-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, NLxGEG15bQPjCqD6IJmgQ0YbTckwpFhHzAiT3moVDCXt98IwfecDseISNs27KL4l ywmYqiRwJhMaLT1ShKaasw== 0000070145-02-000097.txt : 20021216 0000070145-02-000097.hdr.sgml : 20021216 20021216172457 ACCESSION NUMBER: 0000070145-02-000097 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 20 CONFORMED PERIOD OF REPORT: 20020930 FILED AS OF DATE: 20021216 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NATIONAL FUEL GAS CO CENTRAL INDEX KEY: 0000070145 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 131086010 STATE OF INCORPORATION: NJ FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03880 FILM NUMBER: 02859220 BUSINESS ADDRESS: STREET 1: 10 LAFAYETTE SQ CITY: BUFFALO STATE: NY ZIP: 14203 BUSINESS PHONE: 7168576980 MAIL ADDRESS: STREET 1: 10 LAFAYETTE SQ STREET 2: 10 LAFAYETTE SQ CITY: BUFFALO STATE: NY ZIP: 14203 10-K 1 form10k.htm FORM 10-K YEAR ENDING SEPTEMBER 30, 2002 National Fuel Gas Company Form 10-K for September 30, 2002

United States
Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended September 30, 2002

Commission File Number 1-3880


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

New Jersey 13-1086010
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
   
10 Lafayette Square 14203
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.

Title of each class Name of each exchange on which registered
Common Stock, $1 Par Value, and New 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. [    ]

      The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $1,634,293,000 as of November 30, 2002.

      Common Stock, $1 Par Value, outstanding as of November 30, 2002: 80,437,839 shares.

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the registrant's definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 20, 2003 are incorporated by reference into Part III of this report.


For the Fiscal Year Ended September 30, 2002

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
ALL OTHER CATEGORY AND CORPORATE OPERATIONS
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 EQUITY AND RELATED STOCKHOLDER 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 AND RELATED STOCKHOLDER MATTERS

ITEM 13     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Part IV

ITEM 14     CONTROLS AND PROCEDURES

ITEM 15     EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

SIGNATURES

CERTIFICATIONS

This Form 10-K contains “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements included in this Form 10-K at Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those statements that are designated with an asterisk (“*”) following the statement, as well as those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.

PART I

ITEM 1 Business

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The Company and its Subsidiaries

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National Fuel Gas Company (the Registrant), a holding company registered under the Public Utility Holding Company Act of 1935, as amended (the Holding Company Act), was organized under the laws of the State of New Jersey in 1902. The Registrant is engaged in the business of owning and holding securities issued by its twelve directly owned subsidiary companies. Except as otherwise indicated below, the Registrant owns all of the outstanding securities of its subsidiaries. Reference to “the Company” in this report means the Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure. Also, all references to a certain year in this report relate to the Company’s fiscal year ended September 30 of that year unless otherwise noted.

     The Company is a diversified energy company consisting of six reportable business segments.

1. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation sells natural gas or provides natural gas transportation services to approximately 732,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.

2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation. 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. Seneca Independence Pipeline Company (SIP) held a one-third general partnership interest in Independence Pipeline Company (Independence), a Delaware general partnership that had proposed to construct and operate a 400-mile pipeline to transport natural gas from Defiance, Ohio to Leidy, Pennsylvania (the Independence Pipeline). Independence was dissolved on September 30, 2002. As discussed in Item 7, MD&A under the heading "Capital Resources and Liquidity", in June 2002 Independence submitted a motion to the Federal Energy Regulatory Commission (FERC) requesting that FERC vacate the certificate that it had issued to Independence to construct, own and operate the Independence Pipeline. FERC formally vacated the certificate in July 2002.

      As discussed below under "Competition: The Pipeline and Storage Segment", in October 2002 the Company announced its intention to buy the Empire State Pipeline (Empire) from Duke Energy Corporation.

3. The Exploration and Production segment operations are carried out by Seneca Resources Corporation (Seneca), a Pennsylvania corporation. Seneca is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, in Wyoming and in the Gulf Coast region of Texas and Louisiana. Also, Exploration and Production operations are conducted in the provinces of Manitoba, Alberta, Saskatchewan and British Columbia in Canada by Seneca's wholly-owned subsidiaries, National Fuel Exploration Corp. (NFE), an Alberta, Canada corporation, and Player Resources Ltd. (Player), 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 asset is majority ownership of United Energy, a.s. (UE), a wholesale power and district heating company located in the northern part of the Czech Republic.

5. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation which markets natural gas to industrial, commercial, public authority and residential end-users in western and central New York and northwestern Pennsylvania, offering competitively priced energy and energy management services for its customers.

6. The Timber segment operations are carried out by Highland Forest Resources, Inc. (Highland), a Pennsylvania corporation, and by a division of Seneca known as its Northeast Division. This segment markets timber from its New York and Pennsylvania land holdings, owns three 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:

         o Upstate Energy Inc. (Upstate),  a New York corporation  engaged in wholesale natural gas marketing and other  energy-related
         activities;

         o Niagara  Independence  Marketing Company (NIM), a Delaware  corporation which owns a one-third general partnership  interest
         in DirectLink  Gas  Marketing  Company  (DirectLink),  a Delaware  general  partnership.  DirectLink,  was formed to engage in
         natural gas  marketing  and  related  businesses  in part by  subscribing  for firm  transportation  capacity on the  proposed
         Independence Pipeline (see Pipeline and Storage segment discussion above);

         o Leidy Hub, Inc.  (Leidy),  a New York  corporation  formed to provide  various  natural gas hub services to customers in the
         eastern United States;

         o Data-Track Account Services,  Inc.  (Data-Track),  a New York corporation which provides collection services principally for
         the Company's subsidiaries; and

         o Horizon Power, Inc.  (Horizon Power), a New York corporation  which is designated as an "exempt  wholesale  generator" under
         the Holding Company Act and is developing or operating mid-range independent power production facilities.

      No single customer, or group of customers under common control, accounted for more than 10% of the Company's consolidated revenues in 2002.

Rates and Regulations

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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. In 2002, both houses of Congress passed comprehensive energy bills that included repeal of the Holding Company Act. The bills were referred to a conference committee of the House and Senate, but no action was taken by the conferees prior to adjournment. It is likely that comprehensive energy legislation, including repeal of the Holding Company Act, will be re-introduced in the next session of Congress.* Thus far, the proposed legislation would transfer certain oversight responsibilities to the various state public utility regulatory commissions and FERC and would expand the access of these bodies to the books and records of companies in a holding company system. The proposed legislation 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 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 (including foreign) regulations on various subjects, including environmental matters, as other companies doing similar business in the same locations.

The Utility Segment

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The Utility segment contributed approximately 42.1% of the Company's 2002 net income available for common stock.

     Additional discussion of the Utility segment appears below in this Item 1 under the headings "Sources and Availability of Raw Materials," "Competition" and "Seasonality," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

The Pipeline and Storage Segment

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The Pipeline and Storage segment contributed approximately 25.3% of the Company's 2002 net income available for common stock.

     Supply Corporation currently has service agreements for substantially all of its firm transportation capacity, which totals approximately 2,075 thousand dekatherms (MDth) per day. The Utility segment accounts for approximately 1,171 MDth per day or 56.4% of the total capacity, and the Energy Marketing segment represents another 85 MDth per day or 4.1% of the total capacity. The remaining 819 MDth or 39.5% of Supply Corporation's firm transportation capacity is subject to firm contracts with nonaffiliated customers.

     Supply Corporation has available for sale approximately 68,854 MDth of firm storage capacity. The Utility segment has contracted for 31,395 MDth or 45.6% of the total capacity and the Energy Marketing segment accounts for another 3,955 MDth or 5.7% of the total capacity. Nonaffiliated customers have contracted for the remaining 33,504 MDth or 48.7% of the firm storage capacity. 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 Exploraton and Production Segment

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The Exploration and Production segment contributed approximately 22.8% of the Company's 2002 net income available for common stock.

     Additional discussion of the Exploration and Production segment appears below under the headings "Sources and Availability of Raw Materials" and "Competition," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

The International Segment

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The International segment incurred a net loss in 2002. The impact of this segment’s net loss in relation to the Company’s 2002 net income available for common stock was negative 3.8%.

     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 contributed approximately 7.3% of the Company's 2002 net income available for common stock.

     Additional discussion of the Energy Marketing segment appears below under the headings "Sources and Availability of Raw Materials," "Competition" and "Seasonality," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

The Timber Segment

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The Timber segment contributed approximately 8.2% of the Company's 2002 net income available for common stock.

     Additional discussion of the Timber segment appears below under the headings "Sources and Availability of Raw Materials," "Competition" and "Seasonality," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

All Other Category and Corporate Operations

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The All Other category and Corporate operations incurred a net loss in 2002. The impact of this net loss in relation to the Company’s 2002 net income available for common stock was negative 1.9%.

     Additional discussion of the All Other category and Corporate operations appears below in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

Sources and Availability of Raw Materials

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Natural gas is the principal raw material for the Utility segment. In 2002, the Utility segment purchased 109.8 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 57% of these purchases. Purchases of gas on the spot market (contracts of less than a year) accounted for 36% of the Utility segment’s 2002 gas purchases. Gas purchases from Dynegy Marketing and Trade, Mirant Americas Energy Marketing, LP, BP Energy Company and Anadarko Energy Services Company represented 15%, 13%, 12% and 11%, respectively, of total 2002 gas purchases by the Utility segment. These four producers or marketers provided gas from the southwestern United States under long-term contracts. No other producer or marketer provided the Utility segment with 10% or more of its gas requirements in 2002. Currently, the Utility segment’s top suppliers of natural gas are BP Energy Company, Amerada Hess Corp., Conoco Inc., Anadarko Energy Services Company and Occidental Energy Marketing, Inc.

     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. Additional discussion of proposed pipeline projects appears below under "Competition: The Pipeline and Storage Segment," in Item 7, MD&A and in Item 8 at Note H - Commitments and Contingencies.

     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 N - Supplementary Information for Oil and Gas Producing Activities.

     Coal is the principal raw material for the International segment, constituting 52% of the cost of raw materials needed in 2002 to operate the boilers which produce steam or hot water. Natural gas, oil, limestone and water combined accounted for the remaining 48% of such materials. Coal is purchased and delivered directly from the adjacent Mostecka Uhelna Spolecnost, a.s. mine in the Czech Republic for Horizon's largest coal-fired plant under a contract where price and quantity are the subject of negotiation each year. The Company has been informed that this mine has proven reserves through 2030.* The Czech Republic government imports natural gas from sources in Russia and the North Sea and transports the gas through the Transgas pipeline system, which is majority owned by RWE AG, a German multi-utility. The International segment purchases natural gas from one of the eight regional gas distribution companies in the Czech Republic. The Czech Republic government also imports oil. The International segment purchases oil from domestic and foreign refineries.

     With respect to the Timber segment, Highland requires an adequate supply of timber to process in its sawmill and kiln operations. Seventy percent of the timber processed comes from land owned by Seneca; 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 to deliver to its customers. In 2002, this segment purchased 31.5 Bcf of natural gas.

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 deregulation of the natural gas industry should continue to 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.*

     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 remains unclear 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 continue to reshape the roles of the gas utility industry and the state regulatory commissions. Regulators in both New York and Pennsylvania have adopted retail competition programs for natural gas supply purchases. However, 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.*

     In October 2002, the Company announced that it had signed an agreement to acquire Empire. Empire is a natural gas transmission pipeline that originates at the United States/Canada border at the Chippawa Channel of the Niagara River near Buffalo, New York and extends easterly for 157 miles where it terminates in Central New York just north of Syracuse, New York. Empire competes with other pipelines to transport natural gas from Canada to upstate New York. Refer to Item 7, MD&A under the heading "Capital Resources and Liquidity" and Item 8 at Note H - Commitments and Contingencies for further discussion of Empire.

     Supply Corporation and TransCanada PipeLines Limited together are pursuing a proposal to construct a pipeline to transport natural gas from Kirkwall, Ontario to the storage and market hub at Leidy, Pennsylvania. This project, called the Northwinds Pipeline, is competing for customers with other proposed pipeline projects that would bring natural gas from Canada to the markets in the northeast and mid-Atlantic regions of the United States. 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.* If completed, the Northwinds Pipeline would likely create opportunities for increased transportation and storage services by Supply Corporation.* For further discussion of the Northwinds Pipeline projects, refer to Item 7, MD&A under the heading "Investing Cash Flow."

Competition: The Exploration and Production Segment
The Exploration and Production segment competes with other gas and oil producers and marketers with respect to 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 subsidiaries NFE and Player, 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 their size, operating expertise and financial criteria.

Competition: The International Segment
Horizon competes with other entities seeking to develop or acquire foreign and domestic energy projects. Horizon, through UE, faces competition in the sale of thermal energy. Most customers can opt to install boilers to produce their thermal energy, rather than purchase thermal energy from the district heating system. In addition, UE faces competition in the sale of electricity. UE must submit price bids on an annual basis for the sale of its electricity to the regional distribution company. A large percentage of the electricity purchased by the regional distribution companies is produced by the Czech Republic’s dominant state-owned energy producer. UE sells electricity at the wholesale level.

Competition: The Energy Marketing Segment
The Energy Marketing segment competes with other marketers of natural gas and with other providers of energy management services. Although the deregulation of natural gas utilities is a relatively new occurrence, the competition in this area is well developed with regard to price and services from both local and regional marketers.

Competition: The Timber Segment
With respect to the Timber segment, Highland competes with other sawmill operations and with other suppliers of timber, logs and lumber. These competitors may be local, regional, national or international in scope. This competition, however, is primarily limited to those entities which either process or supply high quality hardwoods species such as cherry, oak and maple as veneer logs, saw logs, export logs or lumber ultimately used in the production of high-end furniture, cabinetry and flooring. The Timber segment sells its products both nationally and internationally.

Seasonality

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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 that this has on Utility segment revenues in New York is mitigated by a weather normalization clause which is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is more than 2.2% warmer than normal results in a surcharge being added to customers’ current bills, while weather that is more than 2.2% colder than normal results in a refund being credited to customers’ current bills.

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

     Variations in weather conditions can materially affect the volume of gas consumed by customers of the Energy Marketing segment and the amount of thermal energy consumed by the heating customers of the International segment. Volume variations can have a corresponding impact on revenues within these segments.

     The activities of the Timber segment vary on a seasonal basis and are subject to weather constraints. 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 or majority-owned subsidiaries had a total of 3,177 full-time employees at September 30, 2002, with 2,233 employees in all of its U.S. operations and 944 employees in its international operations. This is a decrease of 1.8% from the 3,235 total employed at September 30, 2001.

     Agreements covering employees in collective bargaining units in New York were renegotiated, effective as of November 2000, and are scheduled to expire in February 2006. Certain agreements covering employees in collective bargaining units in Pennsylvania were renegotiated, effective November 1998, and are scheduled to expire in May 2003. Other agreements covering employees in collective bargaining units in Pennsylvania were renegotiated, effective October 1, 2002, and are scheduled to expire in April 2007. An agreement covering employees in collective bargaining units in the Czech Republic was renegotiated in 2001 and is scheduled to expire in 2004.

     The Utility segment has numerous municipal franchises under which it uses public roads and certain other rights-of-way and public property for the location of facilities. When necessary, the Utility segment renews such franchises.

     The Company's Internet address is WWW.NATIONALFUELGAS.COM. This reference to the Company's Internet address shall not, under any circumstances, be deemed to incorporate the information available at such Internet address into this Form 10-K. The information available at the Company's Internet address is not part of this Form 10-K or any other report filed by the Company with the SEC.

Executive Officers of the Company as of November 15, 2002(1)

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

Philip C. Ackerman           Chairman of the Board of Directors since January 2002;  Chief  Executive  Officer
(58)                         since October  2001;  President  since July 1999;  and President of Horizon since
                             September  1995.  Mr.  Ackerman  has served as a Director  since March 1994,  and
                             previously  served  as  Senior  Vice  President  from  June 1989 to July 1999 and
                             President of Distribution Corporation from October 1995 to July 1999.

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

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

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

David F. Smith               President  of  Distribution  Corporation  since July 1999; Senior Vice President
(49)                         of Supply Corporation since July 2000.  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  President of Highland  since March
(55)                         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.

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

Gerald T. Wehrlin            President of NFR since May 2001;  Controller of the Company since  December 1980;
(64)                         and Vice  President  of Horizon  since  February  1997.  Mr.  Wehrlin  previously
                             served as Senior Vice President of  Distribution  Corporation  from April 1991 to
                             May 2001 and as  Secretary  and  Treasurer  of  Horizon  from  September  1995 to
                             February 1997.

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

Bruce H. Hale                President  of Horizon  Power since March 2001;  Senior Vice  President  of Supply
(53)                         Corporation  since 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.

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

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

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

Joseph P. Pawlowski          Treasurer since December 1980; Senior Vice President of Distribution  Corporation
(61)                         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.

- ---------------------------- --------------------------------------------------------------------------------------
Walter E. DeForest           Senior Vice President of Distribution  Corporation  since August 1993; and Senior
(61)                         Vice President of Supply Corporation from January 1992 to August 1993.

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

Anna Marie Cellino           Senior  Vice  President  of  Distribution   Corporation  since  July  2001;  Vice
(49)                         President of Distribution  Corporation from June 1994 to July 2001; and Secretary
                             of the Company since October 1995.

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

Ronald J. Tanski             Senior Vice President of Distribution  Corporation since July 2001; Controller of
(50)                         Distribution  Corporation since February 1997; Secretary and Treasurer of Horizon
                             since February 1997; and Vice President of  Distribution  Corporation  from April
                             1993 to July 2001.

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

John R. Pustulka             Senior Vice President of Supply  Corporation  since July 2001; and Vice President
(50)                         of Supply Corporation from April 1993 to July 2001.

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

James D. Ramsdell            Senior Vice  President  of  Distribution  Corporation  since July 2001;  and Vice
(47)                         President of Distribution Corporation from June 1994 to July 2001.

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

        (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 or she was elected as an officer. The executive officers serve at the pleasure of the Board of Directors.

        (2) Ages are as of September 30, 2002.

        (3) The information provided relates to the principal subsidiaries of the Company. Many of the executive officers have served 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 $2.8 billion at September 30, 2002. Approximately 51% of this investment was in the Utility and Pipeline and Storage segments, which are primarily located in western New York and northwestern Pennsylvania. The Exploration and Production segment, which is the next largest investment in net property, plant and equipment (38%), is primarily located in California, in the Appalachian region of the United States, in Wyoming, in the Gulf Coast region of Texas and Louisiana and in the provinces of Manitoba, Alberta, Saskatchewan and British Columbia in Canada. The remaining investment in net property, plant and equipment consisted primarily of the International segment (7%) which is located in the Czech Republic 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 augment the reserve base of oil and gas in the United States and Canada, to expand and improve transmission and distribution facilities for both retail and transportation customers, and to purchase district heating and power generation facilities in the Czech Republic. Net property, plant and equipment has increased $1.025 billion, or 56%, since 1997.

     The Utility segment had a net investment in property, plant and equipment of $960.0 million at September 30, 2002. The net investment in its gas distribution network (including 14,783 miles of distribution pipeline) and its service connections to customers represent approximately 57% and 29%, respectively, of the Utility segment's net investment in property, plant and equipment at September 30, 2002.

     The Pipeline and Storage segment had a net investment of $487.8 million in property, plant and equipment at September 30, 2002. Transmission pipeline, with a net cost of $148.1 million, represents 30% of this segment's total net investment and includes 2,471 miles of pipeline required to move large volumes of gas throughout its service area. Storage facilities consist of 32 storage fields, four of which are jointly operated with certain pipeline suppliers, and 439 miles of pipeline. Net investment in storage facilities includes $87.7 million of gas stored underground-noncurrent, representing the cost of the gas required to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other purposes, including that needed for no-notice transportation service. The Pipeline and Storage segment has 29 compressor stations with 75,306 installed compressor horsepower.

     The Exploration and Production segment had a net investment in property, plant and equipment of $1.072 billion at September 30, 2002. Of this amount, $814 million relates to properties located in the United States. The remaining net investment of $258 million relates to properties located in Canada.

     The International segment had a net investment in property, plant and equipment of $207.2 million at September 30, 2002. This represents UE's net investment in district heating and electric generation facilities.

     The Timber segment had a net investment in property, plant and equipment of $110.6 million at September 30, 2002. Located primarily in northwestern Pennsylvania, the net investment includes three sawmills and approximately 155,000 acres of land and timber.

     The Utility and Pipeline and Storage segments' facilities provided the capacity to meet the Company's 2002 peak day sendout, including transportation service, of 1,568.0 million cubic feet (MMcf), which occurred on February 4, 2002. Withdrawals from storage of 682.8 MMcf provided approximately 43.5% of the requirements on that day.

     Company maps are included in exhibit 99.5 of this Form 10-K.


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 N-Supplementary Information for Oil and Gas Producing Activities. Note N sets forth proved developed and undeveloped reserve information for Seneca. During 2002, Seneca’s proved developed and undeveloped reserves decreased significantly. Natural gas reserves decreased from 322 Bcf at September 30, 2001 to 258 Bcf at September 30, 2002 and oil reserves decreased from 115,328 thousands of barrels (Mbbl) to 99,717 Mbbl. These decreases can be attributed to several factors: (i) production and sales of properties (refer to Item 7, MD&A), (ii) limited drilling activity off-shore in the Gulf of Mexico which resulted in a reserve replacement of only 56% of consolidated production (the Company is shifting its emphasis from short-lived off-shore reserves to longer-lived on-shore reserves), and (iii) a determination that certain development drilling programs in California and Canada were uneconomic (reflected in Note N as revisions of previous estimates). Seneca’s oil and gas reserves reported in Note N as of September 30, 2002 were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Ralph E. Davis Associates, Inc. Seneca reports its oil and gas reserve information on an annual basis to the Energy Information Administration (EIA). The basis of reporting Seneca’s reserves to the EIA is identical to that reported in Note N.

     The following is a summary of certain oil and gas information taken from Seneca's records. All monetary amounts are expressed in U.S. dollars.

Production
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
For the Year Ended September 30                                             2002             2001              2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
United States
Average Sales Price per Mcf of Gas(1)                                      $2.99            $5.53             $3.31
Average Sales Price per Barrel of Oil(1)                                  $21.03           $25.43            $25.34
Average Production (Lifting) Cost per Mcf
  Equivalent of Gas and Oil Produced                                       $0.67            $0.55             $0.51
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
Average Sales Price per Mcf of Gas(1)                                      $2.29            $2.41            $ 2.52
Average Sales Price per Barrel of Oil(1)                                  $19.94           $24.29            $29.28
Average Production (Lifting) Cost per Mcf
  Equivalent of Gas and Oil Produced                                       $1.29            $1.34            $ 1.41
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Total
Average Sales Price per Mcf of Gas(1)                                      $2.88            $5.39             $3.31
Average Sales Price per Barrel of Oil(1)                                  $20.63           $24.99            $26.03
Average Production (Lifting) Cost per Mcf
  Equivalent of Gas and Oil Produced                                       $0.84            $0.73             $0.58
- ---------------------------------------------------------------- ----------------- ---------------- -----------------

        (1) Prices do no reflect gains or losses from hedging activities.

Productive Wells
- --------------------------------------- ------------------------ -------------------------- -------------------------
At September 30, 2002                        United States                Canada                     Total
- --------------------------------------- ------------------------ -------------------------- -------------------------
                                        Gas         Oil            Gas          Oil         Gas          Oil

Productive Wells            - gross     1,877       1,167           160         668         2,037        1,835
                            - net       1,763       1,144           100         605         1,863        1,749
- --------------------------- ----------- ----------- ------------ ------------ ------------- ------------ ------------


Developed and Undeveloped Acreage
- ----------------------------------------------- ---------------- ----------------- ---------------- -----------------
At September 30, 2002                                             United States        Canada            Total
- ----------------------------------------------- ---------------- ----------------- ---------------- -----------------


Developed Acreage                               - gross             644,109           148,557            792,666
                                                - net               577,463           113,800            691,263

Undeveloped Acreage                             - gross             792,696           781,645          1,574,341
                                                - net               581,584           700,811          1,282,395
- ----------------------------------------------- ---------------- ----------------- ---------------- -----------------


Drilling Activity
- ----------------------------------------------------------------------------------------------------------------------
                                                                Productive                           Dry
                                                        --------------------------------------------------------------
For the Year Ended September 30                               2002      2001      2000       2002      2001      2000
                                                        --------------------------------------------------------------

United States
Net Wells Completed                  - Exploratory            4.27     11.83     13.89       4.67      4.93      6.53
                                     - Development           75.30    108.60     82.82       2.10      1.00      1.00
- ----------------------------------------------------------------------------------------------------------------------
Canada
Net Wells Completed                  - Exploratory            0.20     10.00      1.00       4.00     11.00         -
                                     - Development           33.70     61.14     21.50       7.90      2.75      4.00
- ----------------------------------------------------------------------------------------------------------------------
Total
Net Wells Completed                  - Exploratory            4.47     21.83     14.89       8.67     15.93      6.53
                                     - Development          109.00    169.74    104.32      10.00      3.75      5.00
- ----------------------------------------------------------------------------------------------------------------------


Present Activities
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
At September 30, 2002                                              United States        Canada            Total
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------

Wells in Process of Drilling                     - gross               38.00             11.00            49.00
                                                 - net                 34.58             11.00            45.58
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------

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 21 injection wells and 89 production wells in the program. The total injection and production from this waterflood project is 4,200 barrels of water per day and 230 barrels of oil per day, respectively.

ITEM 3 Legal Proceedings

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In an action instituted in the New York State Supreme Court, Chautauqua County on January 31, 2000 against Seneca Resources Corporation (“Seneca”), National Fuel Resources, Inc., and “National Fuel Gas Corporation,” Donald J. and Margaret Ortel and Brian and Judith Rapp, “individually and on behalf of all those similarly situated,” allege, in an amended complaint which adds National Fuel Gas Company as a party defendant (a) that Seneca underpaid royalties due under leases operated by it, and (b) that Seneca’s co-defendants (i) fraudulenty participated in and concealed such alleged underpayment, and (ii) induced Seneca’s alleged breach of such leases. Plaintiffs seek an accounting, declaratory and related injunctive relief, and compensatory and exemplary damages. Defendants have denied each of plaintiffs’ material substantive allegations and set up twenty-five affirmative defenses in separate verified answers.

     A motion was made by plaintiffs on July 15, 2002 to certify a class comprising all persons presently and formerly entitled to receive royalties on the sale of natural gas produced and sold from wells operated in New York by Seneca (and its predecessor Empire Exploration, Inc).

     The defendants responded to that motion in August 2002. An oral argument on that motion took place in September 2002. The court has not yet entered a decision on the motion. If a class is certified, discovery would begin on the merits of the claims, and the case eventually tried or settled. The Company believes, based on the information presently known, that the ultimate resolution of this matter will not be material to the consolidated financial condition, results of operations, or cash flow of the Company.* No assurances can be given, however, as to the ultimate outcome of this matter, and it is possible that the outcome could be material to results of operations or cash flow for a particular quarter or annual period.

     For a discussion of various environmental and other matters, refer to Item 7, MD&A and Item 8 at Note H - Commitments and Contingencies.

     The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Company's present liquidity position, nor have a material adverse effect on the financial condition of the Company.

ITEM 4 Submission of Matters to a Vote of Security Holders

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No matter was submitted to a vote of security holders during the fourth quarter of 2002.

PART II

ITEM 5 Market for the Registrant's Common Equity and Related Stockholder Matters

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Information regarding the market for the Company’s common equity and related stockholder matters appears under Item 12 at Securities Authorized for Issuance Under Equity Compensation Plans, Item 8 at Note D-Capitalization and Note M-Market for Common Stock and Related Shareholder Matters (unaudited).

     On July 1, 2002, the Company issued a total of 1,920 unregistered shares of Company common stock to the eight non-employee directors then serving on the Board of Directors, 240 shares to each such director. On September 12, 2002, Rolland E. Kidder, Executive Director of the Robert H. Jackson Center for Justice in Jamestown, New York, was elected to the Board of Directors of the Company, and on September 25, 2002, the Company issued 50 unregistered shares of Company common stock to Mr. Kidder. All of these unregistered shares issued on July 1, 2002 and September 25, 2002 were issued as partial consideration for the directors' services during the quarter ended September 30, 2002, pursuant to the Company's Retainer Policy for Non-Employee Directors. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as transactions not involving a public offering.


ITEM 6 Selected Financial Data

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- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended September 30                             2002             2001            2000             1999            1998
- ----------------------------------------------------------------------------------------------------------------------------------
Summary of Operations (Thousands)
Operating Revenues                                 $1,464,496       $2,059,836      $1,412,416       $1,254,402      $1,248,000
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
  Purchased Gas                                       462,857        1,002,466         488,383          397,053         441,746
  Fuel Used in Heat and
    Electric Generation                                50,635           54,968          54,893           55,788          37,837
  Operation and Maintenance                           394,157          364,318         350,383          328,800         321,411
  Property, Franchise and Other Taxes                  72,155           83,730          78,878           91,146          92,817
  Depreciation, Depletion and
    Amortization                                      180,668          174,914         142,170          124,778         117,238
  Impairment of Oil and Gas
    Producing Properties                                    -          180,781               -                -         128,996
  Income Taxes                                         72,034           37,106          77,068           64,829          24,024
- ----------------------------------------------------------------------------------------------------------------------------------
                                                    1,232,506        1,898,283       1,191,775        1,062,394       1,164,069
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income                                      231,990          161,553         220,641          192,008          83,931
Operations of Unconsolidated
  Subsidiaries:
     Income                                               224            1,794           1,669              999             319
     Impairment of Investment in
       Partnership                                    (15,167)               -               -                -               -

- ----------------------------------------------------------------------------------------------------------------------------------
                                                      (14,943)           1,794           1,669              999             319
- ----------------------------------------------------------------------------------------------------------------------------------
Other Income                                            7,017           10,639           6,366           11,344          35,551
- ----------------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges and
 Minority Interest in Foreign Subsidiaries            224,064          173,986         228,676          204,351         119,801
Interest Charges                                      105,652          107,145         100,085           87,698          85,284
- ----------------------------------------------------------------------------------------------------------------------------------
Minority Interest in Foreign Subsidiaries                (730)          (1,342)         (1,384)          (1,616)         (2,213)
- ----------------------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect                       117,682           65,499         127,207          115,037          32,304
Cumulative Effect of Change in
  Accounting                                                -                -               -                -          (9,116)
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income Available for Common
  Stock                                              $117,682          $65,499        $127,207         $115,037         $23,188
- ----------------------------------------------------------------------------------------------------------------------------------
Per Common Share Data
  Basic Earnings per Common Share                       $1.47(1)         $0.83(2)        $1.63            $1.49           $0.30(3)
  Diluted Earnings per Common Share                     $1.46(1)         $0.82(2)        $1.61            $1.47           $0.30(3)
  Dividends Declared                                    $1.03            $0.99           $0.95            $0.92           $0.89
  Dividends Paid                                        $1.02            $0.97           $0.94            $0.91           $0.88
  Dividend Rate at Year-End                             $1.04            $1.01           $0.96            $0.93           $0.90
At September 30:
Number of Common Shareholders                          20,004           20,345          21,164           22,336          23,743
- ----------------------------------------------------------------------------------------------------------------------------------
Net Property, Plant and Equipment (Thousands)
  Utility                                            $960,015         $945,693        $939,753         $919,642        $906,754
  Pipeline and Storage                                487,793          483,222         474,972          466,524         460,952
  Exploration and Production                        1,072,200        1,081,622         998,852          674,813         638,886
  International                                       207,191          178,250         172,602          210,920         202,590
  Energy Marketing                                        125              262             360              489             353
  Timber                                              110,624           90,453          95,607           88,623          38,593
  All Other                                             6,797            1,209           1,241              214               -
  Corporate                                                 -                2               4                7
                                                                                                                              9
- ----------------------------------------------------------------------------------------------------------------------------------
Total Net Plant                                    $2,844,745       $2,780,713      $2,683,391       $2,361,232      $2,248,137
- ----------------------------------------------------------------------------------------------------------------------------------
Total Assets (Thousands)                           $3,401,309       $3,445,231      $3,251,031       $2,842,586      $2,684,459
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (Thousands)
Comprehensive Shareholders' Equity                 $1,006,858       $1,002,655       $ 987,437        $ 939,293       $ 890,085
Long-Term Debt, Net of Current Portion              1,145,341        1,046,694         953,622          822,743         693,021
- ----------------------------------------------------------------------------------------------------------------------------------

Total Capitalization                               $2,152,199       $2,049,349      $1,941,059       $1,762,036      $1,583,106
- ----------------------------------------------------------------------------------------------------------------------------------

        (1) 2002 includes impairment of investment in partnership of ($0.12) basic and diluted.

        (2) 2001 includes oil and gas asset impairment of ($1.32) basic, ($1.29) diluted.

        (3) 1998 includes oil and gas asset impairment of ($1.03) basic, ($1.02) diluted and cumulative effect of a change in depletion methods of ($0.12) basic and diluted.


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

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Results of Operations

Critical Accounting Policies

     The Company has prepared its consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.* In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting policies, which are defined as those policies whereby judgments or uncertainties could affect the application of those policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Item 8 at Note A - Summary of Significant Accounting Policies.

Oil and Gas Exploration and Development Costs. In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this accounting methodology, all costs associated with property acquisition, exploration, and development activities are capitalized, including internal costs directly identified with acquisition, exploration, and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities.

     The Company believes that determining the amount of the Company's proved reserves is a critical accounting estimate. Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full-cost method of accounting (on a unit-of-production basis). Unevaluated properties are excluded from depletion until it is determined whether or not there are proved reserves that can be assigned to these properties. Once it is determined whether there are proved reserves or not, these costs are transferred to the costs being depleted.

     In addition to depletion under the units-of-production method, proved reserves are a major component in the Securities and Exchange Commission (SEC) full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed on a country-by-country basis and determines a limit, or ceiling, to the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net revenues using a discount factor of 10%, which is computed by applying current market prices of oil and gas to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income taxes. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling, a non-cash impairment must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write-down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. The Company recorded a non-cash impairment relating to its Canadian properties in 2001. This impairment amounted to $104.0 million (after tax) and resulted from low oil and gas prices at September 30, 2001.

Regulation. The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to Statement of Financial Accounting Standards No. 71, "Accounting for the Effect of Certain Types of Regulation" and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows the Company to defer expenses and income on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratesetting process in a period different from the period in which they would have been reflected in the income statement by an unregulated company. These deferred regulatory assets and liabilities are then flowed through the income statement in the period in which the same amounts are reflected in rates. Management's assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item.

Accounting for Derivative Financial Instruments. The Company, primarily in its Exploration and Production and Energy Marketing segments, uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments can be categorized as price swap agreements, no cost collars, options and futures contracts. In accordance with the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, the Company accounts for these instruments as effective cash flow hedges or fair value hedges. As such, gains or losses associated with the derivative financial instruments are matched with gains or losses resulting from the underlying physical transaction that is being hedged. To the extent that the derivative financial instruments would ever be deemed to be ineffective, gains or losses from the derivative financial instruments would be marked-to-market on the income statement without regard to an underlying physical transaction.

     The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The fair value of the non exchange-traded derivative financial instruments are based on valuations determined by the counterparties.

Pension and Other Post-Retirement Benefits. The amounts reported in the Company’s financial statements related to its pension and other post-retirement benefits are determined on an actuarial basis, which uses many assumptions in the calculation of such amounts. These assumptions include the discount rate, the expected return on plan assets, the rate of compensation increase and, for other post-retirement benefits, the expected annual rate of increase in per capita cost of covered medical and prescription benefits. Changes in actuarial assumptions and actuarial experience could have a material impact on the amount of pension and post-retirement benefit costs and funding requirements experienced by the Company.* However, the Company expects to recover substantially all of its net periodic pension and other post-retirement benefit costs attributable to employees in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization.* For financial reporting purposes, the difference between the amounts of pension cost and post-retirement benefit cost recoverable in rates and the amounts of such costs as determined under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate, as discussed above under “Regulation.”

Earnings

2002 Compared with 2001
The Company’s earnings were $117.7 million, or $1.47 per common share ($1.46 per common share on a diluted basis) in 2002. This compares with earnings of $65.5 million, or $0.83 per common share ($0.82 per common share on a diluted basis) in 2001. However, earnings in 2002 included a non-cash impairment of the Company’s investment in the Independence Pipeline project in the Pipeline and Storage segment in the amount of $9.9 million (after tax), or $0.12 per common share (basic and diluted). Earnings in 2001 included a non-cash impairment of oil and gas assets in the Exploration and Production segment in the amount of $104.0 million (after tax), or $1.32 per common share ($1.29 per common share on a diluted basis), which is discussed above under Critical Accounting Policies - Oil and Gas Exploration and Development Costs. Without these non-cash impairments, earnings for 2002 would have been $127.5 million, or $1.59 per common share ($1.58 per common share on a diluted basis) and earnings for 2001 would have been $169.5 million, or $2.14 per common share ($2.11 per common share on a diluted basis). The decrease in earnings of $42.0 million (exclusive of the non-cash impairments) is primarily the result of lower earnings in the Exploration and Production segment. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.

2001 Compared with 2000
The Company’s earnings were $65.5 million, or $0.83 per common share ($0.82 per common share on a diluted basis) in 2001. This compares with 2000 earnings of $127.2 million, or $1.63 per common share ($1.61 per common share on a diluted basis). However, 2001 earnings included a non-cash impairment of oil and gas assets in the Exploration and Production segment in the amount of $104.0 million (after tax), or $1.32 per common share ($1.29 per common share on a diluted basis). Without this non-cash impairment, earnings for 2001 would have been $169.5 million, or $2.14 per common share ($2.11 per common share on a diluted basis). The increase in earnings of $42.3 million (exclusive of the non-cash impairment) was primarily the result of higher earnings in the Exploration and Production segment. 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)                                       2002             2001              2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Utility                                                                 $49,505          $60,707           $57,662
Pipeline and Storage (1)                                                 29,715           40,377            31,614
Exploration and Production  (2)                                          26,851          (32,284)           34,877
International                                                            (4,443)          (3,042)            3,282
Energy Marketing                                                          8,642           (3,432)           (7,790)
Timber                                                                    9,689            7,715             6,133
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
   Total Reportable Segments                                            119,959           70,041           125,778
All Other                                                                  (885)          (4,277)             (371)
Corporate                                                                (1,392)            (265)            1,800
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
   Total Consolidated (1) (2)                                          $117,682          $65,499          $127,207
- ---------------------------------------------------------------- ----------------- ---------------- -----------------

        (1) Exclusive of the non-cash asset impairment of the Company's investment in the Independence Pipeline project, 2002 earnings for the Pipeline and Storage segment, and Total Consolidated would have been $39,574 and $127,541, respectively.

        (2) Exclusive of the non-cash asset impairment of oil and gas assets, 2001 earnings for the Exploration and Production segment and Total Consolidated would have been $71,756 and $169,539, respectively.

Utility

Revenues

Utility Operating Revenues
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)                                   2002             2001              2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
  Retail Revenues:
    Residential                                                        $538,345        $ 875,050         $ 584,618
    Commercial                                                           86,963          154,266            93,914
    Industrial                                                           18,332           29,110            21,543
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                        643,640        1,058,426           700,075
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
  Off-System Sales                                                       68,606           84,078            47,962
  Transportation                                                         83,267           89,037           104,534
  Other                                                                  (1,292)          3,106             (6,112)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                       $794,221       $1,234,647         $ 846,459
- ---------------------------------------------------------------- ----------------- ---------------- -----------------


Utility Throughput - million cubic feet (MMcf)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30                                                2002             2001              2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
  Retail Sales:
    Residential                                                          64,639           73,530            68,196
    Commercial                                                           11,549           13,831            12,312
    Industrial                                                            3,715            4,089             4,276
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                         79,903           91,450            84,784
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
  Off-System Sales                                                       21,541           12,736            12,833
  Transportation                                                         61,909           66,283            71,862
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                        163,353          170,469           169,479
- ---------------------------------------------------------------- ----------------- ---------------- -----------------

2002 Compared with 2001
Operating revenues for the Utility segment decreased $440.4 million in 2002 compared with 2001. This decrease largely resulted from a $414.8 milion decrease in retail gas sales revenues. Off-system sales revenues, transportation revenues, and other revenues also decreased by $15.5 million, $5.8 million and $4.3 million, respectively.

     The decrease in retail gas sales revenues for the Utility segment was largely a function of the recovery of lower gas costs (gas costs are recovered dollar for dollar in revenues) resulting from a much lower cost of purchased gas. See further discussion of purchased gas below under the heading "Purchased Gas." The decrease also resulted from a decrease in retail sales volumes, as shown above. Warmer weather, as shown in the table below, and a general economic downturn in the Utility segment's sales territory were major factors for the decrease in retail sales volumes. Warmer weather and the general economic downturn were also factors in the decrease in transportation revenues and volumes. The decrease in off-system sales revenues was largely due to lower gas prices, which more than offset higher volumes. However, due to profit sharing with retail customers, the margins resulting from off-system sales were minimal.

     The decrease in other revenues primarily reflects estimated refund provisions recorded in 2002 and 2001 amounting to $5.3 million and $2.0 million, respectively, recorded in the Utility's New York jurisdiction under an earnings sharing mechanism. This earnings sharing mechanism, which is in accordance with the three-year rate settlement reached with the NYPSC that went into effect October 1, 2000 (New York Rate Settlement), requires the Utility to share with customers 50% of earnings above a predetermined amount. The final refund for the New York Rate Settlement will not be known until the end of 2003.

     Partly offsetting the decreases to revenue discussed above was the positive impact of a lower bill credit in the Utility's New York jurisdiction. In connection with the New York Rate Settlement, the Utility's New York customers received a $10.0 million rate decrease in the form of a bill credit for the November 1, 2000 through March 31, 2001 heating season. For the November 1, 2001 through March 31, 2002 heating season, the amount of the bill credit was reduced to $5.0 million.

2001 Compared with 2000
Operating revenues for the Utility segment increased $388.2 million in 2001 compared with 2000. This resulted from an increase in retail and off-system gas sales revenues of $358.4 million and $36.1 million, respectively. Other operating revenues also increased by $9.2 million. These increases were partly offset by a decrease in transportation revenues of $15.5 million.

     The increase in retail gas sales revenues for the Utility segment was largely a function of the recovery of higher gas costs, coupled with an increase in retail sales volumes, as shown above. The recovery of higher gas costs resulted from a much higher cost of purchased gas. See further discussion of purchased gas below under the heading "Purchased Gas." The increase in retail sales volumes was primarily the result of the migration of residential and small commercial customers from transportation service to retail service in both the New York and Pennsylvania jurisdictions, coupled with the impact of colder weather. This migration from transportation service resulted from one marketer entering bankruptcy proceedings, another marketer exiting the residential market, and the conclusion of a marketer pilot program in Pennsylvania. Off-system sales revenues increased because of higher gas prices. The decrease in transportation revenues and volumes was primarily due to the migration from transportation service discussed above and the fact that certain commercial and industrial customers were reducing usage due to a slowing economy or they were fuel switching.

     The increase in other operating revenues was due primarily to $5.5 million of various revenue reductions in 2000 that did not recur in 2001 (of which $2.2 million was offset by lower operation and maintenance expense in 2000). These revenue reductions related to the September 30, 2000 conclusion of the 1998 two-year rate settlement approved by the NYPSC. In addition to these adjustments, a $3.5 million lower provision for refund was recorded in 2001 as compared with 2000. The provision for refund in 2000 related to the conclusion of the 1998 two-year rate settlement and the provision for refund in 2001 related to the three-year rate settlement approved by the NYPSC in October 2000 (referred to above as New York Rate Settlement).

     Revenues in 2001 as compared to revenues in 2000 were reduced by a $10.0 million rate decrease for the Utility's New York customers that went into effect October 1, 2000 in connection with the aforementioned New York Rate Settlement. This rate decrease was provided in the form of a bill credit included in rates during the November 1, 2000 through March 31, 2001 heating season.

Earnings

2002 Compared with 2001
The Utility segment’s earnings in 2002 were $49.5 million, a decrease of $11.2 million when compared with the earnings of $60.7 million in 2001. However, the earnings for 2001 included $3.1 million of non-recurring earnings associated with stock appreciation rights (refer to Item 8 at Note D - Capitalization for a discussion of the November 2001 cancellation of stock appreciation rights) and $4.2 million of non-recurring after tax expense associated with early retirement offers in the Utility’s New York and Pennsylvania jurisdictions. Exclusive of these two items, the decrease in earnings was $12.3 million. Warmer weather in the Pennsylvania jurisdiction and lower normalized usage per account (normalized usage excludes the impact of weather on consumption) across the Utility’s service territory due to a downturn in the economy significantly decreased earnings in 2002. Also contributing to the decrease were several routine regulatory true-up adjustments associated with income taxes, lost and unaccounted for gas and interest expense. The impact of the refund provision discussed above was largely offset by lower operation and maintenance expenses, primarily labor. The impact of the lower bill credit ($5.0 million pre tax and $3.3 million after tax), discussed above, partly offset these decreases.

     The impact of weather on the Utility segment'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 the Utility segment's New York customers. In 2002, the WNC in New York preserved earnings of approximately $9.9 million (after tax) as weather, overall in the New York service territory, was warmer than normal for the period from October 2001 through May 2002. Since the Pennsylvania jurisdiction does not have a WNC, uncontrollable weather variations directly impact earnings. In the Pennsylvania service territory, weather during 2002 was 16.0% warmer than 2001 and 13.2% warmer than normal.

2001 Compared with 2000
In the Utility segment, 2001 earnings were $60.7 million, up $3.0 million from the prior year. However, the earnings for 2001 included $4.2 million of non-recurring after tax expense associated with early retirement offers in the Utility’s New York and Pennsylvania jurisdictions, and the earnings for 2000 included $2.2 million of non-recurring after tax revenue adjustments ($3.3 million pretax) related to the conclusion of the 1998 two-year rate settlement, as discussed in the revenue section above. Stock appreciation rights also had a significant impact on earnings as 2001 had earnings of $3.1 million and 2000 had $3.0 million of after tax expense. This was due to a significant change in the market price of the Company’s common stock as the market price increased significantly in 2000 followed by a significant decrease in the market price in 2001. Exclusive of these four items, there was actually a decrease in earnings of $1.1 million. A main reason for the decrease was the $10.0 million rate decrease in the Utility segment’s New York jurisdiction, as previously discussed, which more than offset the positive earnings impact of colder weather in the Utility segment’s Pennsylvania jurisdiction.

     In 2001, the WNC in New York preserved earnings of approximately $1.2 million (after tax) as weather, overall in the New York service territory, was warmer than normal for the period from October 2000 through May 2001. In the Pennsylvania service territory, which does not have a WNC, weather during 2001 was 12.3% colder than 2000 and 2.8% colder than normal.

Degree Days
- ---------------------------------- -------------- -------------- -------------------- --------------------------------
                                                                                              Percent (Warmer)
                                                                                                 Colder Than
                                                                                      --------------------------------
Year Ended September 30                           Normal         Actual               Normal            Prior Year
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
  2002:                            Buffalo        6,847          5,808                (15.2%)            (12.6%)
                                   Erie           6,146          5,334                (13.2%)            (16.0%)
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
  2001:                            Buffalo        6,865          6,648                 (3.2%)              5.3%
                                   Erie           6,179          6,351                  2.8%              12.3%
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
  2000:                            Buffalo        6,932          6,312                 (8.9%)              2.1%
                                   Erie           6,230          5,657                 (9.2%)              0.9%
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------

Purchased Gas
The cost of purchased gas is 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 $4.68 per thousand cubic feet (Mcf) in 2002, a decrease of 36% from the average cost of $7.35 per Mcf in 2001. The average cost of purchased gas in 2001 was 49% higher than the $4.93 per Mcf in 2000. Additional discussion of the Utility segment's gas purchases appears under the heading "Sources and Availability of Raw Materials" in Item 1.

Pipeline and Storage

Revenues

Pipeline and Storage Operating Revenues
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)                                   2002             2001              2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Transportation                                                     $88,082          $91,611           $92,305
Interruptible Transportation                                              3,315            1,917             1,578
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                         91,397           93,528            93,883
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Storage Service                                                     62,733           61,559            62,899
Interruptible Storage Service                                                 7              670               287
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                         62,740           62,229            63,186
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Other                                                                    13,247           15,334            12,590
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                       $167,384         $171,091          $169,659
- ---------------------------------------------------------------- ----------------- ---------------- -----------------

Pipeline and Storage Throughput - (MMcf)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30                                               2002             2001              2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Transportation                                                     290,507          304,183           291,818
Interruptible Transportation                                              7,315           17,372            21,730
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                        297,822          321,555           313,548
- ---------------------------------------------------------------- ----------------- ---------------- -----------------

2002 Compared with 2001
Operating revenues for the Pipeline and Storage segment decreased $3.7 million in 2002 as compared with 2001. For 2002, the decrease resulted primarily from a $2.1 million decrease in transportation revenues, as shown in the table above, and a $1.6 million decrease in cashout revenues included in other revenues in the table above. Cashout revenues represent a cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper. Cashout revenues are offset by purchased gas expense. The decrease in transportation revenues primarily reflects lower gathering rates (the rates charged by Supply Corporation to its transportation customers to move gas from a third-party well site or nearby meter to Supply Corporation’s transmission pipelines for delivery) as a result of a provision in a February 1996 settlement with FERC that ended in 2001. However, this rate decrease is largely offset by a reduction in amortization expense, thus having little impact on net income. Another impact of this settlement was that Supply Corporation no longer had the responsibility to process gas for local producers. As such, there was a reduction in gas processing revenues. However, this reduction was offset by higher revenues from unbundled pipeline sales and open access transportation. Both gas processing revenues and revenues from unbundled pipeline sales and open access transportation are included in other revenues in the table above. While transportation volumes decreased during the year, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight fixed-variable rate design.

2001 Compared with 2000
Operating revenues for the Pipeline and Storage segment increased $1.4 million in 2001 compared with 2000. The increase is attributable primarily to a $2.1 million increase in revenues from unbundled pipeline sales and open access transportation due to higher prices and volumes. While transportation volumes increased 8.0 Bcf during the fiscal year, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight fixed-variable rate design.

Earnings

2002 Compared with 2001
The Pipeline and Storage segment’s earnings in 2002 were $29.7 million, a decrease of $10.7 million when compared with earnings of $40.4 million in 2001. However, as discussed above, the earnings for 2002 included a $9.9 million non-recurring after tax expense ($15.2 million pre tax) associated with the impairment of the Company’s investment in the Independence Pipeline project. Earnings for 2001 included $4.2 million of non-recurring earnings associated with stock appreciation rights, $2.6 million of non-recurring earnings associated with a termination fee received from a customer to cancel a long-term transportation contract, and $1.1 million of non-recurring after tax expense associated with early retirement offers. Exclusive of these four items, there was an increase in earnings of $4.9 million. This increase resulted primarily from lower operation and maintenance expenses, which were the result of the Company’s recent early retirement offers, and a lower effective income tax rate.

2001 Compared with 2000
The Pipeline and Storage segment’s earnings for 2001 were $40.4 million, an increase of $8.8 million when compared with earnings for 2000. However, earnings for 2001 included $2.6 million of non-recurring earnings associated with a termination fee received from a customer to cancel a long-term transportation contract, and $1.1 million of non-recurring after tax expense associated with early retirement offers. Stock appreciation rights also had a significant impact on earnings as 2001 had earnings of $4.2 million and 2000 had $4.6 million of after tax expense. As previously discussed, significant swings in the market price of the Company’s common stock caused this earnings impact. Exclusive of these four items, there was a decrease in earnings of $1.5 million. While revenues from unbundled pipeline sales and open access transportation increased, the increase was more than offset by additional executive retirement benefit expenses in 2001.

Exploration and Production

Revenues

Exploration and Production Operating Revenues
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)                                       2002             2001              2000
- --------------------------------------------------------------- ----------------- ---------------- -----------------
  Gas (after Hedging)                                                 $148,467         $171,045          $108,832
  Oil (after Hedging)                                                  152,746          169,613           117,606
  Gas Processing Plant                                                  16,995           39,986            17,666
  Other                                                                  6,627           17,700            (6,034)
  Intrasegment Elimination (1)                                         (13,855)         (43,339)          (15,234)
- --------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                      $310,980         $355,005          $222,836
- --------------------------------------------------------------- ----------------- ---------------- -----------------

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

Production Volumes
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30                                                   2002             2001              2000
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Gas Production(MMcf)
  Gulf Coast                                                            25,776           30,663            32,760
  West Coast                                                             4,889            4,383             4,374
  Appalachia                                                             4,402            4,142             4,344
  Canada                                                                 6,387            1,816               192
- --------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                        41,454           41,004            41,670
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Oil Production (Mbbl)
  Gulf Coast                                                             1,815            1,914             1,415
  West Coast                                                             3,004            2,875             2,824
  Appalachia                                                                 9                7                 9
  Canada                                                                 2,834            3,061               899
- --------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                         7,662            7,857             5,147
- --------------------------------------------------------------- ----------------- ---------------- -----------------

Average Prices
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30                                                    2002             2001              2000
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Average Gas Price/Mcf
  Gulf Coast                                                              $2.89            $4.93             $3.29
  West Coast                                                              $2.86           $10.18             $3.62
  Appalachia                                                              $3.74            $5.03             $3.16
  Canada                                                                  $2.29            $2.41             $2.52
  Weighted Average                                                        $2.88            $5.39             $3.31
  Weighted Average After Hedging(1)                                       $3.58            $4.17             $2.61

Average Oil Price/barrel (bbl)
  Gulf Coast                                                             $22.83           $27.47            $28.27
  West Coast(2)                                                          $19.94           $24.06            $23.87
  Appalachia                                                             $23.76           $28.51            $25.12
  Canada                                                                 $19.94           $24.29            $29.28
  Weighted Average                                                       $20.63           $24.99            $26.03
  Weighted Average After Hedging(1)                                      $19.94           $21.59            $22.85
- --------------------------------------------------------------- ----------------- ---------------- -----------------

        (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.

2002 Compared with 2001
Operating revenues for the Exploration and Production segment decreased $44.0 million in 2002 as compared with 2001. Oil production revenue after hedging decreased $16.9 million due primarily to a $1.65 per bbl decrease in the weighted average price of oil after hedging. Gas production revenue after hedging, decreased $22.6 million. Decreases in the weighted average price of gas after hedging ($0.59 per Mcf) more than offset an overall increase in gas production. The overall increase in gas production is largely attributable to the Canadian properties acquired in June 2001 (i.e., the Player Petroleum Corp. acquisition) (Player) offset partially by decreased production in the Gulf Coast region. The decrease in Gulf Coast production is the result of the previously announced strategy to exit the Gulf of Mexico and shift emphasis to longer-lived on-shore reserves. The Company is shifting its emphasis because it believes that future quality off-shore reserves will require deeper and riskier off-shore drilling that will be more expensive than the reserves it has been able to find under its current drilling program in the shallow waters of the Gulf of Mexico.* The Company anticipates that shifting to longer-lived on-shore reserves will allow it to drill and develop lower cost, lower risk reserves.* Gas processing plant revenues decreased $23.0 million due to significantly lower gas prices. Other revenues decreased $11.1 million largely due to the non-recurring mark-to-market gains on derivative financial instruments that were recorded in 2001, as discussed below.

     Refer to further discussion of derivative financial instruments in the "Market Risk Sensitive Instruments" section that follows. Refer to the tables above for production and price information.

2001 Compared with 2000
Operating revenues for the Exploration and Production segment increased $132.2 million in 2001 compared with 2000. Gas production revenue after hedging increased $62.2 million due primarily to an increase in the weighted average price of gas after hedging. Overall gas production decreased, primarily in the Gulf Coast region, as there were delays in placing new platforms on production (due to rig availability constraints) and delays in work-over activity, mostly during the first and second quarters of 2001. New Gulf Coast production in the second half of 2001 was primarily oil production. Gas production from the Player acquisition in June 2001 helped mitigate the gas production decline in the Gulf Coast region. Oil production revenue after hedging increased $52.0 million in 2001 compared with 2000. This increase is due primarily to a 53% increase in oil production, largely attributable to the Exploration and Production segment’s Canadian properties acquired as part of the June 2000 acquisition of Tri Link Resources, Ltd. (Tri Link). Revenue from this segment’s gas processing plant was up $22.3 million due to higher prices. In addition, this segment recognized other revenue increases of $23.8 million due to mark-to-market adjustments related to derivative financial instruments. These mark-to-market adjustments largely related to written options that did not qualify for hedge accounting. The written options covered the period from January 1999 to December 2000.

Earnings

2002 Compared with 2001
The Exploration and Production segment’s earnings in 2002 were $26.9 million, an increase of $59.2 million when compared with a loss of $32.3 million in 2001. However, 2001 earnings included a non-cash impairment of this segment’s oil and gas assets totaling $104.0 million after tax, as previously discussed. Excluding the impact of this impairment, there was a decrease in earnings of $44.8 million. As discussed above, decreases in the weighted average commodity prices of crude oil and natural gas after hedging ($1.65 per bbl and $0.59 per Mcf, respectively) were primarily responsible for this earnings decrease. Higher workover expenses in the Gulf Coast region also contributed to the earnings decrease. The major workover expenditures occurred on Vermilion 252 and Eugene Island Block 264.

2001 Compared with 2000
The Exploration and Production segment experienced a loss of $32.3 million in 2001, a decrease of $67.2 million when compared to 2000 earnings of $34.9 million. Excluding the $104.0 million after tax non-cash impairment discussed above, this segment had 2001 earnings of $71.8 million, an increase of $36.9 million from 2000 earnings. A 53% increase in oil production, largely attributable to the Tri Link acquisition in June 2000, combined with higher natural gas prices, were major factors in this segment’s earnings increase, exclusive of the non-cash asset impairment. Also, this segment’s earnings benefited from the mark-to-market revenue increases discussed above. Partly offsetting higher revenues was an increase in production related expenses, including higher depletion, higher purchased gas expense (for the gas processing plant), an increase in lease operating costs and higher production taxes. General and administrative expenses increased, largely due to the Player and Tri Link acquisitions. Greater interest expense due to higher borrowings related to the Player and Tri Link acquisitions also partially offset the positive impact of higher revenues.

International

Revenues
International Operating Revenues
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)                                         2002             2001              2000
- --------------------------------------------------------------- ----------------- ---------------- -----------------

   Heating                                                               $65,386          $69,072           $69,387
   Electricity                                                            26,960           26,398            31,426
   Other                                                                   2,969            2,440             3,923
- --------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                         $95,315          $97,910          $104,736
- --------------------------------------------------------------- ----------------- ---------------- -----------------

International Heating and Electric Volumes
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30                                                     2002             2001              2000
- --------------------------------------------------------------- ----------------- ---------------- -----------------

   Heating Sales (Gigajoules) (1)                                      8,689,887        9,978,118        10,222,024
   Electricity Sales (megawatt hours)                                    972,832        1,019,901         1,147,303

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

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

2002 Compared with 2001
Operating revenues for the International segment decreased $2.6 million in 2002 as compared with 2001. The decrease in heat revenues in 2002 compared to 2001 reflects the June 2001 sale of Jablonecka teplarenska a realitni, a.s. (a district heating plant located in the Czech Republic which had heating revenues of $7.1 million in 2001, and heating volumes of 685,137 gigajoules in 2001). It also reflects the impact of weather in the Czech Republic, which was 5% warmer in 2002 than in the prior year. However, an increase in the average value of the Czech koruna (CZK) compared to the U.S. dollar offset much of the impact of these negative factors.

2001 Compared with 2000
Operating revenues for the International segment decreased $6.8 million in 2001 compared with 2000. The revenue decrease largely reflects a decrease in the average value of the CZK compared to the U.S. dollar during the 2001 heating season compared to the 2000 heating season. Exclusive of the exchange rate impact, heating revenues increased due to rate increases offset partly by lower volumes associated with warmer weather. Electric revenues, exclusive of the exchange rate impact, decreased as a result of lower volumes (principally attributable to the scheduled shutdown of a generating turbine that had reached the end of its useful life) and a decline in electric rates.

Earnings

2002 Compared with 2001
The International segment experienced a loss of $4.4 million in 2002 compared with a loss of $3.0 million in 2001. Higher operation and maintenance expenses associated with the Company’s European power development projects (refer to Capital Resources and Liquidity under the heading “Estimated Capital Expenditures”) were the main factors for the higher loss in 2002. Lower interest expense and a higher effective tax rate partially offset the impact of higher operation and maintenance expenses.

2001 Compared with 2000
The International segment experienced a loss of $3.0 million in 2001 compared with 2000 earnings of $3.3 million. Lower heat and electric margins, as a result of warmer weather and the scheduled shutdown of a generating turbine, were the primary reasons for this decrease. The decrease also reflects a decrease in value of the CZK compared to the U.S. dollar, as previously discussed.

Energy Marketing

Revenues

Energy Marketing Operating Revenues
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30 (Thousands)                                        2002               2001                2000
- ------------------------------------------------------------- ------------------- ------------------ -------------------

Natural Gas (after Hedging)                                            $151,219           $257,005            $139,614
Electricity                                                                   -              1,362               1,941
Other                                                                        38                839              (7,626)
- ------------------------------------------------------------- ------------------- ------------------ -------------------
                                                                       $151,257           $259,206            $133,929
- ------------------------------------------------------------- ------------------- ------------------ -------------------

Energy Marketing Volumes
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30                                                    2002               2001                2000
- ------------------------------------------------------------- ------------------- ------------------ -------------------

Natural Gas - (MMcf)                                                     33,042             36,753              35,465
- ------------------------------------------------------------- ------------------- ------------------ -------------------

2002 Compared with 2001
Operating revenues for the Energy Marketing segment decreased $107.9 million in 2002, as compared with 2001. This decrease was primarily the result of lower natural gas commodity prices that were recovered through revenues. Lower volumes, which were principally the result of warmer weather, also contributed to the decrease in operating revenues.

     Refer to further discussion of derivative financial instruments in the "Market Risk Sensitive Instruments" section that follows.

2001 Compared with 2000
Operating revenues for the Energy Marketing segment increased $125.3 million in 2001 compared with 2000. The primary reason for this increase was the higher gas costs that are reflected in the natural gas marketing revenues. Higher marketing volumes are primarily due to colder weather in 2001 compared to 2000. This compensated for a 4% decrease in NFR’s customers from September 30, 2000 to September 30, 2001. In addition, the Energy Marketing segment recognized a negative $8.6 million mark-to-market adjustment in 2000 (included in “Other” on the table above) related to written options and futures contracts that did not qualify for hedge accounting.

Earnings

2002 Compared with 2001
Earnings in the Energy Marketing segment increased $12.1 million in 2002 as compared with 2001. This increase primarily reflects higher margins on gas sales and lower interest and operation and maintenance expenses. Margins increased as a result of improved operational strategies put in place by the Energy Marketing segment’s new management team.

2001 Compared with 2000
The Energy Marketing segment incurred a loss for 2001 of $3.4 million, a decrease of $4.4 million compared with the loss of $7.8 million in 2000. However, the loss for 2001 included $1.3 million of non-recurring after tax expense associated with a mark-to-market loss on natural gas inventory. Exclusive of this item, the loss in 2001 was $2.1 million, a decrease of $5.7 million from the loss incurred in 2000. The most significant reason for the lower loss was the change in mark-to-market adjustments from 2000 to 2001 ($5.9 million positive contribution after tax), referred to above.

Timber

Revenues

Timber Operating Revenues
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30 (Thousands)                                        2002               2001                2000
- ------------------------------------------------------------- ------------------- ------------------ -------------------

Log Sales                                                               $21,528            $23,460             $24,091
Green Lumber Sales                                                        6,567              5,597               4,397
Kiln Dry Lumber Sales                                                    15,976             12,320              10,152
Other                                                                     3,336              3,537               2,905
- ------------------------------------------------------------- ------------------- ------------------ -------------------
                                                                        $47,407            $44,914             $41,545
- ------------------------------------------------------------- ------------------- ------------------ -------------------

Timber Board Feet
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30 (Thousands)                                        2002               2001                2000
- ------------------------------------------------------------- ------------------- ------------------ -------------------

Log Sales                                                                 8,174              8,839               9,370
Green Lumber Sales                                                       12,878             10,332               8,193
Kiln Dry Lumber Sales                                                    10,794              8,804               6,987
- ------------------------------------------------------------- ------------------- ------------------ -------------------
                                                                         31,846             27,975              24,550
- ------------------------------------------------------------- ------------------- ------------------ -------------------

2002 Compared with 2001
Operating revenues for the Timber segment increased $2.5 million in 2002, as compared with 2001. When comparing 2002 to 2001, log sales decreased $1.9 million as weather that was warmer and wetter than normal during the first and second quarters of 2002 hampered the ability to cut and haul logs, specifically cherry veneer. The Company made up for this lost revenue through higher sales of lumber. Green lumber sales increased $1.0 million and kiln dry lumber sales increased $3.7 million (mostly due to an increase in kiln dry cherry volumes).

2001 Compared with 2000
Operating revenues for the Timber segment increased $3.4 million in 2001, as compared with 2000. Green lumber sales were up due to an increase in board feet sold at slightly higher prices. The increase in kiln dry lumber sales was due to the operation of two additional kilns brought on line in August 2000. The decrease in log sales revenues primarily reflects lower sales of quality logs offset partly by higher average prices.

Earnings

2002 Compared with 2001
Earnings in the Timber segment increased $2.0 million in 2002 as compared with 2001. The increase was primarily due to higher operating revenues, as mentioned above, and lower interest expense. The increase in operating revenues was primarily due to an increase in kiln dry cherry lumber sales volumes.

2001 Compared with 2000
Timber segment earnings of $7.7 million in 2001 were up $1.6 million compared with 2000. The increase was primarily due to higher operating revenues, as mentioned above, and lower interest expense.

Corporate and All Other Operations

2002 Compared with 2001
Corporate and all other operations experienced a loss of $2.3 million in 2002, an improvement of $2.2 million over the loss of $4.5 million in 2001. However, the loss for 2001 included $0.7 million of non-recurring earnings associated with stock appreciation rights and $3.5 million of non-recurring after tax expense associated with a mark-to-market loss on natural gas inventory by Upstate, the Company’s wholly-owned subsidiary which is engaged in wholesale natural gas marketing and other energy-related activities. Exclusive of these items, earnings decreased $0.6 million largely due to higher interest costs, partially offset by lower operation costs.

2001 Compared with 2000
Corporate and all other operations experienced a loss of $4.5 million in 2001, a decrease of $5.9 million over the gain of $1.4 million in 2000. However, the loss for 2001 included $3.5 million of non-recurring after tax expense associated with a mark-to-market loss on natural gas inventory by Upstate, as discussed above. Stock appreciation rights also had a significant impact on earnings as 2001 had earnings of $0.7 million and 2000 had $0.7 million of after tax expense. As previously discussed, significant swings in the market price of the Company’s common stock caused this earnings impact. Exclusive of these three items, earnings decreased $3.8 million largely due to higher interest costs and higher operation costs.

Operations of Unconsolidated Subsidiaries
The Company’s unconsolidated subsidiaries consist of equity method investments in Seneca Energy II, LLC (Seneca Energy), Model City Energy, LLC (Model City), and Energy Systems North East, LLC (ESNE). The Company has 50% ownership interests in each of these entities. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. ESNE sells its electricity into the New York power grid. The Company also had a 33-1/3% equity method investment in Independence Pipeline Company which was written off in 2002, as previously discussed. The Independence write-off of $15.2 million ($9.9 million after tax) is recorded on the Consolidated Statement of Income as Impairment of Investment in Partnership.

2002 Compared with 2001
Income from unconsolidated subsidiaries (which represents the Company’s equity method interest in the income or loss from its investment in unconsolidated subsidiaries) decreased $1.6 million in 2002 compared with 2001. This decrease is largely attributable to losses experienced by the ESNE investment during 2002 of $0.1 million compared to income in the prior year of $0.9 million. ESNE was formed on April 30, 2001 so income for 2001 did not reflect any of the normal operating losses that ESNE incurs during the fall and winter months. ESNE generates most of its electricity during the spring and summer months when electricity demand peaks for air conditioning requirements. ESNE experienced higher electric generation revenues in the spring and summer of 2001 compared with the same period in 2002. The Seneca Energy investment also experienced an earnings decrease of $0.6 million due to lower electric generation revenues and higher repair and maintenance expenditures on the generating engines. Some repairs were delayed from 2001 to 2002 to enable Seneca Energy to operate more hours while market prices for electricity were higher than normal.

2001 Compared with 2000
Income from unconsolidated subsidiaries increased $0.1 million in 2001 compared with 2000. The ESNE and Model City investments added income of $0.9 million and $0.1 million, respectively, as 2001 was the first year of operation for both investments. The Seneca Energy investment also saw an increase in income of $0.5 million as 2001 was the first complete year of operation for this investment. These increases were largely offset by a $1.4 million reduction in equity method income from Independence Pipeline Company.

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 $3.6 million in 2002 compared with 2001. This decrease resulted primarily from a $4.0 million termination fee received in 2001 from a customer in the Pipeline and Storage segment to cancel a long-term transportation contract. The Company has been able to market the excess capacity resulting from this termination.

     Other income increased $4.8 million in 2001 compared with 2000. This increase resulted primarily from the same $4.0 million buyout of a long-term transportation contract in the Pipeline and Storage segment discussed above.

Interest Charges
Interest on long-term debt increased $8.7 million in 2002 and $14.7 million in 2001. The increase in both years resulted mainly from a higher average amount of long-term debt outstanding. Long-term debt balances have grown significantly over the past few years primarily as a result of acquisition activity in the Exploration and Production segment. These acquisitions were initially financed with short-term debt which was subsequently repaid through the proceeds from the issuance of long-term debt.

     Other interest charges decreased $10.2 million in 2002 and $7.6 million in 2001. The decrease in 2002 was the result of a decrease in the average amount of short-term debt outstanding (short-term debt was refinanced with long-term debt) and lower weighted average interest rates. The decrease in 2001 was primarily the result of lower weighted average interest rates on short-term debt.

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)                                        2002                2001                 2000
- ----------------------------------------------------------- -------------------- ------------------- --------------------

Provided by Operating Activities                                        $345.6              $414.0               $238.2
Capital Expenditures                                                    (232.4)             (292.7)              (269.4)
Investment in Subsidiaries,
  Net of Cash Acquired                                                       -               (90.6)              (123.8)
Investment in Partnerships                                                (0.5)               (1.8)                (4.4)
Other Investing Activities                                                27.1                (2.8)                13.3
Short-Term Debt, Net Change                                             (224.8)             (143.4)               226.5
Long-Term Debt, Net Change                                               139.6               187.2                (18.1)
Issuance of Common Stock                                                  10.9                11.5                 14.3
Dividends Paid on Common Stock                                           (81.0)              (76.7)               (73.0)
Dividends Paid to Minority
  Interest                                                                   -                   -                 (0.2)
Effect of Exchange Rates on Cash                                           1.5                (0.6)                (0.5)
- ----------------------------------------------------------- -------------------- ------------------- --------------------
Net Increase (Decrease) in Cash
  and Temporary Cash Investments                                        $(14.0)               $4.1                 $2.9
- ----------------------------------------------------------- -------------------- ------------------- --------------------
Operating Cash Flow

Internally generated cash from operating activities consists of net income available for common stock, adjusted for noncash expenses, noncash income and changes in operating assets and liabilities. Noncash items include depreciation, depletion and amortization, impairment of oil and gas producing properties (in 2001), deferred income taxes, impairment of investment in partnership, income or loss from unconsolidated subsidiaries net of cash distributions and minority interest in foreign subsidiaries.

     Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment's New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation's straight fixed-variable rate design.

     Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil. The Company uses various derivative financial instruments, including price swap agreements, no cost collars and options in an attempt to manage this energy commodity price risk.

     Net cash provided by operating activities totaled $345.6 million in 2002, a decrease of $68.4 million compared with the $414.0 million provided by operating activities in 2001. Lower cash receipts from the sale of oil and gas in the Exploration and Production segment more than offset higher margins on gas sales in the Energy Marketing segment. Oil and gas prices were down significantly in the Exploration and Production segment for much of 2002 and oil and gas production was slightly lower than 2001.

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 $232.9 million in 2002. The table below presents these expenditures:

- ----------------------------------------------------------- ------------------- ------------------- -----------------
                                                                                                              Total
                                                                                      Investments      Expenditures
                                                                      Capital     in Corporations         For Long-
Year Ended September 30, 2002 (Millions)                         Expenditures     or Partnerships      Lived Assets
- ----------------------------------------------------------- ------------------- ------------------- -----------------
Utility                                                               $ 51.5                $  -            $ 51.5
Pipeline and Storage                                                    29.8                 0.5              30.3
Exploration and Production                                             114.6                   -             114.6
International                                                            4.2                   -               4.2
Energy Marketing                                                         0.1                   -               0.1
Timber                                                                  25.6                   -              25.6
All Other                                                                6.6                   -               6.6
- ----------------------------------------------------------- ------------------- ------------------- -----------------
                                                                      $232.4                $0.5            $232.9
- ----------------------------------------------------------- ------------------- ------------------- -----------------

Utility
The majority of the Utility capital expenditures were made for replacement of mains and main extensions, as well as for the replacement of service lines.

Pipeline and Storage
The majority of the Pipeline and Storage segment’s capital expenditures were made for additions, improvements and replacements to this segment’s transmission and gas storage systems. Approximately $4.4 million was spent on expansion of transportation capacity on Line YM53 running from Ellisburg, Pennsylvania to Leidy, Pennsylvania.

     During 2002, SIP made an additional $536,000 investment in Independence Pipeline Company (Independence), bringing SIP's total investment to $15.2 million. In June 2002, Independence submitted a motion to FERC requesting that FERC vacate the certificate issued to Independence on July 12, 2000 to construct, own and operate the Independence Pipeline. Independence took this action because it had been unable to obtain sufficient customer contracts to proceed with the project. In connection with the filing of the motion by Independence, SIP wrote off its $15.2 million investment in Independence, as previously discussed. FERC formally vacated the certificate in an order issued in July 2002.

Exploration and Production
The Exploration and Production segment’s capital expenditures included approximately $81.5 million of capital expenditures for on-shore drilling, construction and recompletion costs for wells located in Louisiana, Texas, California and Canada as well as on-shore geological and geophysical costs, including the purchase of certain three-dimensional seismic data and fixed asset purchases. Of the $81.5 million discussed above, $27.0 million was spent on the Exploration and Production segment’s Canadian properties. The Exploration and Production segment’s capital expenditures also included approximately $33.1 million for its off-shore program in the Gulf of Mexico, including offshore drilling expenditures, offshore construction, lease acquisition costs and geological and geophysical expenditures.

     During 2002, the Exploration and Production segment sold oil and gas properties amounting to $22.1 million. Most of these properties were in the Gulf Coast region. These proceeds were recorded as a reduction of property, plant and equipment and are reflected in Other Investing Activities on the Consolidated Statement of Cash Flows.

International
The majority of the International segment’s capital expenditures were concentrated on the construction of boilers at a district heating and power generation plant in the Czech Republic. The expenditures also included improvements and replacements within the district heating and power generation plants.

Timber
The majority of the Timber segment capital expenditures were made for the purchase of land and timber rights in Potter County, Pennsylvania in June 2002. The land, consisting of approximately 3,656 acres, was purchased by Seneca from Wending Creek 3656, LLC, an entity controlled by certain members of the John Rigas family for $464,930. A Form 8-K filed by Adelphia Communications Corporation (Adelphia) on June 14, 2002 states that the Rigas family had previously agreed to transfer the land to Adelphia in exchange for a $464,930 reduction in the amount of the Rigas family’s primary co-borrowing obligations, and Seneca paid the purchase price of the land directly to Adelphia. Highland purchased the timber rights associated with the land from ACC Operations, Inc., a wholly owned subsidiary of Adelphia, for $19,535,070. The remaining capital expenditures were for smaller purchases of land and timber as well as equipment for this segment’s sawmill and kiln operations.

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

  ------------------------------------------------------------- ----------------- ---------------- -----------------
  Year Ended September 30 (Millions)                                       2003             2004              2005
  ------------------------------------------------------------- ----------------- ---------------- -----------------
  Utility                                                                 $48.1            $48.1             $48.1
  Pipeline and Storage                                                     24.0             30.2              24.8
  Exploration and Production                                               81.6             82.4              83.6
  International                                                             9.6              4.3               4.7
  Timber                                                                    0.8              0.3               0.3
  All Other                                                                10.5                -                 -
  ------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                         $174.6           $165.3            $161.5
  ------------------------------------------------------------- ----------------- ---------------- -----------------

     Estimated capital expenditures for the Utility segment in 2003 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 2003 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 expansion of transportation capacity on Line YM53 running from Ellisburg, Pennsylvania to Leidy, Pennsylvania.* The estimated capital expenditures do not include any partnership investments for Northwinds Pipeline.

     The estimated capital expenditures also do not include the Empire State Pipeline (Empire), which the Company agreed to purchase in October 2002 from Duke Energy Corporation for $180.0 million in cash plus assumed debt of $60.0 million or any subsequent capital expenditures that would occur upon completion of the acquisition. Empire is a 157-mile, 24-inch pipeline that begins at the Canadian border near Buffalo, New York, which is within the Company's service territory, and terminates in Central New York just north of Syracuse, New York. Empire is regulated by the NYPSC. Empire has the capacity to transport 525 million cubic feet of gas per day and currently has almost all of its capacity under contract, with a substantial portion being long-term contracts. Empire delivers natural gas supplies to major industrial companies, utilities (including the Company's Utility segment), and power producers. Empire would better position the Company to bring Canadian gas supplies into the East Coast markets of the United States as demand for natural gas along the East Coast increases.* The Company notified the Department of Justice and Federal Trade Commission of the proposed acquisition as required under the antitrust laws, and the Company's request for early termination of the antitrust waiting period has been granted. The Company has also made a filing seeking approval of the transaction from the NYPSC. Subject to NYPSC approval, it is anticipated that the purchase will be completed in the beginning of calendar 2003.* The Company is evaluating various alternatives to finance this acquisition. Those alternatives could include the sale of certain non-regulated assets, the issuance of equity, or the issuance of debt. *

     The Company continues to explore various opportunities to participate in transporting gas to the Northeast, either through Supply Corporation's system or in partnership with others. This includes the proposed Northwinds Pipeline that the Company and TransCanada PipeLines Limited are pursuing. This project presently contemplates a 215-mile, 30-inch natural gas pipeline that would originate in Kirkwall, Ontario, cross into the United States near Buffalo, New York and follow a southerly route to its destination in the Ellisburg-Leidy area in Pennsylvania. At September 30, 2002, the Company had incurred approximatley $1.3 million in costs (all of which have been expensed) associated with this project. The initial capacity of the pipeline would be approximately 500 million cubic feet of natural gas per day with the estimated cost of the pipeline ranging from $350 to $400 million. If the pipeline is constructed, it is possible that a significant amount of the construction costs would be financed by banks or other financial institutions with the pipeline serving as collateral for the financing arrangement.*

     Estimated capital expenditures in 2003 for the Exploration and Production segment include approximately $37.6 million for Canada, $22.0 million for the Gulf Coast region ($15.4 million on the off-shore program in the Gulf of Mexico), $12.8 million for the West Coast region and $9.2 million for the Appalachian region.* Overall, estimated capital expenditures in 2003 for the Exploration and Production segment are lower than the prior year as the Company intends to live within cash flow and pay down debt.* It should also be noted that estimated off-shore expenditures are lower than the prior year as the Company continues to shift its emphasis from short-lived off-shore reserves to longer-lived on-shore reserves.

     The estimated capital expenditures for the International segment in 2003 will be concentrated on improvements and replacements within the district heating and power generation plants in the Czech Republic.* The estimated capital expenditures do not include any expenditures for the Company's European power development projects. Currently, any costs incurred on these power development projects are expensed. The Company's European power development projects are primarily in Italy and Bulgaria. In Italy, the Company has signed a joint development agreement with an Italian utility for the construction of a 400-megawatt combined-cycle natural gas electric generating plant. The estimated cost of this project is $200.0 million to $210.0 million. In Bulgaria, the Company is pursuing the opportunity to construct, own and operate two new 127 megawatt gas-fired combustion turbines. The estimated cost of this project is $180.0 million to $200.0 million. Whether the Company moves forward to construct these projects will depend on successful negotiation of various operating agreements as well as the availability of funds from banks or other financial institutions to cover a significant amount of the construction costs.* The respective projects would serve as collateral for such financing arrangements.*

     Estimated capital expenditures in the Timber segment will be concentrated on the 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 estimated capital expenditures in the All Other category in 2003 will be concentrated on the purchase and installation of a gas turbine and steam turbine by Horizon Power to create a 55-megawatt cogeneration facility in Buffalo, New York.

     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

In August 2002, $97.7 million of the Company’s $100.0 million 6.214% medium-term notes due August 2027 were repaid by the Company at par plus accrued interest. The Company used short-term debt to temporarily refund the $97.7 million to the debt holders. The remaining $2.3 million of the original $100.0 million issuance is scheduled to mature in August 2027.

     In September 2002, the Company issued $97.7 million of 6.5% senior unsecured notes due in September 2022. These notes become callable by the Company at par in September 2006. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $94.9 million. The proceeds of this debt issuance were used to repay the short-term debt used to temporarily refund the $97.7 million discussed in the previous paragraph.

     In November 2001, the Company issued $150.0 million of 6.70% medium-term notes due in November 2011. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $149.0 million. The proceeds of this debt issuance were used to reduce short-term debt.

     Consolidated short-term debt decreased $224.3 million during 2002 primarily due to the November 2001 medium-term note issuance discussed above, and the use of cash from operations to pay down short-term debt. 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 issuance and repayment. The Company has SEC authorization under the Public Utility Holding Company Act of 1935, to borrow and have outstanding as much as $750.0 million of short-term debt at any time through December 31, 2005. The total amount available to be issued under the Company's commercial paper program is $200.0 million. The commercial paper program is backed by a committed $220 million, 364-day and 3-year credit facility, which was effective on September 30, 2002. Under this committed credit facility, the Company agrees that its debt to capitalization ratio will not, at the last day of any fiscal quarter, exceed .65 from September 30, 2002 through September 30, 2003, .625 from October 1, 2003 through September 30, 2004 and .60 from October 1, 2004 and at all times thereafter. With regards to the Company's short-term notes payable to banks, the Company uses uncommitted bank lines of credit aggregating $415.0 million. These uncommitted bank lines of credit are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed.* If a downgrade in the Company's credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company could borrow under its uncommitted bank lines of credit or seek other liquidity sources, including cash provided by operations. At September 30, 2002, the Company had outstanding short-term notes payable to banks and commercial paper of $91.3 million and $174.1 million, respectively.

     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, 2002, the Company would have been permitted to issue up to a maximum of $179.0 million in additional long-term unsecured indebtedness at projected market interest rates in addition to being able to issue new indebtedness to replace maturing debt.

     The Company's indenture also contains certain cross-default provisions wherein the failure by the Company to pay the scheduled interest or principal on its outstanding short-term or long-term debt (if such failure is not cured) could trigger the obligation to re-pay the debt outstanding under said indenture. The Company believes that it has adequate committed credit facilities in place to protect against such defaults.*

     The Company's embedded cost of long-term debt was 7.0% at both September 30, 2002 and 2001, respectively.

     The Company also has authorization from the SEC, under the Holding Company Act, to issue long-term debt securities and equity securities in amounts not exceeding $1.5 billion at any one time outstanding during the order's authorization period, which extends to December 31, 2005. The Company currently has $27.3 million of securities registered under the Securities Act of 1933. Any additional public offerings above the $27.3 million would require the filing of a registration statement with the SEC.

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

     The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating and capital leases. The Company's consolidated subsidiaries have operating leases, the majority of which are with the Utility and the Pipeline and Storage segments, having a remaining lease commitment of approximately $31.6 million. These leases have been entered into for the use of vehicles, construction tools, meters, computer equipment and other items and are accounted for as operating leases. The Company's minority owned entities, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $9.8 million. The Company has guaranteed 50% or $4.9 million of these capital lease commitments.

     The following table summarizes the Company's expected future contractual cash obligations as of September 30, 2002, and the twelve-month periods over which they occur:

- ------------------------------ -----------------------------------------------------------------------------------------------
                                                            Payments by Expected Maturity Dates
                               -----------------------------------------------------------------------------------------------

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


(Millions)                        2003        2004         2005         2006          2007        Thereafter       Total
- ------------------------------ ------------ ----------- ------------ ------------ -------------- --------------  ------------
Long-Term Debt                     $160.6      $235.6         $6.2         $4.4           $  -         $899.1       $1,305.9
Short-Term Bank Notes                91.3           -            -            -              -              -           91.3
Commercial Paper                    174.1           -            -            -              -              -          174.1
Operating Lease
   Commitments                        8.2         6.4          5.0          3.5            2.7            5.8           31.6
Capital Lease
   Commitments                        0.6         0.6          0.7          0.7            0.7            1.6            4.9

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

     The Company has made certain other guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the consolidated balance sheet in accordance with SFAS 133 (see Item 7, MD&A under the heading "Critical Accounting Policies - Accounting for Derivative Financial Instruments"); (ii) Utility segment obligations to purchase gas to be resold in its regulated business in accordance with established regulatory mechanisms to pass through the cost of that gas to its retail customers; (iii) NFR or Upstate obligations to purchase gas or to purchase gas transportation/storage services where the amounts due on those obligations each month are included on the consolidated balance sheet as a current liability; and (iv) other obligations which are reflected on the consolidated balance sheet. The Company believes that the likelihood it would be required to make payments under the guarantees is remote, and therefore has not included them on the table above.*

     The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Company's present liquidity position, nor have a material adverse effect on the financial condition of the Company.*

     The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) that covers substantially all domestic employees of the Company. The Company has been making contributions to the Retirement Plan over the last several years equal to the maximum funding requirements of applicable laws and regulations. In light of the dramatic decline in the stock market over the last several months, the Company anticipates that it will continue making maximum funding contributions to the Retirement Plan.* During 2002, the Company contributed $15.4 million to the Retirement Plan. The Company anticipates annual contributions to the Retirement Plan will be in the range of $20.0 to $30.0 million for 2003 - 2005.* The Company expects that all subsidiaries having domestic employees covered by the Retirement Plan will make contributions to the Retirement Plan.* The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments, through short-term borrowings or through cash from operations.*

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 receive from or pay to the respective counterparties at September 30, 2002 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas and crude oil transactions that are related to the financial instruments.

     The following tables disclose natural gas and crude oil price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in "Inside FERC" or on the New York Mercantile Exchange. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2002. At September 30, 2002, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2004.

Natural Gas Price Swap Agreements
  ----------------------------------------------------- ----------------------------------------------------------
                                                                          Expected Maturity Dates
                                                        ----------------------------------------------------------
                                                                     2003                2004              Total
  ----------------------------------------------------- ------------------- ------------------- ------------------

  Notional Quantities (Equivalent Bcf)                               12.3                 6.2               18.5
  Weighted Average Fixed Rate (per Mcf)                             $3.81               $3.59              $3.73
  Weighted Average Variable Rate (per Mcf)                          $4.30               $4.20              $4.27
  ----------------------------------------------------- ------------------- ------------------- ------------------

Crude Oil Price Swap Agreements

- ------------------------------------------------------ -----------------------------------------------------------
                                                                         Expected Maturity Dates
                                                       -----------------------------------------------------------
                                                                                     2003
- ------------------------------------------------------ ------------------- ------------------ --------------------

Notional Quantities (Equivalent bbls)                                             3,252,000
Weighted Average Fixed Rate (per bbl)                                                $21.28
Weighted Average Variable Rate (per bbl)                                             $27.92
- ------------------------------------------------------ ------------------- ------------------ --------------------

     At September 30, 2002, the Company would have had to pay the respective counterparties an aggregate of approximately $9.3 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have had to pay an aggregate of approximately $19.7 million to the counterparties to terminate the crude oil price swap agreements outstanding at September 30, 2002.

     At September 30, 2001, the Company had natural gas price swap agreements covering 27.5 Bcf at a weighted average fixed rate of $3.77 per Mcf. The Company also had crude oil price swap agreements covering 6,643,980 bbls at a weighted average fixed rate of $22.15 per bbl. As indicated in the tables above, the Company has significantly reduced its use of natural gas and crude oil price swap agreements, which is primarily attributable to low commodity prices during much of 2002, which prevented the Company from locking in favorable prices for its oil and gas production. As commodity prices have improved in the first quarter of 2003, the Company may increase its use of natural gas and crude oil price swap agreements.*

     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, 2002, the Company had not entered into any natural gas or crude oil no cost collars extending beyond 2004.

No Cost Collars

- ---------------------------------------------------- ------------------------------------------
                                                                 Expected Maturity Dates
                                                     ------------------------------------------
                                                           2003          2004         Total
- ---------------------------------------------------- ------------- -------------- -------------
Natural Gas
   Notional Quantities (Equivalent Bcf)                       8.6            0.2          8.8
   Weighted Average Ceiling Price (per Mcf)                 $5.74          $4.40        $5.71
   Weighted Average Floor Price (per Mcf)                   $3.80          $3.71        $3.80
Crude Oil
   Notional Quantities (Equivalent bbls)                1,125,000        270,000    1,395,000
   Weighted Average Ceiling Price (per bbl)                $26.41         $25.80       $26.29
   Weighted Average Floor Price (per bbl)                  $21.96         $22.00       $21.97
- ---------------------------------------------------- ------------- -------------- -------------

     At September 30, 2002, the Company would have received from the respective counterparties an aggregate of approximately $1.7 million to terminate the natural gas no cost collars outstanding at that date. The Company would have paid an aggregate of approximately $2.4 million to terminate the crude oil no cost collars outstanding at that date.

     At September 30, 2001, the Company had natural gas no cost collars covering 9.2 Bcf at a weighted average floor price of $4.06 per Mcf and a weighted average ceiling price of $5.36 per Mcf. The Company also had crude oil no cost collars covering 2,730,000 bbls at a weighted average floor price of $21.94 per bbl and a weighted average ceiling price of $27.25 per bbl. As discussed above, low commodity prices during much of 2002 were the primary factors for the decrease in no cost collars from September 2001 to September 2002. With improvements in commodity prices during the first quarter of 2003, the Company may increase its use of natural gas and crude oil no cost collars.*

     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 price risk. The put options provide for the Exploration and Production segment of the Company to receive monthly payments from other parties when a variable price falls below an established floor or "strike" price. The call options provide for the Energy Marketing segment of the Company to receive monthly payments from other parties when a variable price rises above an established ceiling or "strike" price. At September 30, 2002, the Company held no options with maturity dates extending beyond 2003.

Options Purchased

- ---------------------------------------------------------- --------------------------------------------------------------
                                                                               Expected Maturity Date
                                                           --------------------------------------------------------------
                                                                                        2003
- ---------------------------------------------------------- ------------------ -------------------------------------------
Natural Gas Put Options
   Notional Quantities (Equivalent Bcf)                                                   0.2
   Weighted Average Strike Price (per Mcf)                                              $3.98
Natural Gas Call Options
   Notional Quantities (Equivalent Bcf)                                                   0.2
   Weighted Average Strike Price (per Mcf)                                              $4.73
- ---------------------------------------------------------- ------------------ ------------------------ ------------------

     At September 30, 2002, the Company would have received from the respective counterparties an aggregate of approximately $0.1 million to terminate the put options outstanding at that date. The Company would have received an aggregate of approximately $0.1 million to terminate the call options outstanding at that date.

     At September 30, 2001, the Exploration and Production segment of the Company had natural gas put options covering 2.7 Bcf at a weighted average strike price of $4.11 per Mcf. The Company did not have any call options outstanding at that date. Because of the low commodity prices during much of 2002, the Company did not enter into any new put options during 2002. As for the call options, the Energy Marketing segment of the Company began purchasing call options in 2002 as it began to offer variable price deals with a price cap to its residential customers.

     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, 2002, the Company held no futures contracts with maturity dates extending beyond 2004.

Futures Contracts

- ---------------------------------------------------------------------- ---------------------------------------------
                                                                                  Expected Maturity Dates
                                                                       ---------------------------------------------
                                                                               2003           2004           Total
- ---------------------------------------------------------------------- -------------- -------------- ---------------

Net Contract Volumes Purchased (Equivalent Bcf)                               3.1            0.3               3.4
Weighted Average Contract Price (per Mcf)                                   $3.70          $2.79             $3.67
Weighted Average Settlement Price (per Mcf)                                 $4.50          $4.44             $4.49
- ---------------------------------------------------------------------- -------------- -------------- ---------------

     At September 30, 2002, the Company would have received $2.1 million to terminate these futures contracts.

     At September 30, 2001, the Company had futures contracts covering 13.2 Bcf (net long position) at a weighted average contract price of $4.17 per Mcf. As indicated in the table above, the Company has significantly reduced its use of natural gas futures contracts. This reduction can be attributed primarily to a reduction in fixed price gas sales commitments in the Energy Marketing segment . At September 30, 2001, natural gas prices were low and many of the customers in the Energy Marketing segment entered into fixed price contracts to lock in the commodity price of natural gas at that time. At September 30, 2002, with natural gas prices being much higher than the prior year, many of the customers in the Energy Marketing segment chose to enter into variable price contracts that provided the opportunity to enter into a fixed price contract at a later date. With variable price contracts, commodity price risk is moved from the Company to the customer.

     The Company may be exposed to credit risk on some of the derivatives disclosed above. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check and then, on an ongoing basis, monitors counterparty credit exposure. Management has obtained guarantees from the parent companies of the respective counterparties to its derivative financial instruments. At September 30, 2001, the Company used five counterparties for its over the counter derivative financial instruments. To further reduce credit risk, the Company increased the number of its counterparties to seven at September 30, 2002. At September 30, 2002, no individual counterparty represented greater than 25% of total credit risk (measured as volumes hedged by an individual counterparty as a percentage of the Company's total volumes hedged).

Exchange Rate Risk
The International segment’s investment in the Czech Republic is valued in Czech korunas, and, as such, this investment is subject to currency exchange risk when the Czech korunas are translated into U.S. dollars. The Exploration and Production segment’s investment in Canada is valued in Canadian dollars, and, as such, this investment is subject to currency exchange risk when the Canadian dollars are translated into U.S. dollars. At September 30, 2002 compared to September 30, 2001, the Czech koruna was higher in value in relation to the U.S. dollar, resulting in a $24.1 million positive adjustment to the Cumulative Foreign Currency Translation Adjustment (CTA) (a component of Accumulated Other Comprehensive Income/Loss). At September 30, 2002 compared to September 30, 2001, the Canadian dollar was slightly higher in value in relation to the U.S. dollar, resulting in a $0.2 million positive 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 arises primarily from its borrowing under short-term debt instruments. At September 30, 2002, these instruments included domestic short-term bank loans and commercial paper totaling $254.0 million. The interest rate on these short-term bank loans and commercial paper approximated 2.0% at September 30, 2002. The Company’s short-term debt instruments also included $11.4 million of short-term bank loans in Canada and the Czech Republic at September 30, 2002. The weighted average interest rates on the Canadian and Czech Republic loans approximated 3.7% and 3.3%, respectively, at September 30, 2002.

     The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company's long-term fixed rate debt as well as the other long-term debt of certain of the Company's subsidiaries. The interest rates for the variable rate debt are based on those in effect at September 30, 2002:

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

(Millions of Dollars)                        2003       2004       2005       2006       2007    Thereafter      Total
- --------------------------------------- --------- ---------- ---------- ---------- ---------- ------------- ----------

National Fuel Gas Company
Long-Term Fixed Rate Debt                    $150       $225       $  -        $ -        $ -        $899       $1,274
Weighted Average Interest
   Rate Paid                                  7.3%       7.3%         -%         -%         -%        6.9%         7.0%
Fair Value =  $1,362.0 million
- --------------------------------------- --------- ---------- ---------- ---------- ---------- ------------- ----------

Other Notes

Long-Term Debt(1)                           $10.6      $10.6       $6.2       $4.4        $ -        $0.1        $31.9
Weighted Average Interest
  Rate Paid                                   5.1%       5.1%       5.6%       6.1%         -%        3.1%         5.3%
Fair Value = $31.9 million
- --------------------------------------- --------- ---------- ---------- ---------- ---------- ------------- ----------

        (1) $15.6 million is variable rate debt; $16.3 million is fixed rate debt.

RATE MATTERS

Utility Operation

Base rate adjustments in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities.

New York Jurisdiction

On October 11, 2000, the NYPSC approved a settlement agreement (Agreement) between Distribution Corporation, Staff of the Department of Public Service, the New York State Consumer Protection Board and Multiple Intervenors (an advocate for large commercial and industrial customers) that establishes rates for a three-year period beginning October 1, 2000. The Agreement provided that customers receive a bill credit of $17.6 million for the November 1, 2000 through March 31, 2001 heating season, of which $7.6 million related to customers’ share of earnings accumulated under previous settlements. The credit was reduced to $5.0 million for the November 1, 2001 through March 31, 2002 heating season. The credit will remain at $5.0 million for the November 1, 2002 through March 31, 2003 heating season and subsequent heating seasons 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 customers. 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 commenced in November 2000 and ultimately produced an interim “Joint Proposal,” or settlement agreement, addressing several discrete issues of interest to the parties and the NYPSC. In an order issued on May 30, 2001, the NYPSC adopted the parties’ Joint Proposal. As recommended by the parties, the Joint Proposal modifies Distribution Corporation’s operations relating to transportation services and transactions with marketers and producers of indigenous natural gas. Under the Joint Proposal, the parties also agreed to continue negotiations to implement additional features of the NYPSC’s restructuring initiative (described below). Those confidential discussions, dubbed “Phase III negotiations,” concluded on January 18, 2002 when the parties executed a “Comprehensive Joint Proposal”. The Comprehensive Joint Proposal proposes a number of changes to Distribution Corporation’s rates and services through September 30, 2003, including the following:

o        Modification of transportation balancing services and upstream capacity rules for the benefit of marketers and to preserve
         reliability;
o        A customer funded "back-out credit" provided to marketers (or marketer customers) to reduce marketer costs and thereby
         promote competition;
o        Provisions to promote increased marketer usage of indigenous natural gas;
o        An expanded low-income program that provides arrearage forgiveness and a discounted rate for up to 30,000 customers;
o        Increased customer funding to offset the cost of uncollectibles;
o        Unbundling of gas costs from delivery rates; and
o        Mechanisms for recovery of stranded pipeline and unbundling costs.

The Comprehensive Joint Proposal was filed with the NYPSC on January 23, 2002 and approved with immaterial modifications on April 18, 2002, effective May 1, 2002. Distribution Corporation’s base rates will not be materially changed under the Comprehensive Joint Proposal, which is not intended to modify the rate and revenue requirements established in the Agreement described above.

On September 20, 2001, the NYPSC issued an order under which Distribution Corporation was Ordered to Show Cause why an action for penalties up to $19 million should not be commenced against it for alleged violations of consumer protection requirements. According to the NYPSC, the alleged violations may have caused or contributed to the death of an individual in an unheated apartment. On December 3, 2001, Distribution Corporation filed its response (submitted under a seal of confidentiality imposed by the Supreme Court, Erie County designed to protect the personal privacy interests of the deceased individual) and requested that the NYPSC either close (dismiss) the Show Cause proceeding based on the evidence presented in Distribution’s response, or hold administrative evidentiary hearings “to demonstrate that a penalty action is unwarranted.” On July 25, 2002 the NYPSC issued an order granting Distribution Corporation’s request for hearings, and referred the matter to an administrative law judge for scheduling. The Company believes and will continue to vigorously assert that the NYPSC’s allegations lack merit.

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.

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.

The federal law under which FERC regulates Supply Corporation’s rates, practices, and terms and conditions of service requires, among other things, that Supply Corporation not grant any undue preference or advantage to any person. In March 2001, FERC staff began a routine audit of Supply Corporation’s practices and dealings with “marketing affiliates,” i.e., other Company subsidiaries which conduct natural gas transportation and/or storage transactions with Supply. On July 11, 2002, FERC adopted an order instituting an investigation directed to Supply Corporation and its natural gas marketing affiliates, under Sections 4 and 5 of the Natural Gas Act and Section 501 of the Natural Gas Policy Act. This is not an investigation into Supply’s currently effective rates, or any energy trading activities, “wash sales,” “round-trip transactions,” sales of electricity into the California market, or other activities that have been the subjects of recent news stories regarding other publicly traded energy companies. The Company does not engage in any such energy trading activities. The stated basis for instituting the investigation is information received during the audit which indicates there may have been violations of FERC regulations, specifically:

  18 CFR Section 161.3(f), which requires that, to the extent Supply Corporation provides to a gas marketing affiliate information related to gas transportation, Supply Corporation must provide that information contemporaneously to all potential shippers [FERC staff has indicated that they believe Supply Corporation violated this regulation by e-mailing information describing daily operationally available capacity on its gas transportation system to a large number of shippers (including one Supply Corporation marketing affiliate) a few hours before that information was posted on Supply Corporation’s website later that same day; Supply Corporation now provides such e-mails after the information is posted on its website]; and

  18 CFR Section 161.3(l), which requires that Supply Corporation must timely post on its website lists of gas marketing affiliates, organizational charts and job descriptions of various individuals (Supply Corporation has updated this information).

Supply Corporation and its affiliates continue to cooperate with FERC staff by providing responses to multiple document requests in connection with this investigation and the preceding audit, and by making individuals available for interviews. The Company believes, based on the information presently known, that neither Supply Corporation nor any affiliate has received any benefit from any violations of FERC regulations which may have occurred, and that the ultimate resolution of this proceeding will not materially affect the Company's operations or financial condition.

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 $5.1 million to $6.1 million.* The minimum liability of $5.1 million has been recorded on the Consolidated Balance Sheet at September 30, 2002. 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 (including those of the Czech Republic) relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures.

     For further discussion refer to Item 8 at Note H - Commitments and Contingencies under the heading "Environmental Matters."

New Accounting Pronouncements
In 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” (SFAS 142) and SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). For a discussion of SFAS 142 and SFAS 143 and their impact on the Company, see disclosure in Item 8 at Note A – Summary of Significant Accounting Policies.

Effects of Inflation
Although the rate of inflation has been relatively low over the past few years, the Company’s operations remain sensitive to increases in the rate of inflation because of its capital spending and the regulated nature of a significant portion of its business.

Approval of Audit and Non-Audit Services
On September 12, 2002, the Company’s audit committee approved audit services relating to the audit of the Company’s financial statements for the fiscal year ending September 30, 2002, and the provision of comfort letters in connection with securities underwritings. The audit committee also approved certain non-audit services to be performed by the Company’s independent accountant, PricewaterhouseCoopers, LLP, including advice concerning methodologies for valuing certain assets, tax advice concerning financing arrangements, and other customary consultation or advice.

Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including those which are designated with an asterisk (“*”), are “forward-looking” statements as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

  1. Changes in economic conditions, including economic disruptions caused by terrorist activities or acts of war;

  2. Changes in demographic patterns and weather conditions;

  3. Changes in the availability and/or price of natural gas and oil;

  4. Inability to obtain new customers or retain existing ones;

  5. Significant changes in competitive factors affecting the Company;

  6. Governmental/regulatory actions, initiatives and proceedings, including those affecting acquisitions, financings, allowed rates of return, industry and rate structure, franchise renewal, and environmental/safety requirements;

  7. Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;

  8. Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs;

  9. The nature and projected profitability of pending and potential projects and other investments;

  10. Occurrences affecting the Company's ability to obtain funds from operations, debt or equity to finance needed capital expenditures and other investments;

  11. Uncertainty of oil and gas reserve estimates;

  12. Ability to successfully identify and finance oil and gas property acquisitions and ability to operate and integrate existing and any subsequently acquired business or properties;

  13. Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves;

  14. Significant changes from expectations in the Company's actual production levels for natural gas or oil;

  15. Changes in the availability and/or price of derivative financial instruments;

  16. Changes in the price of natural gas or oil and the related effect given the accounting treatment or valuation of financial instruments;

  17. Inability of the various counterparties to meet their obligations with respect to the Company's financial instruments;

  18. Regarding foreign operations, changes in trade and monetary policies, inflation and exchange rates, taxes, operating conditions, laws and regulations related to foreign operations, and political and governmental changes;

  19. Significant changes in tax rates or policies or in rates of inflation or interest;

  20. Significant changes in the Company's relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur;

  21. Changes in accounting principles or the application of such principles to the Company;

  22. Changes in laws and regulations to which the Company is subject, including tax, environmental and employment laws and regulations; or

  23. The cost and effects of legal and administrative claims against 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

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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, 2002

     Consolidated Balance Sheets at September 30, 2002 and 2001

     Consolidated Statement of Cash Flows, three years ended September 30, 2002

     Consolidated Statement of Comprehensive Income, three years ended September 30, 2002

     Notes to Consolidated Financial Statements

     Financial Statement Schedules:
       For the three years ended September 30, 2002

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

Report of Management

Management is responsible for the preparation and integrity of the Company’s financial statements. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America 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 auditing standards generally accepted in the United States of America.

     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, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2002, 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, 2002


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)                                   2002              2001             2000
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Income
Operating Revenues                                                 $1,464,496        $2,059,836        $1,412,416
- -------------------------------------------------------------- ----------------- ---------------- -----------------
 Operating Expenses
  Purchased Gas                                                       462,857         1,002,466           488,383
   Fuel Used in Heat and Electric Generation                            50,635            54,968            54,893
   Operation and Maintenance                                           394,157           364,318           350,383
   Property, Franchise and Other Taxes                                  72,155            83,730            78,878
   Depreciation, Depletion and Amortization                            180,668           174,914           142,170
   Impairment of Oil and Gas Producing
     Properties                                                              -           180,781                 -
   Income Taxes                                                         72,034            37,106            77,068
- -------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                     1,232,506         1,898,283         1,191,775
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Income                                                       231,990           161,553           220,641
Operations of Unconsolidated Subsidiaries:
   Income                                                                 224             1,794             1,669
    Impairment of Investment in Partnership                            (15,167)                -                 -
- -------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                       (14,943)            1,794             1,669
- -------------------------------------------------------------- ----------------- ---------------- -----------------

Other Income                                                             7,017            10,639             6,366
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Income Before Interest Charges and
  Minority Interest in Foreign Subsidiaries                           224,064           173,986           228,676
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Interest Charges
  Interest on Long-Term Debt                                           90,543            81,851            67,195
   Other Interest                                                       15,109            25,294            32,890
- -------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                       105,652           107,145           100,085
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Minority Interest in Foreign Subsidiaries                                 (730)           (1,342)           (1,384)
- -------------------------------------------------------------- ----------------- ---------------- -----------------

Net Income Available for Common Stock                                  117,682            65,499           127,207
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Earnings Reinvested in the Business
Balance at Beginning of Year                                          513,488           525,847           472,517
- -------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                       631,170           591,346           599,724
 Dividends on Common Stock                                              81,773            77,858            73,877
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Balance at End of Year                                                $549,397          $513,488          $525,847
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Earnings Per Common Share:
Basic                                                                    $1.47             $0.83             $1.63
Diluted                                                                  $1.46             $0.82             $1.61
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Weighted Average Common Shares Outstanding:
  Used in Basic Calculation                                         79,821,430        79,053,444        78,233,842
  Used in Diluted Calculation                                       80,534,453        80,361,258        79,166,200
- -------------------------------------------------------------- ----------------- ---------------- -----------------

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)                                               2002                2001
- ---------------------------------------------------------------------------- ------------------- -------------------

Assets
Property, Plant and Equipment                                                       $4,512,651          $4,273,716
  Less - Accumulated Depreciation,
    Depletion and Amortization                                                       1,667,906           1,493,003
- ---------------------------------------------------------------------------- ------------------- -------------------
                                                                                     2,844,745           2,780,713
- ---------------------------------------------------------------------------- ------------------- -------------------

Current Assets
  Cash and Temporary Cash Investments                                                   22,216              36,227
  Receivables - Net                                                                     95,510             131,379
  Unbilled Utility Revenue                                                              21,918              25,375
  Gas Stored Underground                                                                77,250              83,231
  Materials and Supplies - at average cost                                              31,582              33,710
  Unrecovered Purchased Gas Costs                                                       12,431               4,113
  Prepayments                                                                           41,354              39,520
  Fair Value of Derivative Financial Instruments                                         3,807              37,585
- ---------------------------------------------------------------------------- ------------------- -------------------
                                                                                       306,068             391,140
- ---------------------------------------------------------------------------- ------------------- -------------------

Other Assets
  Recoverable Future Taxes                                                              82,385              86,586
  Unamortized Debt Expense                                                              20,635              19,796
  Other Regulatory Assets                                                               26,104              23,253
  Deferred Charges                                                                       5,914               8,440
  Other Investments                                                                     65,090              62,924
  Investments in Unconsolidated Subsidiaries                                            16,753              31,768
  Goodwill                                                                               8,255               8,804
  Other                                                                                 25,360              31,807
- ---------------------------------------------------------------------------- ------------------- -------------------
                                                                                       250,496             273,378
- ---------------------------------------------------------------------------- ------------------- -------------------
                                                                                    $3,401,309          $3,445,231
- ---------------------------------------------------------------------------- ------------------- -------------------

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)                                              2002              2001
- ---------------------------------------------------------------------------- ----------------- ----------------
Capitalization and Liabilities
Capitalization:
Comprehensive Shareholders' Equity
  Common Stock, $1 Par Value
    Authorized  - 200,000,000 Shares; Issued and
    Outstanding - 80,264,734 Shares and 79,406,105
    Shares, Respectively                                                             $80,265        $  79,406
  Paid In Capital                                                                    446,832          430,618
  Earnings Reinvested in the Business                                                549,397          513,488
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Common Shareholder Equity Before Items
     Of Other Comprehensive Loss                                                   1,076,494        1,023,512
  Accumulated Other Comprehensive Loss                                               (69,636)         (20,857)
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Comprehensive Shareholders' Equity                                           1,006,858        1,002,655
Long-Term Debt, Net of Current Portion                                             1,145,341        1,046,694
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Capitalization                                                               2,152,199        2,049,349
- ---------------------------------------------------------------------------- ----------------- ----------------
Minority Interest in Foreign Subsidiaries                                             28,785           22,324
- ---------------------------------------------------------------------------- ----------------- ----------------
Current and Accrued Liabilities
  Notes Payable to Banks and
    Commercial Paper                                                                 265,386          489,673
  Current Portion of Long-Term Debt                                                  160,564          109,435
  Accounts Payable                                                                   100,886          123,246
  Amounts Payable to Customers                                                             -           51,223
  Other Accruals and Current Liabilities                                             121,518           89,893
  Fair Value of Derivative Financial Instruments                                      31,204           17,081
- ---------------------------------------------------------------------------- ----------------- ----------------
                                                                                     679,558          880,551
- ---------------------------------------------------------------------------- ----------------- ----------------
Deferred Credits
  Accumulated Deferred Income Taxes                                                  356,220          340,224
  Taxes Refundable to Customers                                                       15,596           16,865
  Unamortized Investment Tax Credit                                                    8,897            9,599
  Other Regulatory Liabilities                                                        82,676           68,957
  Other Deferred Credits                                                              77,378           57,362
- ---------------------------------------------------------------------------- ----------------- ----------------
                                                                                     540,767          493,007
- ---------------------------------------------------------------------------- ----------------- ----------------
Commitments and Contingencies                                                              -                -
- ---------------------------------------------------------------------------- ----------------- ----------------
                                                                                  $3,401,309       $3,445,231
- ---------------------------------------------------------------------------- ----------------- ----------------

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)                           2002             2001              2000
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Operating Activities
  Net Income Available for Common Stock                                  $117,682          $65,499          $127,207
  Adjustments to Reconcile Net Income to Net Cash
    Provided by Operating Activities
      Impairment of Oil and Gas Producing Properties                            -          180,781                 -
      Depreciation, Depletion and Amortization                            180,668          174,914           142,170
      Deferred Income Taxes                                                62,013          (55,849)           41,858
      Impairment of Investment in Partnership                              15,167                -                 -
      (Income) Loss from Unconsolidated Subsidiaries,
        Net of Cash Distributions                                             361           (1,199)           (1,440)
      Minority Interest in Foreign Subsidiaries                               730            1,342             1,384
      Other                                                                 9,842            6,553             5,946
      Change in:
        Receivables and Unbilled Utility Revenue                           40,786           (2,277)          (26,365)
        Gas Stored Underground and Materials and
            Supplies                                                        8,717          (37,054)          (13,707)
        Unrecovered Purchased Gas Costs                                    (8,318)          25,568           (25,105)
        Prepayments                                                        (1,737)            (399)           (3,420)
        Accounts Payable                                                  (24,025)          20,419           (16,489)
        Amounts Payable to Customers                                      (51,223)          41,640             3,649
        Other Accruals and Current Liabilities                            (37,372)          13,969           (10,233)
        Other Assets                                                       11,869          (33,169)              826
        Other Liabilities                                                  20,390           13,289            11,965
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Provided by Operating Activities                                 345,550          414,027           238,246
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Investing Activities
  Capital Expenditures                                                   (232,368)        (292,706)         (269,371)
  Investment in Subsidiaries, Net of Cash Acquired                              -          (90,567)         (123,809)
  Investment in Partnerships                                                 (536)          (1,830)           (4,442)
  Other                                                                    27,080           (2,823)           13,283
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Used in Investing Activities                                    (205,824)        (387,926)         (384,339)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Financing Activities
  Change in Notes Payable to Banks and Commercial
    Paper                                                                (224,845)        (143,397)          226,477
  Net Proceeds from Issuance of Long-Term Debt                            243,844          210,221           149,334
  Reduction of Long-Term Debt                                            (104,212)         (23,052)         (167,426)
  Proceeds from Issuance of Common Stock                                   10,915           11,545            14,278
  Dividends Paid on Common Stock                                          (80,974)         (76,671)          (73,046)
  Dividends Paid to Minority Interest                                           -                -              (152)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash (Used in)  Provided by Financing Activities                     (155,272)         (21,354)          149,465
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Effect of Exchange Rates on Cash                                            1,535             (645)             (469)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Increase (Decrease) in Cash and
  Temporary Cash Investments                                              (14,011)           4,102             2,903
Cash and Temporary Cash Investments
 at Beginning of Year                                                      36,227           32,125            29,222
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Cash and Temporary Cash Investments
  at End of Year                                                          $22,216          $36,227          $ 32,125
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Supplemental Disclosure of Cash Flow Information
Cash Paid For:
   Interest                                                               $98,493         $100,871           $97,042
   Income Taxes                                                            29,985           77,662            41,928
- ------------------------------------------------------------------ ----------------- ---------------- -----------------

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)                        2002                     2001                      2000
- ------------------------------------------------------- -------------------------- ------------------------ -------------------------

Net Income Available for Common Stock                                  $117,682                 $ 65,499                  $127,207
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), Before Tax:
Minimum Pension Liability Adjustment                                    (52,977)                       -                         -
Foreign Currency Translation Adjustment                                  24,278                   (7,158)                  (27,463)
Unrealized Gain (Loss) on Securities Available
    for Sale Arising During the Period                                   (2,086)                    (712)                    2,441
Unrealized Gain (Loss) on Derivative Financial
    Instruments Arising During the Period                               (42,584)                  58,355                         -
Reclassification Adjustment for Realized
    (Gain) Loss on Derivative Financial
    Instruments in Net Income                                           (20,063)                  83,218                         -
Reclassification Adjustment for Realized Gain
    on Securities Available for Sale in Net
     Income                                                                   -                        -                      (103)
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), Before
    Tax:                                                                (93,432)                 133,703                   (25,125)
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Income Tax Benefit Related to Minimum
   Pension Liability Adjustment                                         (18,542)                       -                         -
Income Tax Expense (Benefit) Related to
   Unrealized Gain (Loss) on Securities
   Available for Sale Arising During the Period                            (730)                    (249)                      855
Income Tax Expense (Benefit) Related to
   Unrealized Gain (Loss) on Derivative
   Financial Instruments Arising During the
   Period                                                               (17,341)                  23,053                         -
Reclassification Adjustment for Income Tax
   (Expense) Benefit on Realized (Gain)
   Loss on Derivative Financial Instruments
    In Net Income                                                        (8,040)                  32,032                         -
Reclassification Adjustment for Income Tax
    Expense on Realized Gain on Securities
    Available for Sale in Net Income                                          -                        -                       (36)
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Income Taxes - Net                                                      (44,653)                  54,836                       819
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), Before
   Cumulative Effect                                                    (48,779)                  78,867                   (25,944)
Cumulative Effect of Change in Accounting,
   Net of Tax                                                                 -                  (69,767)                        -
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), After
   Cumulative Effect                                                    (48,779)                   9,100                   (25,944)
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Comprehensive Income                                                   $ 68,903                 $ 74,599                  $101,263
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------

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
Company consolidates its majority owned subsidiaries. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated.

     The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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

Regulation
The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to accounting principles generally accepted in the United States of America, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note B - Regulatory Matters for further discussion.

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

Revenues
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. As a result of low oil and gas prices, the Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling for the Company's Canadian properties at September 30, 2001. The Company was required to recognize a $180.8 million ($104.0 million after tax) impairment of its oil and gas producing properties in the quarter ended September 30, 2001.

     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. 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 4.4% in 2002, 4.7% in 2001 and 4.2% in 2000 on a consolidated basis.

Cumulative Effect of Change in Accounting
Effective October 1, 2000, the Company adopted the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities – Deferral of the Effective Date of FASB Statement No. 133” and by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of Statement 133” (collectively, SFAS 133). The cumulative effect of this change decreased other comprehensive income by $69.8 million (after tax) at adoption on October 1, 2000. The cumulative effect of this change did not have a material impact on net income at adoption on October 1, 2000. Of the cumulative effect recorded in other comprehensive income, $46.3 million (after tax) was reclassified into the Consolidated Statement of Income during 2001. The derivative financial instruments that comprise the cumulative effect recorded in other comprehensive income have been designated and qualify as cash flow hedges, as discussed below.

Financial Instruments
Unrealized gains or losses from the Company’s investments in an equity mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note F Financial Instruments for further discussion.

     The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments include price swap agreements, no cost collars, options and futures contracts. As discussed above, on October 1, 2000 the Company adopted SFAS 133. In accordance with the provisions of these standards, the Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases, the fair value of the instrument is recognized on the Consolidated Balance Sheet as either an asset or a liability labeled fair value of financial instruments. Fair value represents the amount the Company would receive or pay to terminate these instruments.

     For effective cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet. Any ineffectiveness associated with the cash flow hedges is recorded in the Consolidated Statement of Income. The Company did not experience any material ineffectiveness with regard to its cash flow hedges during 2002 or 2001. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues on the Consolidated Statement of Income. For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statement of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheet representing the change in fair value of the asset or firm commitment that is being hedged. The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statement of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. The Company did not experience any material ineffectiveness with regard to its fair value hedges during 2002 or 2001.

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

  ---------------------------------------------------------------- -------------------- --------------------
  Year Ended September 30 (Thousands)                                     2002                 2001
  ---------------------------------------------------------------- -------------------- --------------------

  Minimum Pension Liability Adjustment                                        $(34,435)             $    -
  Cumulative Foreign Currency Translation Adjustment                           (14,815)            (39,093)
  Net Unrealized Gain (Loss)  on Derivative Financial
     Instruments                                                               (20,545)             16,721
  Net Unrealized Gain on Securities Available for Sale                             159               1,515
  ---------------------------------------------------------------- -------------------- --------------------

  Accumulated Other Comprehensive Loss                                        $(69,636)           $(20,857)
  ---------------------------------------------------------------- -------------------- --------------------

     At September 30, 2002, it is estimated that $18.1 million of the net unrealized loss on derivative financial instruments shown in the table above will be reclassified into the Consolidated Statement of Income during 2003.

Gas Stored Underground - Current
In the Utility segment, gas stored underground - current in the amount of $66.4 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 2002, 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 $46.0 million at September 30, 2002. 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 of the country where the operations are located. Asset and liability accounts are translated at the rate of exchange on the balance sheet date. Revenues and expenses are translated at the average exchange rate during the period. Foreign currency translation adjustments are recorded as a component of accumulated other comprehensive income (loss).

Income Taxes
The Company and its domestic subsidiaries file a consolidated federal income tax return. Investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction. No provision has been made for domestic income taxes applicable to certain undistributed earnings of foreign subsidiaries as these amounts are considered to be permanently reinvested outside the United States.

Consolidated Statement of Cash Flows
For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash and temporary cash investments includes cash held in margin accounts to serve as collateral for open positions on exchange-traded futures contracts. The amounts held in margin accounts amounted to $0.4 million and $22.5 million at September 30, 2002 and 2001, respectively.

Earnings Per Common Share
Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The only potentially dilutive securities the Company has outstanding are stock options. The diluted weighted average shares outstanding shown on the Consolidated Statement of Income reflects the potential dilution as a result of these stock options as determined using the Treasury Stock Method. Stock options that are antidilutive are excluded from the calculation of diluted earnings per common share. For 2002 and 2001, 5,260,633 and 1,290,747 stock options, respectively, were excluded as being antidilutive.

New Accounting Pronouncements
In 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142) and SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). SFAS 142 addresses financial accounting and reporting for acquired goodwill and other intangible assets. Under this standard, goodwill and intangible assets that have indefinite useful lives will not be amortized but rather will be tested at least annually for impairment. Intangible assets that have finite useful lives will continue to be amortized over their useful lives, but the amortization period will not be limited to a certain period of time. The Company will adopt SFAS 142 during the first quarter of fiscal 2003 and is in the process of completing its initial impairment test of the goodwill on its balance sheet. The Company does not believe that adoption of SFAS 142 will have a material impact on its financial condition and results of operations.

SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. When the liability is settled, the entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company will adopt SFAS 143 during the first quarter of fiscal 2003. The Company does not believe that adoption of SFAS 143 will have a material impact on its financial condition and results of operations.

Note B - Regulatory Matters

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

- --------------------------------------------------------------------------------- ------------------- -------------------
At September 30 (Thousands)                                                                     2002                2001
- --------------------------------------------------------------------------------- ------------------- -------------------
Regulatory Assets:
Recoverable Future Taxes (Note C)                                                            $82,385             $86,586
Unrecovered Purchased Gas Costs (Note A)                                                      12,431               4,113
Unamortized Debt Expense (Note A)                                                             10,021              11,738
Pension and Post-Retirement Benefit Costs (1) (Note G)                                        24,146              21,065
Other (1)                                                                                      1,958               2,188
- --------------------------------------------------------------------------------- ------------------- -------------------
     Total Regulatory Assets                                                                 130,941             125,690
- --------------------------------------------------------------------------------- ------------------- -------------------
Regulatory Liabilities:
Amounts Payable to Customers (Note A)                                                              -              51,223
New York Rate Settlements(2)                                                                  34,323              27,630
Taxes Refundable to Customers (Note C)                                                        15,596              16,865
Pension and Post-Retirement Benefit Costs(2)  (Note G)                                        39,946              33,829
Other(1)                                                                                       8,407               7,498
- --------------------------------------------------------------------------------- ------------------- -------------------
     Total Regulatory Liabilities                                                             98,272             137,045
- --------------------------------------------------------------------------------- ------------------- -------------------
Net Regulatory Position                                                                      $32,669            $(11,355)
- --------------------------------------------------------------------------------- ------------------- -------------------

        (1) Included in other regulatory assets on the Consolidated Balance Sheets.

        (2) Included in other regulatory liabilities on the Consolidated Balance Sheets.

     If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in income of the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item.

New York Rate Settlements
With respect to utility services provided in New York, the Company has entered into rate settlements approved by the State of New York Public Service Commission (NYPSC). The rate settlements provide for a sharing mechanism, whereby earnings above an 11.5% return on equity are to be shared equally between shareholders and customers. As a result of this sharing mechanism, the Company had liabilities of $9.5 million and $5.8 million at September 30, 2002 and 2001, respectively. Other aspects of the settlements include a special reserve of $6.5 million and $8.2 million at September 30, 2002 and 2001, respectively, to be applied against the Company’s incremental costs resulting from the NYPSC’s gas restructuring effort and a “refund pool” of $15.3 million and $6.0 million at September 30, 2002 and 2001, 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 $3.0 million and $7.7 million at September 30, 2002 and 2001, 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)                                        2002            2001              2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------

Operating Expenses:
  Current Income Taxes -
    Federal                                                              $7,743         $ 67,429          $ 26,352
    State                                                                 1,384           21,330            13,067
    Foreign                                                                 894            4,196            (4,209)
  Deferred Income Taxes -
    Federal                                                              50,205           18,444            29,604
    State                                                                 9,968              431             2,495
    Foreign                                                               1,840          (74,724)            9,759
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                         72,034           37,106            77,068
Other Income:
  Deferred Investment Tax Credit                                           (697)            (348)           (1,051)
Minority Interest in Foreign Subsidiaries                                  (277)            (614)             (259)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Total Income Taxes                                                      $71,060        $ 36,144          $ 75,758
- ---------------------------------------------------------------- ----------------- ---------------- -----------------

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

- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)                                         2002             2001              2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
U.S.                                                                    $180,349         $267,270          $182,813
Foreign                                                                    8,394         (165,627)           20,152
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                        $188,743         $101,643          $202,965
- ---------------------------------------------------------------- ----------------- ---------------- -----------------

     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)                                         2002            2001             2000
- --------------------------------------------------------------- ------------------- --------------- ----------------

Income Tax Expense, Computed at U.S. Federal
  Statutory Rate of 35%                                                  $66,060         $35,575          $71,038
Increase (Reduction) in Taxes Resulting from:
  State Income Taxes                                                       7,379          14,145           10,115
  Foreign Tax Rate Differential                                             (481)        (13,172)          (1,762)
  Depreciation                                                             1,744           1,790            1,925
  Miscellaneous                                                           (3,642)         (2,194)          (5,558)
- --------------------------------------------------------------- ------------------- --------------- ----------------
Total Income Taxes                                                       $71,060          $36,144          $75,758
- --------------------------------------------------------------- ------------------- --------------- ----------------

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

- --------------------------------------------------------------- ------------------- ---------------
At September 30 (Thousands)                                                  2002            2001
- --------------------------------------------------------------- ------------------- ---------------
Deferred Tax Liabilities:
  Property, Plant and Equipment                                           $417,673        $389,879
  Deferred Gas Costs                                                         5,469               -
  Other                                                                     22,461          27,047
- --------------------------------------------------------------- ------------------- ---------------
Total Deferred Tax Liabilities                                             445,603         416,926
- --------------------------------------------------------------- ------------------- ---------------
Deferred Tax Assets:
  Deferred Gas Costs                                                             -         (20,178)
  Other                                                                    (89,383)        (56,524)
- --------------------------------------------------------------- ------------------- ---------------
Total Deferred Tax Assets                                                  (89,383)        (76,702)
- --------------------------------------------------------------- ------------------- ---------------
Total Net Deferred Income Taxes                                           $356,220        $340,224
- --------------------------------------------------------------- ------------------- ---------------

     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 $15.6 million and $16.9 million at September 30, 2002 and 2001, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $82.4 million and $86.6 million at September 30, 2002 and 2001, respectively.

     Undistributed earnings of foreign subsidiaries of $32 million at September 30, 2002 are considered to be permanently reinvested outside the United States and, accordingly, no U.S. income taxes have been provided thereon. In the event such earnings are distributed in the form of dividends, the Company may be subject to U.S. income taxes and foreign withholding taxes, net of allowable foreign tax credits.

     At September 30, 2002, there are Canadian operating loss carryforwards of $23 million which begin to expire if not utilized by the tax year ending September 30, 2006.

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 (Loss)
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
  September 30, 1999                      77,674           $77,674         $393,115         $472,517              $(4,013)
Net Income Available
  for Common Stock                                                                           127,207
Dividends Declared on
  Common Stock
  ($0.95 Per Share)                                                                          (73,877)
Other Comprehensive
  Loss, Net of Tax                                                                                                (25,944)
Acquisition of
  Natural Gas Assets                         110               110            2,702
Common Stock Issued
  Under Stock and
  Benefit Plans                              876               876           17,070

- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
  September 30, 2000                      78,660            78,660          412,887          525,847              (29,957)
Net Income Available
  for Common Stock                                                                            65,499
Dividends Declared on
  Common Stock
  ($0.99 Per Share)                                                                          (77,858)
Other Comprehensive
  Income, Net of Tax                                                                                                9,100
Common Stock Issued
  Under Stock and
  Benefit Plans                              746               746           17,731
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
  September 30, 2001                      79,406            79,406          430,618          513,488              (20,857)
Net Income Available
  for Common Stock                                                                           117,682
Dividends Declared on
  Common Stock                                                                               (81,773)
  ($1.03 Per Share)
Other Comprehensive
  Loss, Net of Tax                                                                                                (48,779)
Common Stock Issued
  Under Stock and
  Benefit Plans                              859               859           16,214
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
  September 30, 2002                      80,265           $80,265         $446,832         $549,397 (1)          $(69,636)
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------

        (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, 2002, $475.0 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 investors 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 independent 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, under which the Board of Directors made adjustments in connection with the two-for-one stock split of September 7, 2001.

     The holders of the Company's common stock have one right (Right) for each of their shares. Each Right, which will initially be evidenced by the Company's common stock certificates representing the outstanding shares of common stock, entitles the holder to purchase one-half of one share of common stock at a purchase price of $65.00 per share, being $32.50 per half share, subject to adjustment (Purchase Price).

     The Rights become exercisable upon the occurrence of a distribution date. At any time following a distribution date, each holder of a Right may exercise its right to receive common stock (or, under certain circumstances, other property of the Company) having a value equal to two times the Purchase Price of the Right then in effect. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.

     A distribution date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company's common stock or other voting stock having 10% or more of the total voting power of the Company's common stock and other voting stock and (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquiring, or obtaining the right to acquire, beneficial ownership of the Company's common stock or other voting stock having 10% or more of the total voting power of the Company's common stock and other voting stock.

     In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company's stock as described above, each holder of a Right will have the right to exercise its Rights to receive common stock of the acquiring company having a value equal to two times the Purchase Price of the Right then in effect. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company's assets or earning power are sold or transferred.

     At any time prior to the end of the business day on the tenth day following the announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of 10% or more of the total voting power of the Company, the Company may redeem the Rights in whole, but not in part, at a price of $0.005 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company's full Board of Directors. Also, at any time following the announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of 10% or more of the total voting power of the Company, 75% of the Company's full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments.

     After a distribution date, Rights that are owned by an acquiring person will be null and void. Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2008, unless they are exchanged or redeemed earlier than that date.

     The Rights have anti-takeover effects because they will cause substantial dilution of the common stock if a person attempts to acquire the Company on terms not approved by the Board of Directors.

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, 2002, 2001 and 2000, 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                                                 2002                2001                2000
- ---------------------------------------------------------- ------------------- ------------------- -------------------
Net Income (Thousands):
     As reported                                                    $117,682             $65,499            $127,207
     Pro forma                                                      $113,041             $59,108            $123,107
Earnings Per Common Share:
     Basic - As reported                                               $1.47               $0.83               $1.63
     Basic - Pro forma                                                 $1.42               $0.75               $1.58
     Diluted - As reported                                             $1.46               $0.82               $1.61
     Diluted - Pro forma                                               $1.40               $0.73               $1.56
- ---------------------------------------------------------- ------------------- ------------------- -------------------

     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, 1999                                             6,728,184                      $19.65
Granted in 2000                                                               1,782,200                      $21.87
Exercised in 2000(1)                                                           (455,484)                     $15.08
Forfeited in 2000                                                               (27,800)                     $23.08
- ------------------------------------------------------------- ---------------------------- ---------------------------
Outstanding at September 30, 2000                                             8,027,100                      $20.38
Granted in 2001                                                               1,787,200                      $27.61
Exercised in 2001 (1)                                                          (372,040)                     $15.89
Forfeited in 2001                                                               (69,574)                     $22.36
- ------------------------------------------------------------- ---------------------------- ---------------------------
Outstanding at September 30, 2001                                             9,372,686                      $21.92
Granted in 2002 (2)                                                           5,673,172                      $22.26
Exercised in 2002 (1)                                                          (247,910)                     $15.76
                                                                                                             $25.56
Forfeited in 2002                                                              (168,444)
- ------------------------------------------------------------- ---------------------------- ---------------------------
Outstanding at September 30, 2002                                            14,629,504                      $22.12
- ------------------------------------------------------------- ---------------------------- ---------------------------
Option shares exercisable at September 30, 2002                              11,766,044                      $21.68
Option shares available for future
  grant at September 30, 2002 (3)                                               942,669
- ------------------------------------------------------------- ---------------------------- ---------------------------

        (1) In connection with exercising these options, 43,834, 78,850 and 116,916 shares were surrendered and canceled during 2002, 2001 and 2000, respectively.

        (2) Including 3,097,172 non-qualified stock options issued in November 2001. The Company canceled 3,097,172 stock appreciation rights (SARs) in November 2001 and issued 3,097,172 non-qualified stock options. The Company eliminated all future awards of SARs.

        (3) Including shares available for restricted stock grants.

     The weighted average fair value per share of options granted in 2002, 2001 and 2000 was $4.32, $5.25 and $4.17, 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                                           2002                2001                2000
- ---------------------------------------------------------- ------------------- ------------------- -------------------

Quarterly Dividend Yield                                            1.07%               0.87%               1.07%
Annual Standard Deviation (Volatility)                             21.83%              20.51%              19.05%
Risk Free Rate                                                      4.88%               5.26%               6.74%
Expected Term - in Years                                             5.5                 5.0                 5.5
- ---------------------------------------------------------- ------------------- ------------------- -------------------

     The following table summarizes information about options outstanding at September 30, 2002:

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

                                   Number     Weighted Average          Weighted            Number            Weighted
                Range of      Outstanding            Remaining           Average       Exercisable             Average
          Exercise Price       at 9/30/02     Contractual Life    Exercise Price        at 9/30/02      Exercise Price
- ------------------------- ---------------- -------------------- ----------------- ----------------- -------------------

         $11.12 - $16.68        1,635,916            2.2 years            $14.91         1,635,916              $14.91

       $16.69 - $22.24        4,572,226            5.9 years            $20.31         4,291,226              $20.21

       $22.25 - $27.80        8,421,362            7.5 years            $24.50         5,838,902              $24.66
- ------------------------- ---------------- -------------------- ----------------- ----------------- -------------------

     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 option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective.

     The following table summarizes the awards of restricted stock over the past three years:

- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30                                                       2002             2001              2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Shares of Restricted Stock Awarded                                         100,000             4,000            15,178
Weighted Average Market Price of
  Stock on Award Date                                                       $24.50            $27.80            $24.47
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

     As of September 30, 2002, 149,728 shares of non-vested restricted stock were outstanding. Vesting restrictions will lapse as follows: 2003 - 13,600 shares; 2004 - 36,600 shares; 2005 - 34,600 shares; 2006 - 34,600 shares; 2007 - 29,000 shares; and 2010 - 1,328 shares.

     Compensation expense related to restricted stock under the Company's stock plans was $0.7 million, $0.3 million and $0.7 million for the years ended September 30, 2002, 2001 and 2000, respectively.

Redeemable Preferred Stock
As of September 30, 2002, 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)                                                                  2002              2001
- ----------------------------------------------------------------------------------- ---------------- -----------------
Debentures:
    7-3/4% due February 2004                                                             $125,000         $ 125,000
Medium-Term Notes:
    6.00% to 8.48% due February 2003 to August 2027(1)                                  1,051,300           999,000
Senior Unsecured Notes:
    6.50% due September 2022(2)                                                            97,700                 -
- ----------------------------------------------------------------------------------- ---------------- -----------------
                                                                                        1,274,000         1,124,000
- ----------------------------------------------------------------------------------- ---------------- -----------------
Other Notes                                                                                31,905            32,129
- ----------------------------------------------------------------------------------- ---------------- -----------------
Total Long-Term Debt                                                                    1,305,905         1,156,129
Less Current Portion                                                                      160,564           109,435
- ----------------------------------------------------------------------------------- ---------------- -----------------
                                                                                       $1,145,341        $1,046,694
- ----------------------------------------------------------------------------------- ---------------- -----------------

        (1) Includes $50 million of 8.48% medium-term notes due July 2024 which are callable at a redemption price of 105.09% through July 2003. The redemption price will decline in subsequent years.

        (2) These notes are callable at par at any time after September 15, 2006. The estate of an individual note holder may exercise a put option in the event of death of an individual note holder.

     As of September 30, 2002, the aggregate principal amounts of long-term debt maturing for the next five years and thereafter are as follows: $160.6 million in 2003, $235.6 million in 2004, $6.2 million in 2005, $4.4 million in 2006, none in 2007 and $899.1 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, 2005.

     The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. As for the former, the Company maintains 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. The commercial paper program is backed by a committed $220 million, 364-day and 3-year credit facility, which was effective on September 30, 2002.

     At September 30, 2002, the Company had outstanding short-term notes payable to banks and commercial paper of $91.3 million (domestic = $79.9 million; foreign = $11.4 million) and $174.1 million, respectively. At September 30, 2001, the Company had outstanding notes payable to banks and commercial paper of $289.7 million (domestic = $259.9 million; foreign = $29.8 million) and $200.0 million, respectively.

     The weighted average interest rate on domestic notes payable to banks was 2.05% and 3.39% at September 30, 2002 and 2001, respectively. The interest rate on the foreign notes payable to banks was 3.64% and 4.65% at September 30, 2002 and 2001, respectively. The weighted average interest rate on commercial paper was 2.04% and 3.13% at September 30, 2002 and 2001, 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:

- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
                                                            2002              2002             2001              2001
                                                        Carrying               Fair         Carrying              Fair
At September 30 (Thousands)                               Amount              Value           Amount             Value
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------

Long-Term Debt                                        $1,305,905         $1,393,949       $1,156,129        $1,186,795
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------

     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 an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.

Other Investments
Other investments includes cash surrender values of insurance contracts and marketable equity securities. The cash surrender values of the insurance contracts amounted to $57.1 million and $52.9 million at September 30, 2002 and 2001, respectively. The fair value of the equity mutual fund was $3.8 million and $4.8 million at September 30, 2002 and 2001, respectively. The gross unrealized loss on the equity mutual fund was $1.5 million and $0.4 million at September 30, 2002 and 2001, respectively. The fair value of the stock of an insurance company was $4.2 million and $5.2 million at September 30, 2002 and 2001, respectively. The gross unrealized gain on this stock was $1.7 million and $2.7 million at September 30, 2002 and 2001, respectively. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.

Derivative Financial Instruments
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with the fluctuations in the price of natural gas and crude oil. These instruments include price swap agreements, no cost collars, options and futures contracts.

     Under the price swap agreements, the Company receives monthly payments from (or makes payments to) other parties based upon the difference between a fixed price and a variable price as specified by the agreement. The variable price is either a crude oil price quoted on the New York Mercantile Exchange (NYMEX) or a quoted natural gas price in "Inside FERC." These derivative financial instruments are accounted for as cash flow hedges and are used to lock in a price for the anticipated sale of natural gas and crude oil production in the Exploration and Production segment. At September 30, 2002, the Company had natural gas price swap agreements covering a notional amount of 18.5 Bcf extending through 2004 at a weighted average fixed rate of $3.73 per Mcf. The Company also had crude oil price swap agreements covering a notional amount of 3,252,000 bbls extending through 2003 at a weighted average fixed rate of $21.28 per bbl. At September 30, 2002, the Company would have had to pay a net $29.0 million to terminate the price swap agreements.

     Under the no cost collars, the Company receives monthly payments from (or makes payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). The variable price is either a crude oil price quoted on the NYMEX or a quoted natural gas price in "Inside FERC." These derivative financial instruments are accounted for as cash flow hedges and are used to lock in a price range for the anticipated sale of natural gas and crude oil production in the Exploration and Production segment. At September 30, 2002, the Company had no cost collars on natural gas covering a notional amount of 8.8 Bcf extending through 2004 with a weighted average floor price of $3.80 per Mcf and a weighted average ceiling price of $5.71 per Mcf. The Company also had no cost collars on crude oil covering a notional amount of 1,395,000 bbls extending through 2004 with a weighted average floor price of $21.97 per bbl and a weighted average ceiling price of $26.29 per bbl. At September 30, 2002, the Company would have had to pay $0.7 million to terminate the no cost collars.

     At September 30, 2002, the Company had purchased call and put options outstanding on natural gas extending through 2003. The call options purchased by the Energy Marketing segment cover a notional amount of 0.2 Bcf at a weighted average strike price of $4.73 per Mcf. The put options, purchased by the Exploration and Production segment cover a notional amount of 0.2 Bcf at a weighted average strike price of $3.98 per Mcf. These derivative financial instruments are accounted for as cash flow hedges. The call options are used to establish a ceiling price (the Company receives payment from the counterparty when a variable price rises above the ceiling price) for the anticipated purchase of natural gas in the Energy Marketing segment. At September 30, 2002, the Company would have received $0.1 million to terminate these call options. The put options are used to establish a floor price (the Company receives payment from the counterparty when a variable price falls below the floor price) for the anticipated sale of natural gas in the Exploration and Production segment. At September 30, 2002, the Company would have received $0.1 million to terminate these put options.

     At September 30, 2002, the Company had long (purchased) futures contracts covering 7.2 Bcf of gas extending through 2004 at a weighted average contract price of $3.71 per Mcf. These derivative financial instruments are accounted for as fair value hedges. They are used by the Company's Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed due to the fixed price gas sales commitments that it enters into with commercial and industrial customers. The Company would have received $5.4 million to terminate these futures contracts at September 30, 2002.

     At September 30, 2002, the Company had short (sold) futures contracts covering 3.8 Bcf of gas extending through 2003 at a weighted average contract price of $3.68 per Mcf. Of this amount, 3.6 Bcf is accounted for as cash flow hedges as these contracts relate to the anticipated sale of natural gas by the Energy Marketing segment. The remaining 0.2 Bcf is accounted for as fair value hedges, since these contracts hedge against falling prices, a risk to which the Energy Marketing segment and All Other category are exposed on their gas storage inventory and fixed price gas purchase commitments. The Company would have had to pay $3.3 million to terminate these futures contracts at September 30, 2002.

     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. Management has obtained guarantees from the parent companies of the respective counterparties to its derivative financial instruments. At September 30, 2001, the Company used five counterparties for its over the counter derivative financial instruments. To further reduce credit risk, the Company increased the number of its counterparties to seven at September 30, 2002. At September 30, 2002, no individual counterparty represented greater than 25% of total credit risk (measured as volumes hedged by an individual counterparty as a percentage of the Company's total volumes hedged).

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 expects to recover substantially all of its net periodic pension and post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization. For financial reporting purposes, the difference between the amounts of pension cost and post-retirement benefit cost recoverable in rates and the amounts of such costs as determined under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate. 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)                                         2002             2001              2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Benefit Obligation
Benefit Obligation at Beginning of Period                               $580,046         $535,894          $538,796
Service Cost                                                              11,639           11,550            11,692
Interest Cost                                                             40,720           39,061            37,954
Amendments                                                                   420            2,343                 -
Actuarial (Gain) Loss                                                     28,880           25,358           (20,216)
Benefits Paid                                                            (36,235)         (34,160)          (32,332)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Benefit Obligation at End of Period                                     $625,470         $580,046          $535,894
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Plan Assets
Fair Value of Assets at Beginning of Period                             $536,625         $569,936          $537,958
Actual Return on Plan Assets                                             (29,898)         (19,248)           36,584
Employer Contribution                                                     15,435           20,097            27,726
Benefits Paid                                                            (36,235)         (34,160)          (32,332)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Fair Value of Assets at End of Period                                   $485,927         $536,625          $569,936
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Reconciliation of Funded Status
Funded Status                                                          $(139,543)        $(43,421)          $34,042
Unrecognized Net Actuarial Loss (Gain)                                   132,064           23,222           (62,008)
Unrecognized Transition Asset                                             (3,716)          (7,432)          (11,148)
Unrecognized Prior Service Cost                                           11,451           12,236            10,943
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Prepaid (Accrued) Benefit Cost                                          $    256         $(15,395)         $(28,171)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Accumulated Benefit Obligation                                          $550,099         $510,155          $464,334
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Amounts Recognized in the Balance Sheets
  Consist of:
  Prepaid Benefit Cost                                                  $    256         $      -          $      -
  Accrued Benefit Cost                                                   (64,428)         (15,395)          (28,171)
  Intangible Asset                                                        11,451                -                 -
  Accumulated Other Comprehensive Loss (Pre Tax)                          52,977                -                 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Net Amount Recognized                                                   $    256         $(15,395)         $(28,171)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                            2002             2001              2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Weighted Average Assumptions as of September 30
Discount Rate                                                             6.75%            7.25%             7.50%
Expected Return on Plan Assets                                             8.50%            8.50%             8.50%
Rate of Compensation Increase                                              6.11%            6.11%             5.00%
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)
Components of Net Periodic Benefit Cost
Service Cost                                                             $11,639          $11,550          $ 11,692
Interest Cost                                                             40,720           39,061            37,954
Expected Return on Plan Assets                                           (48,454)         (45,703)          (41,077)
Amortization of Prior Service Cost                                         1,205            1,050             1,106
Amortization of Transition Amount                                         (3,716)          (3,716)           (3,716)
Recognition of Actuarial (Gain) or Loss                                   (1,061)          (2,256)               60
Early Retirement Window                                                        -            7,337                 -
Net Amortization and Deferral for
  Regulatory Purposes                                                      7,379            4,787               206
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Net Periodic Benefit Cost                                                 $7,712          $12,110           $ 6,225
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Other Comprehensive Loss (Pre Tax) Attributable to
  Change In Additional Minimum Liability Recognition                     $52,977          $     -           $     -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

     In accordance with the provisions of SFAS No. 87, "Employers' Accounting for Pensions," the Company recorded an additional minimum liability at September 30, 2002 representing the excess of the accumulated benefit obligation over the fair value of plan assets plus accrued amounts previously recorded. An intangible asset, as shown in the table above, has offset the additional liability to the extent of previously Unrecognized Prior Service Cost. The amount in excess of Unrecognized Prior Service Cost is recorded net of the related tax benefit as accumulated other comprehensive loss. The pre tax amount of the accumulated other comprehensive loss is shown in the table above.

     The effects of the discount rate changes in 2002 and 2001 were to increase the Benefit Obligation by $34.0 million and $15.6 million as of the end of each period, respectively.

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)                                         2002             2001              2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Benefit Obligation
Benefit Obligation at Beginning of Period                               $304,548        $ 266,460         $ 255,615
Service Cost                                                               4,658            4,234             4,156
Interest Cost                                                             21,617           19,557            18,142
Plan Participants' Contributions                                             610              524               414
Amendments                                                                     -               33                 -
Actuarial (Gain) Loss                                                     76,972           26,661              (355)
Benefits Paid                                                            (14,554)         (12,921)          (11,512)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Benefit Obligation at End of Period                                     $393,851        $ 304,548         $ 266,460
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Plan Assets
Fair Value of Assets at Beginning of Period                             $161,959        $ 176,357         $ 149,884
Actual Return on Plan Assets                                             (18,181)         (19,685)           18,527
Employer Contribution                                                     20,459           17,684            19,044
Plan Participants' Contributions                                             610              524               414
Benefits Paid                                                            (14,554)         (12,921)          (11,512)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Fair Value of Assets at End of Period                                   $150,293        $ 161,959         $ 176,357
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Reconciliation of Funded Status
Funded Status                                                          $(243,558)       $(142,589)         $(90,103)
Unrecognized Net Actuarial (Gain) Loss                                   157,247           52,832            (8,676)
Unrecognized Transition Obligation                                        78,399           85,526            92,653
Unrecognized Prior Service Cost                                               30               33                 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Accrued Benefit Cost                                                   $  (7,882)       $  (4,198)         $ (6,126)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------


- ----------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                            2002             2001              2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Weighted Average Assumptions as of September 30
Discount Rate                                                              6.75%            7.25%             7.50%
Expected Return on Plan Assets                                             8.50%            8.50%             8.50%
Rate of Compensation Increase                                              6.11%            6.11%             5.00%
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)
Components of Net Periodic Benefit Cost
Service Cost                                                              $4,658           $4,234            $4,156
Interest Cost                                                             21,617           19,557            18,142
Expected Return on Plan Assets                                           (13,551)         (14,787)          (12,574)
Amortization of Transition Obligation                                      7,127            7,127             7,127
Amortization of (Gain) Loss                                                4,289             (374)              (24)
Net Amortization and Deferral for
  Regulatory Purposes                                                       (729)           4,075             7,269
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Net Periodic Benefit Cost                                                $23,411          $19,832          $ 24,096
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

     The effects of the discount rate changes in 2002 and 2001 were to increase the Benefit Obligation by $21.7 million and $9.8 million as of the end of each period, respectively.

     The health care trend assumptions were changed in 2002 to better reflect anticipated future experience. The effect of the changed medical care, prescription drug and Medicare Part B assumptions was to increase the Accumulated Postretirement Benefit Obligation by $57.9 million. In 2000, the impact of changes in health care trend assumptions was an increase in the Accumulated Postretirement Benefit Obligation of $13.7 million.

     The annual rate of increase in the per capita cost of covered medical care benefits was assumed to be 10.0% for 2000, 9.0% for 2001, 12% for 2002 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 10.0% in 2000, 9.0% in 2001, 12% in 2002 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 15.0% for 2000, 13.0% for 2001, 15% for 2002 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 10.0% for 2000, 9.0% for 2001, 8% for 2002 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, 2002 would be increased by $58.2 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 2002 by $4.3 million. If the health care cost trend rates were decreased by 1% in each year, the Benefit Obligation as of October 1, 2002 would be decreased by $47.8 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 2002 by $3.5 million.

Note H - Commitments and Contingencies

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

     It is the Company's policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The Company has estimated its remaining clean-up costs related to the sites described below in paragraphs (i) and (ii) will be in the range of $5.1 million to $6.1 million. The minimum estimated liability of $5.1 million has been recorded on the Consolidated Balance Sheet at September 30, 2002. Other than as discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, adverse changes in environmental regulations, new information or other factors could impact the Company.

     (i) Former Manufactured Gas Plant Sites

     The Company has incurred or is incurring clean-up costs at 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). The Company is engaged in litigation regarding that site with the DEC and the party who bought the site from the Company's predecessor. At a second site, remediation is complete. At a third site, the Company is negotiating with the DEC for clean-up under a voluntary program. The fourth site, which allegedly contains, among other things, manufactured gas plant waste, 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, settlement was reached in the amount of $5.5 million to be allocated among five PRPs. The allocation process is currently being determined. Further negotiations remain in process for additional settlements related to this site.

     (iii) Other

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

Other
The Company, in its Utility segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase capacity on nonaffiliated pipelines to meet customer gas supply needs. The majority of these contracts (representing 95% of contracted demand capacity) expire within the next five years. Costs incurred under these contracts are purchased gas costs, subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.

     In October 2002, the Company announced its intention to buy the Empire State Pipeline (Empire) from Duke Energy Corporation for $180.0 million in cash plus assumed debt of $60.0 million. Empire is a 157-mile, 24-inch pipeline that begins at the United States/Canadian border at the Chippawa Channel of the Niagara River near Buffalo, New York, which is within the Company's service territory, and terminates in Central New York just north of Syracuse, New York. Empire is regulated by the NYPSC. Empire can transport 525 million cubic feet of gas per day and currently has almost all of its capacity under contract, with a substantial portion being long-term contracts. Empire delivers natural gas supplies to major industrial companies, utilities (including the Company's Utility segment), and power producers. Empire would better position the Company to bring Canadian gas supplies into the East Coast markets of the United States as demand for natural gas along the East Coast increases. The Company notified the Department of Justice and Federal Trade Commission of the proposed acquisition as required under the antitrust laws, and the Company's request for early termination of the antitrust waiting period has been granted. The Company has also made a filing seeking approval of the transaction from the NYPSC. Subject to NYPSC approval, it is anticipated that the purchase will be completed in the beginning of calendar 2003.

     The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation, and none of these other regulatory matters, are currently expected to have a material adverse effect on the financial condition of the Company.

Note 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. 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 FERC, holds a one-third partnership interest in the Independence Pipeline Company (Independence), whose rates, services and other matters were anticipated to be regulated by FERC. As discussed in Note J - Investments in Unconsolidated Subsidiaries, SIP wrote off its investment in Independence in June 2002. As shown in the table below, this impairment amounted to $15.2 million. On September 30, 2002, Independence was dissolved.

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

     The International segment's operations are carried out by Horizon. Horizon engages in foreign energy projects through the investment of its indirect subsidiaries as the sole or partial owner of various business entities. Horizon's current emphasis is the Czech Republic, where, through its subsidiaries, it owns majority interests in companies having district heating and power generation plants in the northern Bohemia region.

     The Energy Marketing segment is comprised of NFR's operations. NFR markets natural gas to industrial, commercial, public authority and residential end-users in western and central New York and northwestern Pennsylvania, offering competitively priced energy and energy management services for its customers.

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

     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, 2002 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------
                             Pipeline   Exploration                                    Total               Corporate and
                               and          and                   Energy             Reportable             Intersegment       Total
                   Utility   Storage    Production International Marketing   Timber   Segments   All Other  Eliminations    Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------------
Revenue from
External
Customers           $776,577  $ 80,165     $310,980     $95,315  $ 151,257  $47,407  $1,461,701    $2,795           $   -     $1,464,496

Intersegment
Revenues              17,644    87,219            -           -          -        -     104,863     7,340       (112,203)              -

Interest Expense      30,790    10,424       55,367       8,045         76    2,896     107,598       420         (2,366)        105,652

Depreciation,
Depletion and
Amortization          37,412    23,626      103,946      11,977        161    3,429     180,551       115               2        180,668

Income Tax
Expense               31,657    18,148       15,108     (2,030)      5,103    4,476      72,462     (473)              45         72,034

Significant Non-
Cash Item:
Impairment of
Investment in
Partnership                -     15,167           -           -          -        -      15,167         -               -         15,167

Segment Profit
(Loss): Net
Income                49,505    29,715       26,851     (4,443)      8,642    9,689     119,959     (885)         (1,392)        117,682

Expenditures for
Additions to
Long-Lived Assets     51,550    30,329      114,602       4,244         51   25,574     226,350     6,554               -        232,904

At September 30, 2002 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------

Segment Assets    $1,248,426   $532,543  $1,161,310    $241,466   $ 52,850 $131,721  $3,368,316   $33,563          $(570)     $3,401,309
- -----------------------------------------------------------------------------------------------------------------------------------------

Year Ended September 30, 2001 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------
                             Pipeline   Exploration                                    Total               Corporate and
                               and          and                   Energy             Reportable             Intersegment       Total
                   Utility   Storage    Production International Marketing   Timber   Segments   All Other  Eliminations    Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------------
Revenue from
External
Customers         $1,214,614  $ 81,057     $355,005     $97,910   $259,206  $44,914  $2,052,706    $7,130           $   -     $2,059,836

Intersegment
Revenues              20,033    90,034            -           -          -        -     110,067    11,192       (121,259)              -

Interest Expense      27,489    12,131       56,291       9,966      1,649    3,830     111,356       692         (4,903)        107,145

Depreciation
Depletion and
Amortization          36,607    23,746       98,408      12,634        212    3,186     174,794       119               2        174,914

Income Tax
Expense               42,985    29,091     (36,075)         253    (1,660)    4,566      39,160    (2,281)            227         37,106

Significant Non-
cash Item:
Impairment of
Oil and Gas
Producing
Properties                 -          -     180,781           -          -        -     180,781         -               -        180,781



Segment Profit
(Loss): Net
Income                60,707    40,377     (32,284)     (3,042)    (3,432)    7,715      70,041    (4,277)           (265)        65,499
Expenditures for
Additions to
Long-Lived Assets     42,374    25,978      296,419      15,585        116    3,694     384,166       937               -        385,103

At September 30, 2001 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------

Segment Assets    $1,284,189   $549,991  $1,194,393    $206,361   $ 68,178 $113,294  $3,416,406   $26,858          $1,967     $3,445,231
- -----------------------------------------------------------------------------------------------------------------------------------------

Year Ended September 30, 2000 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------
                             Pipeline   Exploration                                    Total               Corporate and
                               and          and                   Energy             Reportable             Intersegment       Total
                   Utility   Storage    Production International Marketing   Timber   Segments   All Other  Eliminations    Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------------
Revenue from
External
Customers           $827,231 $ 81,434      $222,611    $104,736   $133,929  $41,545  $1,411,486      $930           $   -     $1,412,416

Intersegment
Revenues              19,228   88,225           225           -          -        -     107,678     4,415       (112,093)              -

Interest Expense      31,655   13,311        42,034      12,353        774    4,750     104,877       262         (5,054)        100,085

Depreciation,
Depletion and
Amortization          35,842   23,379        69,583      11,110        209    1,948     142,071        97               2        142,170

Income Tax
Expense               38,362   22,172        19,413     (1,783)    (4,372)    3,816      77,608     (205)           (335)         77,068

Segment Profit
(Loss): Net
Income                57,662   31,614        34,877       3,282    (7,790)    6,133     125,778     (371)           1,800        127,207

Expenditures for
Additions to
Long-Lived Assets     55,799  35,806(1)     280,049       9,767         89   13,542     395,052     3,725               -        398,777

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

Segment Assets    $1,233,639   $552,059  $1,088,066    $202,622   $ 47,121 $107,402  $3,230,909   $21,930        $(1,808)     $3,251,031
- -----------------------------------------------------------------------------------------------------------------------------------------

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

 -------------------------------------------------------- ------------------ -------------------- --------------------
  Geographic Information                                         2002                2001                 2000
  -------------------------------------------------------- ------------------ -------------------- --------------------

  For the Year Ended September 30 (Thousands)
  Revenues from External Customers (1):
  United States                                               $1,293,239           $1,887,958           $1,279,329
  Czech Republic                                                  95,315               97,910              104,736
  Canada                                                          75,942               73,968               28,351
  -------------------------------------------------------- ------------------ -------------------- --------------------
                                                              $1,464,496           $2,059,836           $1,412,416

  At September 30 (Thousands)
  -------------------------------------------------------- ------------------ -------------------- --------------------
  Long-Lived Assets:
  United States                                               $2,624,810           $2,645,429           $2,488,180
  Czech Republic                                                 216,044              187,961              183,274
  Canada                                                         258,196              257,939              248,937
  -------------------------------------------------------- ------------------ -------------------- --------------------
                                                              $3,099,050           $3,091,329           $2,920,391
  -------------------------------------------------------- ------------------ -------------------- --------------------

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

Note J - Investments in Unconsolidated Subsidiaries

The Company’s unconsolidated subsidiaries consist of equity method investments in Seneca Energy II, LLC (Seneca Energy), Model City Energy, LLC (Model City), and Energy Systems North East, LLC (ESNE). The Company has 50% interests in each of these entities. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. ESNE sells its electricity into the New York power grid.

     In June 2002, the Company wrote off its 33-1/3% equity method investment in Independence, a partnership that had proposed to construct and operate a 400-mile pipeline to transport natural gas from Defiance, Ohio to Leidy, Pennsylvania. In June 2002, Independence submitted a motion to FERC requesting that FERC vacate the certificate issued to Independence to construct, own and operate the pipeline. Independence took this action because it had been unable to obtain sufficient customer contracts to proceed with the project. In connection with this filing, the Company wrote off its $15.2 million investment in Independence. FERC formally vacated the certificate in an order issued in July 2002.

     A summary of the Company's investments in unconsolidated subsidiaries at September 30, 2002 and 2001 is as follows:

  ---------------------------------------------------------------- --------------------- ---------------------
  At  September 30 (Thousands)
                                                                                  2002                  2001
    ---------------------------------------------------------------- --------------------- ---------------------

  ESNE                                                                         $12,522               $12,950
  Independence                                                                       -                14,632
  Seneca Energy                                                                  3,625                 3,735
  Model City                                                                       606                   451
  ---------------------------------------------------------------- --------------------- ---------------------
                                                                               $16,753               $31,768
  ---------------------------------------------------------------- --------------------- ---------------------

Note K - Stock Acquisitions

In June 2001, the Company acquired the outstanding shares of Player Petroleum Corporation (Player), an oil and gas exploration and development company, with operations based primarily in the Province of Alberta, Canada. The cost of acquiring the outstanding shares of Player was approximately $90.6 million and the acquisition was accounted for in accordance with the purchase method. Player’s results of operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on June 30, 2001.

     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 and the acquisition was accounted for in accordance with the purchase method. Tri Link's results of operations were incorporated into the Company's consolidated financial statements for the period subsequent to the completion of the acquisition on June 15, 2000.

     Details of the stock acquisitions made by the Company during 2001 and 2000 are as follows:

  ---------------------------------------------------------------- --------------------- ---------------------
  Year Ended September 30 (Millions)
                                                                                  2001                  2000
  ---------------------------------------------------------------- --------------------- ---------------------

  Assets acquired                                                               $175.1                $259.9
  Liabilities assumed                                                            (84.5)               (136.1)
  ---------------------------------------------------------------- --------------------- ---------------------
  Cash paid                                                                      $90.6                $123.8
  ---------------------------------------------------------------- --------------------- ---------------------

Note L - Quarterly Financial Data (unaudited)

In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statement of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal 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 (Loss)
                                                                 Available
                                                                    for                  Earnings (Loss) Per
      Quarter             Operating            Operating           Common                   Common Share
                                                                                  ----------------------------------
       Ended              Revenues           Income (Loss)         Stock               Basic           Diluted
- --------------------- ------------------- ------------------ -------------------- ---------------- -----------------
              2002           (Thousands, except per common share amounts)
- --------------------- ----------------------------------------------------------- ----------------------------------
        12/31/2001              $392,327             $58,798            $33,207                $0.42              $0.41
        3/31/2002              $477,436             $89,328            $61,924                $0.78              $0.77
        6/30/2002              $350,123             $57,357            $17,676 (1)            $0.22              $0.22
        9/30/2002              $244,610             $26,507             $4,875                $0.06              $0.06
- --------------------- ----------------------------------------------------------------- ----------------------------
              2001              (Thousands, except per common share amounts)
- --------------------- ----------------------------------------------------------------- ----------------------------
        12/31/2000              $552,212            $ 77,335            $52 984(2)              $0.67             $0.66
         3/31/2001              $864,715            $103,572            $75,275(3)              $0.95             $0.94
         6/30/2001              $393,007            $ 60,212            $36,618                 $0.46             $0.45
         9/30/2001              $249,902            $(79,566)          $(99,378)(4)            $(1.25)           $(1.24)
- --------------------- ------------------- ------------------ -------------------- ---------------- -----------------

        (1) Includes expense of $9.9 million related to the impairment of investment in partnership.

        (2) Includes expense of $7.5 million related to Stock Appreciation Rights (SARs), expense of $1.2 million related to early retirement offers and income of $2.6 million related to the termination of a long-term transportation contract.

        (3) Includes income of $9.7 million related to SARs and expense of $4.2 million related to early retirement offers.

        (4) Includes income of $5.3 million related to SARs and expense of $104.0 million related to the impairment of oil and gas assets.

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

At September 30, 2002, there were 20,004 holders of Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note D - Capitalization. The quarterly price ranges and quarterly dividends declared for the fiscal years ended September 30, 2002 and 2001, are shown below:

- --------------------------------------------------------------- ------------------------------------ -----------------
                                                                           Price Range                     Dividends
                                                                ------------------------------------
Quarter Ended                                                                High              Low          Declared
- --------------------------------------------------------------- ------------------- ---------------- -----------------
    2002
- --------------------------------------------------------------- ------------------- ---------------- -----------------
 12/31/2001                                                                $24.95           $21.95            $.2525
  3/31/2002                                                                $25.70           $22.00            $.2525
  6/30/2002                                                                $24.98           $21.38             $.260
  9/30/2002                                                                $22.84           $15.61             $.260
- --------------------------------------------------------------- ------------------- ---------------- -----------------
    2001
- --------------------------------------------------------------- ------------------- ---------------- -----------------
 12/31/2000                                                                $32.25           $25.57             $.240
  3/31/2001                                                                $31.60           $25.01             $.240
  6/30/2001                                                                $28.99           $25.90            $.2525
  9/30/2001                                                                $26.38           $21.96            $.2525
- --------------------------------------------------------------- ------------------- ---------------- -----------------

Note N - Supplementary Information for Oil and Gas Producing Activities

The following supplementary information is presented in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities," and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars.

Capitalized Costs Relating to Oil and Gas Producing Activities

- ----------------------------------------------------------------------------------- ---------------- -----------------
At September 30 (Thousands)
                                                                                              2002              2001

- ----------------------------------------------------------------------------------- ---------------- -----------------
Proved Properties                                                                       $1,779,962        $1,586,889
Unproved Properties                                                                         50,925           152,326
- ----------------------------------------------------------------------------------- ---------------- -----------------
                                                                                         1,830,887         1,739,215
Less - Accumulated Depreciation, Depletion
  and Amortization                                                                         776,477           675,256
- ----------------------------------------------------------------------------------- ---------------- -----------------
                                                                                        $1,054,410        $1,063,959
- ----------------------------------------------------------------------------------- ---------------- -----------------

     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, 2002:

- ---------------------------- -------------------------- --------------------------------------------------------------
                                           Total as of                       Year Costs Incurred
                                                        --------------------------------------------------------------
(Thousands)                          September 30, 2002              2002            2001           2000          Prior
- ---------------------------- -------------------------- ---------------- --------------- -------------- --------------

Acquisition Costs                               $50,925           $21,170          $7,831        $10,895        $11,029
- ---------------------------- -------------------------- ---------------- --------------- -------------- --------------

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

- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)                                         2002             2001              2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs:
  Proved                                                                 $ 9,316          $ 1,713           $ 2,848
  Unproved                                                                   698           15,296            19,066
Exploration Costs                                                         25,583           42,338            50,163
Development Costs                                                         51,792           88,987            72,039
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                          87,389          148,334           144,116
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs:
  Proved                                                                   (536)          115,643           159,268
  Unproved                                                                 2,804            2,612            77,198
Exploration Costs                                                          8,779            8,523               573
Development Costs                                                         15,332           36,554            11,013
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                          26,379          163,332           248,052
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs: (1)
  Proved                                                                   8,780          117,356           162,116
  Unproved                                                                 3,502           17,908            96,264
Exploration Costs                                                         34,362           50,861            50,736
Development Costs                                                         67,124          125,541            83,052
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
                                                                        $113,768         $311,666          $392,168
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

        (1) Total proved and unproved property acquisition costs for 2001 of $135.3 million include $107.6 million related to the Player acquisition. Total proved and unproved property acquisition costs for 2000 of $258.4 million include $236.5 million related to the Tri Link acquisition.

Results of Operations for Producing Activities

- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands, Except Per Mcfe Amounts)                2002             2001              2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
  Natural Gas (includes revenues from sales to affiliates
    of $43, $4 and $237, respectively)                                  $104,954         $216,729          $137,336
  Oil, Condensate and Other Liquids                                      101,549          121,973           107,645
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1)                                              206,503          338,702           244,981
Production/Lifting Costs                                                  42,956           37,068            33,979
Depreciation, Depletion and Amortization
  ($1.25, $1.13 and $0.97 per Mcfe of production)                         80,142           76,686            64,624
Income Tax Expense                                                        30,253           83,649            52,656
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
  (excluding corporate overheads and interest charges)                    53,152          141,299            93,722
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
  Natural Gas                                                             14,621            4,379               485
  Oil, Condensate and Other Liquids                                       56,511           74,349            26,320
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1)                                               71,132           78,728            26,805
Production/Lifting Costs                                                  30,109           27,089             7,858
Depreciation, Depletion and Amortization
  ($0.93, $0.93 and $0.77 per Mcfe of production)                         21,707           18,719             4,321
Impairment of Oil and Gas Producing Properties(2)                              -          180,781                 -
Income Tax Expense (Benefit)                                                4,672         (63,795)            6,121
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
  (excluding corporate overheads and interest charges)                     14,644         (84,066)            8,505
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
  Natural Gas (includes revenues from sales to affiliates
    of $43, $4 and $237, respectively)                                   119,575          221,108           137,821
  Oil, Condensate and Other Liquids                                      158,060          196,322           133,965
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1)                                              277,635          417,430           271,786
Production/Lifting Costs                                                  73,065           64,157            41,837
Depreciation, Depletion and Amortization
  ($1.16, $1.08 and $0.95 per Mcfe of production)                        101,849           95,405            68,945
Impairment of Oil and Gas Producing Properties(2)                              -          180,781                 -
Income Tax Expense                                                        34,925           19,854            58,777
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
  (excluding corporate overheads and interest charges)                  $ 67,796         $ 57,233          $102,227
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

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

        (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, 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
    Extensions and Discoveries             35,960        15,681         51,641           924         3,625         4,549
    Revisions of
      Previous Estimates                  (22,813)          (34)       (22,847)        1,737       (5,396)        (3,659)
    Production                            (39,188)       (1,816)       (41,004)       (4,796)      (3,061)        (7,857)
    Sales of Minerals in Place             (6,066)         (280)        (6,346)         (685)         (80)          (765)
    Purchases of Minerals
      in Place and Other                      410        38,859         39,269           104         3,259         3,363
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
  September 30, 2001                      266,813        55,567        322,380        74,795        40,533       115,328
    Extensions and Discoveries             16,542        20,263         36,805         1,437           586         2,023
    Revisions of
      Previous Estimates                  (24,108)      (20,676)       (44,784)          916      (10,278)        (9,362)
    Production                            (35,067)       (6,387)       (41,454)       (4,828)      (2,834)        (7,662)
    Sales of Minerals in Place            (14,726)            -        (14,726)         (200)        (410)          (610)
    Purchases of Minerals
      in Place and Other                        -             -              -             -             -             -
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
  September 30, 2002                      209,454        48,767        258,221        72,120        27,597        99,717
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
Proved Developed Reserves:
  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
  September 30, 2001                      213,792        53,463        267,255        50,640        33,676        84,316
  September 30, 2002                      192,833        39,253        232,086        46,940        24,100        71,040
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------

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)
                                                                             2002             2001              2000
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows                                                    $2,764,556       $2,127,601        $3,886,499
Less:
  Future Production Costs                                                 546,182          602,479           600,243
  Future Development Costs                                                117,999          121,240           179,565
  Future Income Tax Expense at
    Applicable Statutory Rate                                             653,347          376,667         1,006,366
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows                                                   1,447,028        1,027,215         2,100,325
Less:
  10% Annual Discount for Estimated
    Timing of Cash Flows                                                  665,941          421,865           859,950
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
    Net Cash Flows                                                        781,087          605,350         1,240,375
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows                                                       888,515          890,381         1,083,598
Less:
  Future Production Costs                                                 413,006          533,848           277,067
  Future Development Costs                                                 25,398           19,608            21,399
  Future Income Tax Expense at
    Applicable Statutory Rate                                             101,919           76,191           286,148
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows                                                     348,192          260,734           498,984
Less:
  10% Annual Discount for Estimated
    Timing of Cash Flows                                                  103,097           79,295           221,227
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
    Net Cash Flows                                                        245,095          181,439           277,757
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows                                                     3,653,071        3,017,982         4,970,097
Less:
  Future Production Costs                                                 959,188        1,136,327           877,310
  Future Development Costs                                                143,397          140,848           200,964
  Future Income Tax Expense at
    Applicable Statutory Rate                                             755,266          452,858         1,292,514
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows                                                   1,795,220        1,287,949         2,599,309
Less:
  10% Annual Discount for Estimated
    Timing of Cash Flows                                                  769,038          501,160         1,081,177
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
    Net Cash Flows                                                     $1,026,182        $ 786,789        $1,518,132
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

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

- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)                                         2002             2001              2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
  Net Cash Flows at Beginning of Year                                   $605,350       $1,240,375          $707,259
    Sales, Net of Production Costs                                      (163,548)        (301,634)         (211,002)
    Net Changes in Prices, Net of Production Costs                       441,085         (921,719)          795,408
    Purchases of Minerals in Place                                             -            1,191                 -
    Sales of Minerals in Place                                           (27,197)         (17,552)          (11,914)
    Extensions and Discoveries                                            42,970           52,062           186,818
    Changes in Estimated Future Development Costs                        (42,069)          (3,157)          (82,270)
    Previously Estimated Development Costs Incurred                       45,310           61,482            88,322
    Net Change in Income Taxes at
      Applicable Statutory Rate                                         (126,263)         363,425          (292,371)
    Revisions of Previous Quantity Estimates                             (32,646)         (29,841)           20,736
    Accretion of Discount and Other                                       38,095          160,718            39,389
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
  Future Net Cash Flows at End of Year                                   781,087          605,350         1,240,375
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
  Net Cash Flows at Beginning of Year                                    181,439          277,757                 -
    Sales, Net of Production Costs                                       (41,023)         (51,638)          (18,948)
    Net Changes in Prices, Net of Production Costs                       111,148         (161,461)                -
    Purchases of Minerals in Place                                             -           30,575           424,072
    Sales of Minerals in Place                                            (3,084)            (761)                -
    Extensions and Discoveries                                            29,813           39,752             2,979
    Changes in Estimated Future Development Costs                         18,151          (31,009)                -
    Previously Estimated Development Costs Incurred                       12,361           12,176                 -
    Net Change in Income Taxes at
      Applicable Statutory Rate                                           (6,910)          73,865          (150,057)
    Revisions of Previous Quantity Estimates                             (88,571)         (64,368)                -
    Accretion of Discount and Other                                       31,771           56,551            19,711
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
  Future Net Cash Flows at End of Year                                   245,095          181,439           277,757
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
  Net Cash Flows at Beginning of Year                                    786,789        1,518,132           707,259
    Sales, Net of Production Costs                                      (204,571)        (353,272)         (229,950)
    Net Changes in Prices, Net of Production Costs                       552,233       (1,083,180)          795,408
    Purchases of Minerals in Place                                             -           31,766           424,072
    Sales of Minerals in Place                                           (30,281)         (18,313)          (11,914)
    Extensions and Discoveries                                            72,783           91,814           189,797
    Changes in Estimated Future Development Costs                        (23,918)         (34,166)          (82,270)
    Previously Estimated Development Costs Incurred                       57,671           73,658            88,322
    Net Change in Income Taxes at
      Applicable Statutory Rate                                         (133,173)         437,290          (442,428)
    Revisions of Previous Quantity Estimates                            (121,217)         (94,209)           20,736
    Accretion of Discount and Other                                       69,866          217,269            59,100
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
  Future Net Cash Flows at End of Year                                $1,026,182        $ 786,789        $1,518,132
- ----------------------------------------------------------------- ----------------- ---------------- -----------------

Schedule II - Valuation and Qualifying Accounts

- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
                                                             Additions      Additions
                                             Balance at     Charged to     Charged to                       Balance at
(Thousands)                                   Beginning      Costs and          Other                           End of
Description                                   of Period       Expenses    Accounts(1)     Deductions(2)         Period
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Year Ended September 30, 2002
Reserve for Doubtful Accounts                   $18,521        $16,082         $2,834           $20,138        $17,299
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Year Ended September 30, 2001
Reserve for Doubtful Accounts                   $12,013        $17,445           $  -           $10,937        $18,521
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Year Ended September 30, 2000
Reserve for Doubtful Accounts                    $7,842        $15,177           $  -           $11,006        $12,013
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------

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

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

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

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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 20, 2003 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2002. 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 2005,” “Directors Whose Terms Expire in 2004,” “Directors Whose Terms Expire in 2003,” 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 20, 2003 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2002. The information concerning executive compensation is set forth in the definitive Proxy Statement under the captions “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and, excepting the “Report of the Compensation Committee” and the “Corporate Performance Graph,” is incorporated herein by reference.

ITEM 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

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Equity Compensation Plan Information
- ------------------------------ ----------------------------- ---------------------------- ----------------------------
 Plan category                 Number of securities Weighte  Weighted-average             Number of securities
                               be issued upon exercise       exercise price of out-       remaining available for
                               of outstanding options,       standing options,            future issuance under
                               warrants and rights           warrants and rights          equity compensation
                                                                                          plans (excluding
                                                                                          securities reflected in
                                                                                          column (a))
                               (a)                           (b)                          (c)

- ------------------------------ ----------------------------- ---------------------------- ----------------------------
Equity compensation
plans approved by                 14,629,504                        $22.12                      942,669
security holders
- ------------------------------ ----------------------------- ---------------------------- ----------------------------
Equity compensation
plans not approved by
security holders                           0                             0                            0
- ------------------------------ ----------------------------- ---------------------------- ----------------------------

     Total
                                  14,629,504                        $22.12                       942,669
- ------------------------------ ----------------------------- ---------------------------- ----------------------------

Security Ownership and Changes in Control

(a) Security Ownership of Certain Beneficial Owners

The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 20, 2003 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2002. 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 20, 2003 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2002. 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 20, 2003 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2002. 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 Controls and Procedures

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     The following information includes the evaluation of disclosure controls and procedures by the Company's Chief Executive Officer and Treasurer, along with any significant changes in internal controls of the Company.

Evaluation of disclosure controls and procedures

     The term "disclosure controls and procedures" is defined in Rules 13a-14(c) and 15d-14(c) of the Securities Exchange Act of 1934 (Exchange Act). These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods. The Company's Chief Executive Officer and Treasurer have evaluated the effectiveness of the Company's disclosure controls and procedures as of a date within 90 days before the filing of this Annual Report on Form 10-K (Evaluation Date), and, they have concluded that, as of the Evaluation Date, such controls and procedures were effective to accomplish those tasks.

Changes in internal controls

     The Company maintains a system of internal accounting controls that are designed to provide reasonable assurance that the Company's transactions are properly authorized, the Company's assets are safeguarded against unauthorized or improper use, and the Company's transactions are properly recorded and reported to permit preparation of the Company's financial statements in conformity with generally accepted accounting principles in the United States. There were no significant changes in the Company's internal controls or in other factors that could significantly affect the Company's internal controls subsequent to the Evaluation Date, nor were there any significant deficiencies or material weaknesses in the Company's internal controls.

ITEM 15 Exhibits, Financial Statement Schedules and Reports on Form 8-K

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         (a)1.  Financial Statements
                Financial  statements  filed as part of this report are listed in the index  included in Item 8 of this Form 10-K,  and
                reference is made thereto.

         (a)2.  Financial Statement Schedules
                Financial  statements  schedules  filed as part of this report are listed in the index  included in Item 8 of this Form
                10-K, and reference is made thereto.

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

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          National  Fuel  Gas  Company  By-Laws  as  amended  on  December  13,  2001  (Exhibit 3.1,  Form
           10-K/A for fiscal year ended September 30, 2001, in File No. 1-3880)

(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          Officers  Certificate   Establishing   Medium-Term   Notes,  dated   October  14,  1999   (Exhibit  4.2,
           Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)

o          Amended and  Restated  Rights  Agreement,  dated as of April 30,  1999,  between  the  Company  and HSBC Bank USA  (Exhibit
           10.2, Form 10-Q for the quarterly period ended March 31, 1999 in File No. 1-3880)

o          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)

o          Officers  Certificate  establishing  6.50% notes due 2022,  dated  September 18, 2002 (Exhibit 4, Form 8-K dated October 3,
           2002 in File No. 1-3880)

(10)       Material Contracts:

(ii)       Contracts upon which the Company's business is substantially dependent:

10.1       Credit Agreement, dated as of September 30, 2002, among the Company, the Lenders Party Thereto and JP Morgan Chase Bank,
           as Administrative Agent.

(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)

o          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)

o          Employment  Agreement,  dated September 17, 1981,  between 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  between  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,  between 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,  between 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  Agreement,  dated as of December 11, 1998, among the Company, National
           Fuel Gas Distribution Corporation and each of Philip C. Ackerman, Anna Marie Cellino, Walter E. DeForest, Joseph P. Pawlowski,
           James D. Ramsdell, Dennis J. Seeley, David Smith, Ronald J. Tanski and Gerald T. Werhrlin (Exhibit 10.1, Form 10-Q for the
           quarterly period ended June 30, 1999 in File No. 1-3880)

o          Form of Employment Continuation and Noncompetition  Agreement,  dated as of December 11, 1998, among the Company, National
           National Fuel Supply Corporation and each of Bruce H. Hale and John R. Pustulka (Exhibit 10.2, Form 10-Q for the quarterly
           period ended June 30, 1999 in File No. 1-3880)

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

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          National   Fuel   Gas  Company  1993  Award  and  Option  Plan,  amended  through  June  14,  2001
           (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 2001 in File No. 1-3880)

o          National   Fuel  Gas  Company  1997  Award  and  Option  Plan,  amended  through  June  14,  2001
           (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 2001 in File No. 1-3880)

o          Amendment   to  National   Fuel  Gas   Company   Deferred   Compensation  Plan,   dated   June  15,
           2001 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 2001 in File No. 1-3880)

o          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 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 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 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 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, between 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, between 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   Restated   Split  Dollar   Insurance   Agreement,   effective  June  15,  2000,   among  the
           Company,   Bernard  J.  Kennedy,  and   Joseph  B.  Kennedy,  as  Trustee  of  the Trust  under  the
           Agreement   dated  January  9,  1998   (Exhibit  10.1,   Form  10-Q  for  the  quarterly  period  ended
           June 30, 2000 in File No. 1-3880)

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

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

o          Amendment   Number  1  to   Amended  and   Restated  Split  Dollar   Insurance  and  Death  Benefit
           Agreement   by  and  between   the  Company   and  Philip  C.  Ackerman,   dated    March  23,  1999
           (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)

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

o          Amendment    Number  1   to   Amended   and  Restated   Split Dollar  Insurance and  Death  Benefit
           Agreement  by  and   between  the  Company  and   Joseph  P.  Pawlowski,  dated  March  23,  1999
           (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)

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

o          Amendment  Number  1   to    Amended  and   Restated  Split   Dollar  Insurance  and   Death  Benefit
           Agreement    by   and   between   the   Company   and   Dennis   J.  Seeley,  dated  March  29,  1999
           (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)

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

o          Amendment  Number 1 to  Split  Dollar  Insurance  and  Death  Benefit  Agreement  by and between
           the  Company  and  Bruce  H. Hale,  dated  March  29,  1999  (Exhibit  10.12, Form  10-K  for  fiscal
           year ended September 30, 1999 in File No. 1-3880)

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

o          Amendment   Number  1  to Split  Dollar  Insurance and  Death Benefit  Agreement by  and between
           the   Company  and  David  F.  Smith,  dated  March 29,  1999   (Exhibit  10.14, Form  10-K for fiscal
           year ended September 30, 1999 in File No. 1-3880)

10.2       Split Dollar Insurance Agreement, dated March 6, 2001, between the Company and James A. Beck.

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 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          Amendment    to   National     Fuel    Gas    Company    and    Participating   Subsidiaries    Executive
           Retirement    Plan,   effective   September   5,   2001  (Exhibit  10.4,   Form  10-K/A   for  fiscal   year
           ended September 30, 2001, in File No. 1-3880)

o          Retirement    Supplement   Agreement,  dated   September  14,  2000,  between  the  Company  and
           Gerald T. Wehrlin  (Exhibit 10.5,  Form 10-K/A for fiscal year  ended September 30, 2001 in File No.
           1-3880)

o          Retirement   Supplement   Agreement,   dated   January  11,  2002,   between   the  C ompany   and
           Joseph  P.  Pawlowski   (Exhibit  10.6,   Form  10-K/A  for  fiscal   year  ended  September  30, 2001
           in File No. 1-3880)

o          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 10, 2002 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, 1998 through 2002

(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

(99)       Additional Exhibits:

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

99.2       Report of Ralph E. Davis Associates, Inc. regarding National Fuel Exploration Corp.

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

99.4       Written statements of Chief Executive Officer and Principal Financial Officer pursuant
           to Section 906 of the Sarbanes-Oxley Act of 2002.

99.5       Company Maps

o          Incorporated herein by reference as indicated.

           All other exhibits are omitted because they are not applicable or the required
           information is shown elsewhere in this Annual Report on Form 10-K.

           (b)  Reports on Form 8-K

        A report on Form 8-K dated August 14, 2002 was filed on August 14, 2002, to report a sworn statement from the principal executive and financial officers, under Item 9, “Regulation FD Disclosure.” Related exhibits were reported under Item 7, “Financial Statements and Exhibits.

        A report on Form 8-K dated July 25, 2002 was filed on July 29, 2002, to report earnings for the quarter ended June 30, 2002, the participation in the drilling of a natural gas discovery and to address certain matters from the Company’s public conference call, under Item 5, “Other Events.” Related exhibits were reported under Item 7, “Financial Statements and Exhibits.


Signatures

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     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

                                                 National Fuel Gas Company
                                                     (Registrant)         




                                              By/s/ P. C. Ackerman   

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

                                              Date:  December 12, 2002


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

        Signature                                          Title






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

   Date:  December 12, 2002


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

   Date:  December 12, 2002


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

   Date:  December 12, 2002


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

   Date:  December 12, 2002


   /s/ B. J. Kennedy                         Director
       B. J. Kennedy

   Date:  December 12, 2002



   /s/ R. E. Kidder                          Director
       R. E. Kidder

   Date:  December 12, 2002


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

   Date:  December 12, 2002


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

   Date:  December 12, 2002


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

   Date:  December 12, 2002


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

   Date:  December 12, 2002


   /s/ J. P. Pawlowski                       Treasurer, Principal Financial
       J. P. Pawlowski                       Officer and Principal Accounting Officer

   Date:  December 12, 2002


CERTIFICATION

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        I, Philip C. Ackerman, certify that:

        1. I have reviewed this annual report on Form 10-K of National Fuel Gas Company;

        2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

        3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

        4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

        a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

        b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

        c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

        5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

        a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

        b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

        6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: December 12, 2002

/s/ Philip C. Ackerman

Philip C. Ackerman
Chairman of the Board, President and
Chief Executive Officer

CERTIFICATION

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        I, Joseph P. Pawlowski, certify that:

        1. I have reviewed this annual report on Form 10-K of National Fuel Gas Company;

        2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

        3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

        4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

        a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

        b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

        c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

        5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

        a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

        b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

        6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: December 12, 2002

/s/ Joseph P. Pawlowski

Joseph P. Pawlowski
Treasurer and Principal Financial Officer
EX-10 3 ex-10_1.htm CREDIT AGREEMENT Exhibit 10.1

EXHIBIT 10.1


JP Morgan Logo

CREDIT AGREEMENT

dated as of

September 30, 2002

among

NATIONAL FUEL GAS COMPANY

The Lenders Party Hereto

and

JPMORGAN CHASE BANK,
as Administrative Agent


J.P. MORGAN SECURITIES INC.,
as Sole Bookrunner and Sole Lead Arranger

===================================================================================================================
                                                 TABLE OF CONTENTS

                                                                                         Page
                                                                                         ----


ARTICLE I Definitions.......................................................................1
         SECTION 1.01. Defined Terms........................................................1
         SECTION 1.02. Classification of Loans and Borrowings..............................12
         SECTION 1.03. Terms Generally.....................................................13
         SECTION 1.04. Accounting Terms; GAAP..............................................13

ARTICLE II The Credits.....................................................................13
         SECTION 2.01. Commitments.........................................................13
         SECTION 2.02. Loans and Borrowings................................................14
         SECTION 2.03. Requests for Borrowings.............................................14
         SECTION 2.04. Funding of Borrowings...............................................15
         SECTION 2.05. Interest Elections..................................................15
         SECTION 2.06. Termination, Reduction and Increase of Commitments..................17
         SECTION 2.07. Repayment of Loans; Evidence of Debt................................20
         SECTION 2.08. Prepayment of Loans.................................................20
         SECTION 2.09. Fees................................................................21
         SECTION 2.10. Interest............................................................22
         SECTION 2.11. Alternate Rate of Interest..........................................22
         SECTION 2.12. Increased Costs.....................................................23
         SECTION 2.13. Break Funding Payments..............................................24
         SECTION 2.14. Taxes...............................................................24
         SECTION 2.15. Payments Generally; Pro Rata Treatment; Sharing of Set-offs.........25
         SECTION 2.16. Mitigation Obligations; Replacement of Lenders......................27

ARTICLE III Representations and Warranties.................................................27
         SECTION 3.01. Corporate Existence.................................................28
         SECTION 3.02. Financial Condition.................................................28
         SECTION 3.03. Litigation..........................................................28
         SECTION 3.04. No Breach...........................................................28
         SECTION 3.05. Action..............................................................29
         SECTION 3.06. Approvals...........................................................29
         SECTION 3.07. Use of Credit.......................................................29
         SECTION 3.08. ERISA...............................................................29
         SECTION 3.09. Taxes...............................................................30
         SECTION 3.10. Investment Company Act..............................................30
         SECTION 3.11. Public Utility Holding Company Act..................................30
         SECTION 3.12. Environmental Matters...............................................30
         SECTION 3.13. Subsidiaries, Etc...................................................31
         SECTION 3.14. True and Complete Disclosure........................................31

ARTICLE IV Conditions......................................................................31
         SECTION 4.01. Effective Date......................................................31
         SECTION 4.02. Each Credit Event...................................................32

ARTICLE V Covenants of the Borrower........................................................33
         SECTION 5.01. Financial Statements, Etc...........................................33
         SECTION 5.02. Existence, Etc......................................................35
         SECTION 5.03. Insurance...........................................................35
         SECTION 5.04. Prohibition of Fundamental Changes..................................35
         SECTION 5.05. Limitation on Liens.................................................36
         SECTION 5.06. Use of Proceeds.....................................................37
         SECTION 5.07. Financial Condition.................................................37

ARTICLE VI Events of Default...............................................................37

ARTICLE VII The Administrative Agent.......................................................40

ARTICLE VIII Miscellaneous.................................................................42
         SECTION 8.01. Notices.............................................................42
         SECTION 8.02. Waivers; Amendments.................................................42
         SECTION 8.03. Expenses; Indemnity; Damage Waiver..................................43
         SECTION 8.04. Successors and Assigns..............................................44
         SECTION 8.05. Survival............................................................47
         SECTION 8.06. Counterparts; Integration; Effectiveness............................48
         SECTION 8.07. Severability........................................................48
         SECTION 8.08. Right of Setoff.....................................................48
         SECTION 8.09. Governing Law; Jurisdiction; Consent to Service of Process..........48
         SECTION 8.10. WAIVER OF JURY TRIAL................................................49
         SECTION 8.11. Headings............................................................49
         SECTION 8.12. Confidentiality.....................................................49


SCHEDULES:

Schedule 2.01 - Commitments
Schedule 3.06 - Governmental Approvals
Schedule 4.01 - Repaid Indebtedness

EXHIBITS:

Exhibit A - Form of Assignment and Assumption



        CREDIT AGREEMENT dated as of September 30, 2002, among NATIONAL FUEL GAS COMPANY, the LENDERS party hereto, and JPMORGAN CHASE BANK, as Administrative Agent.

        The parties hereto agree as follows:

ARTICLE I

Definitions

        SECTION 1.01. Defined Terms. As used in this Agreement, the following terms have the meanings specified below:

        “364-Day Facility Availability Period” means the period from and including the Effective Date to but excluding the earlier of the 364-Day Facility Maturity Date and the 364-Day Facility Commitment Termination Date.

        “364-Day Facility Commitment” means, with respect to each Lender, the commitment of such Lender to make 364-Day Facility Loans, expressed as an amount representing the maximum aggregate amount of such Lender’s 364-Day Facility Credit Exposure hereunder, as such commitment may be (a) reduced or increased from time to time pursuant to Section 2.06 and (b) reduced or increased from time to time pursuant to assignments by or to such Lender pursuant to Section 8.04. The initial amount of each Lender’s 364-Day Facility Commitment is set forth on Schedule 2.01, or in the Assignment and Assumption pursuant to which such Lender shall have assumed its 364-Day Facility Commitment, as applicable. The initial aggregate amount of the Lenders’ 364-Day Facility Commitments is $110,000,000.

        “364-Day Facility Commitment Termination Date” means the date which is 364 days after the Effective Date.

        “364-Day Facility Credit Exposure” means, with respect to any Lender at any time, the outstanding principal amount of such Lender’s 364-Day Facility Loans at such time.

        “364-Day Facility Loan” means a Loan made pursuant to Section 2.03(a).

        “364-Day Facility Maturity Date” means the 364-Day Facility Commitment Termination Date provided, that the 364-Day Facility Maturity Date shall be September 30, 2004 if (i) the Administrative Agent shall have received, at least 30 days prior to the 364-Day Facility Commitment Termination Date, written correspondence from the Borrower requesting such extension of the 364-Day Facility Maturity Date accompanied by a certificate of a senior officer of the Borrower certifying that, at such time and, to the best of the Borrower’s knowledge at the time such certification is made, immediately after giving effect to such extension, no Default shall have occurred and be continuing and (ii) on the 364-Day Facility Commitment Termination Date and immediately after giving effect to such extension, no Default shall have occurred and be continuing.

        “ABR”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Alternate Base Rate.

        “Adjusted LIBO Rate” means, with respect to any Eurodollar Borrowing for any Interest Period, an interest rate per annum (rounded upwards, if necessary, to the next 1/16 of 1%) equal to (a) the LIBO Rate for such Interest Period multiplied by (b) the Statutory Reserve Rate.

        “Administrative Agent” means JPMorgan Chase Bank, in its capacity as administrative agent for the Lenders hereunder.

        “Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Administrative Agent.

        “Affiliate” means, with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified.

        “Alternate Base Rate” means, for any day, a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the Base CD Rate in effect on such day plus 1% and (c) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1%. Any change in the Alternate Base Rate due to a change in the Prime Rate, the Base CD Rate or the Federal Funds Effective Rate shall be effective from and including the effective date of such change in the Prime Rate, the Base CD Rate or the Federal Funds Effective Rate, respectively.

        “Applicable Percentage” means, with respect to any Lender, the percentage of the total Commitments represented by such Lender’s Commitment. If the Commitments have terminated or expired, the Applicable Percentages shall be determined based upon the Commitments most recently in effect, giving effect to any assignments.

        “Applicable Rate” means, for any day, with respect to any ABR Loan or Eurodollar Loan, or with respect to the facility fees payable hereunder, as the case may be, the applicable rate per annum set forth below under the caption “ABR Applicable Margin”, “Eurodollar Applicable Margin” or “Facility Fee Rate”, as the case may be, based upon the ratings by Moody’s, S&P and Fitch, respectively, applicable on such date to the Index Debt:

======================== ========================= =========================== =========================== ==========================
      Ratings of                   ABR                  Eurodollar Rate                 Facility                Drawn Cost for
      Index Debt            Applicable Margin          Applicable Margin                Fee Rate              Initial Borrowings
- ------------------------ ------------------------- --------------------------- --------------------------- --------------------------
      Category 1         364-Day Facility:         364-Day Facility:  0.425%   364-Day Facility:  0.075%   364-Day Facility:  0.500%
      ----------
        A/A2/A           0.000%                    Multi-Year Facility:        Multi-Year Facility:        Multi-Year Facility:
                         Multi-Year Facility:      0.400%                      0.100%                      0.500%
                         0.000%
- ------------------------ ------------------------- --------------------------- --------------------------- --------------------------
      Category 2         364-Day Facility:         364-Day Facility:  0.525%   364-Day Facility:  0.100%   364-Day Facility:  0.625%
      ----------
       A-/A3/A-          0.000%                    Multi-Year Facility:        Multi-Year Facility:        Multi-Year Facility:
                         Multi-Year Facility:      0.500%                      0.125%                      0.625%
                         0.000%
- ------------------------ ------------------------- --------------------------- --------------------------- --------------------------
      Category 3         364-Day Facility:         364-Day Facility:  0.625%   364-Day Facility:  0.125%   364-Day Facility:  0.750%
      ----------
    BBB+/Baa1/BBB+       0.000%                    Multi-Year Facility:        Multi-Year Facility:        Multi-Year Facility:
                         Multi-Year Facility:      0.600%                      0.150%                      0.750%
                         0.000%
- ------------------------ ------------------------- --------------------------- --------------------------- --------------------------
      Category 4         364-Day Facility:         364-Day Facility:  0.725%   364-Day Facility:  0.150%   364-Day Facility:  0.875%
      ----------
     BBB/Baa2/BBB        0.000%                    Multi-Year Facility:        Multi-Year Facility:        Multi-Year Facility:
                         Multi-Year Facility:      0.700%                      0.175%                      0.875%
                         0.000%
- ------------------------ ------------------------- --------------------------- --------------------------- --------------------------
      Category 5         364-Day Facility:         364-Day Facility:  1.075%   364-Day Facility:  0.175%   364-Day Facility:  1.250%
      ----------
    BBB-/Baa3/BBB-       0.075%                    Multi-Year Facility:        Multi-Year Facility:        Multi-Year Facility:
                         Multi-Year Facility:      1.050%                      0.200%                      1.250%
                         0.050%
- ------------------------ ------------------------- --------------------------- --------------------------- --------------------------
      Category 6         364-Day Facility:         364-Day Facility:  1.525%   364-Day Facility:  0.225%   364-Day Facility:  1.750%
      ----------
   < BBB-/Baa3/BBB-      0.525%                    Multi-Year Facility:        Multi-Year Facility:        Multi-Year Facility:
                         Multi-Year Facility:      1.500%                      0.250%                      1.750%
                         0.500%
======================== ========================= =========================== =========================== ==========================

provided, that (i) through the 364-Day Facility Maturity Date, for each day the aggregate principal amount of 364-Day Facility Loans outstanding is greater than 33% of the aggregate 364-Day Facility Commitments, each of the ABR Applicable Margin and the Eurodollar Applicable Margin set forth above for the 364-Day Facility Loans shall be increased by 0.125% and (ii) through the Multi-Year Facility Maturity Date, for each day the aggregate principal amount of Multi-Year Facility Loans outstanding is greater than 33% of the aggregate Multi-Year Facility Commitments, each of the ABR Applicable Margin and the Eurodollar Applicable Margin set forth above for the Multi-Year Facility Loans shall be increased by 0.125%. If, after the 364-Day Facility Commitment Termination Date, any amount of 364-Day Facility Loans remains outstanding, each of the ABR Applicable Margin and the Eurodollar Applicable Margin set forth above for such Loans shall be increased by 0.250%. After the 364-Day Facility Maturity Date, each of the ABR Applicable Margin and the Eurodollar Applicable Margin set forth above for the 364-Day Facility Loans will be increased by 0.125% with respect to any amount of such Loans then outstanding. After the Multi-Year Facility Maturity Date, each of the ABR Applicable Margin and the Eurodollar Applicable Margin set forth above for the Multi-Year Facility Loans will be increased by 0.125% with respect to any amount of such Loans then outstanding.

        For purposes of the foregoing, with respect to the Index Debt, (i) if all three Rating Agencies issue a rating and if the ratings from two Rating Agencies are at the same level and the rating from the third Rating Agency is at a lower level, the higher rating shall apply; (ii) if the ratings from two Rating Agencies are at the same level and the rating from the third Rating Agency is at a higher level, the lower rating shall apply; (iii) if all three ratings from the Rating Agencies are at different levels, the rating next below the highest of the three shall apply; (iv) if only two Rating Agencies issue a rating, the lower of such ratings shall apply; and (v) if only one Rating Agency issues a rating, such rating shall apply. If the ratings established or deemed to have been established by either Rating Agency shall be changed (other than as a result of a change in the rating system of such Rating Agency), such change shall be effective as of the date on which it is first announced by the applicable Rating Agency, irrespective of when notice of such change shall have been furnished by the Borrower to the Administrative Agent and the Lenders pursuant to Section 5.01(i) or otherwise. Each change in the Applicable Rate shall apply during the period commencing on the effective date of such change and ending on the date immediately preceding the effective date of the next such change. If the rating system of either Rating Agency shall change, or if the sole remaining Rating Agency providing a rating with respect to Index Debt shall cease to be in the business of rating corporate debt obligations, the Borrower and the Lenders shall negotiate in good faith to amend this definition to reflect such changed rating system or the unavailability of ratings from such Rating Agency and, pending the effectiveness of any such amendment, the Applicable Rate shall be determined by reference to the rating most recently in effect prior to such change or cessation.

        “Approved Fund” has the meaning assigned to such term in Section 8.04.

        “Assessment Rate” means, for any day, the annual assessment rate in effect on such day that is payable by a member of the Bank Insurance Fund classified as “well-capitalized” and within supervisory subgroup “B” (or a comparable successor risk classification) within the meaning of 12 C.F.R. Part 327 (or any successor provision) to the Federal Deposit Insurance Corporation for insurance by such Corporation of time deposits made in dollars at the offices of such member in the United States; provided that if, as a result of any change in any law, rule or regulation, it is no longer possible to determine the Assessment Rate as aforesaid, then the Assessment Rate shall be such annual rate as shall be determined by the Administrative Agent to be representative of the cost of such insurance to the Lenders.

        “Assignment and Assumption” means an assignment and assumption entered into by a Lender and an assignee (with the consent of any party whose consent is required by Section 8.04), and accepted by the Administrative Agent, in the form of Exhibit A or any other form approved by the Administrative Agent.

        “Assuming Lender” means, at any time, a Person not previously a Lender which becomes a Lender pursuant to Section 2.06(d).

        “Assumption and Acceptance” means an assumption and acceptance entered into by an Assuming Lender, the Borrower and the Administrative Agent, in the form of Exhibit B or any other form approved by the Borrower and the Administrative Agent.

        “Bankruptcy Code” means the Federal Bankruptcy Code of 1978, as amended from time to time.

        “Base CD Rate” means the sum of (a) the Three-Month Secondary CD Rate multiplied by the Statutory Reserve Rate plus (b) the Assessment Rate.

        “Board” means the Board of Governors of the Federal Reserve System of the United States of America.

        “Borrower” means National Fuel Gas Company, a New Jersey corporation.

        “Borrowing” means Loans of the same Type and Class, made, converted or continued on the same date and, in the case of Eurodollar Loans, as to which a single Interest Period is in effect.

        “Borrowing Request” means a request by the Borrower for a Borrowing in accordance with Section 2.03.

        “Business Day” means any day that is not a Saturday, Sunday or other day on which commercial banks in New York City are authorized or required by law to remain closed; provided that, when used in connection with a Eurodollar Loan, the term “Business Day” shall also exclude any day on which banks are not open for dealings in dollar deposits in the London interbank market.

        “Capital Lease Obligations” of any Person means the obligations of such Person to pay rent or other amounts under any lease of (or other arrangement conveying the right to use) real or personal property, or a combination thereof, which obligations are required to be classified and accounted for as capital leases on a balance sheet of such Person under GAAP, and the amount of such obligations shall be the capitalized amount thereof determined in accordance with GAAP.

        “Change in Law” means (a) the adoption of any law, rule or regulation after the date of this Agreement, (b) any change in any law, rule or regulation or in the interpretation or application thereof by any Governmental Authority after the date of this Agreement or (c) compliance by any Lender (or, for purposes of Section 2.12(b), by any lending office of such Lender or by such Lender’s holding company, if any) with any request, guideline or directive (whether or not having the force of law) of any Governmental Authority made or issued after the date of this Agreement.

        “CLO” has the meaning assigned to such term in Section 8.04.

        “Code” means the Internal Revenue Code of 1986, as amended from time to time.

        “Commitment” means, with respect to each Lender, such Lender’s aggregate 364-Day Facility Commitment and Multi-Year Facility Commitment.

        “ Commitment Increase” shall have the meaning specified in Section 2.06(d).

        “ Commitment Increase Date” shall have the meaning specified in Section 2.06(d).

        “Consolidated Capitalization” means, at any date, the sum of Consolidated Net Worth and Consolidated Indebtedness.

        “Consolidated Indebtedness” means, at any date, all Indebtedness of the Borrower and its Subsidiaries at such date, determined on a consolidated basis in accordance with GAAP, as reflected on the balance sheet.

        “Consolidated Net Worth” means, at any date, all amounts that would, in conformity with GAAP, be included on a consolidated balance sheet of the Borrower and its Subsidiaries under stockholders’ equity at such time.

        “Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise. “Controlling” and “Controlled” have meanings correlative thereto.

        “Credit Exposure” means, with respect to any Lender at any time, the outstanding principal amount of such Lender’s Loans at such time.

        “Default” means any event or condition which constitutes an Event of Default or which upon notice, lapse of time or both would, unless cured or waived, become an Event of Default.

        “dollars” or “$” refers to lawful money of the United States of America.

        “Effective Date” means the date on which the conditions specified in Section 4.01 are satisfied (or waived in accordance with Section 8.02).

        “Environmental Laws” means all laws, rules, regulations, codes, ordinances, orders, decrees, judgments, injunctions, notices or binding agreements issued, promulgated or entered into by any Governmental Authority, relating in any way to the environment, preservation or reclamation of natural resources, the management, release or threatened release of any Hazardous Material or to health and safety matters.

        “Environmental Liability” means any liability, contingent or otherwise (including any liability for damages, costs of environmental remediation, fines, penalties or indemnities), of the Borrower or any Subsidiary directly or indirectly resulting from or based upon (a) violation of any Environmental Law, (b) the generation, use, handling, transportation, storage, treatment or disposal of any Hazardous Materials, (c) exposure to any Hazardous Materials, (d) the release or threatened release of any Hazardous Materials into the environment or (e) any contract, agreement or other consensual arrangement pursuant to which liability is assumed or imposed with respect to any of the foregoing.

        “ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time.

        “ERISA Affiliate” means any trade or business (whether or not incorporated) that, together with the Borrower, is treated as a single employer under Section 414(b) or (c) of the Code or, solely for purposes of Section 302 of ERISA and Section 412 of the Code, is treated as a single employer under Section 414 of the Code.

        “Eurodollar”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Adjusted LIBO Rate.

        “Event of Default” has the meaning assigned to such term in Article VI.

        “Excluded Taxes” means, with respect to the Administrative Agent, any Lender or any other recipient of any payment to be made by or on account of any obligation of the Borrower hereunder, (a) income or franchise taxes imposed on (or measured by) its net income by the United States of America, or by the jurisdiction under the laws of which such recipient is organized or in which its principal office is located or, in the case of any Lender, in which its applicable lending office is located, (b) any branch profits taxes imposed by the United States of America or any similar tax imposed by any other jurisdiction in which the Borrower is located and (c) in the case of a Foreign Lender (other than an assignee pursuant to a request by the Borrower under Section 2.16(b)), any withholding tax that is imposed on amounts payable to such Foreign Lender at the time such Foreign Lender becomes a party to this Agreement (or designates a new lending office) or is attributable to such Foreign Lender’s failure to comply with Section 2.14(e), except to the extent that such Foreign Lender (or its assignor, if any) was entitled, at the time of designation of a new lending office (or assignment), to receive additional amounts from the Borrower with respect to such withholding tax pursuant to Section 2.14(a).

        “Federal Funds Effective Rate” means, for any day, the weighted average (rounded upwards, if necessary, to the next 1/100 of 1%) of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average (rounded upwards, if necessary, to the next 1/100 of 1%) of the quotations for such day for such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

        “Financial Officer” means the chief financial officer, principal accounting officer, treasurer or controller of the Borrower.

        “Fitch” means Fitch, Inc.

        “Foreign Lender” means any Lender that is organized under the laws of a jurisdiction other than that in which the Borrower is located. For purposes of this definition, the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction. >

        “GAAP” means generally accepted accounting principles in the United States of America.

        “Governmental Approval” means any authorization, consent, approval, license, ruling, permit, tariff, rate, certification, exemption, filing, variance, order, judgment, decree, publication, notice to, declaration of or registration by or with any Governmental Authority.

        “Governmental Authority” means the government of the United States of America, any other nation or any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government.

        “Guarantee” of or by any Person (the “guarantor”) means any obligation, contingent or otherwise, of the guarantor guaranteeing or having the economic effect of guaranteeing any Indebtedness or other obligation of any other Person (the “primary obligor”) in any manner, whether directly or indirectly, and including any obligation of the guarantor, direct or indirect, (a) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or other obligation or to purchase (or to advance or supply funds for the purchase of) any security for the payment thereof, (b) to purchase or lease property, securities or services for the purpose of assuring the owner of such Indebtedness or other obligation of the payment thereof, (c) to maintain working capital, equity capital or any other financial statement condition or liquidity of the primary obligor so as to enable the primary obligor to pay such Indebtedness or other obligation or (d) as an account party in respect of any letter of credit or letter of guaranty issued to support such Indebtedness or obligation; provided, that the term Guarantee shall not include endorsements for collection or deposit in the ordinary course of business.

        “Hazardous Materials” means all explosive or radioactive substances or wastes and all hazardous or toxic substances, wastes or other pollutants, including petroleum or petroleum distillates, asbestos or asbestos containing materials, polychlorinated biphenyls, radon gas, infectious or medical wastes and all other substances or wastes of any nature regulated pursuant to any Environmental Law.

        “Increasing Lender” shall have the meaning specified in Section 2.06(d).

        “Indebtedness” of any Person means, without duplication, (a) all obligations of such Person for borrowed money or with respect to deposits or advances of any kind, (b) all obligations of such Person evidenced by bonds, debentures, notes or similar instruments, (c) all obligations of such Person upon which interest charges are customarily paid, (d) all obligations of such Person under conditional sale or other title retention agreements relating to property acquired by such Person, (e) all obligations of such Person in respect of the deferred purchase price of property or services (excluding current accounts payable incurred in the ordinary course of business), (f) all Indebtedness of others secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien on property owned or acquired by such Person, whether or not the Indebtedness secured thereby has been assumed, (g) all Guarantees by such Person of Indebtedness of others, (h) all Capital Lease Obligations of such Person, (i) all obligations, contingent or otherwise, of such Person as an account party in respect of letters of credit and letters of guaranty and (j) all obligations, contingent or otherwise, of such Person in respect of bankers’ acceptances. The Indebtedness of any Person shall include the Indebtedness of any other entity (including any partnership in which such Person is a general partner) to the extent such Person is liable therefor as a result of such Person’s ownership interest in or other relationship with such entity, except to the extent the terms of such Indebtedness provide that such Person is not liable therefor.

        “Indemnified Taxes” means Taxes other than Excluded Taxes.

        “Index Debt” means senior, unsecured, long-term indebtedness for borrowed money of the Borrower that is not guaranteed by any other Person or subject to any other credit enhancement.

        “Interest Election Request” means a request by the Borrower to convert or continue a Borrowing in accordance with Section 2.05.

        “Interest Payment Date” means (a) with respect to any ABR Loan, the last day of each March, June, September and December and (b) with respect to any Eurodollar Loan, the last day of the Interest Period applicable to the Borrowing of which such Loan is a part and, in the case of a Eurodollar Borrowing with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period.

        “Interest Period”, means with respect to any Eurodollar Borrowing, the period commencing on the date of such Borrowing and ending on the numerically corresponding day in the calendar month that is one, two, three or six months thereafter, as the Borrower may elect; provided, that (a) if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless such next succeeding Business Day would fall in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day and (b) any Interest Period pertaining to a Eurodollar Borrowing that commences on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the last calendar month of such Interest Period) shall end on the last Business Day of the last calendar month of such Interest Period. For purposes hereof, the date of a Borrowing initially shall be the date on which such Borrowing is made and thereafter shall be the effective date of the most recent conversion or continuation of such Borrowing.

        “Lenders” means the Persons listed on Schedule 2.01 and any other Person that shall have become a party hereto pursuant to an Assignment and Assumption, other than any such Person that ceases to be a party hereto pursuant to an Assignment and Assumption.

        “LIBO Rate” means, with respect to any Eurodollar Borrowing for any Interest Period, the rate appearing on Page 3750 of the Dow Jones Market Service (or on any successor or substitute page of such Service, or any successor to or substitute for such Service, providing rate quotations comparable to those currently provided on such page of such Service, as determined by the Administrative Agent from time to time for purposes of providing quotations of interest rates applicable to dollar deposits in the London interbank market) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period, as the rate for dollar deposits with a maturity comparable to such Interest Period. In the event that such rate is not available at such time for any reason, then the “LIBO Rate” with respect to such Eurodollar Borrowing for such Interest Period shall be the rate at which dollar deposits of $5,000,000 and for a maturity comparable to such Interest Period are offered by the principal London office of the Administrative Agent in immediately available funds in the London interbank market at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period.

        “Lien” means, with respect to any asset, (a) any mortgage, deed of trust, lien, pledge, hypothecation, encumbrance, charge or security interest in, on or of such asset, (b) the interest of a vendor or a lessor under any conditional sale agreement, capital lease or title retention agreement (or any financing lease having substantially the same economic effect as any of the foregoing) relating to such asset and (c) in the case of securities, any purchase option, call or similar right of a third party with respect to such securities.

        “Loans” means 364-Day Facility Loans and Multi-Year Facility Loans made by the Lenders to the Borrower pursuant to this Agreement.

        “Material Adverse Effect” means a material adverse effect on (a) the business, assets, property, operations, prospects or condition, financial or otherwise, of the Borrower and its Subsidiaries taken as a whole, (b) the validity or enforceability of, or the ability of the Borrower to perform any of its obligations under, this Agreement or (c) the rights of, or remedies or benefits available to, the Administrative Agent and the Lenders under this Agreement.

        “Material Subsidiary” means, at any time, a Subsidiary of the Borrower whose assets exceed 10% of the consolidated assets of the Borrower and its Subsidiaries.

        “Moody's” means Moody's Investors Service, Inc.

        “Multiemployer Plan” means a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

        “Multi-Year Facility Availability Period” means the period from and including the Effective Date to but excluding the earlier of the Multi-Year Facility Maturity Date and the Multi-Year Facility Commitment Termination Date.

        “Multi-Year Facility Commitment” means, with respect to each Lender, the commitment of such Lender to make Multi-Year Facility Loans, expressed as an amount representing the maximum aggregate amount of such Lender’s Multi-Year Facility Credit Exposure hereunder, as such commitment may be (a) reduced or increased from time to time pursuant to Section 2.06 and (b) reduced or increased from time to time pursuant to assignments by or to such Lender pursuant to Section 8.04. The initial amount of each Lender’s Multi-Year Facility Commitment is set forth on Schedule 2.01, or in the Assignment and Assumption pursuant to which such Lender shall have assumed its Multi-Year Facility Commitment, as applicable. The initial aggregate amount of the Lenders’ Multi-Year Facility Commitments is $110,000,000.

        “Multi-Year Facility Commitment Termination Date” means the date which is three years after the Effective Date.

        “Multi-Year Facility Credit Exposure” means, with respect to any Lender at any time, the outstanding principal amount of such Lender’s Multi-Year Facility Loans at such time.

        “Multi-Year Facility Loan” means a Loan made pursuant to Section 2.03(b).

        “Multi-Year Facility Maturity Date” means September 30, 2005.

        “Other Obligations” has the meaning set forth in Section 5.05.

        “Other Taxes” means any and all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made hereunder or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement.

        “Participant” has the meaning set forth in Section 8.04.

        “PBGC” means the Pension Benefit Guaranty Corporation referred to and defined in ERISA and any successor entity performing similar functions.

        “Person” means any natural person, corporation, limited liability company, trust, joint venture, association, company, partnership, Governmental Authority or other entity.

        “Plan” means any employee pension benefit plan (other than a Multiemployer Plan) subject to the provisions of Title IV of ERISA or Section 412 of the Code or Section 302 of ERISA, and in respect of which the Borrower or any ERISA Affiliate is (or, if such plan were terminated, would under Section 4069 of ERISA be deemed to be) an “employer” as defined in Section 3(5) of ERISA.

        “Prime Rate” means the rate of interest per annum publicly announced from time to time by JPMorgan Chase Bank as its prime rate in effect at its principal office in New York City; each change in the Prime Rate shall be effective from and including the date such change is publicly announced as being effective.

        “PUHCA” has the meaning set forth in Section 3.11.

        “Rating Agency” means, each of Moody's, S&P and Fitch.

         “Register” has the meaning set forth in Section 8.04.

        “Related Parties” means, with respect to any specified Person, such Person’s Affiliates and the respective directors, officers, employees, agents and advisors of such Person and such Person’s Affiliates.

        “Required Lenders” means, at any time, Lenders having Credit Exposures and unused Commitments representing more than 50% of the sum of the total Credit Exposures and unused Commitments at such time.

        “S&P” means Standard & Poor's Rating Services, a division of the McGraw-Hill Companies, Inc.

        “SEC” means the United States Securities and Exchange Commission or any successor thereto.

        “Statutory Reserve Rate” means a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentages (including any marginal, special, emergency or supplemental reserves) expressed as a decimal established by the Board to which the Administrative Agent is subject (a) with respect to the Base CD Rate, for new negotiable nonpersonal time deposits in dollars of over $100,000 with maturities approximately equal to three months and (b) with respect to the Adjusted LIBO Rate, for eurocurrency funding (currently referred to as “Eurocurrency Liabilities” in Regulation D of the Board). Such reserve percentages shall include those imposed pursuant to such Regulation D. Eurodollar Loans shall be deemed to constitute eurocurrency funding and to be subject to such reserve requirements without benefit of or credit for proration, exemptions or offsets that may be available from time to time to any Lender under such Regulation D or any comparable regulation. The Statutory Reserve Rate shall be adjusted automatically on and as of the effective date of any change in any reserve percentage.

        “subsidiary” means, with respect to any Person (the “parent”) at any date, any corporation, limited liability company, partnership, association or other entity the accounts of which would be consolidated with those of the parent in the parent’s consolidated financial statements if such financial statements were prepared in accordance with GAAP as of such date, as well as any other corporation, limited liability company, partnership, association or other entity (a) of which securities or other ownership interests representing more than 50% of the equity or more than 50% of the ordinary voting power or, in the case of a partnership, more than 50% of the general partnership interests are, as of such date, owned, controlled or held, or (b) that is, as of such date, otherwise Controlled, by the parent or one or more subsidiaries of the parent or by the parent and one or more subsidiaries of the parent.

        “Subsidiary” means any subsidiary of the Borrower.

        “Taxes” means any and all present or future taxes, levies, imposts, duties, deductions, charges or withholdings imposed by any Governmental Authority.

        “Three-Month Secondary CD Rate” means, for any day, the secondary market rate for three-month certificates of deposit reported as being in effect on such day (or, if such day is not a Business Day, the next preceding Business Day) by the Board through the public information telephone line of the Federal Reserve Bank of New York (which rate will, under the current practices of the Board, be published in Federal Reserve Statistical Release H.15(519) during the week following such day) or, if such rate is not so reported on such day or such next preceding Business Day, the average of the secondary market quotations for three-month certificates of deposit of major money center banks in New York City received at approximately 10:00 a.m., New York City time, on such day (or, if such day is not a Business Day, on the next preceding Business Day) by the Administrative Agent from three negotiable certificate of deposit dealers of recognized standing selected by it.

        “Transactions” means the execution, delivery and performance by the Borrower of this Agreement, the borrowing of Loans and the use of the proceeds thereof.

        “Type”, when used in reference to any Loan or Borrowing, refers to whether the rate of interest on such Loan, or on the Loans comprising such Borrowing, is determined by reference to the Adjusted LIBO Rate or the Alternate Base Rate.

        “Wholly-Owned Subsidiary” means, for any Person, any Subsidiary of such Person of which all of the equity securities or other ownership interests (other than in the case of a corporation, directors’ qualifying shares) are directly or indirectly owned or Controlled by such Person.

        SECTION 1.02. Classification of Loans and Borrowings. For purposes of this Agreement, Loans may be classified and referred to by Class (e.g., a "Multi-Year Facility Loan") or by Type (e.g., a "Eurodollar Loan") or by Class and Type (e.g., a "Eurodollar Multi-Year Facility Loan"). Borrowings also may be classified and referred to by Class (e.g., a "Multi-Year Facility Borrowing") or by Type (e.g., a "Eurodollar Borrowing") or by Class and Type (e.g., a "Eurodollar Multi-Year Facility Borrowing").

        SECTION 1.03. Terms Generally. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. Unless the context requires otherwise (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein), (b) any reference herein to any Person shall be construed to include such Person’s successors and assigns, (c) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (d) all references herein to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and Schedules to, this Agreement and (e) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights.

        SECTION 1.04. Accounting Terms; GAAP. Except as otherwise expressly provided herein, all terms of an accounting or financial nature shall be construed in accordance with GAAP, as in effect from time to time; provided that, if the Borrower notifies the Administrative Agent that the Borrower requests an amendment to any provision hereof to eliminate the effect of any change occurring after the date hereof in GAAP or in the application thereof on the operation of such provision (or if the Administrative Agent notifies the Borrower that the Required Lenders request an amendment to any provision hereof for such purpose), regardless of whether any such notice is given before or after such change in GAAP or in the application thereof, then such provision shall be interpreted on the basis of GAAP as in effect and applied immediately before such change shall have become effective until such notice shall have been withdrawn or such provision amended in accordance herewith.

ARTICLE II

The Credits

        SECTION 2.01. Commitments. (a) Subject to the terms and conditions set forth herein, each Lender agrees to make 364-Day Facility Loans to the Borrower from time to time during the 364-Day Facility Availability Period in an aggregate principal amount that will not result in (i) such Lender’s 364-Day Facility Credit Exposure exceeding such Lender’s 364-Day Facility Commitment or (ii) the total 364-Day Facility Credit Exposures exceeding the total 364-Day Facility Commitments. Within the foregoing limits and subject to the terms and conditions set forth herein, the Borrower may borrow, prepay and reborrow 364-Day Facility Loans.

         (b) Subject to the terms and conditions set forth herein, each Lender agrees to make Multi-Year Facility Loans to the Borrower from time to time during the Multi-Year Facility Availability Period in an aggregate principal amount that will not result in (i) such Lender's Multi-Year Facility Credit Exposure exceeding such Lender's Multi-Year Facility Commitment or (ii) the total Multi-Year Facility Credit Exposures exceeding the total Multi-Year Facility Commitments. Within the foregoing limits and subject to the terms and conditions set forth herein, the Borrower may borrow, prepay and reborrow Multi-Year Facility Loans.

        SECTION 2.02. Loans and Borrowings. (a) Each 364-Day Facility Loan shall be made as part of a Borrowing consisting of 364-Day Facility Loans made by the Lenders ratably in accordance with their respective 364-Day Facility Commitments. Each Multi-Year Facility Loan shall be made as part of a Borrowing consisting of Multi-Year Facility Loans made by the Lenders ratably in accordance with their respective Multi-Year Facility Commitments. The failure of any Lender to make any Loan required to be made by it shall not relieve any other Lender of its obligations hereunder; provided that the Commitments of the Lenders are several and no Lender shall be responsible for any other Lender’s failure to make Loans as required.

         (b) Subject to Section 2.11, each Borrowing shall be comprised entirely of ABR Loans or Eurodollar Loans as the Borrower may request in accordance herewith. Each Lender at its option may make any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan; provided that any exercise of such option shall not affect the obligation of the Borrower to repay such Loan in accordance with the terms of this Agreement.

         (c) At the commencement of each Interest Period for any Eurodollar Borrowing, such Borrowing shall be in an aggregate amount that is an integral multiple of $5,000,000 and not less than $10,000,000. At the time that each ABR Borrowing is made, such Borrowing shall be in an aggregate amount that is an integral multiple of $5,000,000 and not less than $10,000,000; provided that an ABR Borrowing of either Class may be in an aggregate amount that is equal to the entire unused balance of the total 364-Day Facility Commitments or Multi-Year Facility Commitments, as applicable. Borrowings of more than one Type and Class may be outstanding at the same time; provided that there shall not at any time be more than a total of six 364-Day Facility Eurodollar Borrowings or six Multi-Year Facility Eurodollar Borrowings outstanding.

         (d) Notwithstanding any other provision of this Agreement, the Borrower shall not be entitled to request, or to elect to convert or continue, (i) any Borrowing of 364-Day Facility Loans if the Interest Period requested with respect thereto would end after the 364-Day Facility Maturity Date and (ii) any Borrowing of Multi-Year Facility Loans if the Interest Period requested with respect thereto would end after the Multi-Year Facility Maturity Date.

        SECTION 2.03. Requests for Borrowings. To request a Borrowing, the Borrower shall notify the Administrative Agent of such request by telephone (a) in the case of a Eurodollar Borrowing, not later than 11:00 a.m., New York City time, three Business Days before the date of the proposed Borrowing or (b) in the case of an ABR Borrowing, not later than 11:00 a.m., New York City time, one Business Day before the date of the proposed Borrowing. Each such telephonic Borrowing Request shall be irrevocable and shall be confirmed promptly by hand delivery or facsimile to the Administrative Agent of a written Borrowing Request in a form approved by the Administrative Agent and signed by the Borrower. Each such telephonic and written Borrowing Request shall specify the following information in compliance with Section 2.02:

        (i) the aggregate amount of the requested Borrowing;

        (ii) the date of such Borrowing, which shall be a Business Day;

        (iii) whether such Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing and whether such Borrowing is of 364-Day Facility Loans or Multi-Year Facility Loans;

        (iv) in the case of a Eurodollar Borrowing, the initial Interest Period to be applicable thereto, which shall be a period contemplated by the definition of the term "Interest Period"; and

        (v) the location and number of the Borrower's account to which funds are to be disbursed, which shall comply with the requirements of Section 2.04.

If no election as to the Type of Borrowing is specified, then the requested Borrowing shall be an ABR Borrowing. If no Interest Period is specified with respect to any requested Eurodollar Borrowing, then the Borrower shall be deemed to have selected an Interest Period of one month’s duration. Promptly following receipt of a Borrowing Request in accordance with this Section, the Administrative Agent shall advise each Lender of the details thereof and of the amount of such Lender’s Loan to be made as part of the requested Borrowing.

        SECTION 2.04. Funding of Borrowings. (a) Each Lender shall make each Loan to be made by it hereunder on the proposed date thereof by wire transfer of immediately available funds by 12:00 noon, New York City time, to the account of the Administrative Agent most recently designated by it for such purpose by notice to the Lenders. The Administrative Agent will make such Loans available to the Borrower by promptly crediting the amounts so received, in like funds, to an account of the Borrower maintained with the Administrative Agent in New York City and designated by the Borrower in the applicable Borrowing Request.

         (b) Unless the Administrative Agent shall have received notice from a Lender prior to the proposed date of any Borrowing that such Lender will not make available to the Administrative Agent such Lender's share of such Borrowing, the Administrative Agent may assume that such Lender has made such share available on such date in accordance with paragraph (a) of this Section and may, in reliance upon such assumption, make available to the Borrower a corresponding amount. In such event, if a Lender has not in fact made its share of the applicable Borrowing available to the Administrative Agent, then the applicable Lender and the Borrower severally agree to pay to the Administrative Agent forthwith on demand such corresponding amount with interest thereon, for each day from and including the date such amount is made available to the Borrower to but excluding the date of payment to the Administrative Agent, at (i) in the case of such Lender, the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation or (ii) in the case of the Borrower, the interest rate applicable to ABR Loans. If such Lender pays such amount to the Administrative Agent, then such amount shall constitute such Lender's Loan included in such Borrowing.

        SECTION 2.05. Interest Elections. (a) Each Borrowing initially shall be of the Type specified in the applicable Borrowing Request and, in the case of a Eurodollar Borrowing, shall have an initial Interest Period as specified in such Borrowing Request. Thereafter, the Borrower may elect to convert such Borrowing to a different Type or to continue such Borrowing and, in the case of a Eurodollar Borrowing, may elect Interest Periods therefor, all as provided in this Section. The Borrower may elect different options with respect to different portions of the affected Borrowing, in which case each such portion shall be allocated ratably among the Lenders holding the Loans comprising such Borrowing, and the Loans comprising each such portion shall be considered a separate Borrowing.

        (b) To make an election pursuant to this Section, the Borrower shall notify the Administrative Agent of such election by telephone by the time that a Borrowing Request would be required under Section 2.03 if the Borrower were requesting a Borrowing of the Type resulting from such election to be made on the effective date of such election. Each such telephonic Interest Election Request shall be irrevocable and shall be confirmed promptly by hand delivery or facsimile to the Administrative Agent of a written Interest Election Request in a form approved by the Administrative Agent and signed by the Borrower.

        (c) Each telephonic and written Interest Election Request shall specify the following information in compliance with Section 2.02:

                (i) the Borrowing to which such Interest Election Request applies and, if different options are being elected with respect to different portions thereof, the portions thereof to be allocated to each resulting Borrowing (in which case the information to be specified pursuant to clauses (iii) and (iv) below shall be specified for each resulting Borrowing);

                (ii) the effective date of the election made pursuant to such Interest Election Request, which shall be a Business Day;

                (iii) whether the resulting Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing; and

                (iv) if the resulting Borrowing is a Eurodollar Borrowing, the Interest Period to be applicable thereto after giving effect to such election, which shall be a period contemplated by the definition of the term "Interest Period".

If any such Interest Election Request requests a Eurodollar Borrowing but does not specify an Interest Period, then the Borrower shall be deemed to have selected an Interest Period of one month’s duration.

        (d) Promptly following receipt of an Interest Election Request, the Administrative Agent shall advise each Lender of the details thereof and of such Lender's portion of each resulting Borrowing.

        (e) If the Borrower fails to deliver a timely Interest Election Request with respect to a Eurodollar Borrowing prior to the end of the Interest Period applicable thereto, then, unless such Borrowing is repaid as provided herein, at the end of such Interest Period such Borrowing shall be converted to an ABR Borrowing. Notwithstanding any contrary provision hereof, if an Event of Default has occurred and is continuing and the Administrative Agent, at the request of the Required Lenders, so notifies the Borrower, then, so long as an Event of Default is continuing (i) no outstanding Borrowing may be converted to or continued as a Eurodollar Borrowing and (ii) unless repaid, each Eurodollar Borrowing shall be converted to an ABR Borrowing at the end of the Interest Period applicable thereto.

        SECTION 2.06. Termination, Reduction and Increase of Commitments. (a) Unless previously terminated, the 364-Day Facility Commitments shall terminate on the 364-Day Facility Commitment Termination Date and the Multi-Year Facility Commitments shall terminate on the Multi-Year Facility Commitment Termination Date.

         (b) The Borrower may at any time terminate, or from time to time reduce, each of the 364-Day Facility Commitments and the Multi-Year Facility Commitments; provided that (i) each such reduction shall be in an amount that is an integral multiple of $5,000,000 and not less than $10,000,000 and (ii) the Borrower shall not terminate or reduce (A) the 364-Day Facility Commitments if, after giving effect to any concurrent prepayment of the Loans in accordance with Section 2.08, the aggregate 364-Day Facility Credit Exposures would exceed the total 364-Day Facility Commitments and (B) the Multi-Year Facility Commitments if, after giving effect to any concurrent prepayment of the Loans in accordance with Section 2.08, the aggregate Multi-Year Facility Credit Exposures would exceed the total Multi-Year Facility Commitments.

        (c) The Borrower shall notify the Administrative Agent of any election to terminate or reduce the 364-Day Facility Commitments or the Multi-Year Facility Commitments under paragraph (b) of this Section at least three Business Days prior to the effective date of such termination or reduction, specifying such election and the effective date thereof. Promptly following receipt of any notice, the Administrative Agent shall advise the Lenders of the contents thereof. Each notice delivered by the Borrower pursuant to this Section shall be irrevocable; provided that a notice of termination of the 364-Day Facility Commitments or the Multi-Year Facility Commitments delivered by the Borrower may state that such notice is conditioned upon the effectiveness of other credit facilities, in which case such notice may be revoked by the Borrower (by notice to the Administrative Agent on or prior to the specified effective date) if such condition is not satisfied. Any termination or reduction of the 364-Day Facility Commitments or the Multi-Year Facility Commitments shall be permanent. Each reduction of the 364-Day Facility Commitments shall be made ratably among the Lenders in accordance with their respective 364-Day Facility Commitments. Each reduction of the Multi-Year Facility Commitments shall be made ratably among the Lenders in accordance with their respective Multi-Year Facility Commitments.

         (d) The Borrower may at any time, by notice to the Administrative Agent, propose that the aggregate amount of the 364-Day Facility Commitments and Multi-Year Facility Commitments be increased (a "Commitment Increase"), effective as of a date (such date or such other date as agreed to by the Administrative Agent and the Borrower being the "Commitment Increase Date") that shall be (A) no later than six months after the Effective Date and (B) at least 15 Business Days after the date of such notice; provided that:

                (1) the Borrower may not propose more than two Commitment Increases;

                (2) the minimum proposed Commitment Increase for each Commitment Increase Date shall be $10,000,000;

                (3) in no event shall the aggregate amount of the 364-Day Facility Commitments and the Multi-Year Facility Commitments at any time exceed $400,000,000; and

                (4) no Default shall have occurred and be continuing on such Commitment Increase Date and immediately after giving effect to such Commitment Increase.

        The Administrative Agent shall notify the Lenders promptly upon its receipt of any such notice. It shall be in each Lender’s sole discretion whether to increase its Commitment in connection with a proposed Commitment Increase. No later than 10 Business Days after its receipt of the Borrower’s notice, each Lender that is willing to increase its 364-Day Facility Commitment and Multi-Year Facility Commitment (an “Increasing Lender”) shall deliver to the Administrative Agent a notice, in which such Lender shall set forth the maximum increase in its Commitment to which such Lender is willing to agree, and the Administrative Agent shall promptly provide to the Borrower a copy of such Increasing Lender’s notice. The Borrower may arrange a Commitment Increase through the increase of the Commitments of one or more of the Lenders and/or the addition as Assuming Lenders of third-party lenders acceptable to the Borrower and the Administrative Agent as parties to this Agreement, provided that (i)(A) with respect to each Increasing Lender, the minimum increase in such Lender’s Commitment shall be $5,000,000, and (B) the minimum Commitment of each Assuming Lender that becomes a party to this Agreement pursuant to this Section 2.06(d) shall be $15,000,000, and (ii) any Commitment Increase shall be allocated ratably between the 364-Day Facility Commitments and Multi-Year Facility Commitments (calculated based on the aggregate amount of Commitments and Loans outstanding of a Class as a percentage of the aggregate Commitments and Loans outstanding hereunder). If agreement is reached prior to the Commitment Increase Date with the Increasing Lenders and Assuming Lenders, if any, as to a Commitment Increase (the amount of which may be less than that specified in the applicable notice from the Borrower), the Borrower shall deliver, no later than one day prior to the Commitment Increase Date, a notice to the Administrative Agent (and the Administrative Agent shall give notice thereof to the Lenders (including any Assuming Lenders)).

        On the Commitment Increase Date, the Assuming Lenders, if any, shall become Lenders hereunder as of the Commitment Increase Date and the Commitments of such Increasing Lenders and such Assuming Lenders shall become or be, as the case may be, as of the Commitment Increase Date the amounts specified in the notice delivered by the Borrower to the Administrative Agent; provided that:

        (x) with respect to each Assuming Lender, the Administrative Agent shall have received, on or prior to 9:00 A.M. (New York City time) on the Commitment Increase Date, an appropriate Assumption and Acceptance, duly executed by such Assuming Lender, the Borrower and the Administrative Agent; and

        (y) each Increasing Lender that proposes to increase its Commitment in connection with such Commitment Increase shall have delivered, on or prior to 9:00 A.M. (New York City time) on the Commitment Increase Date, confirmation in writing satisfactory to the Administrative Agent as to its increased Commitment and a copy of such confirmation to the Borrower.

        Upon its receipt of notice from a Lender that it is increasing its Commitment hereunder, the Administrative Agent shall (I) record the information contained therein in the Register and (II) give prompt notice thereof to the Borrower. Upon its receipt of an Assumption and Acceptance executed by an Assuming Lender, the Administrative Agent shall, if such Assumption and Acceptance has been completed, (i) accept such Assumption and Acceptance, (ii) record the information contained therein in the Register and (iii) give prompt notice thereof to the Borrower.

        In the event that the Administrative Agent shall not have received notice from the Borrower as to such agreement on or prior to the Commitment Increase Date or the Borrower shall, by notice to the Administrative Agent prior to the Commitment Increase Date, withdraw such proposal or any of the actions provided for in clauses (x) and (y) above shall not have occurred by the Commitment Increase Date, such proposal by the Borrower shall be deemed not to have been made. In such event, the actions theretofore taken under clauses (x) and (y) above shall be deemed to be of no effect, and all the rights and obligations of the parties shall continue as if no such proposal had been made.

        In the event that the Administrative Agent shall have received notice from the Borrower as to such agreement on or prior to the Commitment Increase Date and the action provided for in clauses (x) and (y) above shall have occurred by 9:00 A.M. (New York City time) on the Commitment Increase Date, the Administrative Agent shall notify the Lenders (including the Assuming Lenders) of the occurrence of the Commitment Increase Date promptly and in any event by 10:00 A.M. (New York City time) on such date by facsimile. Each Increasing Lender and each Assuming Lender shall, before 11:00 A.M. (New York City time) on the Commitment Increase Date, make available for the account of its applicable lending office to the Administrative Agent at its address referred to in Section 8.01, in same day funds, an amount equal to such Increasing Lender’s or Assuming Lender’s ratable portion of the 364-Facility Borrowings and/or Multi-Year Facility Borrowings then outstanding (calculated based on its 364-Day Facility Commitment and Multi-Year Facility Commitment as a percentage of the aggregate 364-Day Facility Commitments and Multi-Year Facility Commitments, respectively, outstanding after giving effect to the relevant Commitment Increase). After the Administrative Agent’s receipt of such funds, the Administrative Agent will promptly thereafter cause to be distributed like funds to the Lenders for the account of their respective applicable lending offices in an amount to each Lender such that the aggregate amount of the outstanding 364-Day Facility Loans and Multi-Year Facility Loans owing to each Lender after giving effect to such distribution equals such Lender’s ratable portion of the 364-Day Facility Loans or Multi-Year Facility Loans then outstanding (calculated based on its 364-Day Facility Commitment and Multi-Year Facility Commitment as a percentage of the aggregate 364-Day Facility Commitments and Multi-Year Facility Commitments, respectively, outstanding after giving effect to the relevant Commitment Increase). If the Commitment Increase Date shall occur on a date that is not the last day of the Interest Period for all Eurodollar Borrowings then outstanding, (a) the Borrower shall pay any amounts owing pursuant to Section 2.13 as a result of the distributions to Lenders under this Section 2.06(d) and (b) for each Loan comprised of Eurodollar Borrowings, the respective Loans made by the Increasing Lenders and the Assuming Lenders pursuant to this Section 2.06(d) shall be ABR Borrowings until the last day of the then existing Interest Period for such Borrowing.

        SECTION 2.07. Repayment of Loans; Evidence of Debt. (a) The Borrower hereby unconditionally promises to pay to the Administrative Agent for the account of each Lender the then unpaid principal amount of (i) each 364-Day Facility Loan on the 364-Day Facility Maturity Date and (ii) each Multi-Year Facility Loan on the Multi-Year Facility Maturity Date.>

        (b) Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to such Lender resulting from each Loan made by such Lender, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder.

         (c) The Administrative Agent shall maintain accounts in which it shall record (i) the amount of each Loan made hereunder, the Class and Type thereof and the Interest Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder and (iii) the amount of any sum received by the Administrative Agent hereunder for the account of the Lenders and each Lender's share thereof.

         (d) The entries made in the accounts maintained pursuant to paragraph (b) or (c) of this Section shall be prima facie evidence of the existence and amounts of the obligations recorded therein; provided that the failure of any Lender or the Administrative Agent to maintain such accounts or any error therein shall not in any manner affect the obligation of the Borrower to repay the Loans in accordance with the terms of this Agreement.

         (e) Any Lender may request that Loans made by it be evidenced by a promissory note. In such event, the Borrower shall prepare, execute and deliver to such Lender a promissory note payable to the order of such Lender (or, if requested by such Lender, to such Lender and its registered assigns) and in a form approved by the Administrative Agent. Thereafter, the Loans evidenced by such promissory note and interest thereon shall at all times (including after assignment pursuant to Section 8.04) be represented by one or more promissory notes in such form payable to the order of the payee named therein (or, if such promissory note is a registered note, to such payee and its registered assigns).

        SECTION 2.08. Prepayment of Loans. (a) The Borrower shall have the right at any time and from time to time to prepay any Borrowing in whole or in part, subject to prior notice in accordance with paragraph (b) of this Section.

         (b) The Borrower shall notify the Administrative Agent by telephone (confirmed by facsimile) of any prepayment hereunder (i) in the case of prepayment of a Eurodollar Borrowing, not later than 11:00 a.m., New York City time, three Business Days before the date of prepayment or (ii) in the case of prepayment of an ABR Borrowing, not later than 11:00 a.m., New York City time, one Business Day before the date of prepayment. Each such notice shall be irrevocable and shall specify the prepayment date and the principal amount of each Borrowing or portion thereof to be prepaid; provided that, if a notice of prepayment is given in connection with a conditional notice of termination of 364-Day Facility Commitments or Multi-Year Facility Commitments as contemplated by Section 2.06, then such notice of prepayment may be revoked if such notice of termination is revoked in accordance with Section 2.06. Promptly following receipt of any such notice relating to a Borrowing, the Administrative Agent shall advise the Lenders of the contents thereof. Each partial prepayment of any Borrowing shall be in an amount that would be permitted in the case of an advance of a Borrowing of the same Type as provided in Section 2.02. Each prepayment of a Borrowing shall be applied ratably to the Loans included in the prepaid Borrowing. Prepayments shall be accompanied by accrued interest to the extent required by Section 2.10.

        SECTION 2.09. Fees. (a) The Borrower agrees to pay to the Administrative Agent for the account of each Lender a facility fee, which shall accrue at the Applicable Rate on the daily amount of the 364-Day Facility Commitment of such Lender (whether used or unused) during the period from and including the Effective Date to but excluding the 364-Day Facility Commitment Termination Date; provided that, if such Lender continues to have any 364-Day Facility Credit Exposure after the 364-Day Facility Commitment Termination Date, then such facility fee shall continue to accrue on the daily amount of such Lender’s 364-Day Facility Credit Exposure from and including the 364-Day Facility Commitment Termination Date to but excluding the date on which such Lender ceases to have any 364-Day Facility Credit Exposure. Accrued facility fees shall be payable in arrears on the last day of March, June, September and December of each year and on the 364-Day Facility Commitment Termination Date, commencing on the first such date to occur after the date hereof; provided that any facility fees accruing after the 364-Day Facility Commitment Termination Date shall be payable on demand. All such facility fees shall be computed on the basis of a year of 360 days and shall be payable for the actual number of days elapsed (including the first day but excluding the last day).

        (b) The Borrower agrees to pay to the Administrative Agent for the account of each Lender a facility fee, which shall accrue at the Applicable Rate on the daily amount of the Multi-Year Facility Commitment of such Lender (whether used or unused) during the period from and including the Effective Date to but excluding the Multi-Year Facility Commitment Termination Date; provided that, if such Lender continues to have any Multi-Year Facility Credit Exposure after the Multi-Year Facility Commitment Termination Date, then such facility fee shall continue to accrue on the daily amount of such Lender's Multi-Year Facility Credit Exposure from and including the Multi-Year Facility Commitment Termination Date to but excluding the date on which such Lender ceases to have any Multi-Year Facility Credit Exposure. Accrued facility fees shall be payable in arrears on the last day of March, June, September and December of each year and on the Multi-Year Facility Commitment Termination Date, commencing on the first such date to occur after the date hereof; provided that any facility fees accruing after the Multi-Year Facility Commitment Termination Date shall be payable on demand. All such facility fees shall be computed on the basis of a year of 360 days and shall be payable for the actual number of days elapsed (including the first day but excluding the last day).

         (c) The Borrower agrees to pay to the Administrative Agent, for its own account, fees payable in the amounts and at the times separately agreed upon between the Borrower and the Administrative Agent.

         (d) All fees payable hereunder shall be paid on the dates due, in immediately available funds, to the Administrative Agent for distribution, in the case of facility fees, to the Lenders. Fees paid shall not be refundable under any circumstances.

        SECTION 2.10. Interest. (a) The Loans comprising each ABR Borrowing shall bear interest at the Alternate Base Rate plus the Applicable Rate.

         (b) The Loans comprising each Eurodollar Borrowing shall bear interest at the Adjusted LIBO Rate for the Interest Period in effect for such Borrowing plus the Applicable Rate.

         (c) Notwithstanding the foregoing, if any principal of or interest on any Loan or any fee or other amount payable by the Borrower hereunder is not paid when due, whether at stated maturity, upon acceleration or otherwise, such overdue amount shall bear interest, after as well as before judgment, at a rate per annum equal to (i) in the case of overdue principal of any Loan, 2% plus the rate otherwise applicable to such Loan as provided in the preceding paragraphs of this Section or (ii) in the case of any other amount, 2% plus the rate applicable to ABR Loans as provided in paragraph (a) of this Section.

         (d) Accrued interest on each Loan shall be payable in arrears on each Interest Payment Date for such Loan and, in the case of 364-Day Facility Loans, upon each of the 364-Day Facility Commitment Termination Date and the 364-Day Facility Maturity Date and, in the case of Multi-Year Facility Loans, upon each of the Multi-Year Facility Commitment Termination Date and the Multi-Year Facility Maturity Date; provided that (i) interest accrued pursuant to paragraph (c) of this Section shall be payable on demand, (ii) in the event of any repayment or prepayment of any Loan (other than a prepayment of an ABR Loan of either Class prior to the end of the Availability Period with respect to such Class), accrued interest on the principal amount repaid or prepaid shall be payable on the date of such repayment or prepayment and (iii) in the event of any conversion of any Eurodollar Loan prior to the end of the current Interest Period therefor, accrued interest on such Loan shall be payable on the effective date of such conversion.

         (e) All interest hereunder shall be computed on the basis of a year of 360 days, except that interest computed by reference to the Alternate Base Rate at times when the Alternate Base Rate is based on the Prime Rate shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and in each case shall be payable for the actual number of days elapsed (including the first day but excluding the last day). The applicable Alternate Base Rate, Adjusted LIBO Rate or LIBO Rate shall be determined by the Administrative Agent, and such determination shall be conclusive absent manifest error.

        SECTION 2.11. Alternate Rate of Interest. If prior to the commencement of any Interest Period for a Eurodollar Borrowing:

        (a) the Administrative Agent determines (which determination shall be conclusive absent manifest error) that adequate and reasonable means do not exist for ascertaining the Adjusted LIBO Rate or the LIBO Rate, as applicable, for such Interest Period; or

        (b) the Administrative Agent is advised by the Required Lenders that the Adjusted LIBO Rate or the LIBO Rate, as applicable, for such Interest Period will not adequately and fairly reflect the cost to such Lenders of making or maintaining their Loans included in such Borrowing for such Interest Period;

then the Administrative Agent shall give notice thereof to the Borrower and the Lenders by telephone or facsimile as promptly as practicable thereafter and, until the Administrative Agent notifies the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist, (i) any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective and (ii) if any Borrowing Request requests a Eurodollar Borrowing, such Borrowing shall be made as an ABR Borrowing; provided that if the circumstances giving rise to such notice affect only one Type of Borrowings, then the other Type of Borrowings shall be permitted.

        SECTION 2.12. Increased Costs. (a) If any Change in Law shall:

                (i) impose, modify or deem applicable any reserve, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender (except any such reserve requirement reflected in the Adjusted LIBO Rate); or

                (ii) impose on any Lender or the London interbank market any other condition affecting this Agreement or Eurodollar Loans made by such Lender;

and the result of any of the foregoing shall be to increase the cost to such Lender of making or maintaining any Eurodollar Loan (or of maintaining its obligation to make any such Loan) or to reduce the amount of any sum received or receivable by such Lender hereunder (whether of principal, interest or otherwise), then the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender for such additional costs incurred or reduction suffered.

         (b) If any Lender reasonably determines that any Change in Law regarding capital requirements has or would have the effect of reducing the rate of return on such Lender's capital or on the capital of such Lender's holding company, if any, as a consequence of this Agreement or the Loans made by such Lender to a level below that which such Lender or such Lender's holding company could have achieved but for such Change in Law (taking into consideration such Lender's policies and the policies of such Lender's holding company with respect to capital adequacy), then from time to time the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender or such Lender's holding company for any such reduction suffered.

         (c) A certificate of a Lender setting forth the amount or amounts (including the basis of the calculation used to determine such amount or amounts) necessary to compensate such Lender or its holding company, as the case may be, as specified in paragraph (a) or (b) of this Section shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within 10 days after receipt thereof.

         (d) Failure or delay on the part of any Lender to demand compensation pursuant to this Section shall not constitute a waiver of such Lender's right to demand such compensation; provided that the Borrower shall not be required to compensate a Lender pursuant to this Section for any increased costs or reductions incurred more than 270 days prior to the date that such Lender notifies the Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender's intention to claim compensation therefor; provided further that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the 270-day period referred to above shall be extended to include the period of retroactive effect thereof.

        SECTION 2.13. Break Funding Payments. In the event of (a) the payment of any principal of any Eurodollar Loan other than on the last day of an Interest Period applicable thereto (including as a result of an Event of Default or as a result of a Commitment Increase pursuant to Section 2.06(d)), (b) the conversion of any Eurodollar Loan other than on the last day of the Interest Period applicable thereto, (c) the failure to borrow, convert, continue or prepay any Eurodollar Loan on the date specified in any notice delivered pursuant hereto (regardless of whether such notice may be revoked under Section 2.08(b) and is revoked in accordance therewith), or (d) the assignment of any Eurodollar Loan other than on the last day of the Interest Period applicable thereto as a result of a request by the Borrower pursuant to Section 2.16, then, in any such event, the Borrower shall compensate each Lender for the loss, cost and expense attributable to such event. In the case of a Eurodollar Loan, such loss, cost or expense to any Lender shall be deemed to include an amount reasonably determined by such Lender to be the excess, if any, of (i) the amount of interest which would have accrued on the principal amount of such Loan had such event not occurred, at the Adjusted LIBO Rate that would have been applicable to such Loan, for the period from the date of such event to the last day of the then current Interest Period therefor (or, in the case of a failure to borrow, convert or continue, for the period that would have been the Interest Period for such Loan), over (ii) the amount of interest which would accrue on such principal amount for such period at the interest rate which such Lender would bid were it to bid, at the commencement of such period, for dollar deposits of a comparable amount and period from other banks in the eurodollar market. A certificate of any Lender setting forth any amount or amounts (including the basis of the calculation used to determine such amount or amounts) that such Lender is entitled to receive pursuant to this Section shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within 10 days after receipt thereof.

        SECTION 2.14. Taxes. (a) Any and all payments by or on account of any obligation of the Borrower hereunder shall be made free and clear of and without deduction for any Indemnified Taxes or Other Taxes; provided that if the Borrower shall be required to deduct any Indemnified Taxes or Other Taxes from such payments, then (i) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section) the Administrative Agent or Lender (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (ii) the Borrower shall make such deductions and (iii) the Borrower shall pay the full amount deducted to the relevant Governmental Authority in accordance with applicable law.

         (b) In addition, the Borrower shall pay any Other Taxes to the relevant Governmental Authority in accordance with applicable law.

         (c) The Borrower shall indemnify the Administrative Agent and each Lender, within 10 days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes paid by the Administrative Agent or such Lender, as the case may be, on or with respect to any payment by or on account of any obligation of the Borrower hereunder (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section) and any penalties, interest and reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender, or by the Administrative Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.

         (d) As soon as practicable after any payment of Indemnified Taxes or Other Taxes by the Borrower to a Governmental Authority, the Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

         (e) Any Foreign Lender that is entitled to an exemption from or reduction of withholding tax under the law of the jurisdiction in which the Borrower is located, or any treaty to which such jurisdiction is a party, with respect to payments under this Agreement shall deliver to the Borrower (with a copy to the Administrative Agent), at the time or times prescribed by applicable law, such properly completed and executed documentation prescribed by applicable law or reasonably requested by the Borrower as will permit such payments to be made without withholding or at a reduced rate.

         (f) If the Administrative Agent or a Lender determines, in its sole discretion, that it has received a refund of any Taxes or Other Taxes as to which it has been indemnified by the Borrower or with respect to which the Borrower has paid additional amounts pursuant to this Section 2.14, it shall promptly pay over such refund to the Borrower (but only to the extent of indemnity payments made, or additional amounts paid, by the Borrower under this Section 2.14 with respect to the Taxes or Other Taxes giving rise to such refund), net of all out-of-pocket expenses of the Administrative Agent or such Lender and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund); provided, that the Borrower, upon the request of the Administrative Agent or such Lender, agrees to repay the amount paid over to the Borrower (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Administrative Agent or such Lender in the event the Administrative Agent or such Lender is required to repay such refund to such Governmental Authority. This Section shall not be construed to require the Administrative Agent or any Lender to make available its tax returns (or any other information relating to its taxes which it deems confidential) to the Borrower or any other Person.

        SECTION 2.15. Payments Generally; Pro Rata Treatment; Sharing of Set-offs. (a) The Borrower shall make each payment required to be made by it hereunder (whether of principal, interest, fees, or of amounts payable under Section 2.12, 2.13 or 2.14, or otherwise) prior to 12:00 noon, New York City time, on the date when due, in immediately available funds, without set-off or counterclaim. Any amounts received after such time on any date may, in the discretion of the Administrative Agent, be deemed to have been received on the next succeeding Business Day for purposes of calculating interest thereon. All such payments shall be made to the Administrative Agent at its offices at 270 Park Avenue, New York, New York. The Administrative Agent shall distribute any such payments received by it for the account of any other Person to the appropriate recipient promptly following receipt thereof. If any payment hereunder shall be due on a day that is not a Business Day, the date for payment shall be extended to the next succeeding Business Day, and, in the case of any payment accruing interest, interest thereon shall be payable for the period of such extension. All payments hereunder shall be made in dollars.

        (b) If at any time insufficient funds are received by and available to the Administrative Agent to pay fully all amounts of principal, interest and fees then due hereunder, such funds shall be applied (i) first, towards payment of interest and fees then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of interest and fees then due to such parties, and (ii) second, towards payment of principal then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of principal then due to such parties.

         (c) If any Lender shall, by exercising any right of set-off or counterclaim or otherwise, obtain payment in respect of any principal of or interest on any of its Loans resulting in such Lender receiving payment of a greater proportion of the aggregate amount of its Loans and accrued interest thereon than the proportion received by any other Lender, then the Lender receiving such greater proportion shall purchase (for cash at face value) participations in the Loans of other Lenders to the extent necessary so that the benefit of all such payments shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and accrued interest on their respective Loans; provided that (i) if any such participations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations shall be rescinded and the purchase price restored to the extent of such recovery, without interest, and (ii) the provisions of this paragraph shall not be construed to apply to any payment made by the Borrower pursuant to and in accordance with the express terms of this Agreement or any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans to any assignee or participant, other than to the Borrower or any Subsidiary or Affiliate thereof (as to which the provisions of this paragraph shall apply). The Borrower consents to the foregoing and agrees, to the extent it may effectively do so under applicable law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against the Borrower rights of set-off and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of the Borrower in the amount of such participation.

         (d) Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Administrative Agent for the account of the Lenders hereunder that the Borrower will not make such payment, the Administrative Agent may assume that the Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Lenders the amount due. In such event, if the Borrower has not in fact made such payment, then each of the Lenders severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Lender with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Administrative Agent, at the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation.

         (e) If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.04(b) or 2.15(d), then the Administrative Agent may, in its discretion (notwithstanding any contrary provision hereof), apply any amounts thereafter received by the Administrative Agent for the account of such Lender to satisfy such Lender's obligations under such Sections until all such unsatisfied obligations are fully paid.

        SECTION 2.16. Mitigation Obligations; Replacement of Lenders. (a) If any Lender requests compensation under Section 2.12, or if the Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.14, then such Lender shall use reasonable efforts to designate a different lending office for funding or booking its Loans hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 2.12 or 2.14, as the case may be, in the future and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. The Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in connection with any such designation or assignment.

        (b) If any Lender requests compensation under Section 2.12, or if the Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.14, or if any Lender defaults in its obligation to fund Loans hereunder, then the Borrower may, at its sole expense and effort, upon notice to such Lender and the Administrative Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject to the restrictions contained in Section 8.04), all its interests, rights and obligations under this Agreement to an assignee that shall assume such obligations (which assignee may be another Lender, if a Lender accepts such assignment); provided that (i) the Borrower shall have received the prior written consent of the Administrative Agent, which consent shall not unreasonably be withheld, (ii) such Lender shall have received payment of an amount equal to the outstanding principal of its Loans, accrued interest thereon, accrued fees and all other amounts payable to it hereunder, from the assignee (to the extent of such outstanding principal and accrued interest and fees) or the Borrower (in the case of all other amounts) and (iii) in the case of any such assignment resulting from a claim for compensation under Section 2.12 or payments required to be made pursuant to Section 2.14, such assignment will result in a reduction in such compensation or payments. A Lender shall not be required to make any such assignment and delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Borrower to require such assignment and delegation cease to apply.

ARTICLE III

Representations and Warranties

        The Borrower represents and warrants to the Lenders that:

        SECTION 3.01. Corporate Existence. Each of the Borrower and its Material Subsidiaries: (a) is a corporation, partnership or other entity duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization; (b) has all requisite corporate power, and has all material Governmental Approvals necessary to own its assets and carry on its business as now being or as proposed to be conducted; and (c) is qualified to do business and is in good standing in all jurisdictions in which the nature of the business conducted by it makes such qualification necessary and where failure to so qualify could have a Material Adverse Effect.

        SECTION 3.02. Financial Condition. The Borrower has heretofore furnished to each of the Lenders the consolidated balance sheet of the Borrower and its consolidated Subsidiaries as at September 30, 2001 and the related consolidated statement of income and retained earnings and cash flow of the Borrower and its consolidated Subsidiaries for the fiscal year ended on said date, with the opinion thereon (in the case of said consolidated balance sheet and statements) of PricewaterhouseCoopers, and the unaudited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as at June 30, 2002 and the related consolidated statement of income, retained earnings and cash flow of the Borrower and its consolidated Subsidiaries for the nine-month period ended on such date. All such financial statements are complete and correct in all material respects and fairly present in all material respects the consolidated financial condition of the Borrower and its consolidated Subsidiaries (subject, in the case of such financial statements as at June 30, 2002, to normal year-end audit adjustments), all in accordance with GAAP and practices applied on a consistent basis. None of the Borrower nor any of its Subsidiaries has on the date hereof any material contingent liabilities, liabilities for taxes, unusual forward or long-term commitments or unrealized or anticipated losses from any unfavorable commitments, except as referred to or reflected or provided for in said balance sheets as at said dates. Since September 30, 2001, there has been no material adverse change in the consolidated financial condition, operations, prospects or business taken as a whole of the Borrower and its Subsidiaries from that set forth in said financial statements as at said date.

        SECTION 3.03. Litigation. Except as set forth in the Borrower’s Annual Report on SEC Form 10-K for the year ended September 30, 2001 or in any document subsequently filed pursuant to Section 13, 14 or 15(d) of the Securities Exchange Act of 1934, there are no legal or arbitral proceedings, or any proceedings by or before any governmental or regulatory authority or agency, now pending to which the Borrower or any Material Subsidiary is a party, or pending or threatened (of which the Borrower has knowledge), in which there is a reasonable possibility of an adverse decision, which could have a Material Adverse Effect.

        SECTION 3.04. No Breach. None of the execution and delivery of this Agreement, the consummation of the Transactions or compliance with the terms and provisions hereof will conflict with or result in a breach of, or require any consent under, the articles of incorporation or by-laws of the Borrower, or any applicable law or regulation, or, to the best knowledge of the Borrower, any order, writ, injunction or decree of any court or governmental or regulatory authority, agency, instrumentality or political subdivision thereof, or any material agreement or instrument to which the Borrower or any of its Subsidiaries is a party or by which any of them or any of their property is bound or to which any of them or any of their property is subject, or constitute a default under any such agreement or instrument.

        SECTION 3.05. Action. The Borrower has all necessary corporate power, authority and legal right to execute, deliver and perform its obligations under this Agreement; the execution, delivery and performance by the Borrower of this Agreement have been duly authorized by all necessary corporate action on its part (including, without limitation, any required shareholder approvals); and this Agreement has been duly and validly executed and delivered by the Borrower and constitutes its legal, valid and binding obligation, enforceable against the Borrower in accordance with its terms, except as such enforceability may be limited by (a) bankruptcy, insolvency, reorganization, moratorium or similar laws of general applicability affecting the enforcement of creditors’ rights and (b) the application of general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

        SECTION 3.06. Approvals. Except as set forth on Schedule 3.06 hereto (which Governmental Approvals and any renewals thereof, have been made or obtained and are in full force and effect) no Governmental Approval and no authorization, approval or consent of, and no filing or registration with, any securities exchange, is necessary for the execution, delivery or performance by the Borrower of this Agreement or for the legality, validity or enforceability hereof.

        SECTION 3.07. Use of Credit. Neither the Borrower nor any of its Subsidiaries shall, directly or indirectly, use any of the proceeds of any extension of credit hereunder for any purpose, whether immediate, incidental, or ultimate, of buying a “margin stock” or of maintaining, reducing or retiring any indebtedness originally incurred to purchase a stock that is currently a “margin stock” and the extension of credit hereunder will not constitute an extension of “purpose credit” that is directly or indirectly secured by “margin stock”, in each case within the meaning of Regulation U of the Board of Governors of the United States Federal Reserve System Board (12 C.F.R. 221, as amended), and will not violate or result in the violation of Regulation U or of Regulation T (12 C.F.R. 220, as amended) or of Regulation X (12 C.F.R. 224, as amended) or any other regulation of such Board.

        SECTION 3.08. ERISA. Neither a “reportable event” (as defined in Section 4043 of ERISA or the regulations issued thereunder with respect to a Plan (other than an event for which the 30-day notice period is waived)) nor an “accumulated funding deficiency” (within the meaning of Section 412 of the Code or Section 302 of ERISA) has occurred during the six-year period prior to the date on which this representation is made or deemed made with respect to any Plan and each Plan has complied in all material respects with the applicable provisions of ERISA and the Code. Neither the Borrower nor any ERISA Affiliate of the Borrower incurred any liability under Title IV of ERISA which could reasonably be expected to result in a Material Adverse Effect, and no Lien in favor of PBGC or a Plan has arisen, during such six-year period. The present value of all accumulated benefit obligations under each Plan which is a Single Employer Plan (as defined in ERISA) (based on the assumptions used for purposes of Statement of Financial Accounting Standards No. 87) did not, as of the last annual valuation date prior to the date on which this representation is made or deemed made, exceed the value of the assets of such Plan allocable to such accumulated benefit obligations by an amount greater than the lesser of (i) $200,000,000, (ii) 20% of the Consolidated Net Worth, or (iii) 10% of the Consolidated Capitalization. Neither the Borrower nor any ERISA Affiliate of the Borrower has made a filing pursuant to Section 412(d) of the Code or Section 303(d) of ERISA of an application for a waiver of the minimum funding standard with respect to any Plan. Neither the Borrower nor any ERISA Affiliate has had a complete or partial withdrawal from any Plan that has resulted or could reasonably be expected to result in a material liability under ERISA and neither the Borrower nor any ERISA Affiliate would become subject to any material liability under ERISA if the Borrower or any such ERISA Affiliate were to withdraw completely from all Multiemployer Plans as of the valuation date most closely preceding the date on which this representation is made or deemed made. No such Multiemployer Plan is insolvent or in reorganization, within the meaning of Title IV of ERISA.

        SECTION 3.09. Taxes. Each of the Borrower and each of its Subsidiaries has filed or caused to be filed all Federal, state and other material tax returns that are required to be filed and has paid all Taxes shown to be due and payable on such returns or on any assessments made against it or any of its property and all other Taxes imposed on it or any of its property by any Governmental Authority (other than any Taxes the amount or validity of which is currently being contested in good faith by appropriate proceeding and with respect to which reserves in conformity with GAAP have been provided on the books of the Borrower or its Subsidiaries, as the case may be); no material Tax Lien has been filed and, to the knowledge of the Borrower, no material claim is being asserted with respect to any such Tax. The Borrower has not given or been requested to give a waiver of the statute of limitations relating to the payment of Federal, state, local and foreign Taxes or other impositions except for (i) the extension of the statute of limitation with respect to the Borrower’s 1998 fiscal year Federal tax return through December 31, 2002, and (ii) any extensions that may be granted with respect to tax audits by the tax authorities of the State of New York and the Commonwealth of Pennsylvania ongoing as of the date hereof.

        SECTION 3.10. Investment Company Act. Neither the Borrower nor any of its Subsidiaries is an “investment company”, or a company “controlled” by an “investment company”, within the meaning of the Investment Company Act of 1940, as amended.

        SECTION 3.11. Public Utility Holding Company Act. The Borrower is a “holding company” registered under the Public Utility Holding Company Act of 1935, as amended (“PUHCA”). No Loan will be made in violation of PUHCA or any rule or regulation thereunder.

        SECTION 3.12. Environmental Matters. As of the date of this Agreement: (i) each of the Borrower and its Subsidiaries has obtained all environmental, health and safety permits, licenses and other authorizations required under all Environmental Laws to carry on its business as now being conducted, except to the extent failure to have any such permit, license or authorization would not have a Material Adverse Effect; and (ii) each of such permits, licenses and authorizations is in full force and effect and, to the knowledge of the Borrower after due inquiry, each of the Borrower and its Subsidiaries is in compliance with the terms and conditions thereof, and is also in compliance with all other limitations, restrictions, conditions, standards, prohibitions, requirements, obligations, schedules and timetables contained in any applicable Environmental Law or in any regulation, code, plan, order, decree, judgment, injunction, notice or demand letter issued, entered, promulgated or approved thereunder, except to the extent failure to comply therewith would not have a Material Adverse Effect.

        SECTION 3.13. Subsidiaries, Etc. The Borrower owns, free and clear of Liens, and has the unencumbered right to vote, all outstanding ownership interests in each of its Material Subsidiaries; and all of the issued and outstanding capital stock of each such Material Subsidiary organized as a corporation is validly issued, fully paid and nonassessable.

        SECTION 3.14. True and Complete Disclosure. The information, reports, financial statements, exhibits and schedules furnished in writing by or on behalf of the Borrower to the Administrative Agent or any Lender in connection with the negotiation, preparation or delivery of this Agreement or included herein or delivered pursuant hereto, when taken as a whole do not contain any untrue statement of material fact or omit to state any material fact necessary to make the statements herein or therein, in light of the circumstances under which they were made, not misleading. All written information furnished after the date hereof by the Borrower and its Subsidiaries to the Administrative Agent and the Lenders in connection with this Agreement and the transactions contemplated hereby will be true, complete and accurate in every material respect, or (in the case of projections) based on reasonable estimates, on the date as of which such information is stated or certified.

ARTICLE IV

Conditions

        SECTION 4.01. Effective Date. The obligations of the Lenders to make Loans hereunder shall not become effective until the date on which each of the following conditions is satisfied (or waived in accordance with Section 8.02):

        (a) The Administrative Agent (or its counsel) shall have received from each party hereto either (i) a counterpart of this Agreement signed on behalf of such party or (ii) written evidence satisfactory to the Administrative Agent (which may include facsimile transmission of a signed signature page of this Agreement) that such party has signed a counterpart of this Agreement.

        (b) The Administrative Agent shall have received an opinion, dated as of the Effective Date, of each of (i) Milbank, Tweed, Hadley & McCloy LLP, special New York counsel to the Administrative Agent, (ii) Thelen, Reid & Priest LLP, special New York counsel to the Borrower, (iii) in-house counsel to the Borrower, and (iv) Stryker, Tams & Dill LLP, special New Jersey counsel to the Borrower.

        (c) The Administrative Agent shall have received such documents and certificates as the Administrative Agent or its counsel may reasonably request relating to the organization, existence and good standing of the Borrower, the authorization of the Transactions and any other legal matters relating to the Borrower, this Agreement or the Transactions, all in form and substance satisfactory to the Administrative Agent and its counsel.

        (d) The Administrative Agent shall have received all fees and other amounts due and payable on or prior to the Effective Date, including, to the extent invoiced, reimbursement or payment of all reasonable fees, charges and disbursements of counsel incurred in connection with the credit facilities provided under this Agreement and any related documentation required to be reimbursed or paid by the Borrower hereunder.

        (e) The Administrative Agent shall have received satisfactory evidence that all Governmental Approvals (including, without limitation, the Governmental Approvals set forth on Schedule 3.06 hereof) and third-party approvals necessary or, in the discretion of the Administrative Agent, advisable in connection with the Transactions, the repayment of the Indebtedness of the Borrower indicated on Schedule 4.01 and the continuing operations of the Borrower and its Subsidiaries have been obtained and are in full force and effect and all applicable waiting periods have expired with respect thereto without any action being taken or threatened by any Governmental Authority or a third party which would restrain, prevent or otherwise impose adverse conditions on the Transaction or the repayment of the Indebtedness of the Borrower indicated on Schedule 4.01.

        (f) The Administrative Agent and the Lenders shall have received the financial statements required to be furnished by the Borrower pursuant to Section 3.02 hereof.

        (g) The Administrative Agent shall have received satisfactory evidence that the principal of and interest on, and all other amounts owing in respect of, the Indebtedness of the Borrower indicated on Schedule 4.01 that is to be repaid shall have been (or shall be simultaneously) paid in full and that any commitments to extend credit under the agreements or instruments relating to such Indebtedness shall have been canceled or terminated.

        (h) The representations and warranties of the Borrower set forth in this Agreement (including, without limitations, the representations and warranties set forth in Section 3.03 and the last sentence of Section 3.02) shall, as of the Effective Date, be true and correct in all material respects and no Default shall have occurred and be continuing.

The Administrative Agent shall notify the Borrower and the Lenders of the Effective Date, and such notice shall be conclusive and binding. Notwithstanding the foregoing, the obligations of the Lenders to make Loans hereunder shall not become effective unless each of the foregoing conditions is satisfied (or waived pursuant to Section 8.02) at or prior to 3:00 p.m., New York City time, on or before September 30, 2002 (and, in the event such conditions are not so satisfied or waived, the Commitments shall terminate at such time).

        SECTION 4.02. Each Credit Event. The obligation of each Lender to make a Loan on the occasion of any Borrowing, is subject to the satisfaction of the following conditions:

         (a) The representations and warranties of the Borrower set forth in this Agreement (including, without limitations, the representations and warranties set forth in Section 3.03 but excluding the representations and warranties set forth in the last sentence of Section 3.02) shall be true and correct in all material respects on and as of the date of such Borrowing.

         (b) At the time of and immediately after giving effect to such Borrowing no Default shall have occurred and be continuing.

Each Borrowing shall be deemed to constitute a representation and warranty by the Borrower on the date thereof as to the matters specified in paragraphs (a) and (b) of this Section.

ARTICLE V

Covenants of the Borrower

        The Borrower covenants and agrees with the Lenders and the Administrative Agent that, so long as any Commitment or Loan is outstanding and until payment in full of all amounts payable by the Borrower hereunder:

        SECTION 5.01. Financial Statements, Etc. The Borrower shall deliver to each of the Lenders:

         (a) as soon as available and in any event within 60 days after the end of each of the first three fiscal quarters of each fiscal year of the Borrower, consolidated statement of income and retained earnings and cash flow of the Borrower and its consolidated Subsidiaries for such period and for the period from the beginning of the respective fiscal year to the end of such period, and the related consolidated balance sheet of the Borrower and its consolidated Subsidiaries as at the end of such period, setting forth in each case in comparative form to the extent required by SEC Form 10-Q the corresponding consolidated figures for the corresponding period in the preceding fiscal year, accompanied by a certificate of a senior Financial Officer of the Borrower, which certificate shall state that said consolidated financial statements fairly present in all material respects the consolidated financial condition and results of operations of the Borrower and its consolidated Subsidiaries in accordance with GAAP, consistently applied, as at the end of, and for, such period (subject to normal year-end audit adjustments);

        (b) as soon as available and in any event within 100 days after the end of each fiscal year of the Borrower, consolidated statements of income, retained earnings and cash flow of the Borrower and its consolidated Subsidiaries for such fiscal year and the related consolidated balance sheets of the Borrower and its consolidated Subsidiaries as at the end of such fiscal year, setting forth in each case in comparative form the corresponding consolidated figures for the preceding fiscal year and accompanied by an opinion thereon of independent certified public accountants of recognized national standing, which opinion shall state that said consolidated financial statements fairly present in all material respects the consolidated financial condition and results of operations of the Borrower and its consolidated Subsidiaries as at the end of, and for, such fiscal year in accordance with GAAP;

        (c) as soon as available and in any event within 130 days after the end of each fiscal year of the Borrower, consolidating statements of income, retained earnings and cash flow of the Borrower and its consolidated Subsidiaries for such fiscal year and the related consolidating balance sheets of the Borrower and its consolidated Subsidiaries as at the end of such fiscal year, all as such are filed with the SEC in Borrower's form U5S.

        (d) promptly upon their becoming publicly available (i) copies of all registration statements and regular periodic reports, if any, which the Borrower shall have filed with the SEC under the Securities Act of 1933, the Securities Exchange Act of 1934 or any national securities exchange, (ii) copies of any forms U1 or U1A which the Borrower shall have filed with the SEC under PUHCA relating to the Borrower's or its Subsidiaries' financing activities and (iii) upon request of the Administrative Agent or any Lender, copies of other forms, statements and reports, if any, which the Borrower shall have filed with the SEC under PUHCA;

        (e) promptly upon the mailing thereof to the shareholders of the Borrower generally, copies of all financial statements, reports and proxy statements so mailed;

        (f) as soon as possible, and in any event within 30 days after the Borrower knows or has reason to believe that one or more of the following events has occurred or exists: (i) the occurrence of a "reportable event", as defined in Section 4043 of ERISA or the regulations issued thereunder with respect to a Plan (other than an event for which the 30-day notice period is waived); (ii) a failure to make any required contribution to a Plan; (iii) the creation of any Lien in favor of the PBGC or a Plan; (iv) any withdrawal from, or the termination, insolvency or reorganization of any Multiemployer Plan, or (v) the institution of proceedings or the taking of any other action by the PBGC or the Borrower, any ERISA Affiliate or any Multiemployer Plan with respect to the withdrawal from, or the termination, reorganization or insolvency of, any Plan;

        (g) promptly after the Borrower knows or has reason to believe that any Default has occurred, a notice of such Default describing the same in reasonable detail and, together with such notice or as soon thereafter as possible, a description of the action that the Borrower has taken or proposes to take with respect thereto;

        (h) promptly prior to the expiration of any material Governmental Approval, a copy of a renewal or extension of such Governmental Approval, in form and substance satisfactory to the Required Lenders; and

        (i) from time to time, such other information regarding the financial condition, operations, business or prospects of the Borrower (including any change in the ratings established by the Rating Agencies with respect to the Index Debt) or any of its Subsidiaries (including, without limitation, any Plan or Multiemployer Plan and any reports or other information required to be filed under ERISA) as any Lender or the Administrative Agent may reasonably request.

        The Borrower will furnish to each Lender, at the time it furnishes each set of financial statements pursuant to paragraph (a) or (b) above, a certificate of a Financial Officer of the Borrower (i) to the effect that no Default has occurred and is continuing (or, if any Default has occurred and is continuing, describing the same in reasonable detail and describing the action that the Borrower has taken or proposes to take with respect thereto), and (ii) setting forth the calculations required to demonstrate that, as of the end of the fiscal quarter most recently ended, the Borrower is in compliance with Section 5.07 of this Agreement.

        SECTION 5.02. Existence, Etc. The Borrower will, and will cause each of its Material Subsidiaries to:

         (a) preserve and maintain its legal existence and all of its material (i) rights, (ii) privileges, (iii) licenses and (iv) franchises (provided that nothing in this Section 5.02 shall prohibit any transaction expressly permitted under Section 5.04 hereof);

        (b) comply with the requirements of all applicable laws, rules, regulations and orders of any Governmental Authority if failure to comply with such requirements could have a Material Adverse Effect;

        (c) pay and discharge all Taxes imposed on it or on its income or profits or on any of its property prior to the date on which penalties attach thereto, except for any such Tax the payment of which is being contested in good faith and by proper proceedings and against which adequate reserves are being maintained;

        (d) maintain all of its properties used or useful in its business in good working order and condition, ordinary wear and tear excepted;

        (e) keep adequate records and books of account, in which complete entries will be made in accordance with GAAP consistently applied; and

        (f) permit representatives of any Lender or the Administrative Agent, during normal business hours, to examine, copy and make extracts from its books and records, to inspect any of its properties, and to discuss its business and affairs with its officers, all to the extent reasonably requested by such Lender or the Administrative Agent (as the case may be).

        SECTION 5.03. Insurance. The Borrower will, and will cause each of its Material Subsidiaries to, keep insured by financially sound and reputable insurers all property of a character usually insured by corporations engaged in the same or similar business similarly situated against loss or damage of the kinds and in the amounts customarily insured against by such corporations and carry such other insurance as is usually carried by such corporations.

        SECTION 5.04. Prohibition of Fundamental Changes. The Borrower will not, nor will it permit any of its Material Subsidiaries to, enter into any transaction of merger or consolidation or amalgamation, or liquidate, wind up or dissolve itself (or suffer any liquidation or dissolution). The Borrower will not, nor will it permit any of its Material Subsidiaries to, without the consent of the Required Lenders (such consent not to be unreasonably withheld), convey, sell, lease, transfer or otherwise dispose of, in one transaction or a series of transactions, all or any material part of its business or property, whether now owned or hereafter acquired. Notwithstanding the foregoing provisions of this Section 5.04:

        (a) any Material Subsidiary of the Borrower may be merged or consolidated with or into: (i) the Borrower, if the Borrower shall be the continuing or surviving corporation or (ii) any other Subsidiary of the Borrower; provided that if any such transaction shall be between a Subsidiary and a Wholly-Owned Subsidiary, the Wholly-Owned Subsidiary shall be the continuing or surviving corporation;         (b) any Material Subsidiary may sell, lease, transfer or otherwise dispose of any or all of its property (upon voluntary liquidation or otherwise) to the Borrower or a Wholly-Owned Subsidiary of the Borrower; and         (c) the Borrower or any Material Subsidiary of the Borrower may merge or consolidate with or into any other Person if (i) in the case of a merger or consolidation of the Borrower, the Borrower is the continuing or surviving corporation and, in any other case, the continuing or surviving corporation is a Wholly-Owned Subsidiary of the Borrower and (ii) after giving effect thereto no Default would exist hereunder.

        SECTION 5.05. Limitation on Liens. The Borrower will not pledge, mortgage, hypothecate, or permit any other Lien upon, any property or assets at any time owned by it, without making effective provision whereby the obligations of the Borrower to pay the principal of and interest on the Loans and all other amounts payable hereunder shall be equally and ratably secured with the obligations secured by such Lien and with any other obligations (collectively, the “Other Obligations”) similarly entitled by their terms to be equally and ratably secured; provided that this restriction shall not apply to or prevent:

        (a) the mortgaging, pledging, or establishing a Lien on, any property to secure Indebtedness of the Borrower as part of the purchase price of such property, or the extension, renewal or refunding of any such mortgage, pledge or Lien, on substantially the same property theretofore subject thereto or on any part thereof;

        (b) the acquisition by the Borrower of any property subject to mortgages, pledges or Liens existing thereon at the time of acquisition (whether or not the obligations secured thereby are assumed by the Borrower), and the extension, renewal or refunding of any such mortgage, pledge or Lien, on substantially the same property theretofore subject thereto or on any part thereof;

        (c) the pledging of its assets or security for the payment of any Tax demanded from the Borrower by any public body so long as the Borrower in good faith is contesting its liability to pay the same, or as security to be deposited with any State Insurance Department or similar public body in order to entitle the Borrower to maintain self insurance under, or participate under any State insurance fund provided for under any legislation designed to insure employees of the Borrower against injury or occupational diseases or for any other purpose at any time required by law or governmental regulation as a condition to the transaction of any business or the exercise of any privilege or license; or

        (d) the pledging by the Borrower of up to 5% of its total assets (as defined under GAAP) for the purpose of securing a stay or discharge in the course of any legal proceeding to which the Borrower is a party;

but in no event shall the mortgage, pledge or Lien permitted by subdivisions (a) and (b) be in excess of 60% of the total purchase price of the property so acquired.

        In case the Borrower shall propose to pledge, mortgage or hypothecate any assets or Property at any time owned by it to secure any Other Obligations, other than as permitted by the preceding paragraph of this Section 5.05, it will prior thereto give notice thereof to the Administrative Agent, and will prior to or simultaneously with such pledge, mortgage or hypothecation, by an agreement, indenture or other instrument to which the Administrative Agent is a party (or to the extent legally necessary, with a trustee), in form and substance reasonably satisfactory to the Administrative Agent, effectively secure the obligations of the Borrower to pay the principal of and interest on the Loans and all other amounts payable hereunder equally and ratably with such Other Obligations by pledge, mortgage or hypothecation of such assets or property. Such agreement, indenture or other instrument shall contain such provisions as the Borrower and the Required Lenders shall deem advisable or appropriate or as the Required Lenders shall reasonably deem necessary in connection with such pledge, mortgage or hypothecation.

        SECTION 5.06. Use of Proceeds. The Borrower will use the proceeds of the Loans hereunder solely (a) to pay its obligations under (i) its commercial paper program, (ii) other short-term credit facilities and (iii) maturing long-term debt obligations and (b) for the general corporate purposes of the Borrower and its Subsidiaries in the ordinary course of business (in compliance with all applicable legal and regulatory requirements); provided that neither the Administrative Agent nor any Lender shall have any responsibility as to the use of any of such proceeds.

        SECTION 5.07. Financial Condition. The Borrower shall not permit the ratio of Consolidated Indebtedness to Consolidated Capitalization as at the last day of any fiscal quarter to exceed the following respective ratios during the following respective periods:

Period                                                            Ratio
From the Effective Date through September 30, 2003            0.650 to 1.0
From October 1, 2003 Through September 30, 2004               0.625 to 1.0
From October 1, 2004 and at all times thereafter              0.600 to 1.0

ARTICLE VI

Events of Default

        If one or more of the following events (herein called “Events of Default”) shall occur and be continuing:

         (a) The Borrower shall: (i) default in the payment of any principal of any Loan when due (whether at stated maturity or at mandatory or optional prepayment); or (ii) default in the payment of any interest on any Loan, any fee or any other amount payable by it hereunder when due and such default shall have continued unremedied for five or more days; or

         (b) The Borrower or any of its Material Subsidiaries shall default in the payment when due of any principal of or interest on any of its other Indebtedness aggregating $20,000,000 or more; or any event specified in any note, agreement, indenture or other document evidencing or relating to any such Indebtedness shall occur if the effect of such event is to cause, or (with the giving of any notice or the lapse of time or both) to permit the holder or holders of such Indebtedness (or a trustee or agent on behalf of such holder or holders) to cause, such Indebtedness to become due, or to be prepaid in full (whether by redemption, purchase, offer to purchase or otherwise), prior to its stated maturity; or

         (c) Any representation, warranty or certification made or deemed made herein (or in any modification or supplement hereto) by the Borrower, or any certificate furnished to any Lender or the Administrative Agent pursuant to the provisions hereof, shall prove to have been false or misleading as of the time made or furnished in any material respect; or

         (d) The Borrower shall default in the performance of any of its obligations under any of Sections 5.01(g), 5.03, 5.04, 5.05 or 5.07 hereof; or the Borrower shall default in the performance of any of its other obligations in this Agreement and such default shall continue unremedied for a period of 30 days after notice thereof to the Borrower by the Administrative Agent or any Lender (through the Administrative Agent); or

         (e) The Borrower or any of its Material Subsidiaries shall admit in writing its inability to, or be generally unable to, pay its debts as such debts become due; or

         (f) The Borrower or any of its Material Subsidiaries shall (i) apply for or consent to the appointment of, or the taking of possession by, a receiver, custodian, trustee, examiner or liquidator of itself or of all or a substantial part of its property, (ii) make a general assignment for the benefit of its creditors, (iii) commence a voluntary case under the Bankruptcy Code, (iv) file a petition seeking to take advantage of any other law relating to bankruptcy, insolvency, reorganization, liquidation, dissolution, arrangement or winding-up, or composition or readjustment of debts, (v) fail to controvert in a timely and appropriate manner, or acquiesce in writing to, any petition filed against it in an involuntary case under the Bankruptcy Code or (vi) take any corporate action for the purpose of effecting any of the foregoing; or

         (g) A proceeding or case shall be commenced, without the application or consent of the Borrower or any of its Material Subsidiaries, in any court of competent jurisdiction, seeking (i) its reorganization, liquidation, dissolution, arrangement or winding-up, or the composition or readjustment of its debts, (ii) the appointment of a receiver, custodian, trustee, examiner, liquidator or the like of the Borrower or such Subsidiary or of all or any substantial part of its property, or (iii) similar relief in respect of the Borrower or such Subsidiary under any law relating to bankruptcy, insolvency, reorganization, winding-up, or composition or adjustment of debts, and such proceeding or case shall continue undismissed, or an order, judgment or decree approving or ordering any of the foregoing shall be entered and continue unstayed and in effect, for a period of 60 or more days; or an order for relief against the Borrower or such Subsidiary shall be entered in an involuntary case under the Bankruptcy Code; or

         (h) A final judgment or judgments for the payment of money in excess of $5,000,000 in the aggregate (exclusive of judgment amounts fully covered by insurance where the insurer has admitted liability in respect of such judgment) or in excess of $10,000,000 in the aggregate (regardless of insurance coverage) shall be rendered by one or more courts, administrative tribunals or other bodies having jurisdiction against the Borrower or any of its Material Subsidiaries and the same shall not be discharged (or provision shall not be made for such discharge), or a stay of execution thereof shall not be procured, within 30 days from the date of entry thereof and the Borrower or the relevant Subsidiary shall not, within said period of 30 days, or such longer period during which execution of the same shall have been stayed, appeal therefrom and cause the execution thereof to be stayed during such appeal; or

         (i) One of the following events shall occur: (i) any Person shall engage in any "prohibited transaction" (as defined in Section 406 of ERISA or Section 4975 of the Code) involving any Plan; (ii) any "accumulated funding deficiency" (as defined in Section 302 of ERISA), whether or not waived, shall exist with respect to any Plan or any Lien in favor of the PBGC or a Plan shall arise on the assets of the Borrower or any ERISA Affiliate; (iii) a "reportable event" (as defined in Section 4043 of ERISA or the regulations issued thereunder (other than an event for which the 30-day notice period is waived)) shall occur with respect to, or proceedings shall commence to have a trustee appointed, or a trustee shall be appointed, to administer or to terminate, any Single Employer Plan (as defined in ERISA) which "reportable event" or commencement of proceedings or appointment of a trustee is, in the reasonable opinion of the Required Lenders, likely to result in the termination of such Plan for purposes of Title IV of ERISA; (iv) any Single Employer Plan (as defined in ERISA) shall terminate for purposes of Title IV of ERISA; (v) the Borrower or any ERISA Affiliate shall, or in the reasonable opinion of the Required Lenders is likely to, incur any liability in connection with a withdrawal from, or the insolvency or reorganization of, a Multiemployer Plan; (vi) the Borrower or any ERISA Affiliate shall make a filing pursuant to Section 412(d) of the Code or Section 303(d) of ERISA of an application for a waiver of the minimum funding standard with respect to any Plan; or (vii) any other event or condition shall occur or exist with respect to a Plan; and, in each case in clauses (i) through (vii) above, such event or condition, together with all other such events or conditions, if any, could, in the sole judgment of Lenders having Credit Exposures and unused Commitments representing at least 66 2/3% of the sum of the total Credit Exposures and unused Commitments at such time reasonably be expected to have a Material Adverse Effect;

                THEREUPON: (1) in the case of an Event of Default other than one referred to in clause (f) or (g) of this Article VI with respect to the Borrower, (A) the Administrative Agent may and, upon request of the Required Lenders, shall, by notice to the Borrower, terminate the Commitments and they shall thereupon terminate, and (B) the Administrative Agent may and, upon request of the Required Lenders, shall, by notice to the Borrower, declare the principal amount then outstanding of, and the accrued interest on, the Loans and all other amounts payable by the Borrower hereunder (including, without limitation, any amounts payable under Section 2.13 hereof) to be forthwith due and payable, whereupon such amounts shall be immediately due and payable without presentment, demand, protest or other formalities of any kind, all of which are hereby expressly waived by the Borrower; and (2) in the case of the occurrence of an Event of Default referred to in clause (f) or (g) of this Article VI with respect to the Borrower, the Commitments shall automatically be terminated and the principal amount then outstanding of, and the accrued interest on, the Loans and all other amounts payable by the Borrower hereunder (including, without limitation, any amounts payable under Section 2.13 hereof) shall automatically become immediately due and payable without presentment, demand, protest or other formalities of any kind, all of which are hereby expressly waived by the Borrower.

ARTICLE VII

The Administrative Agent

        Each of the Lenders hereby irrevocably appoints the Administrative Agent as its agent and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof, together with such actions and powers as are reasonably incidental thereto.

        The bank serving as the Administrative Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not the Administrative Agent, and such bank and its Affiliates may accept deposits from, lend money to and generally engage in any kind of business with the Borrower or any Subsidiary or other Affiliate thereof as if it were not the Administrative Agent hereunder.

        The Administrative Agent shall not have any duties or obligations except those expressly set forth herein. Without limiting the generality of the foregoing, (a) the Administrative Agent shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing, (b) the Administrative Agent shall not have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby that the Administrative Agent is required to exercise in writing as directed by the Required Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 8.02), and (c) except as expressly set forth herein, the Administrative Agent shall not have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Subsidiaries that is communicated to or obtained by the bank serving as Administrative Agent or any of its Affiliates in any capacity. The Administrative Agent shall not be liable for any action taken or not taken by it with the consent or at the request of the Required Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 8.02) or in the absence of its own gross negligence or willful misconduct. The Administrative Agent shall be deemed not to have knowledge of any Default unless and until written notice thereof is given to the Administrative Agent by the Borrower or a Lender, and the Administrative Agent shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement, (ii) the contents of any certificate, report or other document delivered hereunder or in connection herewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement or any other agreement, instrument or document, or (v) the satisfaction of any condition set forth in Article IV or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to the Administrative Agent.

        The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing believed by it to be genuine and to have been signed or sent by the proper Person. The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to be made by the proper Person, and shall not incur any liability for relying thereon. The Administrative Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.

        The Administrative Agent may perform any and all its duties and exercise its rights and powers by or through any one or more sub-agents appointed by the Administrative Agent. The Administrative Agent and any such sub-agent may perform any and all its duties and exercise its rights and powers through their respective Related Parties. The exculpatory provisions of the preceding paragraphs shall apply to any such sub-agent and to the Related Parties of the Administrative Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent.

        Subject to the appointment and acceptance of a successor Administrative Agent as provided in this paragraph, the Administrative Agent may resign at any time by notifying the Lenders and the Borrower. Upon any such resignation, the Required Lenders shall have the right, in consultation with the Borrower, to appoint a successor. If no successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days after the retiring Administrative Agent gives notice of its resignation, then the retiring Administrative Agent may, on behalf of the Lenders, appoint a successor Administrative Agent which shall be a bank with an office in New York, New York, or an Affiliate of any such bank. Upon the acceptance of its appointment as Administrative Agent hereunder by a successor, such successor shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations hereunder. The fees payable by the Borrower to a successor Administrative Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the Administrative Agent’s resignation hereunder, the provisions of this Article and Section 8.03 shall continue in effect for the benefit of such retiring Administrative Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while it was acting as Administrative Agent.

        Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any related agreement or any document furnished hereunder or thereunder.

ARTICLE VIII

Miscellaneous

SECTION 8.01. Notices. (a) Except in the case of notices and other communications expressly permitted to be given by telephone (and subject to paragraph (b) below), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by facsimile, as follows:

                (i) if to the Borrower, to it at 10 Lafayette Square, Suite 1100, Buffalo, New York 14203, Attention of Ronald J. Tanski (Facsimile No. (716) 857-7206);

                (ii) if to the Administrative Agent, to JPMorgan Chase Bank, Loan and Agency Services Group, One Chase Manhattan Plaza, 8th Floor, New York, New York 10081, Attention of Frank Giacalone (Facsimile No. (212) 552-5650), with a copy to JPMorgan Chase Bank, 2300 Main PL Towers, Buffalo, New York 14202, Attention of Alan Boyce (Facsimile No. (716) 843-4939); and

                (iii) if to any other Lender, to it at its address (or facsimile number) set forth in its Administrative Questionnaire.

                (b) Notices and other communications (including, without limitation, financial statements and other documents delivered pursuant to Section 5.01 hereof) to the Lenders hereunder may be delivered or furnished by electronic communications pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices pursuant to Article II unless otherwise agreed by the Administrative Agent and the applicable Lender. The Administrative Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

                 (c) Any party hereto may change its address or facsimile number for notices and other communications hereunder by notice to the other parties hereto. All notices and other communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given on the date of receipt.

        SECTION 8.02. Waivers; Amendments. (a) No failure or delay by the Administrative Agent or any Lender in exercising any right or power hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power. The rights and remedies of the Administrative Agent and the Lenders hereunder are cumulative and are not exclusive of any rights or remedies that they would otherwise have. No waiver of any provision of this Agreement or consent to any departure by the Borrower therefrom shall in any event be effective unless the same shall be permitted by paragraph (b) of this Section, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given. Without limiting the generality of the foregoing, the making of a Loan shall not be construed as a waiver of any Default, regardless of whether the Administrative Agent, any Lender may have had notice or knowledge of such Default at the time.

        (b) Neither this Agreement nor any provision hereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by the Borrower and the Required Lenders or by the Borrower and the Administrative Agent with the consent of the Required Lenders; provided that no such agreement shall (i) increase the 364-Day Facility Commitment or the Multi-Year Facility Commitment of any Lender (including, without limitation, pursuant to Section 2.06(d)) without the written consent of such Lender, (ii) reduce the principal amount of any Loan or reduce the rate of interest thereon, or reduce any fees payable hereunder, without the written consent of each Lender affected thereby, (iii) postpone the scheduled date of payment of the principal amount of any Loan, or any interest thereon, or any fees payable hereunder, or reduce the amount of, waive or excuse any such payment, or postpone the scheduled date of expiration of either of the 364-Day Facility Commitment or Multi-Year Facility Commitment, without the written consent of each Lender affected thereby, (iv) change Section 2.15(b) or (c) in a manner that would alter the pro rata sharing of payments required thereby, without the written consent of each Lender, or (v) change any of the provisions of this Section or the definition of "Required Lenders" or any other provision hereof specifying the number or percentage of Lenders required to waive, amend or modify any rights hereunder or make any determination or grant any consent hereunder, without the written consent of each Lender; provided further that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent hereunder without the prior written consent of the Administrative Agent.

        SECTION 8.03. Expenses; Indemnity; Damage Waiver. (a) The Borrower shall pay (i) all reasonable fees, charges and disbursements of counsel incurred in the course of preparing for the Transactions (including the preparation of this Agreement and any related documentation) (ii) all reasonable out-of-pocket expenses incurred by the Administrative Agent and its Affiliates, including the reasonable fees, charges and disbursements of counsel for the Administrative Agent, in connection with the administration of this Agreement or any amendments, modifications or waivers of the provisions hereof (whether or not the transactions contemplated hereby or thereby shall be consummated) and (iii) all reasonable out-of-pocket expenses incurred by the Administrative Agent or any Lender, including the reasonable fees, charges and disbursements of any counsel for the Administrative Agent or any Lender, in connection with the enforcement or protection of its rights in connection with this Agreement, including its rights under this Section, or in connection with the Loans made hereunder, including all such reasonable out-of-pocket expenses incurred during any workout, restructuring or negotiations in respect of such Loans.

        (b) The Borrower shall indemnify the Administrative Agent and each Lender, and each Related Party of any of the foregoing Persons (each such Person being called an "Indemnitee") against, and hold each Indemnitee harmless from, any and all losses, claims, damages, liabilities and related expenses, including the fees, charges and disbursements of any counsel for any Indemnitee, incurred by or asserted against any Indemnitee arising out of, in connection with, or as a result of (i) the execution or delivery of this Agreement or any agreement or instrument contemplated hereby, the performance by the parties hereto of their respective obligations hereunder or the consummation of the Transactions or any other transactions contemplated hereby, (ii) any Loan or the use of the proceeds therefrom, (iii) any actual or alleged presence or release of Hazardous Materials on or from any property owned or operated by the Borrower or any of its Subsidiaries, or any Environmental Liability related in any way to the Borrower or any of its Subsidiaries, or (iv) any actual or prospective claim, litigation, investigation or proceeding relating to any of the foregoing, whether based on contract, tort or any other theory and regardless of whether any Indemnitee is a party thereto; provided that such indemnity shall not, as to any Indemnitee, be available to the extent that such losses, claims, damages, liabilities or related expenses are determined by a court or other Governmental Authority of competent jurisdiction by final and nonappealable judgment to have resulted from the gross negligence or willful misconduct of such Indemnitee.

         (c) To the extent that the Borrower fails to pay any amount required to be paid by it to the Administrative Agent under paragraph (a) or (b) of this Section, each Lender severally agrees to pay to the Administrative Agent such Lender's Applicable Percentage (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount; provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Administrative Agent in its capacity as such.

        (d) To the extent permitted by applicable law, the Borrower shall not assert, and hereby waives, any claim against any Indemnitee, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement or any agreement or instrument contemplated hereby, the Transactions, any Loan or the use of the proceeds thereof.

         (e) All amounts due under this Section shall be payable promptly after written demand therefor.

        SECTION 8.04. Successors and Assigns. (a) The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that (i) the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section. Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants (to the extent provided in paragraph (c) of this Section) and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

        (b)(i) Subject to the conditions set forth in paragraph (b)(ii) below, any Lender may assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Multi-Year Facility Commitment or 364-Day Facility Commitment and the Loans at the time owing to it) with the prior written consent (such consent not to be unreasonably withheld) of:

                (A) the Borrower, provided that no consent of the Borrower shall be required for an assignment to a Lender, an Affiliate of a Lender, an Approved Fund (as defined below) or, if an Event of Default under clause (f) or (g) of Article VI has occurred and is continuing, any other assignee; and

                 (B) the Administrative Agent, provided that no consent of the Administrative Agent shall be required for an assignment to an assignee that is a Lender immediately prior to giving effect to such assignment.

        (ii) Assignments shall be subject to the following additional conditions:

                (A) except in the case of an assignment to a Lender or an Affiliate of a Lender or an assignment of the entire remaining amount of the assigning Lender's 364-Day Facility Commitment or Multi-Year Facility Commitment, the amount of the 364-Day Facility Commitment or Multi-Year Facility Commitment, as the case may be, of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall not be less than $5,000,000 unless each of the Borrower and the Administrative Agent otherwise consent, provided that no such consent of the Borrower shall be required if an Event of Default under clause (a), (f) or (g) of Article VI has occurred and is continuing;

                (B) each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender's rights and obligations under this Agreement provided that, with respect to 364-Day Facility Loans following the 364-Day Facility Commitment Termination Date, any assigning Lender may assign a proportionate part of all the assigning Lender's rights and obligations in respect of 364-Day Facility Loans;

                (C) the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500;

                (D) the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire; and

                (E) in the case of an assignment to a CLO (as defined below), the assigning Lender shall retain the sole right to approve any amendment, modification or waiver of any provision of this Agreement, provided that the Assignment and Assumption between such Lender and such CLO may provide that such Lender will not, without the consent of such CLO, agree to any amendment, modification or waiver described in the first proviso to Section 8.02(b) that affects such CLO.

        For the purposes of this Section 8.04(b), the terms “Approved Fund” and “CLO” have the following meanings:

        Approved Fund” means (a) a CLO and (b) with respect to any Lender that is a fund which invests in bank loans and similar extensions of credit, any other fund that invests in bank loans and similar extensions of credit and is managed by the same investment advisor as such Lender or by an Affiliate of such investment advisor.

        “CLO” means any entity (whether a corporation, partnership, trust or otherwise) that is engaged in making, purchasing, holding or otherwise investing in bank loans and similar extensions of credit in the ordinary course of its business and is administered or managed by a Lender or an Affiliate of such Lender.

        (iii) Subject to acceptance and recording thereof pursuant to paragraph (b)(iv) of this Section, from and after the effective date specified in each Assignment and Assumption the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender's rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Sections 2.12, 2.13, 2.14 and 8.03). Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 8.04 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with paragraph (c) of this Section.

        (iv) The Administrative Agent, acting for this purpose as an agent of the Borrower, shall maintain at one of its offices a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the 364-Day Facility Commitment and Multi-Year Facility Commitment of, and principal amount of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the "Register"). The entries in the Register shall be conclusive, and the Borrower, the Administrative Agent and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

         (v) Upon its receipt of a duly completed Assignment and Assumption executed by an assigning Lender and an assignee, the assignee's completed Administrative Questionnaire (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in paragraph (b) of this Section and any written consent to such assignment required by paragraph (b) of this Section, the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register. No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this paragraph.

        (c)(i) Any Lender may, without the consent of the Borrower, the Administrative Agent, sell participations to one or more banks or other entities (a "Participant") in all or a portion of such Lender's rights and obligations under this Agreement (including all or a portion of its 364-Day Facility Commitment and/or Multi-Year Facility Commitment and the Loans owing to it); provided that (A) such Lender's obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrower, the Administrative Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender's rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in the first proviso to Section 8.02(b) that affects such Participant. Subject to paragraph (c)(ii) of this Section, the Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.12, 2.13 and 2.14 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to paragraph (b) of this Section. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 8.08 as though it were a Lender, provided such Participant agrees to be subject to Section 2.15(c) as though it were a Lender.

                (ii) A Participant shall not be entitled to receive any greater payment under Section 2.12 or 2.14 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower's prior written consent. A Participant that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of Section 2.14 unless the Borrower is notified of the participation sold to such Participant and such Participant agrees, for the benefit of the Borrower, to comply with Section 2.14(e) as though it were a Lender.

        (d) Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank, and this Section shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

        SECTION 8.05. Survival. All covenants, agreements, representations and warranties made by the Borrower herein and in the certificates or other instruments delivered in connection with or pursuant to this Agreement shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of this Agreement and the making of any Loans, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the Administrative Agent or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as long as the principal of or any accrued interest on any Loan or any fee or any other amount payable under this Agreement is outstanding and unpaid the 364-Day Facility Commitment and the Multi-Year Facility Commitments have not expired or terminated. The provisions of Sections 2.12, 2.13, 2.14 and 8.03 and Article VII shall survive and remain in full force and effect regardless of the consummation of the transactions contemplated hereby, the repayment of the Loans and the 364-Day Facility Commitments and the Multi-Year Facility Commitments or the termination of this Agreement or any provision hereof.

        SECTION 8.06. Counterparts; Integration; Effectiveness. This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. This Agreement and any separate letter agreements with respect to fees payable to the Administrative Agent constitute the entire contract among the parties relating to the subject matter hereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof. Except as provided in Section 4.01, this Agreement shall become effective when it shall have been executed by the Administrative Agent and when the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto, and thereafter shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. Delivery of an executed counterpart of a signature page of this Agreement by facsimile shall be effective as delivery of a manually executed counterpart of this Agreement.

        SECTION 8.07. Severability. Any provision of this Agreement held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

        SECTION 8.08. Right of Setoff. If an Event of Default shall have occurred and be continuing, each Lender and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other obligations at any time owing by such Lender or Affiliate to or for the credit or the account of the Borrower against any of and all the obligations of the Borrower now or hereafter existing under this Agreement held by such Lender, irrespective of whether or not such Lender shall have made any demand under this Agreement and although such obligations may be unmatured. The rights of each Lender under this Section are in addition to other rights and remedies (including other rights of setoff) which such Lender may have.

        SECTION 8.09. Governing Law; Jurisdiction; Consent to Service of Process. (a)  This Agreement shall be construed in accordance with and governed by the law of the State of New York without giving effect to the principles of conflicts of law thereof (other than Section 5-1401 of the New York General Obligations Law).

        (b) The Borrower hereby irrevocably and unconditionally submits, for itself and its property, to the nonexclusive jurisdiction of the Supreme Court of the State of New York sitting in New York County and of the United States District Court of the Southern District of New York, and any appellate court from any thereof, in any action or proceeding arising out of or relating to this Agreement, or for recognition or enforcement of any judgment, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such New York State or, to the extent permitted by law, in such Federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement shall affect any right that the Administrative Agent or any Lender may otherwise have to bring any action or proceeding relating to this Agreement against the Borrower or its properties in the courts of any jurisdiction.

        (c) The Borrower hereby irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection which it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement in any court referred to in paragraph (b) of this Section. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

        (d) Each party to this Agreement irrevocably consents to service of process in the manner provided for notices in Section 8.01. Nothing in this Agreement will affect the right of any party to this Agreement to serve process in any other manner permitted by law.

        SECTION 8.10. WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

        SECTION 8.11. Headings. Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

        SECTION 8.12. Confidentiality. Each of the Administrative Agent and the Lenders agrees to maintain the confidentiality of the Information (as defined below), except that Information may be disclosed (a) to its and its Affiliates’ directors, officers, employees and agents, including accountants, legal counsel and other advisors (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to the extent requested by any regulatory authority, (c) to the extent required by applicable laws or regulations or by any subpoena or similar legal process, (d) to any other party to this Agreement, (e) in connection with the exercise of any remedies hereunder or any suit, action or proceeding relating to this Agreement or the enforcement of rights hereunder, (f) subject to a written agreement containing provisions substantially the same as those of this Section, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement or (ii) any actual or prospective counterparty (or its advisors) to any swap or derivative transaction relating to the Borrower and its obligations, (g) with the consent of the Borrower or (h) to the extent such Information (i) becomes publicly available other than as a result of a breach of this Section or (ii) becomes available to the Administrative Agent or any Lender on a nonconfidential basis from a source other than the Borrower. For the purposes of this Section, “Information” means all information received from the Borrower relating to the Borrower or its business, other than any such information that is available to the Administrative Agent or any Lender on a nonconfidential basis (and otherwise not clearly marked as confidential) prior to disclosure by the Borrower; provided that, in the case of information received from the Borrower after the date hereof, such information is clearly identified at the time of delivery as confidential. Any Person required to maintain the confidentiality of Information as provided in this Section shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Information as such Person would accord to its own confidential information.


S-1

        IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the day and year first above written.

  NATIONAL FUEL GAS COMPANY,
 
  By:  /s/   J. P. Pawlowski
  Name:  J. P. Pawlowski
  Title:  Treasurer

S-2

  JPMORGAN CHASE BANK,
     as Administrative Agent
 
  By:  /s/   Alan E. Boyce
  Name:  Alan E. Boyce
  Title:  Vice President

S-3

  JPMORGAN CHASE BANK,
     as Lender
 
  By:  /s/   Alan E. Boyce
  Name:  Alan E. Boyce
  Title:  Vice President

S-4

  HSBC BANK USA,
     as Lender
 
  By:  /s/   John G. Tierney
  Name:  John G. Tierney
  Title:  Vice President

S-5

  MANUFACTURERS AND TRADERS TRUST COMPANY,
     as Lender
 
  By:  /s/   Susan Freed-Oestreicher
  Name:  Susan Freed-Oestreicher
  Title:  Vice President

S-6

  KEYBANK NATIONAL ASSOCIATION,
     as Lender
 
  By:  /s/   Sherrie I. Manson
  Name:  Sherrie I. Manson
  Title:  Vice President

S-7

  NATIONAL CITY BANK OF PENNSYLVANIA,
     as Lender
 
  By:  /s/   William A. Feldmann
  Name:  William A. Feldmann
  Title:  Vice President

S-8

  THE NORTHERN TRUST COMPANY,
     as Lender
 
  By:  /s/   Russell Rockenbach
  Name:  Russ Rockenbach
  Title:  Vice President

SCHEDULE 2.01

COMMITMENTS

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

Institution                                  364-Day Facility           Multi-Year
                                             Commitment                 Facility
                                                                        Commitment

                                             $22,500,000                $22,500,000
JPMorgan Chase Bank
                                             $22,500,000                $22,500,000
HSBC Bank USA
                                             $22,500,000                $22,500,000
Manufacturers and Traders Trust Company
                                             $17,500,000                $17,500,000
KeyBank National Association
                                             $12,500,000                $12,500,000
National City Bank of Pennsylvania
                                             $12,500,000                $12,500,000
The Northern Trust Company
- ----------------------------------------------------------------------------------------------------





SCHEDULE 3.06

GOVERNMENTAL APPROVALS

1.           SEC Financing Order (SEC Rel. No. 35-26847)

2.           Supplemental SEC Financing Order (SEC Rel. No.35-27170)


SCHEDULE 4.01

REPAID INDEBTEDNESS

  1. Indebtedness of the Borrower under the Credit Agreement dated as of September 23, 1992 among the Borrower, the Chase Manhattan Bank (National Association) as Agent and the Banks party thereto (as amended).

EXHIBIT A

[ASSIGNMENT AND ASSUMPTION]

        Reference is made to the Credit Agreement dated as of September 30, 2002 (as amended and in effect on the date hereof, the “Credit Agreement”), among National Gas Fuel Company, the Lenders named therein and JPMorgan Chase Bank, as Administrative Agent for the Lenders. Terms defined in the Credit Agreement are used herein with the same meanings.

        The Assignor named on the reverse hereof hereby sells and assigns, without recourse, to the Assignee named on the reverse hereof, and the Assignee hereby purchases and assumes, without recourse, from the Assignor, effective as of the Assignment Date set forth on the reverse hereof, the interests set forth on the reverse hereof (the “Assigned Interest”) in the Assignor’s rights and obligations under the Credit Agreement, including, without limitation, the interests set forth on the reverse hereof in the 364-Day Facility Commitment and Multi-Year Facility Commitment of the Assignor on the Assignment Date and 364-Day Facility Loans and Multi-Year Facility Loans owing to the Assignor which are outstanding on the Assignment Date, but excluding accrued interest and fees to and excluding the Assignment Date. The Assignee hereby acknowledges receipt of a copy of the Credit Agreement. From and after the Assignment Date (i) the Assignee shall be a party to and be bound by the provisions of the Credit Agreement and, to the extent of the Assigned Interest, have the rights and obligations of a Lender thereunder and (ii) the Assignor shall, to the extent of the Assigned Interest, relinquish its rights and be released from its obligations under the Credit Agreement.

        This Assignment and Assumption is being delivered to the Administrative Agent together with (i) if the Assignee is a Foreign Lender, any documentation required to be delivered by the Assignee pursuant to Section 2.14(e) of the Credit Agreement, duly completed and executed by the Assignee, and (ii) if the Assignee is not already a Lender under the Credit Agreement, an Administrative Questionnaire in the form supplied by the Administrative Agent, duly completed by the Assignee. The [Assignee/Assignor] shall pay the fee payable to the Administrative Agent pursuant to Section 8.04(b) of the Credit Agreement.

        This Assignment and Assumption shall be governed by and construed in accordance with the laws of the State of New York.

Date of Assignment:

Legal Name of Assignor:

Legal Name of Assignee:

Assignee's Address for Notices:

Effective Date of Assignment
("Assignment Date"):






A-2

- ------------------------------------------- ------------------- -------------------------------------
Facility                                    Principal Amount    Percentage Assigned of
                                            Assigned            Loan/Commitment
                                                                (set forth, to at least 8 decimals,
                                                                as a percentage of the Loan and the
                                                                aggregate Commitments of all
                                                                Lenders thereunder)
- ------------------------------------------- ------------------- -------------------------------------
364-Day Facility Commitment Assigned:       $                                                      %
- ------------------------------------------- ------------------- -------------------------------------
Multi-Year Facility Commitment Assigned:    $                                                      %
- ------------------------------------------- ------------------- -------------------------------------
364-Day Facility Loans:
- ------------------------------------------- ------------------- -------------------------------------
Multi-Year Facility Loans:
- ------------------------------------------- ------------------- -------------------------------------

The terms set forth above and on the reverse side hereof are hereby agreed to:

  [Name of Assignor],
     as Assignor
 
  By:_________________________
      Name:  
      Title:  
 
 
  [Name of Assignee],
     as Assignee
 
  By:_________________________
      Name:  
      Title:  

The undersigned hereby consent to the within assignment:1

National Fuel Gas Company, JPMorgan Chase Bank,
     as Administrative Agent,
 
By:_______________________________By:___________________________
   Name:    Name:
   Title:    Title:

_____________________

1     Consents to be included to the extent required by Section 8.04(b) of the Credit Agreement.


EXHIBIT B

[ASSUMPTION AND ACCEPTANCE]

        Reference is made to the Credit Agreement dated as of September 30, 2002 (as amended and in effect on the date hereof, the “Credit Agreement”), among National Gas Fuel Company, the Lenders named therein and JPMorgan Chase Bank, as Administrative Agent for the Lenders. Terms defined in the Credit Agreement are used herein with the same meanings.

         1.      [INSERT NAME OF ASSUMING LENDER] (the "Assuming Lender") agrees to become a party to the Credit Agreement and to have the rights and perform the obligations of a Lender under the Credit Agreement, and to be bound in all respects by the terms of the Credit Agreement.
 
          2.      The Assuming Lender hereby agrees to a Commitment of [INSERT AMOUNT OF PROPOSED COMMITMENT].
 
          3.      The Assuming Lender (i) agrees that no Lender has made any representation or warranty, or assumes any responsibility with respect to, (x) any statements, warranties or representations made in or in connection with the Credit Agreement or the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Credit Agreement or any other instrument or document furnished pursuant thereto or (y) the financial condition of the Borrower or the performance or observance by the Borrower of any of its obligations under the Credit Agreement or any other instrument or document furnished pursuant thereto; (ii) confirms that it has received a copy of the Credit Agreement, together with copies of the financial statements referred to in Section 4.01(f) thereof and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assumption and Acceptance; (iii) agrees that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Credit Agreement; (iv) appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers and discretion under the Credit Agreement as are delegated to the Administrative Agent by the terms thereof, together with such powers and discretion as are reasonably incidental thereto; and (v) agrees that it will perform in accordance with their terms all of the obligations that by the terms of the Credit Agreement are required to be performed by it as a Lender.
 
         4.      The effective date for this Assumption and Acceptance shall be [______________, ____] (the "Assumption Date"); provided that this Assumption and Acceptance has been fully executed and delivered to the Administrative Agent for acceptance and recording by the Administrative Agent on or prior to such Assumption Date.
 
          5.      Upon such execution, delivery, acceptance and recording and as of the Assumption Date, the Assuming Lender shall be a party to the Credit Agreement with a 364-Day Facility Commitment and Multi-Year Facility Commitment as set forth in


B-2

 paragraph 2 hereof and, to the extent provided in this Assumption and Acceptance, have the rights and obligations of a Lender under the Credit Agreement.
 
          6.      This Assumption and Acceptance shall be governed by and construed in accordance with the law of the State of New York.
 
          7.      This Assumption and Acceptance may be signed in any number of counterparts, each of which shall be an original, with the same as if the signatures were upon the same instrument.


[remainder of page intentionally blank]




B-3

        IN WITNESS WHEREOF, the Assuming Lender has caused Assumption and Acceptance to be executed by its officers thereunto duly authorized as of the date specified above.


  [NAME OF ASSUMING LENDER]
 
  By:_________________________
      Name:  
      Title:  
 
  Domestic Lending Office:
  [Address]
  Eurocurrency Lending Office:
  [Address]

This Assumption and Acceptance is
hereby acknowledged and agreed on
as of the date set forth above.


NATIONAL FUEL GAS COMPANY



By:____________________________
    Name:
    Title:

JPMORGAN CHASE BANK,
    as Administrative Agent


By:_______________________________
    Name:
    Title:

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Exhibit 10.2


SPLIT DOLLAR INSURANCE AGREEMENT



        WHEREAS, National Fuel Gas Company (hereinafter, with any of its subsidiaries, collectively called the “Company”), in recognition of the highly valued services of James A. Beck (hereinafter called the “Executive”), the Executive’s importance to the success of the Company, and the need of Executive’s family for financial security in the event of Executive’s death, has authorized the adoption of a split dollar insurance agreement benefiting the Executive; and

        WHEREAS, the Executive has agreed not to participate in any noncontributory group term life insurance program while employed by the Company; and

        WHEREAS, the Company desires to be reimbursed, upon termination of this Agreement, for the premiums it advances to maintain a life insurance policy or policies for these purposes.

        NOW THEREFORE, for mutual consideration, the receipt and adequacy of which the Company and Executive each acknowledge, the Company and Executive agree as follows:

I.         LIFE INSURANCE

        The Executive is the owner of a life insurance policy, policy number 5028726 (hereinafter, with any additional or replacement policies, called the “Policy”) in the face amount of $1,396,357, issued by the Guardian Life Insurance Company of America, of New York, New York (hereafter called the “Insurer”). The Executive (or the Executive’s Assignee pursuant to Article IX) shall be the sole owner of the Policy and may exercise all rights and incidents of ownership with respect to the Policy, except as specifically provided in this Agreement. To secure the Company’s interest under this Agreement, the Executive has executed a collateral assignment of the Policy to the Company (the “Collateral Assignment”).

II.         PREMIUMS

        The Company shall advance each premium due on the Policy during the term of this Agreement, to the Insurer on or before the due date, extended by any grace period. The Company may elect to offset all or a portion of the premium advances with dividends from the Policy. Notwithstanding the above, after the Executive reaches age 65 or if the Executive’s employment with the Company terminates prior to such age, the Company shall have no further obligation to make premium payments pursuant to this Section II.

III.         BENEFICIARY

        The Executive (or the Executive’s Assignee) may from time to time while this Agreement is in force, by such written notice to the Insurer as the Insurer may require, designate the beneficiary or beneficiaries (the “Beneficiary”) to receive the Death Benefit as provided in this Agreement.

IV.         TERMINATION OF AGREEMENT

       A.        This Agreement shall terminate upon the earliest to occur of the following:

a)   February 9, 2017 (the Executive's 70th birthday), unless the Company and the Executive agree in writing to a later date;
b)  mutual agreement of the Company and the Executive prior to such date;
c)  the Executive's death.

       B.       If the Executive's employment with the Company is terminated for Cause, as hereinafter defined, or if the Executive engages in Competition, as hereinafter defined, with the Company, whether or not the Executive's employment with the Company has been terminated, the Company may terminate this Agreement by written notice to the Executive. In the event of termination under this Subsection B, the Executive shall forfeit all rights under this Agreement and in the Policy.

V.         REPAYMENT TO THE COMPANY

        Upon termination of this Agreement, the Company shall be entitled to repayment of the amount of the total premiums advanced by the Company to maintain the Policy, less the amount of any distributions therefrom to the Company (including any Policy loans to the Company), (the “Net Premiums”). Such repayment may be made in cash or, if this Agreement terminates during the Executive’s lifetime, in the form of a paid-up policy having equivalent value, as the Company may elect. If full repayment is not made within 60 days of termination of this Agreement, the Company may enforce its rights under the Collateral Assignment, including (without limitation) recovery from the Insurer out of the proceeds of the Policy or by surrender thereof. Upon receipt of the Net Premiums, the Company shall promptly release the Collateral Assignment.

VI.         DEATH BENEFIT WHILE AGREEMENT IS IN FORCE

       A.        If this Agreement terminates by reason of the Executive's death, the Beneficiary shall be entitled to receive from the proceeds of the Policy, after repayment of the Net Premiums, an amount (the "Death Benefit") equal to the sum of 24 times the base monthly salary payable by the Company to the Executive in the month preceding the Executive's death (or, if the Executive is retired, in the month prior to the commencement of such retirement) and two times the most recent award, if any, paid to the Executive under any of the Company's lump sum payment programs including the Annual At Risk Compensation Incentive Program (AARCIP). Awards of restricted stock made to the Executive for service in the Company's fiscal year 1996 or later to supplement an AARCIP award for that fiscal year, which was approximately equal to the maximum AARCIP award then permissible consistent with the shareholder approval applicable to that AARCIP award, shall also be included in the calculation of the Executive's Death Benefit at the rate of two times the most recent such award of restricted stock, if any. The restricted stock shall be valued at the average of the high and low market value on the grant date. If the Executive has retired (on disability or otherwise) and becomes reemployed by the Company, the latest date of commencement of retirement shall be used for purposes of computing the Death Benefit. If the proceeds of the Policy after repayment of the Net Premiums are inadequate to pay the Death Benefit in full, the Company shall have no obligation for the shortfall.

       B.       The Company shall notify the Insurer of the amount of the Death Benefit within 30 days of the death of the Executive while this Agreement is in force, and the Death Benefit shall be paid to the Beneficiary under the settlement option elected by the Executive, the Executive's Assignee or the Beneficiary.

       C.        After payment of the Death Benefit, the Company shall be entitled to any remaining balance of the proceeds of the Policy, and neither the Beneficiary nor the Executive's estate shall have any further rights in or under this Agreement or the Policy.

VII.         OTHER COMPANY BENEFITS

        The Executive shall have no right to participate in any non-contributory group-term life insurance plan maintained by the Company. In other respects, the benefits provided to the Executive under this Agreement and the Policy shall be separate from and in addition to other benefits that may be offered by the Company to the Executive, including any non-contributory accidental death and dismemberment coverage that the Company maintains.

VIII.         POLICY LOANS

        While this Agreement is in force, neither the Company, the Executive nor the Executive’s Assignee shall borrow against or pledge the Policy as security for any debt.

IX.         ASSIGNMENT OF THE POLICY AND THIS AGREEMENT

       A.       The Policy may not be assigned, transferred, pledged, surrendered or otherwise encumbered or alienated without the written consent of the Company. Any assignee pursuant to this Section and any other successor to the Executive's interest in the Policy (both referred to herein as the "Assignee") shall be bound by this restriction.

X.         REPLACEMENT OF THE POLICY

        The Company shall have the right to replace the Policy with a new policy or policies, with the Executive's consent.

XI.         AMENDMENT

        This Agreement may be altered, amended or modified only by a written Agreement signed by the Company and the Executive (or, the Executive’s Assignee). This Agreement and any amendments hereto shall be binding upon the Company and the Executive and their legal representatives, successors, beneficiaries and assigns. In the event that the Company becomes a party to any merger, consolidation or reorganization, this Agreement shall remain in full force and effect as an obligation of the Company or its successors in interest.

XII.         DEFINITION OF TERMS

       A.       "Cause" means serious, willful misconduct in respect of the Executive's obligations to the Company that has damaged or is likely to damage the Company, including (without limitation) any endeavor by the Executive, directly or indirectly, to interfere in the business relations of or otherwise harm the Company, as the Company shall reasonably determine.

       B.       "Competition" means any employment, consulting contract or other arrangement, before or after the termination of the Executive's employment with the Company, with any person or entity that is then or becomes engaged in a business enterprise of any sort that is, in any material respect, competitive with the Company, or any assistance by the Executive to any such enterprise in engaging in such competition.

XIII.         NONINTERFERENCE

        The Executive covenants that the Executive, any Assignee and the Beneficiary shall not interfere with the Company’s rights under this Agreement or take any voluntary action that causes the Policy to fail or lapse, in whole or in part. The Executive, any Assignee and the Beneficiary will cooperate with Company and the Insurer in all respects in obtaining and maintaining the Policy and shall, if necessary, use their best efforts to provide, from time to time, such evidence of insurability as the Insurer may require.

XIV.         MISCELLANEOUS

       A.       If any part of this Agreement or the application of any part to certain persons or circumstances shall be invalid or unenforceable, the remainder of the Agreement shall continue to be effective.

       B.       This Agreement shall be construed and regulated under the laws of the State of New York.

       C.       The Executive understands that the benefits provided under this Agreement will or may result in taxable income to him, and the Company reserves the right to implement tax withholding respecting such amounts as and when it may deem such withholding appropriate.

XV.         ERISA PROVISIONS

        This Agreement constitutes part of a welfare benefit plan (“Welfare Plan”) and, as such, the following provisions are part of this Agreement and are intended to meet the requirements of Title I of the Employee Retirement Income Security Act of 1974 (“ERISA”):

        1.     The named fiduciary of the Welfare Plan is the Company.
 
        2.     The funding policies under the Welfare Plan are that the Company remits all premiums on the Policy to the Insurer when due, less any amount paid by the Executive or the Executive's Assignee, in their sole discretion.
 
        3.     Direct payment by the Insurer is the basis of payment of benefits under this Agreement.
 
        4.     For claims procedure purposes with respect to claims asserted under the Welfare Plan, the "Claims Manager" shall be Robert J. Dauer, or such other person as may be designated from time to time by the Company.
 
 a.    If for any reason a claim for benefits is made by a participant under the Welfare Plan ("Claimant") and is denied by the Company, the Claims Manager shall deliver to the Claimant a written explanation specifying the reasons for the denial, the provisions on which such denial is based, such other data as may be pertinent, and the procedures available to the Claimant to obtain review of the claim, all written in a manner calculated to be understood by the Claimant. For this purpose,
 
          (i) the claim shall be deemed filed when presented in writing to the Claims Manager; and
 
          (ii) the Claims Manager's explanation shall be in writing delivered to the Claimant within 90 days of the date the claim is filed.
 
 b.    The Claimant shall have 60 days following receipt of the denial of the claim to file with the Claims Manager a written request for review of the denial. For such review, the Claimant or his or her representative may submit pertinent documents and written issues and comments.
 
 c.    The Claims Manager shall have discretion to decide the issue on review and shall furnish the Claimant with a copy of the decision within 60 days of receiving the Claimant's request for review of the claim. The decision on review shall be written in a manner calculated to be understood by the Claimant and shall specify the reasons for the decision, as well as the provisions on which the decision is based. If a copy of the decision is not so furnished to the Claimant within such 60 days, the claim shall be deemed denied on review.

        IN WITNESS WHEREOF, the parties have executed this Agreement on the dates set opposite their respective signatures, to be effective on the 6th day of March, 2001.

 NATIONAL FUEL GAS COMPANY
 
3/1/01By:     /s/ Philip C. Ackerman
Date           Philip C. Ackerman
/s/ Robert J. Dauer           President
Witness 
 
 EXECUTIVE:
 
3/12/01/s/ James A. Beck
DateJames A. Beck
/s/ Melissa A. Kuebler-Jones 
Witness 
EX-12 6 ex12.htm EXHIBIT 12 Computation of Ratio of Earnings to Fixed Charges
                                                                                                   COMPUTATION OF RATIO OF                                     EXHIBIT 12
                                                                                                  EARNINGS TO FIXED CHARGES
                                                                                                           UNAUDITED

                                                                                                  Fiscal Year Ended September 30
                                                       -----------------------------------------------------------------------------------------------------

                                                               2002                  2001                 2000                 1999              1998
                                                       -----------------------------------------------------------------------------------------------------

EARNINGS:

Income Before Interest Charges and Minority Interest
     in Foreign Subsidiaries (2)                                     222,137              172,060             $226,696             $202,512        $118,085
Allowance for Borrowed Funds Used in Construction                        446                  438                  424                  303             110
Federal Income Tax                                                     8,637               71,625               22,143               44,583          43,626
State Income Tax                                                       1,385               21,330               13,067                6,215           6,635
Deferred Inc. Taxes - Net (3)                                         62,018              (55,844)              41,858               14,030         (26,237)
Investment Tax Credit - Net                                             (702)                (353)              (1,051)                (729)           (663)
Rentals (1)                                                            4,906                4,893                4,561                4,281           4,672
                                                       -----------------------------------------------------------------------------------------------------

                                                                    $298,827             $214,149             $307,698             $271,195        $146,228
                                                       =====================================================================================================

FIXED CHARGES:

Interest & Amortization of Premium and
   Discount of Funded Debt                                           $90,543              $81,851              $67,195              $65,402         $53,154
Interest on Commercial Paper and
   Short-Term Notes Payable                                            6,218               21,733               23,840               17,319          13,605
Other Interest (2)                                                     7,410                2,072                7,495                2,835          16,919
Rentals (1)                                                            4,906                4,893                4,561                4,281           4,672
                                                       -----------------------------------------------------------------------------------------------------

                                                                    $109,077             $110,549             $103,091              $89,837         $88,350
                                                       =====================================================================================================

RATIO OF EARNINGS TO FIXED CHARGES                                      2.74                 1.94                 2.98                 3.02            1.66


Notes:
   (1) Rentals shown above represent the portion of all rentals (other than delay rentals) deemed representative of the interest factor.
   (2) Fiscal 2002, 2001, 2000, 1999 and 1998 reflect the reclassification of $1,927, $1,927, $1,979, 1,927 and $1,839
        representing the loss on reacquired debt amortized during each period, from Other Interest Charges
        to Operation Expense.
   (3) Deferred Income Taxes - Net for fiscal 1998 excludes the cumulative effect of change in accounting.
EX-23 7 ex-23_1.htm CONSENT OF RALPH E. DAVIS Exhibit 23.1

Exhibit 23.1


RALPH E. DAVIS ASSOCIATES, INC.
CONSULTANTS-PETROLEUM AND NATURAL GAS
1717 ST. JAMES PLACE-SUITE 460
HOUSTON, TX 77056
(713) 622-8955

CONSENT OF ENGINEER

                We hereby consent to the reproduction of our audit report for Seneca Resources Corporation dated October 17, 2002, and to the reference to our estimate dated October 1, 2002, appearing in this National Fuel Gas Company Annual Report on Form 10-K.

                We also consent to the incorporation by reference in (i) the Registration Statement (Form S-8, No. 2-94539), as amended, relating to the National Fuel Gas Company 1983 Incentive Stock Option Plan and the National Fuel Gas Company 1984 Stock Plan, and in the related Prospectuses, (ii) the Registration Statements (Form S-8, No. 33-28037, No. 333-3055, and Nos. 2-97641,33-17341 and 333-03057), as amended, relating to the National Fuel Gas Company Tax-Deferred Savings Plan and the National Fuel Gas Company Tax Deferred Savings Plan for Non-Union Employees, respectively, and in the related Prospectuses, (iii) the Registration Statement (Form S-3, No. 333-03803), as amended, relating to $500,000,000 of National Fuel Gas Company debentures and/or medium term notes and, in the related Prospectus, (iv) the Registration Statements (Form S-3, No. 33-51881 and Form S-3D, No. 333-51769), as amended, relating to the National Fuel Gas Company Dividend Reinvestment and Stock Purchase Plan, and in the related Prospectuses, (v) the Registration Statement (Form S-3, No. 33-36868), as amended, relating to the National Fuel Gas Company Customer Stock Purchase Plan, and in the related Prospectus, (vi) the Registration Statement (Form S-8, No. 33-49693), as amended, relating to the National Fuel Gas Company 1993 Award and Option Plan, and in the related Prospectus, and (vii) the Registration Statement (Form S-8, No. 333-51595), relating to the National Fuel Gas Company 1997 Award and Option Plan, and in the related Prospectus, (viii) the Registration Statement (Form S-4, No. 333-74887), as amended, relating to the acquisition of the assets of Cunningham Natural Gas, and in the related Prospectus, (ix) the Registration Statement (Form S-3, No. 333-83497), as amended, relating to $625,000,000 of National Fuel Gas Company debentures and/or common stock, and in the related Prospectus, (x) the Registration Statement (Form S-3,No. 333-85711), relating to the National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan, and in the related Prospectus, of the reproduction of our report dated October 17, 2002, appearing in this National Fuel Gas Company Annual Report on Form 10-K.

  RALPH E. DAVIS ASSOCIATES, INC.
  
  
  Allen C. Barron, P.E.
  President


Houston, Texas
November 7, 2002

EX-23 8 ex-23_2.htm CONSENT OF RALPH E. DAVIS Exhibit 23.2

Exhibit 23.2


RALPH E. DAVIS ASSOCIATES, INC.
CONSULTANTS-PETROLEUM AND NATURAL GAS
1717 ST. JAMES PLACE-SUITE 460
HOUSTON, TX 77056
(713) 622-8955

CONSENT OF ENGINEER

                We hereby consent to the reproduction of our audit report for National Fuel Exploration Corporation dated October 11, 2002, and to the reference to our estimate dated October 1, 2002, appearing in this National Fuel Gas Company Annual Report on Form 10-K.

                We also consent to the incorporation by reference in (i) the Registration Statement (Form S-8, No. 2-94539), as amended, relating to the National Fuel Gas Company 1983 Incentive Stock Option Plan and the National Fuel Gas Company 1984 Stock Plan, and in the related Prospectuses, (ii) the Registration Statements (Form S-8, No. 33-28037, No. 333-3055, and Nos. 2-97641, 33-17341 and 333-03057), as amended, relating to the National Fuel Gas Company Tax-Deferred Savings Plan and the National Fuel Gas Company Tax Deferred Savings Plan for Non-Union Employees, respectively, and in the related Prospectuses, (iii) the Registration Statement (Form S-3, No. 333-03803), as amended, relating to $500,000,000 of National Fuel Gas Company debentures and/or medium term notes and, in the related Prospectus, (IV) the Registration Statements (Form S-3, No. 33-51881 and Form S-3D, No. 333-51769), as amended, relating to the National Fuel Gas Company Dividend Reinvestment and Stock Purchase Plan, and in the related Prospectuses, (v) the Registration Statement (Form S-3, No. 33-36868), as amended, relating to the National Fuel Gas Company Customer Stock Purchase Plan, and in the related Prospectus, (vi) the Registration Statement (Form S-8, No. 3349693), as amended, relating to the National Fuel Gas Company 1993 Award and Option Plan, and in the related Prospectus, and (vii) the Registration Statement (Form S-8, No. 333-51595), relating to the National Fuel Gas Company 1997 Award and Option Plan, and in the related Prospectus, (viii) the Registration Statement (Form S-4, No. 333-74887), as amended, relating to the acquisition of the assets of Cunningham Natural Gas, and in the related Prospectus, (ix) the Registration Statement (Form S-3, No. 333-83497), as amended, relating to $625,000,000 of National Fuel Gas Company debentures and/or common stock, and in the related Prospectus, (x) the Registration Statement (Form S-3, No. 333-8571 1), relating to the National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan, and in the related Prospectus, of the reproduction of our report dated October 11, 2002, appearing in this National Fuel Gas Company Annual Report on Form 10-K.

  RALPH E. DAVIS ASSOCIATES, INC.
  
  
  Allen C. Barron, P.E.
  President


Houston, Texas
November 7, 2002

EX-23 9 ex-23_3.htm CONSENT OF RALPH E. DAVIS Exhibit 23.3

Exhibit 23.3


RALPH E. DAVIS ASSOCIATES, INC.
CONSULTANTS-PETROLEUM AND NATURAL GAS
1717 ST. JAMES PLACE-SUITE 460
HOUSTON, TX 77056
(713) 622-8955

CONSENT OF ENGINEER

                We hereby consent to the reproduction of our audit report for Player Resources Ltd. dated October 17, 2002, and to the reference to our estimate dated October 1, 2002, appearing in this National Fuel Gas Company Annual Report on Form 10-K.

                We also consent to the incorporation by reference in (i) the Registration Statement (Form S-8, No. 2-94539), as amended, relating to the National Fuel Gas Company 1983 Incentive Stock Option Plan and the National Fuel Gas Company 1984 Stock Plan, and in the related Prospectuses, (ii) the Registration Statements (Form S-8, No. 33-28037, No. 333 -3055, and Nos. 2-97641, 33-17341 and 333-03057), as amended, relating to the National Fuel Gas Company Tax-Deferred Savings Plan and the National Fuel Gas Company Tax Deferred Savings Plan for Non-Union Employees, respectively, and in the related Prospectuses, (iii) the Registration Statement (Form S-3, No. 333-03803), as amended, relating to $500,000,000 of National Fuel Gas Company debentures and/or medium term notes and, in the related Prospectus, (iv) the Registration Statements (Form S-3, No. 33-51881 and Form S-3D, No. 333-51769), as amended, relating to the National Fuel Gas Company Dividend Reinvestment and Stock Purchase Plan, and in the related Prospectuses, (v) the Registration Statement (Form S-3, No. 33-36868), as amended, relating to the National Fuel Gas Company Customer Stock Purchase Plan, and in the related Prospectus, (vi) the Registration Statement (Form S-8, No. 33-49693),as amended, relating to the National Fuel Gas Company 1993 Award and Option Plan, and in the related Prospectus, and (vii) the Registration Statement (Form S-8, No. 333-51595), relating to the National Fuel Gas Company 1997 Award and Option Plan, and in the related Prospectus, (viii) the Registration Statement (Form S4, No. 333-74887), as amended, relating to the acquisition of the assets of Cunningham Natural Gas, and in the related Prospectus, (ix) the Registration Statement (Form S-3, No. 333-83497), as amended, relating to $625,000,000 of National Fuel Gas Company debentures and/or common stock, and in the related Prospectus, (x) the Registration Statement (Form S-3, No. 333-85711), relating to the National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan, and in the related Prospectus, of the reproduction of our report dated October 17, 2002, appearing in this National Fuel Gas Company Annual Report on Form 10-K.

  RALPH E. DAVIS ASSOCIATES, INC.
  
  
  Allen C. Barron, P.E.
  President


Houston, Texas
November 7, 2002

EX-23 10 ex-23_4.htm CONSENT OF INDEPENDENT ACCOUNTANTS Exhibit 23.4


Exhibit 23.4


Consent of Independent Accountants


We hereby consent to the incorporation by reference in the Registration Statement on Forms S-3 (Nos. 333-85711, 333-83497, 33-51881, 33-36868, 333-03803 and 333-51769), Forms S-8 (Nos. 2-94539, 33-49693, 333-03057, 333-03055, 333-51595 and 333-55124) and Form S-4 (No. 333-74887) of National Fuel Gas Company of our report dated October 23, 2002 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.




PricewaterhouseCoopers LLP

Buffalo, New York
December 13, 2002

EX-99 11 ex-99_1.htm REPORT OF RALPH E. DAVIS Exhibit 99.1

Exhibit 99.1


RALPH E. DAVIS ASSOCIATES, INC.
CONSULTANTS-PETROLEUM AND NATURAL GAS
1717 ST. JAMES PLACE-SUITE 460
HOUSTON, TX 77056
(713) 622-8955

October 11, 2002

Seneca Resources Corporation
1201 Louisiana, Suite 400
Houston, Texas 77002


Attention: Mr. Don A. Brown
  Vice President

Re:    Oil, Condensate and Natural Gas Reserves,
  Seneca Resources Corporation
  As of October 1, 2002

Gentlemen:

At your request, the firm of Ralph E. Davis Associates, Inc. has audited an evaluation of the proved oil, condensate and natural gas reserves on leaseholds in which Seneca Resources Corporation has certain interests. This report presents a summary of the Proved Developed (producing, nonproducing and shut-in) and Proved Undeveloped reserves anticipated to be produced from Seneca Resources’ interest.

Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil. Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the official temperature and pressure bases of the areas wherein the gas reserves are located.



Consultants to the Petroleum and Natural Gas Industries Since the 1920's



Seneca Resources Corporation RALPH E. DAVIS ASSOCIATES, INC.
Oil, Condensate and Natural Gas Reserves October 11, 2002
Mr. Don A. Brown Page 2




The summarized results of the reserve audit are as follows:


Estimated Proved Reserves
Net to Seneca Resources Corporation
As of October 1, 2002


                                          Proved Developed                       Proved
                                          ----------------                       ------
Division:                   Producing      Non Producing          Shut-In     Undeveloped        Total Proved
- ---------                   ---------      -------------          -------     -----------        ------------

EAST COAST:
Oil/Condensate: MBbls              94.4             0.0              0.0               0.0              94.4
Gas:    MMcf                   78,202.0             0.0             70.5               0.0          78,272.5


GULF COAST:
Oil/Condensate: MBbls           3,925.9         1,185.4              0.0               5.9           5,117.2
Gas:    MMcf                   27,786.1        29,487.7              0.0             590.6          57,864.4


WEST COAST:                    41,355.4           229.0            150.3          25,173.8          66,908.5
Oil/Condensate: MBbls          56,315.3           531.9            439.1          16,030.4          73,316.7
Gas:    MMcf


TOTAL COMPANY:                 45,375.7         1,414.4            150.3          25,179.7          72,120.1
Oil/Condensate: MBbls         162,303.4        30,019.6            509.6          16,621.0         209,453.6
Gas:    MMcf


DISCUSSION:

The scope of this study was to audit the proved reserves attributable to the interests of Seneca Resources Corporation. Reserve estimates were prepared by Seneca using acceptable evaluation principals for each source. The quantities presented herein are estimated reserves of oil, condensate and natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under existing economic conditions with reasonable certainty.



Seneca Resources Corporation RALPH E. DAVIS ASSOCIATES, INC.
Oil, Condensate and Natural Gas Reserves October 11, 2002
Mr. Don A. Brown Page 3



Ralph E. Davis Associates, Inc. has audited the reserve estimates, the data incorporated into preparing the estimates and the methodology used to evaluate the reserves. In each of Seneca's producing divisions all current year additions and those properties of significant value were reviewed by Ralph E. Davis. Reserve estimates of current producing zones, productive zones behind pipe and undrilled well locations were reviewed in detail. Certain changes to either individual reserve estimates or the categorization of reserves were suggested by Ralph E. Davis Associates, Inc. and accepted by Seneca Resources. It is our opinion that the reserves presented herein meet all the criteria of Proved Reserves.

Neither Ralph E. Davis Associates, Inc. nor any of its employees have any significant interest in Seneca Resources Corporation or the properties reported herein. The employment and compensation to make this study are not contingent on our estimate of reserves.

We appreciate the opportunity to be of service to you in this matter, and will be glad to address any questions or inquiries you may have.

 Very truly yours,
  
  RALPH E. DAVIS ASSOCIATES, INC.
  
  
  Allen C. Barron, P.E.
  President


EX-99 12 ex-99_2.htm REPORT OF RALPH E. DAVIS Exhibit 99.2

Exhibit 99.2


RALPH E. DAVIS ASSOCIATES, INC.
CONSULTANTS-PETROLEUM AND NATURAL GAS
1717 ST. JAMES PLACE-SUITE 460
HOUSTON, TX 77056
(713) 622-8955


October 17, 2002

National Fuel Exploration Corp.
550 6th Avenue SW
Suite 1000
Calgary, Alberta T2P 02S


Attention:Mr. Darrell Ibach
 President
Re:    Oil, Condensate and Natural Gas Reserves,
  National Fuel Exploration Corp.
  As of October 1, 2002

Gentlemen:

At your request, the firm of Ralph E. Davis Associates, Inc. has audited an evaluation of the proved oil, condensate and natural gas reserves on leaseholds in which National Fuel Exploration Corp. has certain interests. This report presents a summary of the Proved Developed (producing, nonproducing and shut-in) and Proved Undeveloped reserves anticipated to be produced from National Fuel Exploration’s interest.

Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil. Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the official temperature and pressure bases of the areas wherein the gas reserves are located.



Consultants to the Petroleum and Natural Gas Industries Since the 1920's




National Fuel Exploration Corp.  RALPH E. DAVIS ASSOCIATES, INC.
Oil, Condensate and Natural Gas Reserves October 17, 2002
Mr. Darrell Ibach Page 2


The summarized results of the reserve audit are as follows:



Estimated Proved Reserves
Net to National Fuel Exploration Corp.
As of October 1, 2002


                             Proved Developed
                             ----------------                             Proved
                                Producing           Non Producing         Shut-In       Undeveloped       Total Proved
                                ---------           -------------         -------       -----------       ------------
TOTAL COMPANY:
Oil/Condensate: MBbls              22,907.3                0.0                 0.0           3,497.2         26,404.5
Gas: MMcf                             661.0                0.0                 0.0               0.0            661.0



DISCUSSION:

The scope of this study was to audit the proved reserves attributable to the interests of National Fuel Exploration Corp. Reserve estimates were prepared by National Fuel Exploration using acceptable evaluation principals for each source. The quantities presented herein are estimated reserves of oil, condensate and natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under existing economic conditions with reasonable certainty.

Ralph E. Davis Associates, Inc. has audited the reserve estimates, the data incorporated into preparing the estimates and the methodology used to evaluate the reserves. In each of National Fuel Exploration's producing areas all current year additions and those properties of significant value were reviewed by Ralph E. Davis. Reserve estimates of current producing zones, productive zones behind pipe and undrilled well locations were reviewed in detail. Certain changes to either individual reserve estimates or the categorization of reserves were suggested by Ralph E. Davis Associates, Inc. and accepted by National Fuel Exploration. It is our opinion that the reserves presented herein meet all the criteria of Proved Reserves.

Neither Ralph E. Davis Associates, Inc. nor any of its employees have any significant interest in




National Fuel Exploration Corp.  RALPH E. DAVIS ASSOCIATES, INC.
Oil, Condensate and Natural Gas Reserves October 17, 2002
Mr. Darrell Ibach Page 3



National Fuel Exploration Corp. or Seneca Resources Corporation or the properties reported herein. The employment and compensation to make this study are not contingent on our estimate of reserves.

We appreciate the opportunity to be of service to you in this matter, and will be glad to address any questions or inquiries you may have.

 Very truly yours,
  
  RALPH E. DAVIS ASSOCIATES, INC.
  
  
  Allen C. Barron, P.E.
  President


EX-99 13 ex-99_3.htm REPORT OF RALPH E. DAVIS Exhibit 99.3

Exhibit 99.3


RALPH E. DAVIS ASSOCIATES, INC.
CONSULTANTS-PETROLEUM AND NATURAL GAS
1717 ST. JAMES PLACE-SUITE 460
HOUSTON, TX 77056
(713) 622-8955

October 17, 2002

Player Resources Ltd.
550 6th Avenue SW
Suite 1000
Calgary, Alberta T2P OS2


Attention: Mr. Darrell Ibach
  President
Re:    Oil, Condensate and Natural Gas Reserves,
  Player Resources Ltd.
  As of October 1, 2002

Gentlemen:

At your request, the firm of Ralph E. Davis Associates, Inc. has audited an evaluation of the proved oil, condensate and natural gas reserves on leaseholds in which Player Resources Ltd. has certain interests. This report presents a summary of the Proved Developed (producing, non-producing and shut-in) and Proved Undeveloped reserves anticipated to be produced from Player Resources interest.

Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil. Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the official temperature and pressure bases of the areas wherein the gas reserves are located.



Consultants to the Petroleum and Natural Gas Industries Since the 1920's



Player Resources Ltd. RALPH E. DAVIS ASSOCIATES, INC.
Oil, Condensate and Natural Gas Reserves October 17, 2002
Mr. Darrell Ibach Page 2



The summarized results of the reserve audit are as follows:



Estimated Proved Reserves
Net to Player Resources’ Corporation
As of October 1, 2002



                                 Proved Developed                                 Proved
                                 ----------------
Division:                  Producing,      Non Producing       Shut-In      Undeveloped Total Proved
- ---------                  ---------       -------------       -------      ----------- ------------

TOTAL COMPANY:
Oil/Condensate: MBbls        1,169.4               23.2          0.0               0.0       1,192.6
Gas: MMcf                   36,042.0            2,550.4          0.0           9,513.6      48,106.0



DISCUSSION:

The scope of this study was to audit the proved reserves attributable to the interests of Player Resources Corporation. Reserve estimates were prepared by Player Resources using acceptable evaluation principals for each source, The quantities presented herein are estimated reserves of oil, condensate and natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under existing economic conditions with reasonable certainty.

Ralph E. Davis Associates, Inc. has audited the reserve estimates, the data incorporated into preparing the estimates and the methodology used to evaluate the reserves. In each of Player Resources' producing areas all current year additions and those properties of significant value were reviewed by Ralph E. Davis. Reserve estimates of current producing zones, productive zones behind pipe and undrilled well locations were reviewed in detail. Certain changes to either individual reserve estimates or the categorization of reserves were suggested by Ralph E. Davis Associates, Inc. and accepted by Player Resources. It is our opinion that the reserves presented herein meet all the


Player Resources Ltd. RALPH E. DAVIS ASSOCIATES, INC.
Oil, Condensate and Natural Gas Reserves October 17, 2002
Mr. Darrell Ibach Page 3


criteria of Proved Reserves.

Neither Ralph E. Davis Associates, Inc. nor any of its employees have any significant interest in Player Resources Ltd. or the properties reported herein. The employment and compensation to make this study are not contingent on our estimate of reserves.

We appreciate the opportunity to be of service to you in this matter, and will be glad to address any questions or inquiries you may have.

 Very truly yours,
  
  RALPH E. DAVIS ASSOCIATES, INC.
  
  
  Allen C. Barron, P.E.
  President


EX-99 14 ex99_4.htm EXHIBIT99_4 Statement Pursuant to Section 906 of Sarbanes-Oxley Act of 2002

Exhibit 99.4

NATIONAL FUEL GAS COMPANY

Statement Pursuant to Section 906
of Sarbanes - Oxley Act of 2002

              Each of the undersigned, PHILIP. C. ACKERMAN, the Chairman of the Board, President and Chief Executive Officer, and JOSEPH P. PAWLOWSKI, the Treasurer and Principal Financial Officer of NATIONAL FUEL GAS COMPANY (the "Company"), DOES HEREBY CERTIFY that:

   1.  The  Company's  Annual Report  on  Form  10-K  for  the  year  ended  September 30, 2002 (the
       "Report") fully complies with the requirements of section 13(a) of the Securities Exchange Act of
       1934, as amended; and

   2.  Information contained in the Report fairly presents,  in all material respects,  the financial condition and
       results of operations of the Company.

              IN WITNESS WHEREOF, each of the undersigned has executed this statement this 12th day of December, 2002.

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




                                                                  /s/  Joseph P. Pawlowski
                                                                  Treasurer and Principal Financial Officer
EX-99 15 ex-99_5.htm COMPANY MAPS Exhibit 99.5

Exhibit 99.5


Exploration and Production

Exploration & Production Segment


Timber

Timber Segment


Pipeline and Storage

Pipeline & Storage Segment


International

International Segment


Utility

Utility Segment

Energy Marketing

Energy Marketing Segment
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