------------- -------------
                                                       458,520       413,867
- -------------------------------------------------- ------------- -------------
Commitments and Contingencies-             -
- -------------------------------------------------- ------------- -------------
                                                    $3,236,888    $2,842,586
- -------------------------------------------------- ------------- -------------

See Notes to Consolidated Financial Statements

Back to Index of Financial Statements

National Fuel Gas Company
Consolidated Statement of Cash Flows


- ------------------------------------------------------- ------------- ------------- --------------
Year Ended September 30 (Thousands of Dollars)2000          1999           1998
- ------------------------------------------------------- ------------- ------------- --------------
Operating Activities
  Net Income Available for Common Stock                   $127,207      $115,037       $ 23,188
  Adjustments to Reconcile Net Income to Net Cash
    Provided by Operating Activities
      Cumulative Effect of a Change in Accounting
        for Depletion                                            -             -          9,116
      Impairment of Oil and Gas Producing Properties             -             -        128,996
      Depreciation, Depletion and Amortization             142,170       124,778        117,238
      Deferred Income Taxes                                 41,858        14,030        (26,237)
      Minority Interest in Foreign Subsidiaries              1,384         1,616          2,213
      Other                                                  4,540         7,018         (6,378)
      Change in:
        Receivables and Unbilled Utility Revenue           (26,825)      (18,161)        45,200
        Gas Stored Underground and Materials and
            Supplies                                       (13,707)       (7,280)        (2,744)
        Unrecovered Purchased Gas Costs                    (25,105)        1,740         (6,316)
        Prepayments                                          3,436       (15,322)           829
        Accounts Payable                                   (16,372)       22,871        (24,975)
        Amounts Payable to Customers                         3,649           153         (4,735)
        Other Accruals and Current Liabilities              (4,642)       10,931        (15,481)
        Other Assets                                         8,537          (906)            36
        Other Liabilities                                   (7,884)       10,999          9,913
- ------------------------------------------------------- ------------- ------------- --------------
Net Cash Provided by Operating Activities238,246       267,504        249,863
- ------------------------------------------------------- ------------- ------------- --------------
Investing Activities
  Capital Expenditures                                    (269,371)     (256,120)      (390,118)
  Investment in Subsidiaries, Net of Cash Acquired        (123,809)       (5,774)      (111,966)
  Investment in Partnerships                                (4,442)       (3,633)        (5,453)
  Other                                                     13,283         6,687          7,583
- ------------------------------------------------------- ------------- ------------- --------------
Net Cash Used in Investing Activities(384,339)     (258,840)      (499,954)
- ------------------------------------------------------- ------------- ------------- --------------
Financing Activities
  Change in Notes Payable to Banks and Commercial
    Paper                                                  226,477        67,195        229,387
  Net Proceeds from Issuance of Long-Term Debt             149,334       198,217        198,750
  Reduction of Long-Term Debt                             (167,426)     (213,849)      (103,867)
  Proceeds from Issuance of Common Stock                    14,278        10,735          7,853
  Dividends Paid on Common Stock                           (73,046)      (69,878)       (66,959)
  Dividends Paid to Minority Interest                         (152)         (246)          (253)
- ------------------------------------------------------- ------------- ------------- --------------
Net Cash Provided by (Used in) Financing Activities 149,465        (7,826)       264,911
- ------------------------------------------------------- ------------- ------------- --------------
Effect of Exchange Rates on Cash    (469)       (2,053)         1,578
- ------------------------------------------------------- ------------- ------------- --------------
Net Increase (Decrease) in Cash and  Temporary Cash Investments          2,903        (1,215)        16,398
Cash and Temporary Cash Investments  at Beginning of Year               29,222        30,437         14,039
- ------------------------------------------------------- ------------- ------------- --------------
Cash and Temporary Cash Investments  at End of Year                   $ 32,125      $ 29,222       $ 30,437
- ------------------------------------------------------- ------------- ------------- --------------
Supplemental Disclosure of Cash Flow InformationCash Paid For:   Interest                                      $97,042       $75,813        $46,242
   Income Taxes                                   41,928        48,995         64,537
- ------------------------------------------------------- ------------- ------------- --------------

See Notes to Consolidated Financial Statements

Back to Index of Financial Statements

National Fuel Gas Company
Consolidated Statement of Comprehensive Income


- ---------------------------------------------- --------------------------------------------------------------
Year Ended September 30 (Thousands of
Dollars)
                                               --------------------------------------------------------------
                                                        2000                   1999                 1998
                                               -------------------- --------------------- -------------------

Net Income Available for Common Stock                   $127,207             $115,037              $23,188
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Foreign Currency Translation Adjustment                  (27,463)             (11,737)               9,350
Unrealized Gain on Securities Available for
    Sale Arising During the Period                         2,441                  706                    -
Reclassification Adjustment for Gains on
    Securities Available for Sale Realized
in Net                                                      (103)                   -                    -
    Income
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Other Comprehensive Income (Loss), Before
    Tax:                                                 (25,125)             (11,031)               9,350
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Income Tax Expense Related to Unrealized
   Gain on Securities Available for Sale
Arising                                                      855                  247                    -
   During the Period
Reclassification Adjustment for Income Tax
    Expense on Gains on Securities Available
    for Sale Realized in Net Income                         (36)                    -                    -
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Income Taxes - Net                                           819                  247                    -
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Other Comprehensive Income (Loss), Net of
    Tax                                                  (25,944)             (11,278)               9,350
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Comprehensive Income                                    $101,263             $103,759              $32,538
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------

See Notes to Consolidated Financial Statements

Back to Index of Financial Statements

National Fuel Gas Company

Notes to Consolidated Financial Statements

Back to Index of 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 generally accepted accounting principles 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 generally accepted accounting principles, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note B - Regulatory Matters for further discussion.

     In the International segment, rates charged for the sale of thermal energy and electric energy at the retail level are subject to regulation and audit in the Czech Republic by the Czech Ministry of Finance. The regulation of electric energy rates at the retail level indirectly impacts the rates charged by the International segment for its electric energy sales at the wholesale level.

Revenues
Revenues are recorded 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.

Unrecovered Purchased Gas Costs and Refunds
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.

     Estimated refund liabilities to ratepayers represent management's current estimate of such refunds. Reference is made to Note B - Regulatory Matters for further discussion.

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. Due to significant declines in oil prices in 1998, capitalized costs under the full-cost method of accounting exceeded these limits at March 31, 1998. The Company was required to recognize an impairment of its oil and gas producing properties in the quarter ended March 31, 1998. This charge amounted to $129.0 million (pretax) and reduced net income for 1998 by $79.1 million.

     Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries' property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.

Depreciation, Depletion and Amortization
Depreciation, depletion and amortization are computed by application of either the straight-line method or the units of production method, in amounts sufficient to recover costs over the estimated service lives of property in service, and for oil and gas properties, based on quantities produced in relation to proved reserves (see discussion of change in method of depletion for oil and gas properties below). The costs of unevaluated oil and gas properties are excluded from this computation. For timber properties, depletion, determined on a property by property basis, is charged to operations based on the annual amount of timber cut in relation to the total amount of recoverable timber. The provisions for depreciation, depletion and amortization, as a percentage of average depreciable property, were 4.2% in 2000, 4.1% in 1999 and 4.3% in 1998 on a consolidated basis.

Cumulative Effect of Change in Accounting
Effective October 1, 1997, the Company changed its method of depletion for oil and gas properties from the gross revenue method to the units of production method. The units of production method was applied retroactively to prior years to determine the cumulative effect through October 1, 1997. This cumulative effect reduced earnings for 1998 by $9.1 million, net of income tax. Depletion of oil and gas properties for 2000, 1999 and 1998 was computed under the units of production method.

Gas Stored Underground - Current
In the Utility segment, gas stored underground - current in the amount of $29.3 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 2000, 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 $104.2 million at September 30, 2000. All other gas stored underground - current is carried at lower of cost or market on either an average cost or first-in, first-out method.

Unamortized Debt Expense
Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related issues. 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. 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.

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 undistributed earnings of foreign subsidiaries as the amounts are considered to be permanently reinvested outside the U.S.

Financial Instruments
Unrealized gains or losses from the Company's investments in marketable equity securities are recorded as a component of Accumulated Other Comprehensive Income. Reference is made to Note F - Financial Instruments for further discussion.

     The Company uses a variety of financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments can be categorized as price swap agreements, no cost collars, options and futures contracts. Gains or losses from price swap agreements are accrued in operating revenues at the contract settlement dates. Options and futures contracts that have not been designated as hedges are marked-to-market on a quarterly basis with gains or losses recorded in operating revenues. For options that have been designated as hedges, premiums are amortized on a straight-line basis over the life of the option. Gains or losses resulting from the exercise of options that have been designated as hedges are reflected in operating revenues when the hedged commodity transaction occurs. Gains or losses from futures contracts that have been designated as hedges are recorded in other deferred credits or deferred debits until the hedged commodity transaction occurs, at which point they are reflected in operating revenues.

     The Company also uses an interest rate swap to eliminate interest rate fluctuations on certain variable rate debt. Gains or losses are accrued in interest charges at the contract settlement dates.

     In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). This statement was subsequently amended by SFAS 137, "Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133," and by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of Statement 133." SFAS 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement requires the Company to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The intended use of the derivatives and their designation as either a fair value hedge, a cash flow hedge, or a foreign currency hedge will determine when the gains or losses on the derivatives are to be reported in earnings and when they are to be reported as a component of other comprehensive income. The Company will adopt SFAS 133, as amended, during the first quarter of fiscal 2001. The cumulative effect of this change will decrease fiscal 2001 net income by approximately $0.3 million after tax. The cumulative effect of this change will decrease other comprehensive income by approximately $69.8 million after tax.

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


- ------------------------------------------------------ ------------- --------------
Year Ended September 30 (Thousands)2000           1999
- ------------------------------------------------------ ------------- --------------

Cumulative Foreign Currency Translation Adjustment        $(31,935)       $(4,472)

Net Unrealized Gain on Securities Available for Sale          1,978            459
- ------------------------------------------------------ ------------- --------------

Accumulated Other Comprehensive Loss                      $(29,957)       $(4,013)
- ------------------------------------------------------ ------------- --------------

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 generally three months or less to be cash equivalents.

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.

Note B - Regulatory Matters

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


- ------------------------------------------------------ ------------ -----------
At September 30 (Thousands)2000        1999
- ------------------------------------------------------ ------------ -----------
Regulatory Assets:
Recoverable Future Taxes (Note C)                          $84,199     $87,724
Unrecovered Purchased Gas Costs (Note A)                    29,681       4,576
Unamortized Debt Expense (Note A)                           13,454      15,223
Pension and Post-Retirement Benefit Costs (Note G)          16,370      21,217
Other                                                        1,148       3,997
- ------------------------------------------------------ ------------ -----------
     Total Regulatory Assets                               144,852     132,737
- ------------------------------------------------------ ------------ -----------
Regulatory Liabilities:
Amounts Payable to Customers (Note A)                        9,583       5,934
New York Rate Settlements                                   21,315      18,913
Taxes Refundable to Customers (Note C)                      14,410      14,814
Pension and Post-Retirement Benefit Costs(1)  (Note G)      17,439      26,087
Other(1)                                                     2,975       3,226
- ------------------------------------------------------ ------------ -----------
     Total Regulatory Liabilities                           65,722      68,974
- ------------------------------------------------------ ------------ -----------
Net Regulatory Position                                    $79,130     $63,763
- ------------------------------------------------------ ------------ -----------

(1) Included in Other Deferred Credits 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 their 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 a 12% return on equity (11.5% effective October 1, 2000) are to be shared equally between shareholders and ratepayers. As a result of this sharing mechanism, the Company had liabilities of $11.2 million and $8.6 million at September 30, 2000 and 1999, respectively. Of these amounts, $7.6 million and $3.0 million are included in Amounts Payable to Customers at September 30, 2000 and 1999, respectively, to reflect the amounts estimated to be passed back to customers in the following year. Other aspects of the settlements include a special reserve of $7.8 million and $7.4 million at September 30, 2000 and 1999, respectively, to be applied against the Company's incremental costs resulting from the NYPSC's gas restructuring effort and a "refund pool" of $5.6 million and $3.5 million at September 30, 2000 and 1999, respectively. The refund pool 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 $4.2 million and $2.5 million at September 30, 2000 and 1999, 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 (Thousands)2000        1999       1998
- ------------------------------------------- ------------- ----------- ----------
Operating Expenses:
  Current Income Taxes -
    Federal                                   $ 26,352    $ 43,467   $ 40,740
    State                                       13,067       6,215      6,635
  Deferred Income Taxes -
    Federal                                     29,604      11,149    (21,687)
    State                                        2,495       1,244     (5,997)
  Foreign Income Taxes                           5,550       2,754      4,333
- ------------------------------------------- ------------- ----------- ----------
                                                77,068      64,829     24,024
Other Income:
  Deferred Investment Tax Credit                (1,051)       (729)      (665)
Minority Interest in Foreign Subsidiaries         (259)       (642)    (1,218)
Cumulative Effect of Change in Accounting
  for Depletion                                      -           -     (5,737)
- ------------------------------------------- ------------- ----------- ----------
Total Income Taxes                            $ 75,758    $ 63,458   $ 16,404
- ------------------------------------------- ------------- ----------- ----------

The U.S. and foreign components of income (loss) before income taxes are as follows:

- ----------------------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands) 2000            1999          1998
- ----------------------------------------------------- ------------- -------------- -------------
U.S.                                                     $182,813        $169,038      $ 31,127
Foreign                                                    20,152           9,457         8,465
- ----------------------------------------------------- ------------- -------------- -------------
                                                         $202,965        $178,495      $ 39,592
- ----------------------------------------------------- ------------- -------------- -------------

     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 (Thousands)                    2000       1999      1998
- --------------------------------------------- --------------- ---------- ---------
Income Tax Expense, Computed at Federal
  Statutory Rate of 35%                            $ 71,038   $ 62,473  $ 13,857
Increase (Reduction) in Taxes Resulting from:
  State Income Taxes                                 10,115      4,848       986
  Depreciation                                        1,925      1,872     2,186
  Property Retirements                               (1,470)      (833)   (1,609)
  Keyman Life Insurance                                (964)      (502)     (774)
  Prior Years' Tax Adjustment                           137     (1,362)    2,846
  Miscellaneous                                      (5,023)    (3,038)  (1,088)
- --------------------------------------------- --------------- ---------- ---------
Total Income Taxes                                 $ 75,758   $ 63,458  $ 16,404
- --------------------------------------------- --------------- ---------- ---------

     Significant components of the Company's deferred tax liabilities and assets were as follows:


- ------------------------------------- ------------- ------------
At September 30 (Thousands)2000          1999
- ------------------------------------- ------------- ------------
Deferred Tax Liabilities:
  Property, Plant and Equipment          $375,660      $305,688
  Other                                    23,776        19,045
- ------------------------------------- ------------- ------------
Total Deferred Tax Liabilities            399,436       324,733
- ------------------------------------- ------------- ------------
Deferred Tax Assets:
  Other                                   (72,442)      (49,725)
- ------------------------------------- ------------- ------------
Total Net Deferred Income Taxes          $326,994      $275,008
- ------------------------------------- ------------- ------------

     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 $14.4 million and $14.8 million at September 30, 2000 and 1999, 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 $84.2 million and $87.7 million at September 30, 2000 and 1999, respectively.

Note D - Capitalization

Summary of Changes in Common Stock Equity


- --------------------- --------- ------------ ------------- ------------- -----------------
                                                              Earnings       Accumulated
                                                    Paid    Reinvested             Other
(Thousands, Except Per Share Common Stock             In        in the     Comprehensive
Amounts)                Shares       Amount       Capital      Business            Income
- ---------------------- --------- ------------- ------------- ------------- -----------------
Balance at
  September 30, 1997    38,166      $38,166      $405,028      $472,595          $(2,085)
Net Income Available
  for Common Stock                                               23,188
Dividends Declared
  on Common Stock
  ($1.77 Per Share)                                             (67,671)
Other Comprehensive
  Income, Net of Tax                                                                9,350
Common Stock Issued
  Under Stock and
  Benefit Plans            303          303        11,211
- ---------------------- --------- ------------ ------------- ------------- -----------------
Balance at
  September 30, 1998    38,469       38,469       416,239       428,112            7,265
Net Income Available
  for Common Stock                                              115,037
Dividends Declared on
  Common Stock
  ($1.83 Per Share)                                             (70,632)
Other Comprehensive
  Income, Net of Tax                                                             (11,278)
Common Stock Issued
  Under Stock and
  Benefit Plans            368          368        15,713
- ---------------------- --------- ------------ ------------- ------------- -----------------
Balance at
  September 30, 1999    38,837        38,837       431,952       472,517           (4,013)
Net Income Available
  for Common Stock                                               127,207
Dividends Declared on
  Common Stock
  ($1.89 Per Share)                                              (73,877)
Other Comprehensive
  Income, Net of Tax                                                              (25,944)
Acquisition of
  Natural Gas Assets        5555 2,757
Common Stock Issued
  Under Stock and
  Benefit Plans            43843817,508
- ---------------------- --------- ------------- ------------- ------------- -----------------
Balance at
  September 30, 2000    39,330$39,330$452,217$525,847(1)$(29,957)
- ---------------------- --------- ------------- ------------- ------------- -----------------

(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, 2000, $451.5 million of accumulated earnings was free of such limitations.

Common Stock
The Company has various plans which allow shareholders, customers and employees to purchase shares of Company common stock. The National Fuel Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends or make cash investments in the Company's common stock and provides residential customers the opportunity to acquire shares of Company common stock without the payment of any brokerage commissions or service charges in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in Company common stock, in addition to a variety of other investment alternatives. 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 agent.

     The Company also has a Director Stock Program under which it issues shares of 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.

     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 $130 per share, being $65 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 $.01 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.

Stock Option and Stock Award Plans
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, stock appreciation rights, 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.

     For the years ended September 30, 2000, 1999 and 1998, no compensation expense was recognized for options granted under these plans. Had compensation expense for stock options granted under the Company's stock option and stock award plans been determined based on fair value at the grant dates, the Company's net income and earnings per share would have been reduced to the pro forma amounts below:


- -------------------------------- ------------- -------------- -------------
Year Ended September 30                 2000           1999          1998
- -------------------------------- ------------- -------------- -------------
Net Income (Thousands):
     As reported                    $127,207       $115,037       $23,188
     Pro forma                      $123,107       $111,385       $18,859
Earnings Per Common Share:
     Basic - As reported               $3.25          $2.98         $0.61
     Basic - Pro forma                 $3.15          $2.88         $0.49
     Diluted - As reported             $3.21          $2.95         $0.60
     Diluted - Pro forma               $3.11          $2.85         $0.49
- -------------------------------- ------------- -------------- -------------

     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, 1997            2,174,346                 $33.21
Granted in 1998                                770,000                 $44.44
Exercised in 1998                            (205,200)                 $27.41
Forfeited in 1998                              (7,250)                 $41.68
- ------------------------------------- ------------------- ----------------------
Outstanding at September 30, 1998            2,731,896                 $36.79
Granted in 1999                                753,400                 $46.70
Exercised in 1999                             (111,504)                $28.41
Forfeited in 1999                               (9,700)                $37.41
- ------------------------------------- ------------------- ----------------------
Outstanding at September 30, 1999            3,364,092                 $39.29
Granted in 2000                                891,100                  $43.74
Exercised in 2000(1)                          (227,742)                 $30.16
Forfeited in 2000                              (13,900)                 $46.15
- ------------------------------------- ------------------- ----------------------
Outstanding at September 30, 2000            4,013,550                  $40.77
- ------------------------------------- ------------------- ----------------------
Option shares exercisable
at September 30, 2000                        3,005,354                  $39.63
Option shares available for future
  grant at September 30, 2000(2)             1,099,830
- ------------------------------------- ------------------- ----------------------

(1) In connection with exercising these options, 58,458, 16,531 and 44,580 shares were surrendered and canceled during 2000, 1999 and 1998, respectively.
(2) Including shares available for restricted stock grants.

     The weighted average fair value per share of options granted in 2000, 1999 and 1998 was $8.34, $7.43 and $7.91, 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                    2000         1999         1998
- -------------------------------------- --------------- ------------ -----------

Quarterly Dividend Yield                     1.07%        0.97%        0.98%
Annual Standard Deviation (Volatility)      19.05%       18.86%       16.48%
Risk Free Rate                               6.74%        4.74%        5.77%
Expected Term - in Years                       5.5          5.0          5.5
- -------------------------------------- --------------- ------------ -----------

     The following table summarizes information about options outstanding at September 30, 2000:


- ------------------------------------------------------------- --------------------------
                    Options Outstanding                          Options Exercisable
- ------------------------------------------------------------- --------------------------

                                        Weighted
                         Number          Average    Weighted        Number     Weighted
         Range of   Outstanding        Remaining     Average   Exercisable      Average
   Exercise Price    at 9/30/00      Contractual    Exercise    at 9/30/00     Exercise
                                            Life       Price                      Price
- ------------------ ------------- ---------------- ----------- ------------- ------------


 $23.81 - $35.72       697,026        3.8 years      $29.34       697,026       $29.34$35.73 - $49.72     3,316,524        7.8 years      $43.17     2,308,328       $42.73
- ------------------ ------------- ---------------- ----------- --------------- ------------

     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 being 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 options 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                       2000           1999          1998
- ------------------------------------- ------------- -------------- -------------
Shares of Restricted Stock Awarded           7,589          6,580         7,609
Weighted Average Market Price of
  Stock on Award Date                       $48.94         $46.06        $44.88
- ------------------------------------- ------------- -------------- -------------

     As of September 30, 2000, 75,693 shares of non-vested restricted stock were outstanding. Vesting restrictions will lapse as follows: 2001 - 35,104 shares; 2002 - 8,000 shares; 2003 - 12,925 shares; 2004 - 7,000 shares; 2005 - 6,000 shares; 2006 - 6,000 shares; and 2009 - 664 shares.

     Stock Appreciation Rights (SARs) give the grantee the right to cash compensation equal to the appreciation in the market price of Company common stock from the grant date to the exercise date. SARs are marked-to-market each quarter with the related increase or decrease in expense recognized in the income statement. At September 30, 2000, 1,381,000 SARs were outstanding at a weighted average exercise price of $38.54.

     Compensation expense related to SARs and restricted stock under the Company's stock plans was $14.9 million, $1.0 million and $4.1 million for the years ended September 30, 2000, 1999 and 1998, respectively.

Redeemable Preferred Stock
As of September 30, 2000, 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 (Thousands) 2000          1999
- ------------------------------------ -------------- -------------
Debentures:
    7-3/4% due February 2004            $125,000      $125,000
Medium-Term Notes:
    6.00% to 8.48% due February
    2000 to August 2027(1)               799,000       699,000
- ------------------------------------ -------------- -------------
                                         924,000       824,000
- ------------------------------------ -------------- -------------
Other Notes                               40,884        68,351
- ------------------------------------ -------------- -------------
Total Long-Term Debt                     964,884       892,351
Less Current Portion                      11,262        69,608
- ------------------------------------ -------------- -------------
                                        $953,622      $822,743
- ------------------------------------ -------------- -------------

(1)Includes $50 million of 8.48% medium-term notes due July 2024 which are callable at a redemption price of 105.94% through July 2001. The redemption price will decline in subsequent years. It also includes $100 million of 6.214% medium-term notes due August 2027 which are putable by debt holders only on August 12, 2002, at par.

     The aggregate principal amounts of long-term debt maturing for the next five years and thereafter are as follows: $11.3 million in 2001, $8.5 million in 2002, $158.6 million in 2003, $233.7 million in 2004, $2.7 million in 2005 and $550.1 million thereafter.

Note E - Short-Term Borrowings

The Company has SEC authorization under the Public Utility Holding Company Act of 1935, as amended, to borrow and have outstanding as much as $750.0 million of short-term debt at any time through December 31, 2002.

     The Company historically has borrowed short-term funds either through bank loans or the issuance of commercial paper. As for the former, the Company maintains uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines are revocable at the option of the financial institutions and are reviewed on an annual basis.

     At September 30, 2000, the Company had outstanding short-term notes payable to banks and commercial paper of $419.5 million (domestic = $401.2 million; foreign = $18.3 million) and $200.0 million, respectively. At September 30, 1999, the Company had outstanding notes payable to banks and commercial paper of $246.0 million (domestic = $244.8 million; foreign = $1.2 million) and $147.5 million, respectively.

     The weighted average interest rate on domestic notes payable to banks was 6.81% and 5.55% at September 30, 2000 and 1999, respectively. The interest rate on the foreign notes payable to banks was 5.73% and 6.35% at September 30, 2000 and 1999, respectively. The weighted average interest rate on commercial paper was 6.62% and 5.49% at September 30, 2000 and 1999, respectively.

Note F - Financial Instruments

Fair Values
The fair market value of the Company's long-term debt is estimated based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:


- ---------------------- ---------- ------------- -------------- -------------
                            20002000           1999          1999
                        Carrying  Fair       Carrying          Fair
At September 30
(Thousands)  Amount Value         Amount         Value
- ---------------------- ---------- ------------- -------------- -------------

Long-Term Debt          $964,884$928,066       $892,351      $867,056
- ---------------------- ---------- ------------- -------------- -------------

     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 amounts which approximate 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 a 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.

Investments
Other assets includes cash surrender values of insurance contracts and marketable equity securities. The cash surrender values of the insurance contracts amounted to $49.4 million and $44.2 million at September 30, 2000 and 1999, respectively. The marketable equity securities amounted to $10.0 million and $7.3 million at September 30, 2000 and 1999, respectively. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.

Derivative Financial Instruments
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with the fluctuations in the price of natural gas and crude oil. These instruments can be categorized as price swap agreements, no cost collars, options and futures contracts and are highly correlated with the physical side of the natural gas and crude oil transactions that are related to these instruments. The instruments are not held for trading purposes. The fair value of these instruments at September 30, 2000 is a net liability and is represented as the amount that the Company would have to pay to terminate the instruments. However, the calculation of this liability to the counterparties does not consider the physical side of the natural gas and crude oil transactions that are related to the financial instruments.

     Under the price swap agreements, the Company receives monthly payments from (or makes payments to) other parties based upon the difference between a fixed 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." At September 30, 2000, the Company had natural gas price swap agreements covering a notional amount of 44.9 Bcf extending through 2003 at a weighted average fixed rate of $3.34 per Mcf. The Company also had crude oil price swap agreements covering a notional amount of 10,361,895 bbls extending through 2003 at a weighted average fixed rate of $21.75 per bbl. At September 30, 2000, the Company would have had to pay $106.2 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 natural gas price quoted in "Inside FERC." At September 30, 2000, the Company had no cost collars on natural gas covering a notional amount of 6.6 Bcf extending through 2001 with a weighted average floor price of $3.83 per Mcf and a weighted average ceiling price of $5.75 per Mcf. The Company also had no cost collars on crude oil covering a notional amount of 4,725,000 bbls extending through 2004 with a weighted average floor price of $22.49 per bbl and a weighted average ceiling price of $28.44 per bbl. At September 30, 2000, the Company would have had to pay $5.8 million to terminate the no cost collars.

     At September 30, 2000, the Company had purchased options outstanding on natural gas covering a notional amount of 31.1 Bcf extending through 2001 at a weighted average strike price of $4.76 per Mcf. The Company also had sold options outstanding on natural gas covering a notional amount of 37.9 Bcf extending through 2001 at a weighted average strike price of $4.76 per Bcf. The Company also had sold options outstanding on crude oil covering a notional amount of 368,000 bbls extending through 2001 at a weighted average strike price of $15.25 per bbl. At September 30, 2000, the Company would have had to pay $9.8 million to terminate all of these options.

     At September 30, 2000, the Company had futures contracts covering 3.9 Bcf of gas on a net basis (net short position) extending through 2002 at a weighted average contract price of $4.20 per Mcf. The Company would have had to pay $5.5 million to terminate the futures contracts at September 30, 2000.

     The Company may be exposed to credit risk on some of its derivative financial instruments. 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.

     The Company uses an interest rate swap to eliminate interest rate fluctuations on certain variable rate debt. Under the terms of the interest rate swap, which extends until 2002, the Company pays a fixed rate of 8.31% and receives a floating rate of six month Prague Interbank Offered Rate (PRIBOR). At September 30, 2000, the Company would have had to pay $1.4 million to terminate the interest rate swap.

Note G - 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. Retirement Plan and Post-Retirement Plan assets primarily consist of equity and fixed income investments or units in commingled funds or money market funds.

     The Company is fully recovering 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, the difference between the amounts of pension cost and post-retirement benefit cost recoverable in rates and the amounts of such costs as determined by their actuary under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate. 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.

Retirement Plan
Reconciliations of the Benefit Obligation, Retirement Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions are as follows:


- -------------------------------------------- ------------- ----------- ----------
Year Ended September 30 (Thousands)2000        1999       1998
- -------------------------------------------- ------------- ----------- ----------
Change in Benefit Obligation
Benefit Obligation at Beginning of Period      $538,796    $532,250   $462,377
Service Cost                                     11,692      12,676     10,655
Interest Cost                                    37,954      36,299     35,485
Amendments                                            -       1,691          -
Actuarial (Gain) Loss                           (20,216)    (13,598)    52,446
Benefits Paid                                   (32,332)    (30,522)   (28,713)
- -------------------------------------------- ------------- ----------- ----------
Benefit Obligation at End of Period            $535,894    $538,796   $532,250
- -------------------------------------------- ------------- ----------- ----------
Change in Plan Assets
Fair Value of Assets at Beginning of Period    $537,958    $509,393   $473,205
Actual Return on Plan Assets                     36,584      47,888     59,415
Employer Contribution                            27,726      11,199      5,486
Benefits Paid                                   (32,332)    (30,522)   (28,713)
- -------------------------------------------- ------------- ----------- ----------
Fair Value of Assets at End of Period          $569,936    $537,958   $509,393
- -------------------------------------------- ------------- ----------- ----------
Reconciliation of Funded Status
Funded Status                                   $34,042       $(838)  $(22,857)
Unrecognized Net Actuarial Gain                 (62,008)    (45,853)   (12,659)
Unrecognized Transition Asset                   (11,148)    (14,864)   (18,580)
Unrecognized Prior Service Cost                  10,943      12,048     11,369
- -------------------------------------------- ------------- ----------- ----------
Accrued Benefit Cost                           $(28,171)   $(49,507)  $(42,727)
- -------------------------------------------- ------------- ----------- ----------


- ----------------------------------------------- ------------- -------------- -------------
                                                      2000           1999          1998
- ----------------------------------------------- ------------- -------------- -------------
Weighted Average Assumptions as of September 30
Discount Rate                                        7.50%          7.25%         7.00%
Expected Return on Plan Assets                       8.50%          8.50%         8.50%
Rate of Compensation Increase                        5.00%          5.00%         5.00%
- ----------------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands)Components of Net Periodic Benefit Cost
Service Cost                                      $ 11,692       $ 12,676      $ 10,655
Interest Cost                                       37,954         36,299        35,485
Expected Return on Plan Assets                     (41,077)       (38,158)      (35,724)
Amortization of Prior Service Cost                   1,106          1,012         1,065
Amortization of Transition Amount                   (3,716)       (3,716)        (3,716)
Recognition of Actuarial Loss                           60          2,833           981
Early Retirement Window                                  -          7,032             -
Net Amortization and Deferral for
  Regulatory Purposes                                  206          2,721         4,829
- ----------------------------------------------- ------------- -------------- -------------
Net Periodic Benefit Cost                          $ 6,225       $ 20,699      $ 13,575
- ----------------------------------------------- ------------- -------------- -------------

     The effect of the discount rate change in 2000 was to decrease the Benefit Obligation by $15.3 million as of the end of the period. The effect of the discount rate change in 1999 was to decrease the Benefit Obligation as of the end of the period by $15.9 million.

Other Post-Retirement Benefits
Reconciliations of the Benefit Obligation, Post-Retirement Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions are as follows:


- -------------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands)2000           1999          1998
- -------------------------------------------- ------------- -------------- -------------
Change in Benefit Obligation
Benefit Obligation at Beginning of Period     $ 255,615      $ 256,983      $218,370
Service Cost                                      4,156          4,493         4,022
Interest Cost                                    18,142         17,635        17,122
Plan Participants' Contributions                    414            673           867
Actuarial (Gain) Loss                              (355)       (13,542)       27,014
Benefits Paid                                   (11,512)       (10,627)     (10,412)
- -------------------------------------------- ------------- -------------- -------------
Benefit Obligation at End of Period           $ 266,460      $ 255,615      $256,983
- -------------------------------------------- ------------- -------------- -------------
Change in Plan Assets
Fair Value of Assets at Beginning of Period   $ 149,884      $ 122,870      $ 98,639
Actual Return on Plan Assets                     18,527         17,345        14,602
Employer Contribution                            19,044         19,623        19,174
Plan Participants' Contributions                    414            673           867
Benefits Paid                                   (11,512)       (10,627)     (10,412)
- -------------------------------------------- ------------- -------------- -------------
Fair Value of Assets at End of Period         $ 176,357      $ 149,884      $122,870
- -------------------------------------------- ------------- -------------- -------------
Reconciliation of Funded Status
Funded Status                                  $(90,103)     $(105,731)   $(134,113)
Unrecognized Net Actuarial (Gain) Loss           (8,676)        (2,396)       19,660
Unrecognized Transition Obligation               92,653         99,780       106,907
- -------------------------------------------- ------------- -------------- -------------
Accrued Benefit Cost                           $ (6,126)      $ (8,347)    $ (7,546)
- -------------------------------------------- ------------- -------------- -------------


- ----------------------------------------------- ------------- -------------- -------------
                                                      2000            1999          1998
- ----------------------------------------------- ------------- -------------- -------------
Weighted Average Assumptions as of September 30
Discount Rate                                        7.50%           7.25%         7.00%
Expected Return on Plan Assets                       8.50%           8.50%         8.50%
Rate of Compensation Increase                        5.00%           5.00%         5.00%
- ----------------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands)Components of Net Periodic Benefit Cost
Service Cost                                        $4,156          $4,493        $4,022
Interest Cost                                       18,142          17,635        17,122
Expected Return on Plan Assets                     (12,574)        (10,134)      (8,099)
Amortization of Transition Obligation                7,127           7,127         7,127
Amortization of (Gain) Loss                            (24)          1,304           683
Net Amortization and Deferral for
  Regulatory Purposes                                7,269           1,774           915
- ----------------------------------------------- ------------- -------------- -------------
Net Periodic Benefit Cost                         $ 24,096        $ 22,199      $ 21,770
- ----------------------------------------------- ------------- -------------- -------------

     The effect of the discount rate change in 2000 was to decrease the Benefit Obligation by $8.9 million. The effect of the discount rate change in 1999 was to decrease the Benefit Obligation by $9.1 million.

     The health care trend assumptions were changed in 2000 to better reflect anticipated future experience. The effect of the changed medical care, prescription drug and Medicare Part B assumptions mentioned below, was to increase the Accumulated Postretirement Benefit Obligation by $13.7 million.

     The annual rate of increase in the per capita cost of covered medical care benefits was assumed to be 9.0% for 1998, 8.0% for 1999, 10.0% for 2000 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase for medical care benefits provided by healthcare maintenance organizations was assumed to be 7.5% in 1998, 7.0% in 1999, 10.0% in 2000 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed to be 9.0% for 1998, 8.0% for 1999, 15.0% for 2000 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase in the per capita Medicare Part B Reimbursement was assumed to be 9.0% for 1998, 8.0% for 1999, 10.0% for 2000 and gradually decline to 5.5% by the year 2005 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, 2000 would be increased by $36.8 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 2000 by $3.9 million. If the health care cost trend rates were decreased by 1% in each year, the Benefit Obligation as of October 1, 2000 would be decreased by $29.2 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 2000 by $3.3 million.

Note H - Commitments and Contingencies

Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

     It is the Company's policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The Company has estimated its remaining clean-up costs related to the sites described below in (i) and (ii) will be in the range of $6.4 million to $7.6 million. The minimum estimated liability of $6.4 million has been recorded on the Consolidated Balance Sheet at September 30, 2000. Other than discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, adverse changes in environmental regulations, new information or other factors could impact the Company.

     (i) Former Manufactured Gas Plant Sites

     The Company has incurred or is incurring clean-up costs at four 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) and is also engaged in litigation with the DEC and the party who bought that site from the Company's predecessor. At a second site, remediation is in progress and is expected to be completed in 2001. At a third site the Company is negotiating with the DEC for clean-up under a voluntary program. The fourth is a site allegedly containing, among other things, manufactured gas plant waste and is in the investigation stage.

     (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, the remedial design has been agreed to and the parties are in settlement discussions.

     (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 of 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. The majority of these contracts (representing 87% 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, 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 expected to have a material adverse effect on the financial condition of the Company at this time.

Note I - 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 Pennsylvania Public Utility Commission (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 by the Federal Energy Regulatory Commission (FERC) and are carried out by Supply Corporation and SIP. 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. SIP, although not regulated itself by the FERC, holds a one-third partnership interest in the Independence Pipeline Company, whose rates, services and other matters are or will be regulated by the FERC.

     The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in the Gulf Coast region of Texas and Louisiana, in California, in Wyoming, in the Appalachian region of the United States and in the provinces of Manitoba, Alberta and Saskatchewan in Canada. Seneca's production is, for the most part, sold to purchasers located in the vicinity of its wells.

     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 of the Czech Republic.

     The Energy Marketing segment is comprised of NFR's operations. NFR is engaged in the retail marketing of natural gas, the marketing of electricity and the performance of energy management services for industrial, commercial, public authority and residential end-users located in the northeastern United States.

     The Timber segment's operations are carried out by the Northeast division of Seneca and by Highland. This segment has timber holdings in the northeastern United States and several sawmills and kilns in Pennsylvania.

     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.

Year Ended September 30, 2000 (Thousands)


- -------------------------------------------------------------------------------------------------------
                                     Pipeline      Exploration
                                      and             and                       Energy
                         Utility     Storage       Production   International  Marketing        Timber
- -------------------------------------------------------------------------------------------------------
Revenue from
External
Customers              $  827,231   $   81,434      $  237,845   $  104,736    $  133,929    $   39,172

Intersegment
Revenues                   19,228       88,225             225            -             -             -

Interest Expense           31,655       13,311          42,034       12,353           774         4,750

Depreciation,
Depletion and
Amortization               35,842       23,379          69,583       11,110           209         1,948

Income Tax
Expense                    38,362       22,172          19,413       (1,783)       (4,372)        3,816

Segment Profit
(Loss): Net
Income                     57,662       31,614          34,877        3,282        (7,790)        6,133

Expenditures for
Additions to
Long-Lived Assets          55,799       35,806(1)      280,049        9,767            89        13,542


At September 30, 2000 (Thousands)
- -------------------------------------------------------------------------------------------------------

Segment Assets         $1,219,496   $  552,059      $1,088,066   $  202,622    $   47,121    $  107,402

- -------------------------------------------------------------------------------------------------------

- --------------------------------------------------------------------------------
                         Total                     Corporate and
                      Reportable                   Intersegment       Total
                       Segments      All Other     Eliminations    Consolidated
- --------------------------------------------------------------------------------
Revenue from
External
Customers              $1,424,347   $      930         $   -       $1,425,277

Intersegment
Revenues                  107,678        4,415      (112,093)               -

Interest Expense          104,877          262        (5,054)         100,085

Depreciation,
Depletion and
Amortization              142,071           97             2          142,170

Income Tax
Expense                    77,608         (205)         (335)          77,068

Segment Profit
(Loss): Net
Income                    125,778         (371)        1,800          127,207

Expenditures for
Additions to
Long-Lived Assets         395,052        3,725             -          398,777


At September 30, 2000 (Thousands)
- --------------------------------------------------------------------------------

Segment Assets         $3,216,766   $   21,930    $   (1,808)      $3,236,888

- --------------------------------------------------------------------------------

(1)Amount includes $1.2 million in a stock-for-asset swap.

Year Ended September 30, 1999 (Thousands)


- --------------------------------------------------------------------------------------------------
                                     Pipeline    Exploration
                                       and           and                    Energy
                         Utility      Storage    Production  International  Marketing      Timber
- --------------------------------------------------------------------------------------------------
Revenue from
External
Customers              $  801,053   $   82,994   $  140,212   $  107,045   $   99,088   $   31,117

Intersegment
Revenues                    6,302       85,789        6,782            -            -            -

Interest Expense           29,659       13,147       34,409       11,451          234        2,208

Depreciation,
Depletion and
Amortization               34,215       22,690       55,750       10,473          165        1,476

Income Tax
Expense                    34,741       22,439        2,992           15        1,138        2,788

Segment Profit
(Loss): Net
Income                     56,875       39,765        7,127        2,276        2,054        4,769

Expenditures for
Additions to
Long-Lived Assets          46,974       34,873       97,586       33,412          302       52,314

At September 30, 1999 (Thousands)
- --------------------------------------------------------------------------------------------------

Segment Assets         $1,178,185   $  542,962   $  727,557   $  255,042   $   18,676   $   98,830

- --------------------------------------------------------------------------------------------------

- --------------------------------------------------------------------------------
                          Total                   Corporate and
                       Reportable                 Intersegment       Total
                        Segments     All Other    Eliminations    Consolidated
- --------------------------------------------------------------------------------


Revenue from
External
Customers              $1,261,509   $    1,765         $   -       $1,263,274

Intersegment
Revenues                   98,873            -       (98,873)               -

Interest Expense           91,108          100        (3,510)          87,698

Depreciation,
Depletion and
Amortization              124,769            7             2          124,778

Income Tax
Expense                    64,113           55           661           64,829

Segment Profit
(Loss): Net
Income                    112,866         (162)        2,333          115,037

Expenditures for
Additions to
Long-Lived Assets         265,461           66             -          265,527

At September 30, 1999 (Thousands)
- --------------------------------------------------------------------------------

Segment Assets         $2,821,252   $    7,351    $   13,983       $2,842,586

- --------------------------------------------------------------------------------

Year Ended September 30, 1998 (Thousands)


- ---------------------------------------------------------------------------------------------------
                                    Pipeline     Exploration
                                       and           and                       Energy
                          Utility    Storage      Production   International  Marketing     Timber
- ---------------------------------------------------------------------------------------------------
Revenue from
External
Customers              $  867,802   $   84,218   $  113,194    $   76,259   $   87,187   $   17,805

Intersegment
Revenues                    3,378       86,765       11,078             -            -            -

Interest Expense           44,639       15,232       21,454         7,188           31        1,580

Depreciation,
Depletion and
Amortization               33,459       21,816       50,937         7,309           91        3,527

Income Tax
Expense (Benefit)          30,076       29,644      (39,478)        2,158          471        1,445

Significant
Noncash Item:
Impairment of Oil
and Gas Producing
Properties                      -            -      128,996             -            -            -

Segment Profit
(Loss): Income
Before Cumulative
Effect of Change
in Accounting              51,788       39,852      (64,110)        1,279          787        1,904

Expenditures for
Additions to
Long-Lived Assets          50,680       29,145      323,627        96,987          320        6,778

At September 30, 1998 (Thousands)
- ---------------------------------------------------------------------------------------------------

Segment Assets         $1,171,645   $  526,738   $  673,706    $  242,339   $   16,944   $   45,507

- ---------------------------------------------------------------------------------------------------

- --------------------------------------------------------------------------------
                          Total                 Corporate and
                       Reportable               Intersegment       Total
                        Segments     All Other  Eliminations   Consolidated
- --------------------------------------------------------------------------------

Revenue from
External
Customers              $1,246,465   $    1,535      $     -    $1,248,000

Intersegment
Revenues                  101,221            -     (101,221)            -

Interest Expense           90,124           33       (4,873)       85,284

Depreciation,
Depletion and
Amortization              117,139           97            2       117,238

Income Tax
Expense (Benefit)          24,316          119         (411)       24,024

Significant
Noncash Item:
Impairment of Oil
and Gas Producing
Properties                128,996            -            -       128,996

Segment Profit
(Loss): Income
Before Cumulative
Effect of Change
in Accounting              31,500          143          661        32,304

Expenditures for
Additions to
Long-Lived Assets         507,537            -            -       507,537

At September 30, 1998 (Thousands)
- --------------------------------------------------------------------------------

Segment Assets         $2,676,879   $    5,216   $    2,364    $2,684,459

- --------------------------------------------------------------------------------



 -------------------------------------- --------------- ------------- -------------
 Geographic Information                      2000         1999          1998
 -------------------------------------- --------------- ------------- -------------

 For the Year Ended September 30 (Thousands)
 Revenues from External Customers(1):
 United States                           $1,292,190    $1,156,229    $1,171,741
 Czech Republic                             104,736       107,045        76,259
 Canada                                      28,351             -             -
 -------------------------------------- --------------- ------------- -------------
                                         $1,425,277    $1,263,274    $1,248,000

 At September 30 (Thousands)
 -------------------------------------- --------------- ------------- -------------
 Long-Lived Assets:
 United States                           $2,480,406    $2,369,840    $2,258,817
 Czech Republic                             183,274       215,457       215,125
 Canada                                     248,937             -             -
 -------------------------------------- --------------- ------------- -------------
                                         $2,912,617    $2,585,297    $2,473,942
 -------------------------------------- --------------- ------------- -------------

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

Note J - Stock Acquisitions

In June 2000, the Company acquired the outstanding shares of Tri Link Resources, Ltd. (Tri Link) a Calgary, Alberta based oil and gas exploration and production company. The cost of acquiring the outstanding shares of Tri Link was approximately $123.8 million. Upon completing this acquisition, Tri Link was amalgamated under the name of National Fuel Exploration Corp. (NFE). NFE's results of operations were incorporated into the Company's consolidated financial statements for the period subsequent to the completion of the acquisition of Tri Link on June 15, 2000.

     In May 1998, the Company acquired the outstanding shares of HarCor Energy, Inc. (HarCor) for approximately $32.6 million ($29.8 million, net of cash acquired). HarCor's results of operations were incorporated into the Company's consolidated financial statements for the period subsequent to the completion of the tender offer in May 1998.

     During 1998 and 1999, the Company purchased majority ownership interests in Severoeeske teplarny, a.s. (SCT), Prvni severozapadni teplarenska, a.s. (PSZT) and Jablonecka teplarenska a realitni, a.s. (JTR) (a majority owned subsidiary of SCT). The cost of acquiring these shares in 1998 was $89.4 million ($82.2 million, net of cash acquired). In 1999, an additional $5.8 million was invested ($5.7 million, net of cash acquired). In 2000, SCT and PSZT merged and the merged company was renamed United Energy, a.s.

     All of the acquisitions disclosed above were accounted for in accordance with the purchase method. The goodwill resulting from these acquisitions is being amortized over a twenty-year period and is recorded in Other Assets. This goodwill amounted to $8.7 million and $9.5 million at September 30, 2000 and 1999, respectively.

     Details of the stock acquisitions made by the Company during 2000, 1999 and 1998 are as follows:


- ------------------------------------------ ----------- ------------ ------------
Year Ended September 30 (Millions)2000         1999      1998
- ------------------------------------------ ----------- ------------ ------------

Assets acquired                               $259.9        $13.5       $313.5
Liabilities assumed                           (136.1)        (7.3)      (172.6)
Existing investment at acquisition                 -         (0.4)       (18.9)
Cash acquired at acquisition                       -         (0.1)       (10.0)
- ------------------------------------------ ----------- ------------ ------------
Cash paid, net of cash acquired               $123.8         $5.7       $112.0
- ------------------------------------------ ----------- ------------ ------------

Note K - 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 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
                                                   for                Earnings Per
Quarter          Operating        Operating       Common              Common Share
                                                               ----------------------------
 Ended           Revenues          Income         Stock            Basic        Diluted
- -------------- --------------- -------------- ---------------- -------------- -------------
       2000(Thousands, except per common share amounts)
- -------------- ------------------------------------------------ ---------------------------
 12/31/1999         $377,031        $70,237        $ 44,868          $ 1.15         $1.14
  3/31/2000         $517,767        $91,074        $ 71,051          $ 1.82         $1.81
  6/30/2000(1)      $281,201        $30,043         $ 9,070(2)       $ 0.23         $0.23
  9/30/2000         $249,278        $26,914         $ 2,218(3)       $ 0.06         $0.06
- -------------- ---------------------------------------------------- -----------------------
       1999       (Thousands, except per common share amounts)
- -------------- ---------------------------------------------------- -----------------------
 12/31/1998         $340,422        $56,835      $ 37,619(4)       $   0.98          $0.97
  3/31/1999         $483,404        $83,475     $  61,145            $ 1.58          $1.57
  6/30/1999         $248,658        $31,319      $ 11,840(5)       $   0.31          $0.30
  9/30/1999         $190,790        $20,379       $ 4,433(6)         $ 0.11          $0.11
- -------------- --------------- -------------- ---------------- -------------- -------------

(1) As revised.
(2) Includes expense of $14.2 million related to mark-to-market and other revenue adjustments related to derivative financial instruments and expense of $3.5 million related to SAR's.

(3) Includes expense of $6.6 million related to SAR's, expense of $3.7 million for adjustments related to the New York rate settlement, expense of $1.6 million related to the recording of a loss contingency on fixed price sales contracts and income of $3.9 million related to mark-to-market and other revenue adjustments related to derivative financial instruments.

(4) Includes income of $3.9 million related to IRS audit settlement and expense of $3.5 million related to an early retirement offer.

(5) Includes expense of $3.8 million related to SAR's, expense of $1.1 million related to an early retirement offer and income of $1.0 million for lost and unaccounted for (LAUF) gas adjustment related to 1998.

(6) Includes income of $1.6 million for LAUF gas adjustment related to 1999 and income of $1.6 million related to a gain on stock received from the demutualization of an insurance company.

Note L - Market for Common Stock and Related Shareholder Matters (unaudited)

At September 30, 2000, there were 21,164 holders of National Fuel Gas 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. The quarterly price ranges and quarterly dividends declared for the fiscal years ended September 30, 2000 and 1999, are shown below:


- --------------------------------- ------------------------------ -------------
                                          Price Range              Dividends
                                  ------------------------------
Quarter Ended                              High            Low      Declared
- --------------------------------- --------------- -------------- -------------
    2000
- --------------------------------- --------------- -------------- -------------
12/31/1999                               $52.94         $46.00         $.465
  3/31/2000                              $46.75         $39.38         $.465
  6/30/2000                              $51.94         $43.13         $.480
  9/30/2000                              $58.81         $48.13         $.480
- --------------------------------- --------------- -------------- -------------
    1999
- --------------------------------- --------------- -------------- -------------
12/31/1998                               $49.63         $44.88         $.450
  3/31/1999                              $46.50         $39.25         $.450
  6/30/1999                              $50.00         $37.50         $.465
  9/30/1999                              $49.75         $44.63         $.465
- --------------------------------- --------------- -------------- -------------

Note M - Supplementary Information for Oil and Gas Producing Activities

The following supplementary information is presented in accordance with SFAS 69, "Disclosures about Oil and Gas Producing Activities," and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars.

Capitalized Costs Relating to Oil and Gas Producing Activities


- ---------------------------------------------- -------------- -------------
At September 30 (Thousands)2000          1999

- ---------------------------------------------- -------------- -------------
Proved Properties                                $1,218,871      $880,470
Unproved Properties                                 152,360        92,097
- ---------------------------------------------- -------------- -------------
                                                  1,371,231       972,567
Less - Accumulated Depreciation, Depletion
  and Amortization                                  390,267       315,675
- ---------------------------------------------- -------------- -------------
                                                   $980,964      $656,892
- ---------------------------------------------- -------------- -------------

     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, 2000:


- ----------------------- -------------- --------------------------------------------------
                          Total as of                 Year Costs Incurred
                                       --------------------------------------------------
(Thousands)September 30, 2000         2000         1999         1998       Prior
- ----------------------- -------------- ------------ ------------ ------------ -----------

Acquisition Costs            $152,360     $106,665       $5,608      $31,640      $8,447
- ----------------------- -------------- ------------ ------------ ------------ -----------

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


- ------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands)2000           1999          1998
- ------------------------------------- ------------- -------------- -------------

United States
- ------------------------------------- ------------- -------------- -------------

Property Acquisition Costs:
  Proved                                  $ 2,848        $ 2,798      $189,201
  Unproved                                 19,066         11,530        88,369
Exploration Costs                          50,163         52,141        74,421
Development Costs                          72,039         30,985        23,887
- ------------------------------------- ------------- -------------- -------------
                                          144,116         97,454       375,878
- ------------------------------------- ------------- -------------- -------------

Canada
- ------------------------------------- ------------- -------------- -------------
Property Acquisition Costs:
  Proved                                  157,835              -             -
  Unproved                                 76,504              -             -
Exploration Costs                             573              -             -
Development Costs                          11,013              -             -
- ------------------------------------- ------------- -------------- -------------
                                          245,925              -             -
- ------------------------------------- ------------- -------------- -------------

Total
- ------------------------------------- ------------- -------------- -------------
Property Acquisition Costs: (1)
  Proved                                  160,683          2,798       189,201
  Unproved                                 95,570         11,530        88,369
Exploration Costs                          50,736         52,141        74,421
Development Costs                          83,052         30,985        23,887
- ------------------------------------- ------------- -------------- -------------
                                         $390,041        $97,454      $375,878
- ------------------------------------- ------------- -------------- -------------

(1) Total proved and unproved property acquisition costs for 2000 of $256.3 million include $236.5 million related to the Tri Link acquisition (now known as NFE). Total proved and unproved property acquisition costs for 1998 of $277.6 million include amounts related to the HarCor, Bakersfield Energy and Whittier Trust properties acquired in 1998 of $87.0 million, $25.3 million and $141.1 million, respectively.

Results of Operations for Producing Activities


- ------------------------------------------------------ ------------- -------------- -------------
Year Ended September 30 (Thousands, Except Per Mcfe2000           1999          1998
                          Amounts)
- ------------------------------------------------------ ------------- -------------- -------------
United States
- ------------------------------------------------------ ------------- -------------- -------------
Operating Revenues:
  Natural Gas (includes revenues from sales to
affiliates
    of $237, $6,365 and $11,065, respectively)           $137,336       $ 81,734      $ 89,284
  Oil, Condensate and Other Liquids                       107,645         51,592        31,770
- ------------------------------------------------------ ------------- -------------- -------------
Total Operating Revenues(1)                               244,981        133,326       121,054
Production/Lifting Costs                                   33,979         28,119        23,622
Depreciation, Depletion and Amortization
  ($0.97, $0.89 and $0.96 per Mcfe of production)          64,624         54,439        50,221
Impairment of Oil and Gas Producing Properties(2)               -              -       128,996
Income Tax Expense (Benefit)                               52,656         16,255       (28,949)
- ------------------------------------------------------ ------------- -------------- -------------
Results of Operations for Producing Activities
  (excluding corporate overheads and interest              93,722         34,513       (52,836)
charges)
- ------------------------------------------------------ ------------- -------------- -------------

Canada
- ------------------------------------------------------ ------------- -------------- -------------
Operating Revenues:
  Natural Gas                                                 485              -             -
  Oil, Condensate and Other Liquids                        26,320              -             -
- ------------------------------------------------------ ------------- -------------- -------------
Total Operating Revenues(1)                                26,805              -             -
Production/Lifting Costs                                    7,858              -             -
Depreciation, Depletion and Amortization
  ($0.77 , $ -  and $ - per Mcfe of production)             4,321              -             -
Income Tax Expense                                          6,121              -             -
- ------------------------------------------------------ ------------- -------------- -------------
Results of Operations for Producing Activities
  (excluding corporate overheads and interest               8,505              -             -
charges)
- ------------------------------------------------------ ------------- -------------- -------------
Total
- ------------------------------------------------------ ------------- -------------- -------------
Operating Revenues:
  Natural Gas (includes revenues from sales to
affiliates
    of $237, $6,365 and $11,065, respectively)            137,821         81,734        89,284
  Oil, Condensate and Other Liquids                       133,965         51,592        31,770
- ------------------------------------------------------ ------------- -------------- -------------
Total Operating Revenues(1)                               271,786        133,326       121,054
Production/Lifting Costs                                   41,837         28,119        23,622
Depreciation, Depletion and Amortization
  ($0.95, $0.89 and $0.96 per Mcfe of production)          68,945         54,439        50,221
Impairment of Oil and Gas Producing Properties(2)               -              -       128,996
Income Tax Expense (Benefit)                               58,777         16,255       (28,949)
- ------------------------------------------------------ ------------- -------------- -------------
Results of Operations for Producing Activities
  (excluding corporate overheads and interest            $102,227       $ 34,513      $(52,836)
charges)
- ------------------------------------------------------ ------------- -------------- -------------

(1) Exclusive of hedging gains and losses. See further discussion in Note F - Financial Instruments.

(2) See discussion of impairment in Note A - Summary of Significant Accounting Policies.

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                           Oil Mbbl
                                ---------------------------------- ----------------------------------
                                  U.S.      Canada       Total       U.S.      Canada       Total
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------
Proved Developed and
Undeveloped Reserves:
  September 30, 1997             232,449           -     232,449     17,981           -      17,981
    Extensions and Discoveries    40,293           -      40,293        640           -         640
    Revisions of
      Previous Estimates         (18,623)          -     (18,623)    (4,191)          -      (4,191)
    Production                   (36,474)          -     (36,474)    (2,614)          -      (2,614)
    Sales of Minerals in Place         -           -           -          -           -           -
    Purchases of Minerals
      in Place and Other         107,420           -     107,420     54,775           -      54,775
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------
  September 30, 1998             325,065           -     325,065     66,591           -      66,591
    Extensions and Discoveries    46,423           -      46,423      3,716           -       3,716
    Revisions of
      Previous Estimates         (13,091)          -     (13,091)     9,808           -       9,808
    Production                   (37,166)          -     (37,166)    (4,016)          -      (4,016)
    Sales of Minerals in Place      (439)          -        (439)      (280)          -        (280)
    Purchases of Minerals
      in Place and Other               -           -           -          -           -           -
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------
  September 30, 1999             320,792           -     320,792     75,819           -      75,819
    Extensions and Discoveries    34,641           -      34,641      2,167       1,765       3,932
    Revisions of
      Previous Estimates          (8,001)          -      (8,001)     4,000           -       4,000
    Production                   (41,478)        (192)    41,670)    (4,248)       (899)     (5,147)
    Sales of Minerals in Place    (7,444)          -      (7,444)      (227)          -        (227)
    Purchases of Minerals
      in Place and Other               -       3,349       3,349          -      41,320      41,320
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------
  September 30, 2000             298,510       3,157     301,667     77,511      42,186     119,697
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------
Proved Developed Reserves:
  September 30, 1997             194,454           -     194,454     11,354           -      11,354
  September 30, 1998             230,508           -     230,508     48,081           -      48,081
  September 30, 1999             222,929           -     222,929     57,333           -      57,333
  September 30, 2000             227,250       3,157     230,407     66,074      35,130     101,204
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------

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 the widely fluctuating political and economic conditions of today's world.

     The standardized measure is intended instead to provide a somewhat better 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 (Thousands)2000           1999          1998
United States
- ------------------------------------------- ------------- -------------- -------------
Future Cash Inflows                          $3,886,499     $2,402,308    $1,547,216
Less:
  Future Production Costs                       600,243        560,459       413,753
  Future Development Costs                      179,565        185,617       160,884
  Future Income Tax Expense at
    Applicable Statutory Rate                 1,006,366        477,205       245,120
- ------------------------------------------- ------------- -------------- -------------
Future Net Cash Flows                         2,100,325      1,179,027       727,459
Less:
  10% Annual Discount for Estimated
    Timing of Cash Flows                        859,950        471,768       260,688
- ------------------------------------------- ------------- -------------- -------------
Standardized Measure of Discounted Future
    Net Cash Flows                            1,240,375        707,259       466,771
- ------------------------------------------- ------------- -------------- -------------

Canada
- ------------------------------------------- ------------- -------------- -------------
Future Cash Inflows                           1,083,598              -             -
Less:
  Future Production Costs                       277,067              -             -
  Future Development Costs                       21,399              -             -
  Future Income Tax Expense at
    Applicable Statutory Rate                   286,148              -             -
- ------------------------------------------- ------------- -------------- -------------
Future Net Cash Flows                           498,984              -             -
Less:
  10% Annual Discount for Estimated
    Timing of Cash Flows                        221,227              -             -
- ------------------------------------------- ------------- -------------- -------------
Standardized Measure of Discounted Future
    Net Cash Flows                              277,757              -             -
- ------------------------------------------- ------------- -------------- -------------

Total
- ------------------------------------------- ------------- -------------- -------------
Future Cash Inflows                           4,970,097      2,402,308     1,547,216
Less:
  Future Production Costs                       877,310        560,459       413,753
  Future Development Costs                      200,964        185,617       160,884
  Future Income Tax Expense at
    Applicable Statutory Rate                 1,292,514        477,205       245,120
- ------------------------------------------- ------------- -------------- -------------
Future Net Cash Flows                         2,599,309      1,179,027       727,459
Less:
  10% Annual Discount for Estimated
    Timing of Cash Flows                      1,081,177        471,768       260,688
- ------------------------------------------- ------------- -------------- -------------
Standardized Measure of Discounted Future
    Net Cash Flows                           $1,518,132       $707,259      $466,771
- ------------------------------------------- ------------- -------------- -------------

     The principal sources of change in the standardized measure of discounted future net cash flows were as follows:


- ------------------------------------------------------ ------------- -------------- -------------
Year Ended September 30 (Thousands)2000           1999          1998
- ------------------------------------------------------ ------------- -------------- -------------

United States
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted Future
  Net Cash Flows at Beginning of Year                    $707,259       $466,771      $383,200
    Sales, Net of Production Costs                       (211,002)       (53,615)      (97,432)
    Net Changes in Prices, Net of Production Costs        795,408        317,356      (180,853)
    Purchases of Minerals in Place                              -              -       364,102
    Sales of Minerals in Place                            (11,914)        (2,706)            -
    Extensions and Discoveries                            186,818        122,894        36,844
    Changes in Estimated Future Development Costs         (82,270)       (97,082)     (104,181)
    Previously Estimated Development Costs Incurred        88,322         72,349        28,514
    Net Change in Income Taxes at
      Applicable Statutory Rate                          (292,371)      (232,085)       57,190
    Revisions of Previous Quantity Estimates               20,736         40,964       (75,136)
    Accretion of Discount and Other                        39,389         72,413        54,523
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted
  Future Net Cash Flows at End of Year                  1,240,375        707,259       466,771
- ------------------------------------------------------ ------------- -------------- -------------

Canada
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted Future
  Net Cash Flows at Beginning of Year                           -              -             -
    Sales, Net of Production Costs                        (18,948)             -             -
    Net Changes in Prices, Net of Production Costs              -              -             -
    Purchases of Minerals in Place                        424,072              -             -
    Sales of Minerals in Place                                  -              -             -
    Extensions and Discoveries                              2,979              -             -
    Changes in Estimated Future Development Costs               -              -             -
    Previously Estimated Development Costs Incurred             -              -             -
    Net Change in Income Taxes at
      Applicable Statutory Rate                          (150,057)             -             -
    Revisions of Previous Quantity Estimates                    -              -             -
    Accretion of Discount and Other                        19,711              -             -
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted
  Future Net Cash Flows at End of Year                    277,757              -             -
- ------------------------------------------------------ ------------- -------------- -------------

Total
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted Future
  Net Cash Flows at Beginning of Year                     707,259        466,771       383,200
    Sales, Net of Production Costs                       (229,950)       (53,615)      (97,432)
    Net Changes in Prices, Net of Production Costs        795,408        317,356      (180,853)
    Purchases of Minerals in Place                        424,072              -       364,102
    Sales of Minerals in Place                            (11,914)        (2,706)            -
    Extensions and Discoveries                            189,797        122,894        36,844
    Changes in Estimated Future Development Costs         (82,270)       (97,082)     (104,181)
    Previously Estimated Development Costs Incurred        88,322         72,349        28,514
    Net Change in Income Taxes at
      Applicable Statutory Rate                          (442,428)      (232,085)       57,190
    Revisions of Previous Quantity Estimates               20,736         40,964       (75,136)
    Accretion of Discount and Other                        59,100         72,413        54,523
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted
  Future Net Cash Flows at End of Year                 $1,518,132       $707,259      $466,771
- ------------------------------------------------------ ------------- -------------- -------------

Schedule II - Valuation and Qualifying Accounts

Back to Index of Financial Statements

- ---------------------------------- ------------ ----------- ------------ ------------- ------------
                                                Additions    Additions
                                   Balance at   Charged     Charged to                 Balance at
                                                       to
(Thousands)                         Beginning   Costs            Other                     End of
                                                      and
Description                        of                       Accounts(1)  Deductions(2)     Period
                                 Period Expenses
- ---------------------------------- ------------ ----------- ------------ ------------- ------------
Year Ended September 30, 2000
Reserve for Doubtful Accounts          $7,842     $15,177         $  -       $11,006      $12,013
- ---------------------------------- ------------ ----------- ------------ ------------- ------------
Year Ended September 30, 1999
Reserve for Doubtful Accounts          $6,232     $15,337         $  1       $13,728       $7,842
- ---------------------------------- ------------ ----------- ------------ ------------- ------------
Year Ended September 30, 1998
Reserve for Doubtful Accounts          $8,291     $15,861         $746       $18,666       $6,232
- ---------------------------------- ------------ ----------- ------------ ------------- ------------

(1) Represents opening balance sheet reserve plus exchange rate impact of translating the Czech koruna to the U.S. dollar for Horizon.

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

ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

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None



PART III

ITEM 10 Directors and Executive Officers of the Registrant

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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 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. 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 2003," "Directors Whose Terms Expire in 2002," "Directors Whose Terms Expire in 2001," 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.

ITEM 11 Executive Compensation

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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 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. 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

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(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 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. 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.

(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 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. 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

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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 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. 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.

PART IV

ITEM 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K

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(a)1.  Financial Statement SchedulesStatements
All financial statement schedules
                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.
  • Reports on(a)2.  Financial Statement Schedules
                Financial  statements  schedules  filed as part of this report
                are listed in the index  included in Item 8 of this Form
                8-K
    None
  • 10-K, and reference is made thereto.

         (a)3.  Exhibits
    Exhibit
    Number                  Description of Exhibits
    • 
           3(i) Articles of Incorporation:

            o•   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:

         o**3.1  National Fuel Gas Company By-Laws as amended on February 17, 2000 (Exhibit 3.1, Form 10-K for fiscal
                         year ended June 30, 2000 in File No. 1-3880)December 13, 2001


           (4)  Instruments Defining the Rights of Security Holders, Including Indentures:

            o•   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)

            o•   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)

            o•   Tenth  Supplemental  Indenture,  dated as of February 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(a),  Form 8-K dated February 14, 1992 in File No.
                1-3880)

            o•   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)

            o•   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)

            o•   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)

            o•   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)

            o•   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)

            o•   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)

            o•   Officer's  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)

            o•   Amended and  Restated  Rights  Agreement,  dated as of April
                30, 1999,  between National  Fuel Gasthe 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)

          (10)  Material Contracts:

          (iii) Compensatory plans for officers:

            o•   Retirement  and  Consulting  Agreement,  dated  September  5,
                2001,  between  the  Company  and  Bernard J.  Kennedy  (Exhibit
                10(iii)(a), Form 8-K dated September 19, 2001 in File No. 1-3880)

            •   Pension Settlement  Agreement,  dated September 5, 2001,
                between the Company and Bernard J. Kennedy (Exhibit 10(iii)(b),  Form
                8-K dated September 19, 2001 in File No. 1-3880)

            •   Employment  Agreement,  dated  September 17, 1981,  withbetween
                the Company and Bernard J. Kennedy  (Exhibit  10.4,  Form 10-K for
                fiscal year ended September 30, 1994 in File No. 1-3880)

            o•   Tenth  Amendment to  Employment  Agreement  withbetween the Company
                and Bernard J. Kennedy,  effective  September 1, 1999 (Exhibit
                10.1, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)

            o•   Agreement,  dated August 1, 1986,  withbetween the Company and
                Joseph P. Pawlowski  (Exhibit 10.1, Form 10-K for fiscal year ended
                September 30,1997 in File No. 1-3880)

            o•   Agreement,  dated August 1, 1986,  withbetween the Company and
                Gerald T. Wehrlin  (Exhibit  10.2,  Form 10-K for fiscal year ended
                September 30, 1997, in File No. 1-3880)

            o•   Form of Employment  Continuation and  Noncompetition
                Agreements,  dated as of December 11, 1998, withbetween the Company
                and each of Philip C. Ackerman, Walter E. DeForest, Joseph P.
                Pawlowski,  Dennis J. Seeley, David F. Smith and Gerald T. Wehrlin
                (Exhibit 10.1, Form 10-Q for the quarterly period ended June 30,
                1999 in File No. 1-3880)

            o•   Severance  Agreement,  Release and Waiver dated March 27, 2000,
                between National Fuel Gas Supply Corporation and Richard Hare
                (Exhibit 10.2, Form 10-Q for the quarterly period ended March 31, 2000)

            o•   Form of Employment  Continuation and  Noncompetition  Agreement,
                dated as of December 11, 1998, withbetween the Company and James
                A. Beck (Exhibit 10.3, Form 10-Q for the quarterly period ended
                June 30, 1999 in File No. 1-3880)

            o•   National Fuel Gas Company 1983 Incentive Stock Option Plan,
                as amended and restated  through  February 18, 1993 (Exhibit 10.2,
                Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880)

            o•   National Fuel Gas Company 1984 Stock Plan, as amended and
                restated  through  February 18, 1993  (Exhibit  10.3,  Form 10-Q for
                the quarterly period ended March 31, 1993 in File No. 1-3880)

            o•   Amendment to the National Fuel Gas Company 1984 Stock Plan,
                dated December 11, 1996 (Exhibit 10.7,  Form 10-K for fiscal year
                ended September 30, 1996 in File No. 1-3880)

            o•   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)

            o•   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)

            o•   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)

            o•   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)

          o           Amended10.1  National Fuel Gas Company 1993 Award and RestatedOption Plan, amended
                through June 14, 2001

          10.2  National Fuel Gas Company 1997 Award and Option Plan, as amended
                and restated  through February  17,  2000  (Exhibit  10.1,  Form  10-Q for the
                        quarterly  period  ended  March  31,  2000 in  File  No.
                        1-3880)

            oJune 14, 2001

          10.3  Amendment to National Fuel Gas Company Deferred Compensation
                Plan, dated June 15, 2001

            •   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)

            o•   Amendment to the 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)

            o•   Amendment to the 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)

            o•   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)

            o•   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)

            o•   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)

            o•   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)

            o•   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)

            o•   Amendment No. 1 to the 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)

            o•   Amendment No. 2 to the 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)

            o•   Death Benefits  Agreement,  dated August 28, 1991,  withbetween
                the Company and Bernard J. Kennedy  (Exhibit 10-TT,  Form 10-K for
                fiscal year ended September 30, 1991 in File No. 1-3880)

            o•   Amendment to Death Benefit  Agreement of August 28, 1991,
                withbetween the Company and Bernard J. Kennedy,  dated  March 15,  1994
                (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1995
                in File No. 1-3880)

            o•   Amended and Restated Split Dollar Insurance  Agreement,
                effective June 15, 2000, among National Fuel Gasthe 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)

            o•   Contingent  Benefit  Agreement,  effective June 15, 2000
                between National Fuel Gasthe Company and Bernard J. Kennedy  (Exhibit 10.2,  Form
                10-Q for the quarterly period ended June 30, 2000 in File No. 1-3880)

            o•   Amended and Restated  Split Dollar  Insurance and Death Benefit
                Agreement,  dated  September 17, 1997 withbetween the Company and
                Philip C. Ackerman (Exhibit 10.5, Form 10-K for fiscal year ended
                September 30, 1997 in File No. 1-3880)

            o•   Amendment Number 1 to Amended and Restated Split Dollar
                Insurance and Death Benefit  Agreement by and Between
                        National Fuel Gasbetween 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)

            o•   Amended and Restated Split Dollar Insurance and Death Benefit
                Agreement,  dated  September 15,  1997, withbetween the Company and
                Joseph P. Pawlowski (Exhibit 10.7, Form 10-K for fiscal year ended
                September 30, 1997 in File No. 1-3880)

            o•   Amendment Number 1 to Amended and Restated Split Dollar
                Insurance and Death Benefit  Agreement by and Between
                        National Fuel Gasbetween 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)

            o•   Second Amended and Restated Split Dollar  Insurance  Agreement
                dated June 15, 1999,  withbetween the Company and Gerald T. Wehrlin
                (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 1999
                in File No. 1-3880)

            o•   Amended and Restated Split Dollar Insurance and Death Benefit
                Agreement,  dated  September 15,  1997, withbetween the Company and
                Walter E. DeForest (Exhibit 10.7, Form 10-K for fiscal year ended
                September 30, 1999 in File No. 1-3880)

            o•   Amendment Number 1 to Amended and Restated Split Dollar
                Insurance and Death Benefit  Agreement by and Between
                        National Fuel Gasbetween the Company and
                Walter E. DeForest,  dated March 29, 1999 (Exhibit 10.8, Form 10-K
                for fiscal year ended September 30, 1999 in File No. 1-3880)

            o•   Amended and Restated Split Dollar Insurance and Death Benefit
                Agreement,  dated  September 15,  1997, withbetween the Company and
                Dennis J. Seeley (Exhibit 10.9, Form 10-K for fiscal year ended
                September 30, 1999 in File No. 1-3880)

            o•   Amendment Number 1 to Amended and Restated Split Dollar
                Insurance and Death Benefit  Agreement by and Between
                        National  Fuel Gasbetween 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)

            o•   Split Dollar  Insurance and Death Benefit  Agreement dated
                September 15, 1997,  withbetween the Company and Bruce H. Hale (Exhibit
                10.11, Form 10-K for fiscal year ended September 30, 1999 in File
                No. 1-3880)

            o•   Amendment Number 1 to Split Dollar  Insurance and Death Benefit
                Agreement by and Between  National  Fuel  Gasbetween 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)

            o•   Split  Dollar  Insurance  and Death  Benefit  Agreement,
                dated  September  15,  1997,  withbetween the Company and David F. Smith
                (Exhibit 10.13, Form 10-K for fiscal year ended September 30,
                1999 in File No. 1-3880)

            o•   Amendment  Number 1 to Split  Dollar  Insurance  and Death
                Benefit  Agreement  by and Between  National  Fuel  Gasbetween 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)

            o•   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)

            o•   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)

            o•   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)

            o•   Amendments to  the 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)

            o•   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)

         o**10.4 Amendment to National Fuel Gas Company and  Participating
                Subsidiaries  Executive  Retirement  Plan, effective September 5, 2001

         **10.5 Retirement Supplement Agreement, dated September 14, 2000, between
                the Company and Gerald T. Wehrlin

         **10.6 Retirement Supplement Agreement, dated January 11, 2002, between the Company and
                Joseph P. Pawlowski

            •   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)

            o•   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 14, 2000 in File No. 1-3880)

            o•   Administrative  Rules of the  Compensation  Committee of the
                Board of Directors of National  Fuel Gas Company,  as amended and
                restated,  effective  December 10, 1998 (Exhibit  10.3,  Form 10-Q
                for the quarterly  period ended December 31, 1998 in
                File No. 1-3880)

            o•   Excerpts of Minutes  from the  National  Fuel Gas  Company
                Board of  Directors  Meeting of February  20, 1997  regarding  the
                Retirement  Benefits for Bernard J. Kennedy (Exhibit 10.10,  Form
                10-K for fiscal year ended September 30, 1997 in File No. 1-3880)

            o•   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)

           (12) Statements  regarding  Computation of Ratios:  Ratio of Earnings
                to Fixed Charges for the fiscal years ended  September 30,
                1977 through 2001

           (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 National
                Fuel Exploration Corp.

           23.3 Consent of Ralph E. Davis Associates, Inc. regarding Player
                Resources Ltd.

           23.4 Consent of Independent Accountants

            23.3        Consent of McDaniel & Associates Consultants Ltd.

            (27)        Financial Data Schedules:

            27.1        Financial  Data  Schedule  for the Twelve  Months  Ended
                        September 30, 2000

            27.2        Restated  Financial  Data Schedule for the Twelve Months
                        Ended September 30, 1999

           (99) Additional Exhibits:

           99.1 Report of Ralph E. Davis Associates, Inc. regarding Seneca
                Resources Corporation

           99.2 Report of McDaniel &Ralph E. Davis Associates, ConsultantsInc. regarding National Fuel
                Exploration Corp.

           99.3 Report of Ralph E. Davis Associates, Inc. regarding Player
                Resources Ltd.


    • Incorporated herein by reference as indicated.
    ** Indicates exhibit amended or added by this Form 10K/A and filed herewith as part of this Form 10K/A.
    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.


o       Incorporated herein by reference as indicated.


    SignaturesSignature

    Back to Table of Contents

         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/ B./s/ J. Kennedy
                                                ---------------------------
                                                            B. J. Kennedy
                                                  Chairman of the Board
                                                  and Chief Executive Officer

                                              Date:  December 7, 2000


        Pursuant to the  requirements  of the  Securities  Exchange Act of 1934,
this  report has been  signed  below by the  following  persons on behalf of the
registrant and in the capacities and on the dates indicated.

        Signature                                          Title



  /s/ B. J. Kennedy                  Chairman of the Board,
  ---------------------------
       B. J. Kennedy                 Chief Executive Officer and Director

   Date:  December 7, 2000


   /s/ P. C. Ackerman                President, Principal Financial
   --------------------------
        P. C. Ackerman                  Officer and Director


   Date:  December 7, 2000


   /s/ R. T. Brady                   Director
   -------------------------
        R. T. Brady

   Date:  December 7, 2000


   /s/ J. V. Glynn                   Director
   -------------------------
        J. V. Glynn

   Date:  December 7, 2000


   /s/ W. J. Hill                    Director
   -------------------------
        W. J. Hill

   Date:  December 7, 2000


   /s/ B. S. Lee                     Director
   -------------------------
        B. S. Lee

   Date:  December 7, 2000


   /s/ E. T. Mann                    Director
   -------------------------
        E. T. Mann

   Date:  December 7, 2000


   /s/ G. L. Mazanec                 Director
   -------------------------
        G. L. Mazanec

   Date:  December 7, 2000


   /s/ J. F. Riordan                 Director
   -------------------------
        J. F. Riordan

   Date:  December 7, 2000


   /s/Pawlowski  

                                                   J. P. Pawlowski
                                                   Treasurer and Principal --------------------------
        J. P. Pawlowski              Accounting Officer

                                              Date:  December 7, 2000

    
APPENDIX TO ITEM 2 - PROPERTIES

     Six maps outlining the Company's  operating areas at September 30, 2000 are
     included  throughout  pages  3 - 16 of  the  paper  format  version  of the
     Company's combined Annual Report to  Shareholders/Form  10-K. The first map
     identifies the Company's  Exploration and Production  operating area (i.e.,
     Seneca's  operating area). The second map identifies the Company's  Utility
     operating area (i.e.,  Distribution  Corporation's service area). The third
     map  identifies  the Company's  Pipeline and Storage  operating area (i.e.,
     Supply  Corporation's   storage  areas  and  pipelines).   The  fourth  map
     identifies  the  Company's  Timber  Operating  area  (i.e.,   Seneca's  and
     Highland's  timber and sawmill  operations).  The fifth map  identifies the
     Company's  International  operating  area (i.e.,  Horizon's  Czech Republic
     operations).  The sixth  map  identifies  the  Company's  Energy  Marketing
     operating area (i.e., NFR's marketing service area).

APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION - GRAPHS

A.  The Revenue Dollar - 2000

      Two pie graphs  detailing the revenue  dollar in 2000:  where it came from
and where it went to, broken down as follows:

      Where it came from:

      $ .405 Residential Gas Sales
        .151 Oil and Gas Production  Revenues
        .113 Commercial,  Industrial  and Off-System Gas Sales
        .093 Energy Marketing  Revenues
        .086 Gas  Transportation   Revenues
        .048 District  Heating  Revenues
        .027 Timber and Sawmill Revenues
        .022 Gas Storage Service  Revenues
        .022 Electric  Generation  Revenues
        .033 Other Revenues
      $1.000 Total

      Where it went to:

      $ .349 Gas Purchased
        .140 Wages, Including Benefits
        .109 Other Materials and Services
        .107 Taxes
        .099 Depreciation
        .069 Interest
        .051 Dividends - Common Stock
        .038 Fuel Used in Heat and Electric Generation
        .037 Reinvested in the Business
        .001 Minority Interest in Foreign Subsidiaries
      $1.000 TotalJanuary 23, 2002



                                                    Exhibit Index
                                                 -------------


                     (12)            Computation  of Ratio of  Earnings3.1            National Fuel Gas Company By-Laws as amended on
                                    December 13, 2001

                    10.4            Amendment to Fixed
                                    Charges

                    23.1            Consent of Ralph E. Davis Associates, Inc.

                    23.2            Consent of Independent Accountants

                    23.3            Consent of McDaniel & Associates Consultants Ltd.

                    27.1            Financial   Data  Schedule  forNational Fuel Gas Company and
                                    Participating Subsidiaries Executive Retirement
                                    Plan, effective September 5, 2001

                    10.5            Retirement Supplement Agreement, dated
                                    September 14, 2000, between the Twelve
                                    Months Ended September 30, 2000

                    27.2            Restated  Financial  Data  Schedule  forCompany and
                                    Gerald T. Wehrlin

                    10.6            Retirement Supplement Agreement, dated
                                    January 11, 2002, between the Twelve Months Ended September 30, 1999

                    99.1            Report of Ralph E. Davis Associates, Inc.

                    99.2            Report of McDaniel & Associates Consultants Ltd.Company and
                                    Joseph P. Pawlowski