UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 þ ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended September 30, 2006
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended September 30, 2004Transition Period from           to          

Commission File Number 1-3880

National Fuel Gas Company
(Exact name of registrant as specified in its charter)
   
New Jersey 13-1086010
(State or other jurisdiction of
incorporation or organization)
 (I.R.S. Employer
Identification No.)
 
6363 Main Street
Williamsville, New York
(Address of principal executive offices)
 14221
(Zip Code)

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


Securities registered pursuant to Section 12(b) of the Act:
   
Name of
Each Exchange
on Which
Title of Each Class
Name of Each Exchange on Which Registered


Common Stock, $1 Par Value, and
Common Stock Purchase Rights
 New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act.  Yes o     No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation 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 thisForm 10-K or any amendment to thisForm 10-K.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” inRule 12b-2 of the Exchange Act.
Large Accelerated Filer þ     Accelerated Filer o     Non-Accelerated Filer o
Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Act).  Yes þo     No oþ

The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $1,997,020,000$2,715,600,700 as of March 31, 2004.

2006.

Common Stock, $1 Par Value, outstanding as of November 30, 2004: 83,178,7172006: 82,385,144 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 17, 200515, 2007 are incorporated by reference into Part III of this report.




Glossary of Terms
Frequently used abbreviations, acronyms, or terms used in this report:
National Fuel Gas Companies
Company The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Data-Track Data-Track Account Services, Inc.
Distribution Corporation National Fuel Gas Distribution Corporation
Empire Empire State Pipeline
ESNE Energy Systems North East, LLC
HighlandHighland Forest Resources, Inc.
HorizonHorizon Energy Development, Inc.
Horizon B.V.Horizon Energy Development B.V.
Horizon LFGHorizon LFG, Inc.
Horizon PowerHorizon Power, Inc.
Leidy HubLeidy Hub, Inc.
Model CityModel City Energy, LLC
National FuelNational Fuel Gas Company
NFRNational Fuel Resources, Inc.
RegistrantNational Fuel Gas Company
SECISeneca Energy Canada Inc.
SenecaSeneca Resources Corporation
Seneca EnergySeneca Energy II, LLC
Supply CorporationNational Fuel Gas Supply Corporation
ToroToro Partners, LP
U.E.United Energy, a.s.
Regulatory Agencies
EPAUnited States Environmental Protection Agency
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
NYPSCState of New York Public Service Commission
PaPUCPennsylvania Public Utility Commission
SECSecurities and Exchange Commission
NTSBNational Transportation Safety Board
Other
APB 18Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock
APB 20Accounting Principles Board Opinion No. 20, Accounting Changes
APB 25Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees
BblBarrel (of oil)
BcfBillion cubic feet (of natural gas)
Bcf (or Mcf) EquivalentThe total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. National Fuel uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.
Board footA measure of lumberand/or timber equal to 12 inches in length by 12 inches in width by one inch in thickness.
BtuBritish thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.
Capital expenditureRepresents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Cashout revenuesA 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.
CTACumulative Foreign Currency Translation Adjustment
Degree dayA measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
DerivativeA financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net, and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.
Development costsCosts incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
Development wellA well drilled to a known producing formation in a previously discovered field.
DthDecatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Energy Policy ActEnergy Policy Act of 2005
Exchange ActSecurities Exchange Act of 1934, as amended
Expenditures for long-lived assetsIncludes capital expenditures, stock acquisitionsand/or investments in partnerships.
Exploration costsCosts incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
Exploratory wellA well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
FINFASB Interpretation Number
FIN 47FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations — an interpretation of SFAS 143.
FIN 48FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of SFAS 109.
Firm transportationand/or storageThe transportationand/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAPAccounting principles generally accepted in the United States of America
GoodwillAn intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
GridThe layout of the electrical transmission system or a synchronized transmission network.
Heavy oilA type of crude petroleum that usually is not economically recoverable in its natural state without being heated or diluted.
HedgingA method of minimizing the impact of price, interest rate,and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
HubLocation where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
Interruptible transportationand/or storageThe transportationand/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LIBORLondon InterBank Offered Rate
LIFOLast-in, first-out
MbblThousand barrels (of oil)
McfThousand cubic feet (of natural gas)
MD&AManagement’s Discussion and Analysis of Financial Condition and Results of Operations
MDthThousand decatherms (of natural gas)
MMcfMillion cubic feet (of natural gas)
MMcfeMillion cubic feet equivalent
NYMEXNew York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Order 636An order issued by FERC entitled “Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission’s Regulations.”
Order667-AAn order issued by FERC to clarify Order 667 entitled “Repeal of the Public Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding Company Act of 2005.”
Precedent AgreementAn agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.
Proved developed reservesReserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reservesReserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive.
PRPPotentially responsible party
PUHCA 1935Public Utility Holding Company Act of 1935
PUHCA 2005Public Utility Holding Company Act of 2005
ReservesThe unproduced but recoverable oiland/or gas in place in a formation which has been proven by production.
RestructuringGenerally referring to partial “deregulation” of the utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundled”) of gas commodity service from transportation service for wholesale and large- volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.
SFASStatement of Financial Accounting Standards
SFAS 3Statement of Financial Accounting Standards No. 3, Reporting Accounting Changes in Interim Financial Statements
SFAS 69Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities
SFAS 71Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation
SFAS 87Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions
SFAS 88Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits
SFAS 106Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions.
SFAS 109Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes
SFAS 123Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation
SFAS 123RStatement of Financial Accounting Standards No. 123R, Share-Based Payment
SFAS 132RStatement of Financial Accounting Standards No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits
SFAS 133Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
SFAS 142Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets
SFAS 143Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations
SFAS 154Statement of Financial Accounting Standards No. 154, Accounting Changes and Error Corrections
SFAS 157Statement of Financial Accounting Standards No. 157, Fair Value Measurements
SFAS 158Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of SFAS 87, 88, 106, and 132R
Spot gas purchasesThe purchase of natural gas on a short-term basis.
Stock acquisitionsInvestments in corporations.
Unbundled serviceA service that has been separated from other services, with rates charged that reflect only the cost of the separated service.
VEBAVoluntary Employees’ Beneficiary Association
WNCWeather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.


For the Fiscal Year Ended September 30, 20042006

CONTENTS
       
Page

    
 BUSINESS 3
   THE COMPANY AND ITS SUBSIDIARIES The Company and its Subsidiaries 3
   RATES AND REGULATION Rates and Regulation 4
   THE UTILITY SEGMENT The Utility Segment 5
   THE PIPELINE AND STORAGE SEGMENT The Pipeline and Storage Segment 5
   THE EXPLORATION AND PRODUCTION SEGMENT The Exploration and Production Segment 6
   THE INTERNATIONAL SEGMENT The Energy Marketing Segment 6
   THE ENERGY MARKETING SEGMENT The Timber Segment 6
   THE TIMBER SEGMENT 6
  ALL OTHER CATEGORY AND CORPORATE OPERATIONSAll Other Category and Corporate Operations 7
   SOURCES AND AVAILABILITY OF RAW MATERIALS Discontinued Operations 7
   COMPETITION 8
Sources and Availability of Raw Materials   SEASONALITY7
 Competition7
Seasonality 9
   CAPITAL EXPENDITURES Capital Expenditures 10
   ENVIRONMENTAL MATTERS Environmental Matters 10
   MISCELLANEOUS Miscellaneous 10
   EXECUTIVE OFFICERS OF THE COMPANY 11
 PROPERTIES10
 RISK FACTORS 12
   GENERAL INFORMATION ON FACILITIESUNRESOLVED STAFF COMMENTS 1217
   EXPLORATION AND PRODUCTION ACTIVITIESPROPERTIES 17
12 General Information on Facilities17
  Exploration and Production Activities18
 LEGAL PROCEEDINGS 1621
 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 1722
 
Part II
 
PART II
MARKET FOR THE REGISTRANT’S COMMON EQUITY, AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 1722
 SELECTED FINANCIAL DATA 1823
 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 1925
 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 5059
 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 5160
 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 100114
 CONTROLS AND PROCEDURES 100114
 OTHER INFORMATION 101114


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ThisThis 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 thisForm 10-K at Itemitem 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A),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 1Business

The Company and its Subsidiaries

National Fuel Gas Company (the Registrant), incorporated in 1902, is 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.Jersey. Except as otherwise indicated below, the Registrant owns directly or indirectly all of the outstanding securities of its subsidiaries. Reference to “the Company” in this report means the Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure. Also, all references to a certain year in this report relate to the Company’s fiscal year ended September 30 of that year unless otherwise noted.

The Company is a diversified energy company consisting of sixfive 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 732,000727,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.

2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation, and Empire State Pipeline (Empire), a New York joint venture between two wholly-owned entitiessubsidiaries of the Company. Supply Corporation provides interstate natural gas transportation and storage services for affiliated and nonaffiliated companies through (i) an integrated gas pipeline system extending from southwestern Pennsylvania to the New York-Canadian border at the Niagara River and eastward to Ellisburg and Leidy, Pennsylvania, and (ii) 28 underground natural gas storage fields owned and operated by Supply Corporation as well as four other underground natural gas storage fields owned and operated jointly with various other interstate gas pipeline companies. Empire, an intrastate pipeline company, transports natural gas for Distribution Corporation and for other utilities, large industrial customers and power producers in New York State. Empire owns a157-mile pipeline that extends from the United States/Canadian border at the Niagara River near Buffalo, New York to near Syracuse, New York. The Company acquired Empire in February 2003.

3. The Exploration and Production segment operations are carried out by Seneca Resources Corporation (Seneca), a Pennsylvania corporation. Seneca is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, and in the Gulf Coast region of Texas, Louisiana, and Alabama.Alabama, including offshore areas in federal waters and some state waters. Also, Exploration and Production operations are conducted in the provinces of Alberta, Saskatchewan and British Columbia in Canada by Seneca Energy Canada Inc. (SECI), formerly Player Resources Ltd. SECI is an Alberta, Canada corporation and a subsidiary of Seneca. At September 30, 2004,2006, the Company had U.S. and Canadian reserves of 65,213 thousand barrels (Mbbl)58,018 Mbbl of oil and 224,784 million cubic feet (MMcf).

     4. The International segment operations are carried out by Horizon Energy Development, Inc. (Horizon), a New York corporation. Horizon engages in foreign and domestic energy projects through investments as a sole or substantial owner in various business entities. These entities include Horizon’s wholly-owned

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subsidiary, Horizon Energy Holdings, Inc., a New York corporation, which owns 100%232,575 MMcf of Horizon Energy Development B.V. (Horizon B.V.). Horizon B.V. is a Dutch company whose principal asset is majority ownership of United Energy, a.s. (UE), a wholesale power and district heating company located in the northern part of the Czech Republic. Horizon B.V. is also pursuing power development projects in other parts of Europe.natural gas.

     5.

4. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation, which markets natural gas to industrial, 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.


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5. The Timber segment operations are carried out by Highland Forest Resources, Inc. (Highland), a New York corporation, and by a division of Seneca known as its Northeast Division. This segment markets timber from its New York and Pennsylvania land holdings, owns two sawmill operations in northwestern Pennsylvania and processes timber consisting primarily of high quality hardwoods. At September 30, 2004,2006, the Company owned and managed approximately 87,000100,000 acres of timber property.

property and managed an additional 4,000 acres of timber rights.

Financial information about each of the Company’s business segments can be found in Item 7, MD&A and also in Item 8 at Note HJ — Business Segment Information.

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

• Horizon Energy Development, Inc. (Horizon), a New York corporation formed to engage in foreign and domestic energy projects through investments as a sole or substantial owner in various business entities. These entities include Horizon’s wholly-owned subsidiary, Horizon Energy Holdings, Inc., a New York corporation, which owns 100% of Horizon Energy Development B.V. (Horizon B.V.). Horizon B.V. is a Dutch company that is in the process of winding up or selling certain power development projects in Europe;
 • Horizon LFG, Inc. (Horizon LFG), a New York corporation engaged through subsidiaries in the purchase, sale and transportation of landfill gas in Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Horizon LFG and one of its wholly owned subsidiaries own all of the partnership interests in Toro Partners, LP (Toro), a limited partnership which owns and operates short-distance landfill gas pipeline companies. Further information can be foundThe Company acquired Toro in Item 8 at Note J — Acquisitions;June 2003;
 
 • Leidy Hub, Inc. (Leidy)(Leidy Hub), a New York corporation formed to provide various natural gas hub services to customers in the eastern United States;
 
 • Data-Track Account Services, Inc. (Data-Track), a New York corporation which providesformed to provide collection services principally for the Company’s subsidiaries; and
 
 • Horizon Power, Inc. (Horizon Power), a New York corporation which is designated as an “exempt wholesale generator” under the Holding Company ActPUHCA 2005 and is developing or operating mid-range independent power production facilities and landfill gas electric generation facilities.facilities; and
• Empire Pipeline, Inc., a New York corporation formed in 2005 to be the surviving corporation of a planned future merger with Empire, which is expected to occur after construction of the Empire Connector project (described below under the heading “Rates and Regulation” and under Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters”).*

No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 2004.

2006.

Rates and Regulation

The Registrant is a holding company as defined under PUHCA 2005. PUHCA 2005 repealed PUHCA 1935, to which the Company iswas formerly subject, and granted the FERC and state public utility commissions access to regulation bycertain books and records of companies in holding company systems. Pursuant to the SecuritiesFERC’s regulations under PUHCA 2005, the Company and Exchange Commission (SEC)its subsidiaries are exempt from the FERC’s books and records regulations under the broad regulatory provisions of the Holding Company Act, including provisions relating to issuance of securities, sales and acquisitions of securities and utility assets, intra-company transactions and limitations on diversification. In 2003, both houses of Congress passed comprehensive energy bills that included repeal of the Holding Company Act, but since November 2003 have been unable to reconcile their differences and pass any comprehensive energy legislation. The Company is unable to predict at this time what the ultimate outcome of legislative or regulatory changes will be and, therefore, whether the Holding Company Act will be repealed and what impact the repeal of the Holding Company Act might have on the Company.*

PUHCA 2005.

The Utility segment’s rates, services and other matters are regulated by the State of New York Public Service Commission (NYPSC)NYPSC with respect to services provided within New York and by the Pennsylvania Public Utility Commission (PaPUC)PaPUC with respect to services provided within Pennsylvania. For additional discussion of the Utility segment’s rates and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 atNote B-RegulatoryC-Regulatory Matters.

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The Pipeline and Storage segment’s rates, services and other matters are currently regulated by the FERC with respect to Supply Corporation are regulated by the Federal Energy Regulatory Commission (FERC) and by the NYPSC with respect to Empire. On October 11, 2005, Empire


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filed an application with the FERC for the authority to build and operate an extension of its natural gas pipeline (the Empire Connector). If the FERC grants that application and the Company builds and commences operations of the Empire Connector, Empire will at that time become a FERC-regulated pipeline company.* For additional discussion of the Pipeline and Storage segment’s rates and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 atNote B-RegulatoryC-Regulatory Matters.

For further discussion of the Empire Connector project, refer to Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters.”

The discussion under Item 8 atNote B-RegulatoryC-Regulatory Matters includes a description of the regulatory assets and liabilities reflected on the Company’s Consolidated Balance Sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company’s Consolidated Balance Sheets and such accounting treatment would be discontinued.

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

In addition, the Company and its subsidiaries are subject to the same federal, state and local (including foreign) regulations on various subjects, including environmental matters, to which other companies doing similar business in the same locations are subject.

The Utility Segment

The Utility segment contributed approximately 28.0%36.1% of the Company’s 20042006 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”“Competition: The Utility Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

The Pipeline and Storage Segment

The Pipeline and Storage segment contributed approximately 28.6%40.3% of the Company’s 20042006 net income available for common stock.

Supply Corporation has service agreements for all of its firm storage capacity, which totals approximately 68,728 thousand dekatherms (MDth).68,408 MDth. The Utility segment has contracted for 27,865 MDth or 40.6%40.7% of the total firm storage capacity, and the Energy Marketing segment accounts for another 3,8683,888 MDth or 5.6%5.7% of the total firm storage capacity. Nonaffiliated customers have contracted for the remaining 36,99536,655 MDth or 53.8%53.6% of the total firm storage capacity. Following an industry trend, most of Supply Corporation’s storage and transportation services are performed under contracts that allow Supply Corporation or the shipper to terminate the contract upon six or twelve months’ notice effective at the end of the contract term, and from timeterm. The contracts also typically include “evergreen” language designed to time thereafter.allow the contracts to extendyear-to-year at the end of the primary term. At the beginning of 2005, approximately 88%2007, 95.9% of Supply Corporation’s total firm storage capacity (including the 40.6% contracted for by affiliated shippers) was committed under contracts that, subject to 2006 shipper or Supply Corporation notifications, could have expired or been terminated before the end of 2005. Based on contract expirations and termination notifications received before the deadline for termination effective within 2005, contracts representing approximately 3.3% of Supply Corporation’s firm storage capacity will be terminated during 2005.*in 2007. Supply Corporation has been successfulneither issued nor received any contract termination notices in marketing2006, however, so it does not expect any storage contract terminations effective in 2007.* In 2006, the increased value of market-area storage afforded Supply Corporation the opportunity to eliminate a significant number of monetary rate discounts and obtaining executed contracts for storage service (at discounted rates) as it becomes available and expects to continue to do so.*

sign certain multi-year primary term extensions.

Supply Corporation’s firm transportation capacity is not a fixed quantity, due to the diverse weblike nature of its pipeline system, and is subject to change as the market identifies different transportation paths and receipt/delivery point combinations are identified with the market.combinations. Supply Corporation currently has firm transportation service agreements for approximately 2,2321,995 MDth per day (contracted transportation capacity). The Utility segment accounts for approximately 1,1221,092 MDth per day or 50.3%54.7% of contracted transportation capacity, and the Energy Marketing segment represents another 7899 MDth per day or 3.5%5.0% of contracted transportation capacity. The remaining 1,032804 MDth or 46.2%40.3% of contracted transportation capacity areis subject to firm contracts with nonaffiliated customers.


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At the beginning of 2005, 47%2007, 56.9% of Supply Corporation’s contracted transportation capacity was committed under affiliate contracts that were scheduled to expire in 2007 or, subject to 2006 shipper or Supply Corporation notifications, could have expired or been terminated effective before the end of 2005.in 2007. Based on contract expirations and termination notices received before the deadlinein 2006 for 2007 termination, effective within 2005, affiliate contracts representing only 0.3%and taking into account any known contract additions, contracted transportation capacity with affiliates is expected to decrease 0.8% in 2007.* Similarly, 28.4% of contracted capacity will actually expire or be terminated effective during 2005. Similarly, 28% of contractedtransportation capacity was committed under unaffiliated shipper contracts that were scheduled to expire in 2007 or, subject to 2006 shipper or Supply Corporation notifications, could expire or behave been terminated effective before the end of 2005.in 2007. Based on contract expirations and termination notices received before the deadlinein 2006 for 2007 termination, within 2005,and taking into account any known contract additions, contracted transportation capacity with unaffiliated contracts representing 11% of contracted capacity will actually expire or be terminated effective during 2005.shippers is expected to decrease 2.4% in 2007.* Supply Corporation previously has been successful in marketing and obtaining executed contracts for suchavailable transportation service previouslycapacity (at discounted rates when necessary), and expects its success to continue to do so.continue.*

Empire has service agreements for the 2004-20052006-2007 winter period for all of its firm transportation capacity, which totals approximately 562575 MDth per day. Empire provides service under both annual (12 months per year) and seasonal (winter or summer only) contracts. Approximately 74%88.7% of Empire’s firm transportationcontracted capacity is contracted on aan annual long-term basis. NoneAnnual long-term agreements representing 0.5% of these transportationEmpire’s firm contracted capacity expire in 2007. Approximately 3.4% of Empire’s firm contracted capacity is under multi-year seasonal contracts, could be terminatednone of which expire in 2007. The remaining capacity, which represents 7.9% of Empire’s firm contracted capacity, is under single season or annual contracts which will expire in 2005 before the end of 2007. Empire expects that all of this expiring capacity will be re-contracted under seasonaland/or 2006. annual arrangements for future contracting periods.* The Utility segment accounts for approximately 60 MDth per day or 10.7%8.6% of Empire’s totalfirm contracted capacity, and the Energy Marketing segment accounts for approximately 10 MDth per day or 1.8%1.7% of Empire’s totalfirm contracted capacity, with the remaining 87.5%89.7% of Empire’s firm contracted transportation capacity subject to firm contracts with nonaffiliated customers. Approximately 14% of Empire’s total capacity (including 5% of its total capacity contracted with affiliated shippers) is currently contracted under seasonal or annual contracts which will expire effective before the end of 2005.* Empire expects that all of this capacity will be re-contracted under seasonal and/or annual arrangements for future contracting periods.*

Additional discussion of the Pipeline and Storage segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition”“Competition: The Pipeline and Storage Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

The Exploration and Production Segment

The Exploration and Production segment contributed approximately 32.6%15.2% of the Company’s 20042006 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,“Competition: The Exploration and Production Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

The InternationalEnergy Marketing Segment

The InternationalEnergy Marketing segment contributed approximately 3.6%4.2% of the Company’s 20042006 net income available for common stock.

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

The Energy Marketing Segment

     The Energy Marketing segment contributed approximately 3.3% of the Company’s 2004 net income available for common stock.

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

The Timber Segment

The Timber segment contributed approximately 3.4%4.1% of the Company’s 20042006 net income available for common stock.

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


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All Other Category and Corporate Operations

The All Other category and Corporate operations contributed approximately 0.5%less than 1% of the Company’s 20042006 net income available for common stock.

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

Discontinued Operations
In July 2005, Horizon B.V. sold its entire 85.16% interest in United Energy, a.s. (U.E.), a district heating and electric generation business in the Czech Republic. United Energy’s operations are presented in the Company’s financial statements as discontinued operations.
Additional discussion of the Company’s discontinued operations appears in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
Sources and Availability of Raw Materials

Natural gas is the principal raw material for the Utility segment. In 2004,2006, the Utility segment purchased 105 billion cubic feet (Bcf)74.5 Bcf of gas of which 85 Bcf servedfor core market demand and 17 Bcf was used for off-system sales. The remaining 3 Bcf represents gas used in operations offset by storage withdrawals.demand. Gas purchased from producers and suppliers in the southwestern United States and Canada under firm contracts (seasonal and longer) accounted for 71%82% of the core marketthese purchases. Purchases of gas on the spot market (contracts for one month or less) accounted for the remaining 29%18% of the Utility segment’s 2004 core market2006 purchases. Purchases from Conoco Phillips CompanyChevron Natural Gas (16%), Cinergy MarketingConocoPhillips Company (15%), Total Gas & Trading, L.P. (13%), BP Energy CompanyPower North America Inc. (11%), Occidental Energy Marketing, Inc. (10%) and Anadarko Energy Services Company (9%(11%) accounted for 59%53% of the Utility’s 2004 core market2006 gas purchases. No other producer or supplier provided the Utility segment with more than 9%10% of its gas requirements in 2004.

2006.

Supply Corporation transports and stores gas owned by its customers, whose gas originates in the southwestern, mid-continent and Appalachian regions of the United States as well as in Canada. Empire transports gas owned by its customers, whose gas originates in the southwestern and mid-continent regions of the United States as well as in Canada. Additional discussion of proposed pipeline projects appears below under “Competition”“Competition: The Pipeline and Storage Segment” and in Item 7, MD&A.

The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as further described in this report in Item 7, MD&A and Item 8 at Notes H-BusinessNote J-Business Segment Information and N-SupplementaryNote O-Supplementary Information for Oil and Gas Producing Activities.

     Coal is the principal raw material for the International segment, constituting 54% of the cost of raw materials needed in 2004 to operate the boilers which produce steam or hot water. Natural gas, oil, limestone and water combined accounted for the remaining 46% of such materials. Coal is purchased and delivered directly from the adjacent Mostecka Uhelna Spolecnost, a.s. mine in the Czech Republic for UE’s largest coal-fired plant under a contract where price and quantity are the subject of negotiation each year. The Company has been informed that this mine is expected to have reserves through 2030, although the Company has not been provided with an independent reserve study to support this information.* Natural gas is imported into the Czech Republic from sources in Russia and the North Sea and is transported through the Transgas pipeline system, which is majority owned by RWE AG, a German multi-utility. The International segment purchases natural gas from one of the eight regional gas distribution companies in the Czech Republic. Oil is also imported into the Czech Republic. The International segment purchases oil from domestic and foreign refineries.

With respect to the Timber segment, Highland requires an adequate supply of timber to process in its sawmill and kiln operations. Approximately 50%Fifty-five percent of the timber processed during 20042006 in Highland’s sawmill operations came from land owned by Seneca.

the Company’s subsidiaries, and 45% came from outside sources. In addition, Highland purchased approximately eight million board feet of green lumber to augment lumber supply for its kiln operations.

The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2004,2006, this segment purchased 4447 Bcf of natural gas, of which 4245 Bcf served core market demands. The remaining 2 Bcf largely represents gas used in operations.

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The gas purchased by the Energy Marketing segment originates in either the Appalachian or mid-continent regions of the United States or in Canada.

Competition

Competition in the natural gas industry exists among providers of natural gas, as well as between natural gas and other sources of energy. The deregulationnatural gas industry has gone through various stages of regulation. Apart from environmental and state utility commission regulation, the natural gas industry has experienced considerable deregulation. This has enhanced the competitive position of natural gas relative to other energy sources, such as fuel oil or electricity, by removingsince some of the historical regulatory impediments to adding customers and responding to market forces.forces have been removed. In addition, management believes that the environmental advantages of natural gas have enhanced its competitive position relative to other fuels.


7


The electric industry has been moving toward a more competitive environment as a result of the Federal Energy Policy Act ofchanges in federal law in 1992 and initiatives undertaken by the FERC and various states. It remains unclear what the impact will be on the Company of any further restructuring in response to legislation or other events.events may be.*

The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this “Competition” heading, do not compete with the Company to any significant extent.*

Competition: The Utility Segment

The changes precipitated by the FERC’s restructuring of the natural gas industry in Order No. 636, which was issued in 1992, continue to reshape the roles of the gas utility industry and the state regulatory commissions. In both New York and Pennsylvania, Distribution Corporation has retained substantial numbers of residential and small commercial customers as sales customers. However, for many years almost all the industrial and a substantial number of commercial customers have purchased their gas supplies from marketers and utilized Distribution Corporation’s gas transportation services. Regulators in both New York and Pennsylvania have adopted retail competition programs for natural gas supply purchases. However, regulators in Pennsylvania have not pursued such programs recently, and there have been no significant new market entrants in New York.purchases by the remaining utility sales customers. To date, the Utility segment’s traditional distribution function remains largely unchanged; however, the NYPSC continueshas stepped up its efforts to encourage customer choice at the retail residential level.

In New York, the Utility segment has instituted a number of programs to accommodate more widespread customer choice. In Pennsylvania, the PaPUC issued a report in October 2005 that concluded “effective competition” does not exist in the retail natural gas supply market statewide. In 2006, the PaPUC reconvened a stakeholder group to explore ways to increase the participation of retail customers in choice programs. The findings of the stakeholder group are expected to be presented to the PaPUC during 2007.

Competition for large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment’s service territories without use of the utility’s facilities (i.e., bypass). In addition, competition continues with fuel oil suppliers and may increase with electric utilities making retail energy sales.*

The Utility segment competes, through its unbundled flexible services, in its most vulnerable markets (the large commercial and industrial markets).* The Utility segment continues to (i) develop or promote new sources and uses of natural gas or new services, rates and contracts and (ii) emphasize and provide high quality service to its customers.

Competition: The Pipeline and Storage Segment

Supply Corporation competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and with other companies providing gas storage services. Supply Corporation has some unique characteristics which enhance its competitive position. Its facilities are located adjacent to Canada and the northeastern United States and provide part of the link between gas-consuming regions of the eastern United States and gas-producing regions of Canada and the southwestern, southern and other continental regions of the United States. This location offers the opportunity for increased transportation and storage services in the future.*

Empire competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and upstate New York in particular. Empire is particularly well situated to provide transportation from Canadian sourced gas, and its facilities are readily expandable. These characteristics provide Empire the opportunity to compete for an increased share of the gas transportation markets.

As announced in February 2004,noted above, Empire is pursuing athe Empire Connector project, towhich would expand its natural gas pipeline to serve new markets in New York and elsewhere in the Northeast.* For further discussion of this project, refer to Item 7, MD&A under the headingheadings “Investing Cash Flow.Flow” and “Rate and Regulatory Matters.


8

8


Competition: The Exploration and Production Segment

The Exploration and Production segment competes with other oil and natural gas producers and marketers with respect to sales of oil and natural gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other oil and natural gas producers with respect to exploration and development prospects.

To compete in this environment, each of Seneca and SECI each originateoriginates and actacts as operator on mostcertain of its prospects, seeks to minimize the risk of exploratory efforts through partnership-type arrangements, apply the latestutilizes technology for both exploratory studies and drilling operations, and focus onseeks market niches that suit theirbased on size, operating expertise and financial criteria.

Competition: The International Segment

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

Competition: The Energy Marketing Segment

The Energy Marketing segment competes with other marketers of natural gas and with other providers of energy management services. Although the deregulation of natural gas utilities continues to progress, the competitionCompetition in this area is well developed with regard to price and services from both local, regional and, regionalmore recently, national marketers.

Competition: The Timber Segment

With respect to the Timber segment, Highland competes with other sawmill operations and with other suppliers of timber, logs and lumber. These competitors may be local, regional, national or international in scope. This competition, however, is primarily limited to those entities which either process or supply high quality 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 nationallyin domestic and internationally.

international markets.

Seasonality

Variations in weather conditions can materially affect the volume of gas delivered by the Utility segment, as virtually all of its residential and commercial customers use gas for space heating. The effect that this has on Utility segment revenuesmargins in New York is mitigated by a weather normalization clauseWNC, which is designed to adjustcovers the rates of retail customers to reflect the impact of deviationseight-month period from normal weather.October through May. Weather that is more than 2.2% warmer than normal results in a surcharge being added to customers’ current bills, while weather that is more than 2.2% colder than normal results in a refund being credited to customers’ current bills.

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

Volumes transported by Empire may vary materially depending on weather, and can have a moderate effect on its revenues. Empire’s allowed rates are based on a modified fixed-variable rate design, which allows recovery of most fixed costs in fixed monthly reservation charges. Variable charges based on volumes are

9


designed to recover variable costs associated with actual transportation of gas, to recover return on equity, and to recover income taxes.

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

this segment.

The activities of the Timber segment vary on a seasonal basis and are subject to weather constraints. Traditionally, the timber harvesting season occurs when timber growth is dormant and runs from approximately September to March. The operations conducted in the summer months typically focus on pulpwood and on thinning out lower-grade speciesor lower value trees from the timber stands to encourage the growth of higher-grade species. During 2004, several factors, including the sale of acreage in 2003, changes in market demands, and facility upgrades resulted in a change in our cutting schedule and a more level harvest each month.or higher value trees.


9


Capital Expenditures

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

Environmental Matters

A discussion of material environmental matters involving the Company is included in Item 7, MD&A under the heading “Other“Environmental Matters” and in Item 8, Note GH — Commitments and Contingencies.

Miscellaneous

The Company and its wholly-owned or majority-owned subsidiaries had a total of 2,9181,993 full-time employees at September 30, 2004,2006, with 2,0551,970 employees in all of its U.S. operations and 86323 employees in its international operations.Canadian operations at SECI. This is a decrease of 3.9%2.5% from the 3,0372,044 total employed at September 30, 2003.

2005.

Agreements covering employees in collective bargaining units in New York were renegotiated, effective as of November 2003, and are scheduled to expire in February 2008. Certain agreements covering employees in collective bargaining units in Pennsylvania were renegotiated, effective November 2003, and are scheduled to expire in April 2009. Other2009, and other agreements covering employees in collective bargaining units in Pennsylvania were renegotiated, effective November 2003, and are scheduled to expire in May 2009. An agreement covering employees in collective bargaining units in the Czech Republic is scheduled to expire on December 31, 2004. A new four-year contract is currently being negotiated.

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

The Company makes its annual report onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 8-K, and any amendments to those reports, available free of charge on the Company’s internet website, www.nationalfuelgas.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. The information available at the Company’s internet website is not part of thisForm 10-K or any other report filed with or furnished to the SEC.

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Executive Officers of the Company as of November 15, 2004(1)2006 (except as otherwise noted)(1)
   
Current Company
Positions and
Other Material
Business Experience
Name and Age (as of
Current Company Positions and Other MaterialDuring Past
September 30, 2004)November 15, 2006)
Business Experience During Past Five Years


Philip C. Ackerman
(60)(62)
 Chairman of the Board of Directors since January 2002; Chief Executive Officer since October 2001; President since July 1999; and President of Horizon since September 1995. Mr. Ackerman has served as a Director of the Company since March 1994, and previously served as Senior Vice President of the Company from June 1989 to July 1999 and President of Distribution Corporation from October 1995 to July 1999.through January 2006.
David F. Smith
(51)(53)
 President of Distribution Corporationthe Company since July 1999; Senior ViceFebruary 2006; Chief Operating Officer of the Company since February 2006; President of Supply Corporation since July 2000. Mr. Smith served as Senior Vice President of Distribution Corporation from January 1993 to July 1999.
Dennis J. Seeley
(61)
President of Supply Corporation since March 2000;April 2005; President of Empire since February 2003; Senior Vice President of Distribution Corporation since February 1997.April 2005. Mr. SeeleySmith previously served as Vice President of the Company from April 2005 through January 2006; President of Distribution Corporation from July 1999 to April 2005; and Senior Vice President of Supply Corporation from July 2000 to April 2000.2005.


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James A. Beck
(57)
 President
Current Company
Positions and
Other Material
Business Experience
Name and Age (as of Seneca since October 1996 and President of Highland since March 1998.
During Past
November 15, 2006)
Five Years
Ronald J. Tanski
(52)(54)
 Treasurer and Principal Financial Officer of the Company since April 2004; President of Distribution Corporation since February 2006; Treasurer of Distribution Corporation since April 2004; Secretary and Treasurer of Supply Corporation since April 2004; Secretary and Treasurer of Horizon since February 1997. Mr. Tanski previously served as Controller of the Company from February 2003 through March 2004; Senior Vice President of Distribution Corporation sincefrom July 2001;2001 through January 2006; and Controller of Distribution Corporation from February 1997 through March 2004; Treasurer2004.
Matthew D. Cabell
(48)
President of Distribution Corporation since April 2004; TreasurerSeneca effective December 11, 2006. Mr. Cabell previously served as Executive Vice President and SecretaryGeneral Manager of Supply Corporation since April 2004; SecretaryMarubeni Oil & Gas (USA) Inc., an exploration and Treasurerproduction company with assets of Horizon since February 1997; andover $1,000,000,000, as Vice President of Distribution Corporation from April 1993 to July 2001.Randall & Dewey, Inc., a major oil and gas transaction advisory firm, as an independent consultant assisting oil companies in upstream acquisition and divestment transactions as well as Gulf of Mexico entry strategy, and as Vice President, Gulf of Mexico Exploration for Texaco Corporation. Mr. Cabell’s prior employers are not subsidiaries or affiliates of the Company.
Karen M. Camiolo
(45)(47)
 Controller and Principal Accounting Officer of the Company since April 2004; Controller of Distribution Corporation and Supply Corporation since April 2004; and Chief Auditor of the Company from July 1994 through March 2004.
Anna Marie Cellino
(51)(53)
 Secretary of the Company since October 1995; Senior Vice President of Distribution Corporation since July 2001;2001.
Paula M. Ciprich
(46)
General Counsel of the Company since January 2005; Assistant Secretary and Vice PresidentGeneral Counsel of Distribution Corporation from June 1994 to July 2001.since February 1997.
Bruce H. Hale
Donna L. DeCarolis
(55)(47)
 President of Horizon PowerNFR since January 2005; Secretary of NFR since March 2001;2002; Vice President of Horizon since September 1995. Mr. Hale previously served as Senior Vice President of Supply CorporationNFR from February 1997May 2001 to March 2003.January 2005.
John R. Pustulka
(52)(54)
 Senior Vice President of Supply Corporation since July 2001; and Vice President of Supply Corporation from April 1993 to July 2001.
James D. Ramsdell
(49)(51)
 Senior Vice President of Distribution Corporation since July 2001; and Vice President of Distribution Corporation from June 1994 to July 2001.


(1)The executive officers serve at the pleasure of the Board of Directors. The information provided relates to the Company and its principal subsidiaries. Many of the executive officers also have served or currently serve as officers or directors of other subsidiaries of the Company.

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Item 1A  Risk Factors
As a holding company, National Fuel depends on its operating subsidiaries to meet its financial obligations.
National Fuel is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, National Fuel relies exclusively on repayments of principal and interest on intercompany loans made by National Fuel to its operating subsidiaries and income from dividends and other cash flow from the subsidiaries. Such operating subsidiaries may not generate sufficient net income to pay upstream dividends or generate sufficient cash flow to make payments of principal or interest on such intercompany loans.
National Fuel is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies.
In addition to its longer term debt that is issued to the public under its indentures, National Fuel has relied, and continues to rely, upon shorter term bank borrowings and commercial paper to finance the execution of a portion of its operating strategies. National Fuel is dependent on these capital sources to provide capital to its subsidiaries to allow them to acquire and develop their properties. The availability and cost of these credit sources is cyclical and these capital sources may not remain available to National Fuel or National Fuel may not be able to obtain money at a reasonable cost in the future. National Fuel’s ability to borrow under its credit facilities and commercial paper agreements depends on National Fuel’s compliance with its obligations under the facilities and agreements. In addition, all of National Fuel’s short-term bank loans are in the form of floating rate debt or debt that may have rates fixed for very short periods of time. At present, National Fuel has no active interest rate hedges in place to protect against interest rate fluctuations on short-term bank debt. National Fuel has no active interest rate hedges in place with respect to other debt except at the project level of Empire, where there is an interest rate collar on the approximate $22.8 million of project debt (at September 30, 2006). In addition, the interest rates on National Fuel’s short-term bank loans and the ability of National Fuel to issue commercial paper are affected by its debt credit ratings published by Standard & Poor’s Ratings Service, Moody’s Investors Service and Fitch Ratings Service. A ratings downgrade could increase the interest cost of this debt and decrease future availability of money from banks, commercial paper purchasers and other sources. National Fuel believes it is important to maintain investment grade credit ratings to conduct its business.
National Fuel’s credit ratings may not reflect all the risks of an investment in its securities.
National Fuel’s credit ratings are an independent assessment of its ability to pay its obligations. Consequently, real or anticipated changes in the Company’s credit ratings will generally affect the market value of the specific debt instruments that are rated, as well as the market value of the Company’s common stock. National Fuel’s credit ratings, however, may not reflect the potential impact on the value of its common stock of risks related to structural, market or other factors discussed in thisForm 10-K.
National Fuel’s need to comply with comprehensive, complex, and sometimes unpredictable government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.
While National Fuel generally refers to its Utility segment and its Pipeline and Storage segment as its “regulated segments,” there are many governmental regulations that have an impact on almost every aspect of National Fuel’s businesses. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may affect its business in ways that the Company cannot predict.
In its Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC and the PaPUC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or if Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover


12


increased costs (including costs that may be incurred in connection with governmental investigations or proceedings or mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.
In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have sought to establish competitive markets in which customers may purchase supplies of gas from marketers, rather than from utility companies. In June 1999, the Governor of Pennsylvania signed into law the Natural Gas Choice and Competition Act. The Act revised the Public Utility Code relating to the restructuring of the natural gas industry. The purpose of the law was to permit consumer choice of natural gas suppliers. To a certain degree, the early programs instituted to comply with the Act have not been overly successful, and many residential customers currently continue to purchase natural gas from the utility companies. In October 2005 the PaPUC concluded that “effective competition” does not exist in the retail natural gas supply market statewide. The PaPUC has reconvened a stakeholder group to explore ways to increase the participation of retail customers in choice programs. In New York, in August 2004, the NYPSC issued its Statement of Policy on Further Steps Toward Competition in Retail Energy Markets. This policy statement has a similar goal of encouraging customer choice of alternative natural gas providers. In 2005, the NYPSC stepped up its efforts to encourage customer choice at the retail residential level. These new forms of regulation may increase Distribution Corporation’s cost of doing business, put an additional portion of its business at regulatory risk, and create uncertainty for the future, all of which may make it more difficult to manage Distribution Corporation’s business profitably.
In its Pipeline and Storage segment, National Fuel is subject to the jurisdiction of the FERC with respect to Supply Corporation, and to the jurisdiction of the NYPSC with respect to Empire. (On October 11, 2005, Empire filed an application with the FERC for the authority to build and operate an extension of its natural gas pipeline (the Empire Connector). If the FERC grants that application and the Company builds and commences operations of the Empire Connector, Empire will at that time become a FERC-regulated pipeline company.) The FERC and the NYPSC, among other things, approve the rates that Supply Corporation and Empire, respectively, may charge to their natural gas transportationand/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. State commissions can also petition the FERC to investigate whether Supply Corporation’s rates are still just and reasonable, and if not, to reduce those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to reduce the rates it charges its natural gas transportationand/or storage customers, or if Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation’s or Empire’s earnings may decrease.
National Fuel’s liquidity, and in certain circumstances, its earnings, could be adversely affected by the cost of purchasing natural gas during periods in which natural gas prices are rising significantly.
Tariff rate schedules in each of the Utility segment’s service territories contain purchased gas adjustment clauses which permit Distribution Corporation to file with state regulators for rate adjustments to recover increases in the cost of purchased gas. Assuming those rate adjustments are granted, increases in the cost of purchased gas have no direct impact on profit margins. Nevertheless, increases in the cost of purchased gas affect cash flows and can therefore impact the amount or availability of National Fuel’s capital resources. National Fuel has issued commercial paper and used short-term borrowings in the past to temporarily finance storage inventories and purchased gas costs, and National Fuel expects to do so in the future.* Distribution Corporation is required to file an accounting reconciliation with the regulators in each of the Utility segment’s service territories regarding the costs of purchased gas. Due to the nature of the regulatory process, there is a risk of a disallowance of full recovery of these costs during any period in which there has been a substantial upward spike in these costs. Any material disallowance of purchased gas costs could have a material adverse effect on cash flow and earnings. In addition, even when Distribution Corporation is allowed full recovery of these purchased gas costs, during periods when natural gas prices are significantly higher than historical levels, customers may have trouble paying the resulting higher bills, and Distribution Corporation’s bad debt expenses may increase and ultimately reduce earnings.


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Uncertain economic conditions may affect National Fuel’s ability to finance capital expenditures and to refinance maturing debt.
National Fuel’s ability to finance capital expenditures and to refinance maturing debt will depend upon general economic conditions in the capital markets. The direction in which interest rates may move is uncertain. Declining interest rates have generally been believed to be favorable to utilities, while rising interest rates are generally believed to be unfavorable, because of the levels of debt that utilities may have outstanding. In addition, National Fuel’s authorized rate of return in its regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, National Fuel’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, National Fuel’s ability to earn its authorized rate of return may be adversely impacted.
Decreased oil and natural gas prices could adversely affect revenues, cash flows and profitability.
National Fuel’s exploration and production operations are materially dependent on prices received for its oil and natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, gathering and processing oil and natural gas. Oil and natural gas prices can be volatile and can be affected by: weather conditions, including natural disasters; the supply and price of foreign oil and natural gas; the level of consumer product demand; national and worldwide economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents; political conditions in foreign countries; the price and availability of alternative fuels; the proximity to, and availability of capacity on, transportation facilities; regional levels of supply and demand; energy conservation measures; and government regulations, such as regulation of natural gas transportation, royalties, and price controls. National Fuel sells most of its oil and natural gas at current market prices rather than through fixed-price contracts, although as discussed below, National Fuel frequently hedges the price of a significant portion of its future production in the financial markets. The prices National Fuel receives depend upon factors beyond National Fuel’s control, including the factors affecting price mentioned above. National Fuel believes that any prolonged reduction in oil and natural gas prices would restrict its ability to continue the level of activity National Fuel otherwise would pursue, which could have a material adverse effect on its revenues, cash flows and results of operations.*
National Fuel has significant transactions involving price hedging of its oil and natural gas production.
In order to protect itself to some extent against unusual price volatility and to lock in fixed pricing on oil and natural gas production for certain periods of time, National Fuel periodically enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may at any time cover as much as approximately 70% of National Fuel’s expected energy production during the upcoming 12 month period. These contracts reduce exposure to subsequent price drops but can also limit National Fuel’s ability to benefit from increases in commodity prices.
In addition, under the applicable accounting rules, such hedging arrangements are subject to quarterly effectiveness tests. Inherent within those effectiveness tests are assumptions concerning the long-term price differential between different types of crude oil, assumptions concerning the difference between published natural gas price indexes established by pipelines in which hedged natural gas production is delivered and the reference price established in the hedging arrangements, and assumptions regarding the levels of production that will be achieved. Depending on market conditions for natural gas and crude oil and the levels of production actually achieved, it is possible that certain of those assumptions may change in the future, and, depending on the magnitude of any such changes, it is possible that a portion of the Company’s hedges may no longer be considered highly effective. In that case, gains or losses from the ineffective derivative financial instruments would bemarked-to-market on the income statement without regard to an underlying physical transaction. Gains would occur to the extent that hedge prices exceed market prices, and losses would occur to the extent that market prices exceed hedge prices.
Use of energy commodity price hedges also exposes National Fuel to the risk of non-performance by a contract counterparty. National Fuel carefully evaluates the financial strength of all contract counterparties, but these parties might not be able to perform their obligations under the hedge arrangements.


14


It is National Fuel’s policy that the use of commodity derivatives contracts be strictly confined to the price hedging of existing and forecast production, and National Fuel maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades could occur that may expose National Fuel to substantial losses to cover positions in these contracts. In addition, in the event actual production falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.
You should not place undue reliance on reserve information because such information represents estimates.
ThisForm 10-K contains estimates of National Fuel’s proved oil and natural gas reserves and the future net cash flows from those reserves that were prepared by National Fuel’s petroleum engineers and audited by independent petroleum engineers. Petroleum engineers consider many factors and make assumptions in estimating National Fuel’s oil and natural gas reserves and future net cash flows. These factors include: historical production from the area compared with production from other producing areas; the assumed effect of governmental regulation; and assumptions concerning oil and natural gas prices, production and development costs, severance and excise taxes, and capital expenditures. Lower oil and natural gas prices generally cause estimates of proved reserves to be lower. Estimates of reserves and expected future cash flows prepared by different engineers, or by the same engineers at different times, may differ substantially. Ultimately, actual production, revenues and expenditures relating to National Fuel’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of National Fuel’s reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.
If conditions remain constant, then National Fuel is reasonably certain that its reserve estimates represent economically recoverable oil and natural gas reserves and future net cash flows. If conditions change in the future, then subsequent reserve estimates may be revised accordingly. You should not assume that the present value of future net cash flows from National Fuel’s proved reserves is the current market value of National Fuel’s estimated oil and natural gas reserves. In accordance with SEC requirements, National Fuel bases the estimated discounted future net cash flows from its proved reserves on prices and costs as of the date of the estimate. Actual future prices and costs may differ materially from those used in the net present value estimate. Any significant price changes will have a material effect on the present value of National Fuel’s reserves.
Petroleum engineering is a subjective process of estimating underground accumulations of natural gas and other hydrocarbons that cannot be measured in an exact manner. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Future economic and operating conditions are uncertain, and changes in those conditions could cause a revision to National Fuel’s future reserve estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, and the assumed effects of regulations by governmental agencies. Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the production and operating costs incurred, the amount and timing of future development expenditures, and the price received for the production.
The amount and timing of actual future oil and natural gas production and the cost of drilling are difficult to predict and may vary significantly from reserves and production estimates, which may reduce National Fuel’s earnings.
There are many risks in developing oil and natural gas, including numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures. The future success of National Fuel’s Exploration and Production segment depends on its ability to develop additional oil and natural gas reserves that are economically recoverable, and its failure to do so may reduce National Fuel’s earnings. The total and timing of actual future production may


15


vary significantly from reserves and production estimates. National Fuel’s drilling of development wells can involve significant risks, including those related to timing, success rates, and cost overruns, and these risks can be affected by lease and rig availability, geology, and other factors. Drilling for natural gas can be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their cancellation. The cost of drilling, completing, and operating wells is often uncertain, and new wells may not be productive or National Fuel may not recover all or any portion of its investment. Without continued successful exploitation or acquisition activities, National Fuel’s reserves and revenues will decline as a result of its current reserves being depleted by production. National Fuel cannot assure you that it will be able to find or acquire additional reserves at acceptable costs.
Financial accounting requirements regarding exploration and production activities may affect National Fuel’s profitability.
National Fuel accounts for its exploration and production activities under the full cost method of accounting. Each quarter, on acountry-by-country basis, National Fuel must compare the level of its unamortized investment in oil and natural gas properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses quarter-end spot prices for oil and natural gas. If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future revenues, such investment may be considered to be “impaired,” and the full cost accounting rules require that the investment must be written down to the calculated net present value. Such an instance would require National Fuel to recognize an immediate expense in that quarter, and its earnings would be reduced. The event that had the most significant impact in 2006, and the main reason for the significant earnings decrease over 2005, was the Exploration and Production segment recording after-tax impairment charges totaling $68.6 million related to its Canadian oil and gas assets during 2006 under the full cost method of accounting. Because of the variability in National Fuel’s investment in oil and natural gas properties and the volatile nature of commodity prices, National Fuel cannot predict when in the future it may again be affected by such an impairment calculation.
Environmental regulation significantly affects National Fuel’s business.
National Fuel’s business operations are subject to federal, state, and local laws and regulations (including those of Canada) relating to environmental protection. These laws and regulations concern the generation, storage, transportation, disposal or discharge of contaminants into the environment and the general protection of public health, natural resources, wildlife and the environment. Costs of compliance and liabilities could negatively affect National Fuel’s results of operations, financial condition and cash flows. In addition, compliance with environmental laws and regulations could require unexpected capital expenditures at National Fuel’s facilities. Because the costs of complying with environmental regulations are significant, additional regulation could negatively affect National Fuel’s business. Although National Fuel cannot predict the impact of the interpretation or enforcement of EPA standards or other federal, state and local regulations, National Fuel’s costs could increase if environmental laws and regulations become more strict.
The nature of National Fuel’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.
National Fuel’s operations are subject to inherent hazards and risks such as: fires; natural disasters; explosions; formations with abnormal pressures; blowouts; collapses of wellbore casing or other tubulars; pipeline ruptures; spills; and other hazards and risks that may cause personal injury, death, property damage, environmental damage or business interruption losses. Additionally, National Fuel’s facilities, machinery, and equipment may be subject to sabotage. Any of these events could cause a loss of hydrocarbons, environmental pollution, claims for personal injury, death, property damage or business interruption, or governmental investigations, recommendations, claims, fines or penalties. As protection against operational hazards, National Fuel maintains insurance coverage against some, but not all, potential losses. In addition, many of the


16


agreements that National Fuel executes with contractors provide for the division of responsibilities between the contractor and National Fuel, and National Fuel seeks to obtain an indemnification from the contractor for certain of these risks. National Fuel is not always able, however, to secure written agreements with its contractors that contain indemnification, and sometimes National Fuel is required to indemnify others.
Insurance or indemnification agreements when obtained may not adequately protect National Fuel against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, the imposition of fines, penalties or mandated programs by governmental authorities, the failure of a contractor to meet its indemnification obligations, or the failure of an insurance company to pay valid claims could result in substantial losses to National Fuel. In addition, insurance may not be available, or if available may not be adequate, to cover any or all of these risks. It is also possible that insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive.
Due to large insurance losses caused by Hurricanes Katrina and Rita in 2005, the insurance industry has significantly increased premiums for insurance on Gulf of Mexico properties, and has reduced the limits typically available for windstorm damage. As a result, National Fuel has determined that it is not economical to purchase insurance to fully cover its exposures in the Gulf of Mexico in the event of a named windstorm. National Fuel has procured named windstorm coverage in an amount equal to approximately three times the estimated physical damage loss sustained by National Fuel as a result of named windstorms during the 2005 hurricane season, subject to a deductible of $2 million per occurrence. No assurance can be given, however, that such amount will be sufficient to cover losses that may occur in the future.
Hazards and risks faced by National Fuel, and insurance and indemnification obtained or provided by National Fuel, may subject National Fuel to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against National Fuel or be resolved on unfavorable terms, the result of which could have a material adverse effect on National Fuel’s results of operations, financial condition and cash flows.
National Fuel may be adversely affected by economic conditions.
Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect National Fuel’s revenues and cash flows or restrict its future growth. Economic conditions in National Fuel’s utility service territories also impact its collections of accounts receivable.
Item 1BUnresolved Staff Comments
None
 
Item 2Properties

General Information on Facilities

The investment of the Company in net property, plant and equipment was $3.0$2.9 billion at September 30, 2004.2006. Approximately 58%61% of this investment was in the Utility and Pipeline and Storage segments, which are primarily located in western and central New York and northwestern Pennsylvania. The Exploration and Production segment, which has the next largest investment in net property, plant and equipment (31%(35%), is primarily located in California, in the Appalachian region of the United States, in Wyoming, in the Gulf Coast region of Texas, Louisiana, and Alabama and in the provinces of Alberta, Saskatchewan and British Columbia in Canada. The remaining investment in net property, plant and equipment consisted primarily of the International segment (7%) which is located in the Czech Republic, the Timber segment (3%) which is located primarily in northwestern Pennsylvania, and All Other and Corporate operations (1%). During the past five years, the Company has made significant additions to property, plant and equipment in order to augment the reserve base of oil and gas in the United States and Canada, and to expand and improve transmission and distribution facilities for both retail and transportation customers. Net property, plant and equipment has increased $646$97.0 million, or 27%3.5%, since 1999.2001. During 2005, the Company


17


sold its majority interest in U.E., a district heating and electric generation business in the Czech Republic. The net property, plant and equipment of U.E. at the date of sale was $223.9 million.
The Utility segment had a net investment in property, plant and equipment of $1.0$1.1 billion at September 30, 2004.2006. The net investment in its gas distribution network (including 14,78114,809 miles of distribution pipeline) and its service connections to customers represent approximately 57%53% and 29%33%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2004.

2006.

The Pipeline and Storage segment had a net investment of $696.5$674.2 million in property, plant and equipment at September 30, 2004.2006. Transmission pipeline represents 37%36% of this segment’s total net investment and includes 2,5752,528 miles of pipeline required to move large volumes of gas throughout its service area. Storage facilities represent 24% of this segment’s total net investment and consist of 32 storage fields, four of which are jointly owned and operated with certain pipeline suppliers, and 439 miles of pipeline. Net investment in storage facilities includes $91.1$93.8 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 2928 compressor stations with 75,30675,361 installed compressor horsepower.

horsepower that represent 13% of this segment’s total net investment in property, plant and equipment.

The Exploration and Production segment had a net investment in property, plant and equipment of $923.7 million$1.0 billion at September 30, 2004.2006. Of this amount, $780.9$914.2 million relates to properties located in the United States. The remaining net investment of $142.8$88.0 million relates to properties located in Canada.

     The International segment had a net investment in property, plant and equipment of $227.9 million at September 30, 2004. This represents UE’s net investment in district heating and electric generation facilities.

The Timber segment had a net investment in property, plant and equipment of $82.8$90.9 million at September 30, 2004.2006. Located primarily in northwestern Pennsylvania, the net investment includes two sawmills, and approximately 87,000100,000 acres of land and timber.

timber, and approximately 4,000 acres of timber rights.

The Utility and Pipeline and Storage segments’ facilities provided the capacity to meet the Company’s 20042006 peak day sendout, including transportation service, of 1,756.31,542.4 MMcf, which occurred on January 15, 2004.February 18, 2006. Withdrawals from storage of 736.2545.2 MMcf provided approximately 41.9%35.3% of the requirements on that day.

Company maps are included in exhibit 99.3 of thisForm 10-K and are incorporated herein by reference.

Exploration and Production Activities

The Company is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, and in the Gulf Coast region of Texas, Louisiana, and Alabama. Also, Exploration and Production operations are conducted in the provinces of Alberta, Saskatchewan and British Columbia in Canada. Further discussion of oil and gas producing activities is included in Item 8,Note N-SupplementaryO-Supplementary Information for Oil and Gas Producing Activities.

12


Note NO sets forth proved developed and undeveloped reserve information for Seneca. During 2004, Seneca’s proved developed and undeveloped reserves decreased modestly from the prior year. Naturalnatural gas reserves decreased from 251238 Bcf at September 30, 20032005 to 233 Bcf at September 30, 2006. This decrease can be attributed primarily to production and downward reserve revisions related primarily to the Canadian properties. These decreases were partially offset by extensions and discoveries. The downward reserve revisions were largely a function of a significant decrease in gas prices during the fourth quarter of 2006. Seneca’s proved developed and undeveloped oil reserves decreased from 60,257 Mbbl at September 30, 2005 to 58,018 Mbbl at September 30, 2006. This decrease can be attributed mostly to production. Seneca’s proved developed and undeveloped natural gas reserves increased from 225 Bcf at September 30, 2004 to 238 Bcf at September 30, 2005. This increase can be attributed to the fact that net extensions and discoveries outpaced production. However, Seneca’s proved developed and undeveloped oil reserves decreased from 69,76465,213 Mbbl at September 30, 2004 to 65,213 Mbbl. These decreases are60,257 Mbbl at September 30, 2005. This decrease can be attributed primarily to the fact that U.S. and Canadian production outpaced net extensions and discoveries. Seneca’s proved developed and undeveloped reserves also decreased in 2003 as compared to 2002. Natural gas reserves decreased from 258 Bcf at September 30, 2002 to 251 Bcf at September 30, 2003 and oil reserves decreased from 99,717 Mbbl to 69,764 Mbbl. These decreases are attributed to the following factors: (i) U.S. and Canadian production and sales of Canadian properties (refer to Item 7, MD&A) and (ii) downward reserve revisions primarily related to the Canadian properties sold during the year (reflected in Note N as revisions of previous estimates).

Seneca’s oil and gas reserves reported in Note NO as of September 30, 20042006 were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Ralph E. Davis Associates, Inc. Seneca reports its oil and gas reserve information on an annual basis to the Energy Information Administration (EIA), a


18


statistical agency of the U.S. Department of Energy. The basis of reporting Seneca’s reserves to the EIA is identical to that reported in Note N.

O.

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

200420032002



United States
            
Gulf Coast Region            
 Average Sales Price per Mcf of Gas $5.61  $5.41  $2.89 
 Average Sales Price per Barrel of Oil $35.31  $29.17  $22.83 
 Average Sales Price per Mcf of Gas (after hedging) $4.78  $4.22  $3.69 
 Average Sales Price per Barrel of Oil (after hedging) $31.51  $27.88  $22.51 
 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.60  $0.56  $0.60 
 Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  73   75   100 
West Coast Region            
 Average Sales Price per Mcf of Gas $5.54  $5.01  $2.86 
 Average Sales Price per Barrel of Oil $31.89  $26.12  $19.94 
 Average Sales Price per Mcf of Gas (after hedging) $5.72  $5.12  $2.86 
 Average Sales Price per Barrel of Oil (after hedging) $22.86  $23.67  $20.09 
 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.05  $1.00  $0.81 
 Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  55   59   63 
Appalachian Region            
 Average Sales Price per Mcf of Gas $5.91  $5.07  $3.74 
 Average Sales Price per Barrel of Oil $31.30  $28.77  $23.76 
 Average Sales Price per Mcf of Gas (after hedging) $5.72  $5.10  $3.74 
 Average Sales Price per Barrel of Oil (after hedging) $31.30  $28.77  $23.76 
 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.54  $0.43  $0.53 
 Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  14   14   12 
             
  For the Year Ended September 30 
  2006  2005  2004 
 
United States
            
Gulf Coast Region            
Average Sales Price per Mcf of Gas $8.01  $7.05  $5.61 
Average Sales Price per Barrel of Oil $64.10  $49.78  $35.31 
Average Sales Price per Mcf of Gas (after hedging) $5.89  $6.01  $4.82 
Average Sales Price per Barrel of Oil (after hedging) $47.46  $35.03  $31.51 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.86  $0.71  $0.60 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  36   50   73 
West Coast Region            
Average Sales Price per Mcf of Gas $7.93  $6.85  $5.54 
Average Sales Price per Barrel of Oil $56.80  $42.91  $31.89 
Average Sales Price per Mcf of Gas (after hedging) $7.19  $6.15  $5.72 
Average Sales Price per Barrel of Oil (after hedging) $37.69  $23.01  $22.86 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.35  $1.15  $1.05 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  53   53   55 
Appalachian Region            
Average Sales Price per Mcf of Gas $9.53  $7.60  $5.91 
Average Sales Price per Barrel of Oil $65.28  $48.28  $31.30 
Average Sales Price per Mcf of Gas (after hedging) $8.90  $7.01  $5.72 
Average Sales Price per Barrel of Oil (after hedging) $65.28  $48.28  $31.30 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.69  $0.63  $0.54 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  15   13   14 
Total United States
            
Average Sales Price per Mcf of Gas $8.42  $7.13  $5.66 
Average Sales Price per Barrel of Oil $58.47  $44.87  $33.13 
Average Sales Price per Mcf of Gas (after hedging) $7.02  $6.26  $5.13 
Average Sales Price per Barrel of Oil (after hedging) $40.26  $26.59  $26.06 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.09  $0.90  $0.76 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  104   117   142 


19

13


              
For the Year Ended
September 30

200420032002



Total United States
            
 Average Sales Price per Mcf of Gas $5.66  $5.28  $2.99 
 Average Sales Price per Barrel of Oil $33.13  $27.16  $21.03 
 Average Sales Price per Mcf of Gas (after hedging) $5.11  $4.52  $3.58 
 Average Sales Price per Barrel of Oil (after hedging) $26.06  $25.11  $21.01 
 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.76  $0.72  $0.67 
 Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  142   148   175 
Canada
            
 Average Sales Price per Mcf of Gas $4.87  $4.67  $2.29 
 Average Sales Price per Barrel of Oil $30.94  $26.41  $19.94 
 Average Sales Price per Mcf of Gas (after hedging) $4.87  $4.20  $3.59 
 Average Sales Price per Barrel of Oil (after hedging) $30.94  $15.85  $18.11 
 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.00  $1.65  $1.29 
 Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  22   55   64 
Total Company
            
 Average Sales Price per Mcf of Gas $5.51  $5.18  $2.88 
 Average Sales Price per Barrel of Oil $32.98  $26.90  $20.63 
 Average Sales Price per Mcf of Gas (after hedging) $5.06  $4.47  $3.58 
 Average Sales Price per Barrel of Oil (after hedging) $26.40  $21.84  $19.94 
 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.80  $0.97  $0.84 
 Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  164   203   239 

             
  For the Year Ended September 30 
  2006  2005  2004 
 
Canada
            
Average Sales Price per Mcf of Gas $7.14  $6.15  $4.87 
Average Sales Price per Barrel of Oil $51.40  $42.97  $30.94 
Average Sales Price per Mcf of Gas (after hedging) $7.47  $6.14  $4.79 
Average Sales Price per Barrel of Oil (after hedging) $51.40  $42.97  $30.94 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.57  $1.29  $1.00 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  26   27   22 
Total Company
            
Average Sales Price per Mcf of Gas $8.04  $6.86  $5.51 
Average Sales Price per Barrel of Oil $57.94  $44.72  $32.98 
Average Sales Price per Mcf of Gas (after hedging) $7.15  $6.23  $5.06 
Average Sales Price per Barrel of Oil (after hedging) $41.10  $27.86  $26.40 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.18  $0.98  $0.80 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  130   144   164 
Productive Wells
                                 
United States

Gulf CoastWest CoastAppalachian
RegionRegionRegionTotal U.S.




At September 30, 2004GasOilGasOilGasOilGasOil









Productive Wells — Gross  32   34      1,155   1,912   31   1,944   1,220 
Productive Wells — Net  20   15      1,146   1,837   25   1,857   1,186 

                                 
  United States       
  Gulf Coast
  West Coast
  Appalachian
    
  Region  Region  Region  Total U.S. 
At September 30, 2006
 Gas  Oil  Gas  Oil  Gas  Oil  Gas  Oil 
 
Productive Wells — Gross  34   30      1,274   2,138   31   2,172   1,335 
Productive Wells — Net  21   14      1,266   2,052   25   2,073   1,305 
Productive Wells
                 
CanadaTotal Company


At September 30, 2004GasOilGasOil





Productive Wells — Gross  177   49   2,121   1,269 
Productive Wells — Net  124   34   1,981   1,220 

14


                 
  Canada  Total Company 
At September 30, 2006
 Gas  Oil  Gas  Oil 
 
Productive Wells — Gross  217   53   2,389   1,388 
Productive Wells — Net  155   36   2,228   1,341 
Developed and Undeveloped Acreage
                          
United States

GulfWest
CoastCoastAppalachianTotalTotal
At September 30, 2004RegionRegionRegionU.S.CanadaCompany







Developed Acreage — Gross  102,270   9,839   508,466   620,575   109,194   729,769 
 — Net  76,549   9,469   481,732   567,750   74,302   642,052 
Undeveloped Acreage — Gross  206,619      464,525   671,144   421,690   1,092,834 
 — Net  115,909      440,004   555,913   316,820   872,733 

                         
  United States       
  Golf
  West
             
  Coast
  Coast
  Appalachian
  Total
     Total
 
At September 30, 2006
 Region  Region  Region  U.S.  Canada  Company 
 
Developed Acreage                        
— Gross  144,610   10,479   514,222   669,311   117,955   787,266 
— Net  104,173   10,109   487,384   601,666   84,182   685,848 
Undeveloped Acreage                        
— Gross  174,503      475,909   650,412   393,169   1,043,581 
— Net  85,117      451,733   536,850   243,287   780,137 
As of September 30, 2004,2006, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 142,172 acres in 2005 (106,758 net acres), 98,660 acres in 2006 (91,148 net acres), 130,707191,159 acres in 2007 (80,783(128,900 net acres), 112,156 acres in 2008 (65,174 net acres), 83,246 acres in 2009 (57,538 net acres), and 721,295657,020 acres thereafter (594,044(528,525 net acres).

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Drilling Activity
                           
ProductiveDry


For the Year Ended September 30200420032002200420032002







United States
                        
Gulf Coast Region                        
 Net Wells Completed — Exploratory     1.25   1.27   0.50      3.67 
  — Development  0.65   2.10   0.31          
West Coast Region                        
 Net Wells Completed — Exploratory                  
  — Development  49.00   30.97   47.99         2.00 
Appalachian Region                        
 Net Wells Completed — Exploratory     3.00   3.00   3.00   0.10   1.00 
  — Development  41.00   58.00   27.00         0.10 
Total United States                        
 Net Wells Completed — Exploratory     4.25   4.27   3.50   0.10   4.67 
  — Development  90.65   91.07   75.30         2.10 
Canada
                        
 Net Wells Completed — Exploratory  52.85   5.00   0.20   6.08   2.50   4.00 
  — Development10.50   17.16   33.70      5.00   7.90 
Total
                        
 Net Wells Completed — Exploratory  52.85   9.25   4.47   9.58   2.60   8.67 
  — Development101.15   108.23   109.00      5.00   10.00 

                         
  Productive  Dry 
For the Year Ended September 30
 2006  2005  2004  2006  2005  2004 
 
United States
                        
Gulf Coast Region                        
Net Wells Completed                        
— Exploratory  2.94   1.30      0.85   0.47   0.50 
— Development  0.78   0.23   0.65          
West Coast Region Net Wells Completed                        
— Exploratory                  
— Development  92.98   116.97   49.00   1.00       
Appalachian Region Net Wells Completed                        
— Exploratory  3.88   3.00         4.00   3.00 
— Development  140.58   45.00   41.00   1.75   1.00    
Total United States Net Wells Completed                        
— Exploratory  6.82   4.30      0.85   4.47   3.50 
— Development  234.34   162.20   90.65   2.75   1.00    
Canada
                        
Net Wells Completed                        
— Exploratory  12.60   21.14   52.85   1.35   2.00   6.08 
— Development  2.50   3.50   10.50   1.00       
Total
                        
Net Wells Completed                        
— Exploratory  19.42   25.44   52.85   2.20   6.47   9.58 
— Development  236.84   165.70   101.15   3.75   1.00    
Present Activities
                          
United States

GulfWest
CoastCoastAppalachianTotalTotal
At September 30, 2004RegionRegionRegionU.S.CanadaCompany







Wells in Process of Drilling(1) — Gross  1.00   5.00   25.00   31.00   1.00   32.00 
— Net  0.67   5.00   24.05   29.72   1.00   30.72 


                         
  United States       
  Gulf
  West
             
  Coast
  Coast
  Appalachian
  Total
     Total
 
At September 30, 2006
 Region  Region  Region  U.S.  Canada  Company 
 
Wells in Process of Drilling(1)                        
— Gross  5.00   6.00   54.00   65.00   5.00   70.00 
— Net  2.69   5.50   54.00   62.19   2.13   64.32 
(1)Includes wells awaiting completion.

15


 
Item 3Legal Proceedings

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

     A motion was made by plaintiffs on July 15, 2002 to certify a class comprising all persons presently and formerly entitled to receive royalties on the sale of natural gas produced and sold from wells operated in New York by Seneca (and its predecessor Empire Exploration, Inc). On December 23, 2002, the court granted certification of the proposed class, as modified to exclude those leaseholders whose leases provide for calculation of royalties based upon a flat fee, or flat fee per cubic foot of gas produced. The court’s order states that there are approximately 749 potential class members. Discovery has begun on the merits of the claims.

In an action instituted in the New York State Supreme Court, Kings County on February 18, 2003 against Distribution Corporation and Paul J. Hissin, an unaffiliated third party, plaintiff Donna Fordham-Coleman, as administratrix of the estate of Velma Arlene Fordham, alleges that Distribution Corporation’s denial of natural gas service in November 2000 to the plaintiff’s decedent, Velma Arlene Fordham, caused the decedent’s death in February 2001. The plaintiff seekssought damages for wrongful death and pain and suffering, plus punitive damages. Distribution Corporation has denied plaintiff’s material allegations, set upasserted seven affirmative defenses in separate verified answers and filedasserted a cross-claim against the co-defendant. Distribution Corporation believes, and willhas vigorously assertasserted, that plaintiff’s allegations lack merit. The Court changed venue of the action to New York State Supreme Court, Erie County. Discovery closed in October 2005, and Distribution Corporation filed a motion for summary judgment in November 2005. On February 24, 2006, the Court granted Distribution Corporation’s motion for summary


21


judgment dismissing plaintiff’s claims for wrongful death and punitive damages. The litigationCourt denied Distribution Corporation’s motion for summary judgment to dismiss plaintiff’s negligence claim seeking recovery for conscious pain and suffering. On March 15, 2006, the plaintiff appealed the Court’s decision to the New York State Supreme Court, Appellate Division, Fourth Department. On March 29, 2006, Distribution Corporation filed a cross-appeal. A trial date is inscheduled for October 15, 2007 (although it is possible that the early stagesCourt may change that date or that a trial may become unnecessary, based on the progress or outcome of discovery.the pending appeals).
On April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office of Consumer Advocate filed a complaint and a motion for summary disposition against Supply Corporation with the FERC under Sections 5(a) and 13 of the Natural Gas Act. For a discussion of a related matter before the NYPSC,these matters, refer to Part II, Item 7 — MD&A of this report under the heading “Regulatory“Other Matters — Rate and Regulatory Matters.”

On December 22, 2003,June 8, 2006, the Pennsylvania Department of Environmental Protection (DEP)NTSB issued an ordersafety recommendations to Seneca to halt its timber harvesting operations on 21,000 acres in Cameron, ElkDistribution Corporation, the PaPUC and McKean counties in Pennsylvania. The order asserts certain violations of DEP regulations concerning erosion, sedimentation and stream crossings. The order requires Seneca to apply for certain permits, control erosion, submit plans for removal of water encroachments not included in permit applications, notify the DEP of additional current or planned timber harvesting operations, and grant the DEP access to timber acreage. On January 9, 2004, Seneca filed with the Pennsylvania Environmental Hearing Board (Hearing Board)others as a notice of appeal, objecting to each finding and order contained in the order, and asserting that the DEP’s findings are factually incorrect, an arbitrary exercise of the DEP’s functions and duties, and contrary to law. Also on January 9, 2004, Seneca filed with the Hearing Board a petition requesting a stay of operation of portions of the order. On January 16, 2004, the parties settled Seneca’s request for a stay. Seneca has resumed its timber harvesting operations pursuant to the terms of the settlement. The settlement preserves various issues raised by the DEP’s order for a hearing on the merits of Seneca’s notice of appeal. The most substantial question involves whether Seneca is required to apply for a permit under Section 102.5(b) of Title 25 of the Pennsylvania Code, governing earth disturbance activities of greater than 25 acres. The DEP takes the position that Seneca must aggregate the acreage of allresult of its logging sites across its entire 21,000 acre tract for purposesinvestigation of determining whether its earth disturbing activities meeta natural gas explosion that occurred on Distribution Corporation’s system in Dubois, Pennsylvania in August 2004. For a discussion of this matter, refer to Part II, Item 7 — MD&A of this report under the 25 acres threshold. Seneca maintains that no permit is required, because the law does not require aggregationheading “Other Matters — Rate and each of its individual logging sites disturbs less than 25 acres. Seneca is engaged in negotiations to resolve this dispute on acceptable terms, and litigation deadlines have been extended to accommodate those discussions.

Regulatory Matters.”

The Company believes, based on the information presently known, that the ultimate resolution of thesethe above matters individually or in the aggregate, will not be material to the consolidated financial condition, results of operations, or cash flow of the Company.* No assurances can be given, however, as to the ultimate outcomes

16


outcome of these matters, and it is possible that the outcomes, individually or in the aggregateoutcome 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 GH — Commitments and Contingencies.

The

In addition to the matters disclosed above, the Company is involved in other litigation and regulatory matters arising in the normal course of business. Also in the normal course of business, the Company is involved inThese other matters may include, for example, negligence claims and tax, regulatory andor other governmental audits, inspections, investigations andor other proceedings thatproceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service, and purchased gas cost issues, among other things. While the resolution of such litigation or regulatorythese normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period of resolution, none of this litigation, and none of these regulatory matters,in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor to have a material adverse effect on the financial condition of the Company.*
 
Item 4Submission of Matters to a Vote of Security Holders

No matter was submitted to a vote of security holders during the quarter ended September 30, 2004.
2006.

PART II
 
Item 5Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Information regarding the market for the Company’s common equity and related stockholder matters appears under Item 12 at Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, Item 8 atNote D-CapitalizationE-Capitalization and Short-Term Borrowings andNote M-MarketN-Market for Common Stock and Related Shareholder Matters (unaudited).

On July 1, 2004,2006, the Company issued a total of 1,8002,100 unregistered shares of Company common stock to the sixseven non-employee directors of the Company then serving on the Board of Directors, 300 shares to each such director. All of these unregistered shares were issued as partial consideration for such directors’ services during the quarter ended September 30, 2004,2006, 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.


22


Issuer Purchases of Equity Securities
                 
Total Number of
Shares PurchasedMaximum Number of
as Part of PubliclyShares that May Yet
Total Number ofAnnounced ShareBe Purchased Under
SharesAverage PriceRepurchase PlansShare Repurchase
PeriodPurchased(a)Paid per Shareor ProgramsPlans or Programs





July 1-31, 2004  59,546  $26.04       
Aug. 1-31, 2004  35,616  $26.49       
Sept. 1-30, 2004  216,163  $27.97       
   
   
   
   
 
Total  311,325  $27.43       
   
   
   
   
 


                 
        Total Number
  Maximum Number
 
        of Shares
  of Shares
 
        Purchased as
  that May
 
        Part of
  Yet Be
 
        Publicly Announced
  Purchased Under
 
  Total Number
  Average Price
  Share Repurchase
  Share Repurchase
 
  of Shares
  Paid per
  Plans or
  Plans or
 
Period
 Purchased(a)  Share  Programs  Programs(b) 
 
July 1-31, 2006  444,198  $36.32   94,400   5,621,250 
Aug. 1-31, 2006  47,155  $37.91      5,621,250 
Sept. 1-30, 2006  192,702  $36.46   147,800   5,473,450 
                 
Total  684,055  $36.47   242,200   5,473,450 
                 
 
(a)Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices and/or applicable withholding taxes.taxes, and (iii) shares of common stock of the Company purchased on the open market pursuant to the Company’s publicly announced share repurchase program. Shares purchased other than through a publicly announced share repurchase program totaled 349,798 in July 2006, 47,155 in August 2006 and 44,902 in September 2006 (a three month total of 441,855). Of those shares, 27,499 were purchased for the Company’s 401(k) plans and 414,356 were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock.
(b)On December 8, 2005, the Company’s Board of Directors authorized the repurchase of up to eight million shares of the Company’s common stock. Repurchases may be made from time to time in the open market or through private transactions.

17


 
Item 6Selected Financial Data(1)
                      
Year Ended September 30

20042003200220012000





(Thousands)
Summary of Operations
                    
Operating Revenues $2,031,393  $2,035,471  $1,464,496  $2,059,836  $1,412,416 
   
   
   
   
   
 
Operating Expenses:                    
 Purchased Gas  949,452   963,567   462,857   1,002,466   488,383 
 Fuel Used in Heat and Electric Generation  65,722   61,029   50,635   54,968   54,893 
 Operation and Maintenance  413,593   386,270   394,157   364,318   350,383 
 Property, Franchise and Other Taxes  72,111   82,504   72,155   83,730   78,878 
 Depreciation, Depletion and Amortization  189,538   195,226   180,668   174,914   142,170 
 Impairment of Oil and Gas Producing Properties     42,774      180,781    
   
   
   
   
   
 
   1,690,416   1,731,370   1,160,472   1,861,177   1,114,707 
Gain (Loss) on Sale of Timber Properties  (1,252)  168,787          
Gain (Loss) on Sale of Oil and Gas Producing Properties  4,645   (58,472)         
   
   
   
   
   
 
Operating Income  344,370   414,416   304,024   198,659   297,709 
Other Income (Expense):                    
 Income from Unconsolidated Subsidiaries  805   535   224   1,794   1,669 
 Impairment of Investment in Partnership        (15,167)      
 Other Income  6,671   6,887   7,017   10,639   6,366 
 Interest Expense on Long-Term Debt  (83,827)  (92,766)  (90,543)  (81,851)  (67,195)
 Other Interest Expense  (6,763)  (12,290)  (15,109)  (25,294)  (32,890)
   
   
   
   
   
 
Income Before Income Taxes and Minority Interest in Foreign Subsidiaries  261,256   316,782   190,446   103,947   205,659 
Income Tax Expense  92,737   128,161   72,034   37,106   77,068 
Minority Interest in Foreign Subsidiaries  (1,933)  (785)  (730)  (1,342)  (1,384)
   
   
   
   
   
 
Income Before Cumulative Effect of Changes in Accounting  166,586   187,836   117,682   65,499   127,207 
Cumulative Effect of Changes in Accounting     (8,892)         
   
   
   
   
   
 
Net Income Available for Common Stock $166,586  $178,944  $117,682  $65,499  $127,207 
   
   
   
   
   
 
                     
  Year Ended September 30 
  2006  2005  2004  2003  2002 
  (Thousands) 
 
Summary of Operations
                    
Operating Revenues $2,311,659  $1,923,549  $1,907,968  $1,921,573  $1,369,869 
                     
Operating Expenses:                    
Purchased Gas  1,267,562   959,827   949,452   963,567   462,857 
Operation and Maintenance  413,726   404,517   385,519   361,898   372,063 
Property, Franchise and Other Taxes  69,942   69,076   68,978   79,692   69,837 
Depreciation, Depletion and Amortization  179,615   179,767   174,289   181,329   168,745 
Impairment of Oil and Gas Producing Properties  104,739         42,774    
                     
   2,035,584   1,613,187   1,578,238   1,629,260   1,073,502 
Gain (Loss) on Sale of Timber Properties        (1,252)  168,787    
Gain (Loss) on Sale of Oil and Gas Producing Properties        4,645   (58,472)   
                     
Operating Income  276,075   310,362   333,123   402,628   296,367 


23

18


                      
Year Ended September 30

20042003200220012000





(Thousands)
Per Common Share Data
                    
 Basic Earnings per Common Share $2.03  $2.21(2) $1.47  $0.83  $1.63 
 Diluted Earnings per Common Share $2.01  $2.20(2) $1.46  $0.82  $1.61 
 Dividends Declared $1.10  $1.06  $1.03  $0.99  $0.95 
 Dividends Paid $1.09  $1.05  $1.02  $0.97  $0.94 
 Dividend Rate at Year-End $1.12  $1.08  $1.04  $1.01  $0.96 
At September 30:                    
Number of Common Shareholders
  19,063   19,217   20,004   20,345   21,164 
   
   
   
   
   
 
Net Property, Plant and Equipment(Thousands)
                    
 Utility $1,048,428  $1,028,393  $960,015  $945,693  $939,753 
 Pipeline and Storage  696,487   705,927   487,793   483,222   474,972 
 Exploration and Production  923,730   925,833   1,072,200   1,081,622   998,852 
 International  227,905   219,199   207,191   178,250   172,602 
 Energy Marketing  80   171   125   262   360 
 Timber  82,838   87,600   110,624   90,453   95,607 
 All Other  21,172   22,042   6,797   1,209   1,241 
 Corporate  6,124   1,883      2   4 
   
   
   
   
   
 
Total Net Plant $3,006,764  $2,991,048  $2,844,745  $2,780,713  $2,683,391 
   
   
   
   
   
 
Total Assets(Thousands)
 $3,711,798  $3,719,060  $3,401,309  $3,445,231  $3,251,031 
   
   
   
   
   
 
Capitalization(Thousands)
                    
Comprehensive Shareholders’ Equity $1,253,701  $1,137,390  $1,006,858  $1,002,655  $987,437 
Long-Term Debt, Net of Current Portion  1,133,317   1,147,779   1,145,341   1,046,694   953,622 
   
   
   
   
   
 
Total Capitalization $2,387,018  $2,285,169  $2,152,199  $2,049,349  $1,941,059 
   
   
   
   
   
 
                     
  Year Ended September 30 
  2006  2005  2004  2003  2002 
  (Thousands) 
 
Other Income (Expense):                    
Income from Unconsolidated Subsidiaries  3,583   3,362   805   535   224 
Impairment of Investment in Partnership     (4,158)        (15,167)
Interest Income  10,275   6,496   1,771   2,204   2,593 
Other Income  2,825   12,744   2,908   2,427   3,184 
Interest Expense on Long-Term Debt  (72,629)  (73,244)  (82,989)  (91,381)  (88,646)
Other Interest Expense  (5,952)  (9,069)  (6,763)  (11,196)  (15,109)
                     
Income from Continuing Operations Before Income Taxes  214,177   246,493   248,855   305,217   183,446 
Income Tax Expense  76,086   92,978   94,590   124,150   69,944 
                     
Income from Continuing Operations  138,091   153,515   154,265   181,067   113,502 
                     
Discontinued Operations:                    
Income from Operations, Net of Tax     10,199   12,321   6,769   4,180 
Gain on Disposal, Net of Tax     25,774          
                     
Income from Discontinued Operations, Net of Tax     35,973   12,321   6,769   4,180 
                     
Income Before Cumulative Effect of Changes in Accounting  138,091   189,488   166,586   187,836   117,682 
Cumulative Effect of Changes in Accounting           (8,892)   
                     
Net Income Available for Common Stock $138,091  $189,488  $166,586  $178,944  $117,682 
                     
Per Common Share Data
                    
Basic Earnings from Continuing Operations per Common Share $1.64  $1.84  $1.88  $2.24  $1.42 
Diluted Earnings from Continuing Operations per Common Share $1.61  $1.81  $1.86  $2.23  $1.41 
Basic Earnings per Common Share(2) $1.64  $2.27  $2.03  $2.21  $1.47 
Diluted Earnings per Common Share(2) $1.61  $2.23  $2.01  $2.20  $1.46 
Dividends Declared $1.18  $1.14  $1.10  $1.06  $1.03 
Dividends Paid $1.17  $1.13  $1.09  $1.05  $1.02 
Dividend Rate at Year-End $1.20  $1.16  $1.12  $1.08  $1.04 
At September 30:                    
Number of Registered Shareholders
  17,767   18,369   19,063   19,217   20,004 
                     

24


                     
  Year Ended September 30 
  2006  2005  2004  2003  2002 
  (Thousands) 
 
Net Property, Plant and Equipment
                    
Utility $1,084,080  $1,064,588  $1,048,428  $1,028,393  $960,015 
Pipeline and Storage  674,175   680,574   696,487   705,927   487,793 
Exploration and Production  1,002,265   974,806   923,730   925,833   1,072,200 
Energy Marketing  59   97   80   171   125 
Timber  90,939   94,826   82,838   87,600   110,624 
All Other  17,394   18,098   21,172   22,042   6,797 
Corporate(3)  8,814   6,311   234,029   221,082   207,191 
                     
Total Net Plant $2,877,726  $2,839,300  $3,006,764  $2,991,048  $2,844,745 
                     
Total Assets
 $3,734,331  $3,725,282  $3,717,603  $3,725,414  $3,429,163 
                     
Capitalization
                    
Comprehensive Shareholders’ Equity $1,443,562  $1,229,583  $1,253,701  $1,137,390  $1,006,858 
Long-Term Debt, Net of Current Portion  1,095,675   1,119,012   1,133,317   1,147,779   1,145,341 
                     
Total Capitalization $2,539,237  $2,348,595  $2,387,018  $2,285,169  $2,152,199 
                     
(1)Certain prior year amounts have been reclassified to conform with current year presentation.
 
(2)Includes discontinued operations and cumulative effect of changes in accountingaccounting.
(3)Includes net plant of ($0.11) basicthe former international segment as follows: $27 for 2006, $20 for 2005, $227,905 for 2004, $219,199 for 2003, and diluted.$207,191 for 2002.
 
Item 7Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

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

1. The critical accounting estimates of the Company;
2. Changes in revenues and earnings of the Company under the heading, “Results of Operations;”
3. Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity;”
4. Off-Balance Sheet Arrangements;
5. Contractual Obligations; and
1. The critical accounting policies of the Company;
2. Changes in revenues and earnings of the Company under the heading, “Results of Operations;”
3. Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity;”
4. Off-Balance Sheet Arrangements;

19


5. Contractual Obligations; and
 6. Other Matters, including: a.) 2006 and 2007 funding to the Company’s defined benefit retirement plan and post-retirement benefit plan, b.) realizability of deferred tax assets, c.) disclosures and tables concerning market risk sensitive instruments, b.d.) rate and regulatory matters in the Company’s New York, Pennsylvania and FERC regulated jurisdictions, c.e.) environmental matters, and d.f.) new accounting pronouncements.

The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report.

25

     Throughout MD&A,


The event that had the most significant earnings impact in 2006, and the main reason for the significant earnings decrease over 2005, was the Exploration and Production segment recording after-tax impairment charges totaling $68.6 million related to its Canadian oil and gas assets during 2006 under the full cost method of accounting, which is discussed below under Critical Accounting Estimates. In addition, the Company’s earnings for 2006 as compared to 2005 are impacted by the Company’s 2005 sale of its entire 85.16% interest in U.E., a few events will stand outdistrict heating and electric generation business in the Czech Republic. This sale resulted in a $25.8 million gain in 2005, net of tax. As a result of the decision to sell its majority interest in U.E., the Company began presenting the Czech Republic operations as discontinued operations in June 2005. With this change in presentation, the Company discontinued all reporting for an International segment. Any remaining international activity has been included in corporate operations for all periods presented below. The Company’s earnings are discussed further in the Results of Operations section that impact the results of operations andfollows.
From a capital resources and liquidity ofperspective, the Company for 2004 and 2003. First,spent $294.2 million on capital expenditures during 2006, with approximately 71% being spent in the Company, in its Exploration and Production segment, sold its Southeast Saskatchewan oil and gas propertiessegment. This is in 2003 after a thorough review of the economics of its non-regulated business. These properties were sold given their overall marginal contribution to earnings. Second,line with the Company’s Exploration and Production segment benefited from higher commodity prices in 2004. Third, the Company, in its Pipeline and Storage segment, purchased Empire State Pipeline (Empire) from Duke Energy Corporation on February 6, 2003. Empire was acquired because the Company believes that the pipeline better positions the Company to bring Canadian gas supplies into the East Coast markets of the United States as demand for natural gas along the East Coast increases.*expectations. In furtherance of that objective, in February 2004,November 2006, the Company announced that it is pursuing an extensionhad selected EOG Resources, Inc. (EOG) to jointly explore approximately 770,000 acres of the Company’s mineral holdings and 130,000 acres of EOG’s mineral holdings in Pennsylvania and New York. EOG will be the operator and the primary exploration targets are the Devonian black shales, which have similar characteristics to the prolific Barnett Shale that is actively producing natural gas in the Fort Worth Basin. Exploratory drilling is expected to begin in 2007; however, the Company does not share in the initial exploratory costs and no capital expenditures have been forecasted for 2007 related to this joint venture.* Earliest production estimates have production starting no sooner than 2008.*
The Company is still pursuing its Empire State PipelineConnector project to expand its natural gas pipeline operations. In July 2006, Empire revised the planned in-service date for the Empire Connector to extend beyond November 2007, as an upstream supply linkoriginally reported. The new targeted in-service date is November 2008, or sooner if feasible.* On July 20, 2006, FERC issued a Preliminary Determination regarding the rate and non-environmental aspects of Empire’s application for Phase IFERC approval. Empire then made a compliance filing on September 18, 2006 regarding certain non-environmental issues, which is discussed further in the Capital Resources and Liquidity section that follows. On October 13, 2006, FERC subsequently issued a final environmental impact statement on the Empire Connector project and the other related downstream projects, indicating that FERC has not identified any environmental reasons why those projects could not be built. There are no other significant changes in the status of the Millennium Pipeline. Fourth,project and the Company in its Timber segment, sold approximately 70,000 acres of timber properties in August 2003 as a means of financing its acquisition of Empire. continues to await final FERC approval to build and operate the project.
The Company recognizedalso began repurchasing outstanding shares of common stock during the concerns about its debtquarter ended March 31, 2006 under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to capital ratio afterrepurchase up to an aggregate amount of 8 million shares. Through September 30, 2006, the Empire acquisitionCompany had repurchased 2,526,550 shares. These matters are discussed further in the Capital Resources and therefore sold these timber propertiesLiquidity section that follows.
From a rate and regulatory matters perspective, management is concerned with declining usage per customer in the Utility segment. It has been one of the items leading to reduce the short-term debt usedfiling of rate cases in New York and Pennsylvania. In Pennsylvania, the Company filed a rate case in June 2006 that included a revenue decoupling mechanism, or a conservation tracker. A settlement for this rate case was reached in October 2006, and while the revenue decoupling mechanism was withdrawn in order to initially financeachieve the acquisition.settlement, the PaPUC instituted a generic proceeding to look at rate mechanisms such as revenue decoupling across the state. In New York, there is currently a proceeding going on to examine revenue decoupling mechanisms.
Lastly, on April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office of Consumer Advocate filed a complaint and motion for summary disposition against Supply Corporation with the FERC. The complainants alleged that Supply Corporation’s rates were unjust and unreasonable, and that Supply Corporation was permitted to retain more gas from shippers than it needed for fuel and loss. It also asked FERC to determine whether Supply Corporation had the authority to make sales of gas retained from shippers (which are referred to under “Results of Operations” as “unbundled pipeline sales”). On September 26, 2006, the active parties


26

     Another event, which occurred


reached a settlement in 2003principle. On November 17, 2006, Supply Corporation filed a motion asking FERC to approve an uncontested settlement of the proceeding. The proposed settlement would be implemented when and if FERC approves the settlement, but if approved would be effective as of December 1, 2006. This matter, including the primary elements of the settlement, is discussed more fully in Item 8 at Note J – Acquisitions, is the acquisition of all of the partnership interests in Toro Partners, L.P. (Toro). The Company has been successful in operating landfill gas projects, where the gas is used to generate electricity,Rate and this acquisition allows the Company to operate short-distance landfill gas pipelinesRegulatory Matters section that purchase, transport and resell landfill gas to customers.

     Overall, the Company emphasized debt reduction in 2004 and, to that end, has reduced its debt to capitalization ratio from .57 at September 30, 2003 to .51 at September 30, 2004.

follows.

CRITICAL ACCOUNTING POLICIESESTIMATES

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

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

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

In addition to depletion under theunits-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SECRegulation S-X RuleS-XRule 4-10. The ceiling test is performed on acountry-by-country basis and determines a limit, or ceiling, to the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net revenues using a discount factor of 10%, which is computed by applying current market prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income taxes. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions or subtractions to proved reserves and significant fluctuations in oil and gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment must be recorded to write down the book value of the reserves to their present


27


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-downwrite down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. The Company recorded non-cash impairments relating to its Canadian properties in 2003 which amounted to $28.9 million (after tax) and resulted from downward revisions to crude oil reserves (related toBecause of the Canadian properties sold) as well as a decline in crude oil prices subsequent to the March 31, 2003 ceiling test calculation. At September 30, 2003,price of natural gas during the capitalized coststhird and fourth quarters of 2006, the book value of the Company’s Canadian oil and gas properties less accumulated depletion and related deferred taxes were nearly equal to the ceiling for Canadian oil and gas properties. During 2004, the Canadian oil and gas properties passed the quarterly ceiling tests but capitalized costs less accumulated depletion and related deferred taxes were still nearly equal toexceeded the ceiling at both June 30, 2006 and September 30, 2004. A downward revision to2006. Consequently, SECI recorded impairment charges of $62.4 million ($39.5 million after-tax) in the third quarter of 2006 and $42.3 million ($29.1 million after-tax) in the fourth quarter of 2006. Further decreases in the price of natural gas, absent the addition of new reserves, or prices could result in an impairment of the Canadian oil and gas properties in the future.

future impairments.*

It is difficult to predict what factors could lead to future impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations or subtractions to proved reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.

Regulation.  The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to Statement of Financial Accounting Standards No.SFAS 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

21


and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note BC — Regulatory Matters.

Accounting for Derivative Financial Instruments.  The Company, in its Exploration and Production segment, Energy Marketing segment, Pipeline and Storage segment and All Other Category,category, uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments are categorized as price swap agreements, no cost collars, options and futures contracts. The Company, in its Pipeline and Storage segment, uses an interest rate collar to limit interest rate fluctuations on certain variable rate debt. In accordance with the provisions of Statement of Financial Accounting Standards No.SFAS 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 based on the effectiveness testing,mark-to-marketgains or losses from the derivative financial instruments would be marked-to-market onrecognized in the income statement without regard to an underlying physical transaction.

As discussed below, the Company was required to discontinue hedge accounting for a portion of its derivative financial instruments, resulting in a charge to earnings in 2005.

The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The fair value of the non exchange-traded derivative financial instruments are based on valuations determined by the counterparties. Refer to the “Market Risk Sensitive Instruments” section in Item 7, MD&A,below for further discussion of the Company’s derivative financial instruments.

Pension and Other Post-Retirement Benefits.  The amounts reported in the Company’s financial statements related to its pension and other post-retirement benefits are determined on an actuarial basis, which uses many assumptions in the calculation of such amounts. These assumptions include the discount rate, the expected return on plan assets, the rate of compensation increase and, for other post-retirement benefits, the expected annual rate of increase in per capita cost of covered medical and prescription benefits. The discount rate used by the Company is equal to the Moody’s Aa Long-Term Corporate Bond index, rounded to the nearest 25 basis points. The duration of the securities underlying that index (approximately 13 years) reasonably matches the


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expected timing of anticipated future benefit payments (approximately 12 years). The expected return on plan assets assumption used by the Company reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets. Changes in actuarial assumptions and actuarial experience could have a material impact on the amount of pension and post-retirement benefit costs and funding requirements experienced by the Company.* However, the Company expects to recover substantially all of its net periodic pension and other post-retirement benefit costs attributable to employees in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization.* For financial reporting purposes, the difference between the amounts of pension cost and post-retirement benefit cost recoverable in rates and the amounts of such costs as determined under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate, as discussed above under “Regulation.”

Pension and post-retirement benefit costs for the Utility and Pipeline and Storage segments represented 96% and 97%, respectively, of the Company’s total pension and post-retirement benefit costs as determined under SFAS 87 and SFAS 106 for the years ended September 30, 2006 and September 30, 2005.

Changes in actuarial assumptions and actuarial experience could also have an impact on the benefit obligation and the funded status related to the Company’s pension and post-retirement benefit plans and could impact the Company’s equity. For example, the discount rate used to determine benefit obligations was changed from 5.0% in 2005 to 6.25% in 2006. The change in the discount rate reduced the pension plan projected benefit obligation by $113.1 million and the accumulated post-retirement benefit obligation by $77.5 million. As a result of the discount rate change, the Company no longer had to record a minimum pension liability adjustment at September 30, 2006, resulting in an increase to other comprehensive income of $107.8 million, as shown in the Consolidated Statement of Comprehensive Income. Other examples include actual versus expected return on plan assets, which has an impact on the funded status of the plans, and actual versus expected benefit payments, which has an impact on the pension plan projected benefit obligations and the accumulated post-retirement benefit obligation for the Post-Retirement Plan. For 2006, actual versus expected return on plan assets resulted in an increase to the funded status of the Retirement Plan and the Post-Retirement Plan of $18.7 million and $12.5 million, respectively. The actual versus expected benefit payments for 2006 caused a decrease of $1.0 million and $0.3 million to the projected benefit obligation and accumulated post-retirement benefit obligation, respectively. In calculating the projected benefit obligation for the Retirement Plan and the accumulated post-retirement obligation for the Post-Retirement Plan, the actuary takes into account the average remaining service life of active participants. The average remaining service life of active participants in the Retirement Plan is 10 years. The average remaining service life of active participants in the Post-Retirement Plan is 9 years. For further discussion of the Company’s pension and other post-retirement benefits, refer to Other Matters in this Item 7 and to Item 8 at Note G — Retirement Plan and Other Post Retirement Benefits.
RESULTS OF OPERATIONS

EARNINGS

20042006 Compared with 20032005

The Company’s earnings were $166.6$138.1 million in 20042006 compared with earnings of $178.9$189.5 million in 2003.2005. As previously discussed, the Company presented its Czech Republic operations as discontinued operations in conjunction with the sale of U.E. The Company’s earnings from continuing operations were $138.1 million in 2006 compared with $153.5 million in 2005. The Company’s earnings from discontinued operations were zero in 2006 compared with $36.0 million in 2005. The decrease in earnings from continuing operations of $15.4 million is primarily the result of lower earnings in the TimberExploration and UtilityProduction and Pipeline and Storage segments partially offset somewhat by higher earnings in the ExplorationUtility segment, Energy Marketing segment, Timber segment, and Production, International,All Other category and Pipeline and Storage

22


segments,a lower loss in the Corporate category, as shown in the table below. The decrease in earnings from discontinued operations reflects the non-recurrence of the gain on the sale of U.E. recognized in 2005. In the discussion that follows, note that all amounts used in the earnings discussions are


29


after tax amounts. Earnings from continuing operations and discontinued operations were impacted by several events in 20042006 and 2003,2005, including:
 
20042006 Events

• $68.6 million of impairment charges related to the Exploration and Production segment’s Canadian oil and gas assets under the full cost method of accounting using natural gas pricing at June 30, 2006 and September 30, 2006;
• An $11.2 million benefit to earnings in the Exploration and Production segment related to income tax adjustments recognized during 2006; and
• A $2.6 million benefit to earnings in the Utility segment related to the correction of a regulatory mechanism calculation.
2005 Events
• A $25.8 million gain on the sale of U.E., which was completed in July 2005. This amount is included in earnings from discontinued operations;
• A $2.6 million gain in the Pipeline and Storage segment associated with a FERC approved sale of base gas;
• A $3.9 million gain in the Pipeline and Storage segment associated with insurance proceeds received in prior years for which a contingency was resolved during 2005;
• A $3.3 million loss related to certain derivative financial instruments that no longer qualified as effective hedges;
• A $2.7 million impairment in the value of the Company’s 50% investment in ESNE (recorded in the All Other category), a limited liability company that owns an 80-megawatt, combined cycle, natural gas-fired power plant in the town of North East, Pennsylvania; and
• A $1.8 million impairment of a gas-powered turbine in the All Other category that the Company had planned to use in the development of a co-generation plant.
2005 Compared with 2004
The Company’s earnings were $189.5 million in 2005 compared with earnings of $166.6 million in 2004. As previously discussed, the Company has presented its Czech Republic operations as discontinued operations. The Company’s earnings from continuing operations were $153.5 million in 2005 compared with $154.3 million in 2004. The Company’s earnings from discontinued operations were $36.0 million in 2005 compared with $12.3 million in 2004. Earnings from continuing operations did not change significantly as higher earnings in the Pipeline and Storage segment were largely offset by lower earnings in the Utility and Exploration and Production segments and a higher loss in the All Other category. The increase in earnings from discontinued operations resulted from the gain on the sale of U.E. in 2005. Earnings from continuing operations and discontinued operations were impacted by the 2005 events discussed above and the following 2004 events:
2004 Events
 • A $5.2 million reduction to deferred income tax expense in the International segment resulting from a change in the statutory income tax rate in the Czech Republic;Republic. This amount is included in earnings from discontinued operations;
 
 • Settlement of a pension obligation which resulted in the recording of additional expense amounting to $6.4 million, after tax, allocated among the segments as follows: $2.2 million to the Utility segment ($1.2 million in the New York jurisdiction and $1.0 million in the Pennsylvania jurisdiction), $2.0 million to the Pipeline and Storage segment ($1.8 million to Supply Corporation and $0.2 million to Empire State Pipeline), $0.9 million to the Exploration and Production segment, $0.4 million to the International segment, $0.3 million to the Energy Marketing segment and $0.6$1.0 million to the Corporate and All Other categories;


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 • An adjustment to the 2003 sale of the Company’s Southeast Saskatchewan oil and gas properties in the Exploration and Production segment which increased 2004 earnings by $4.6 million; and
 
 • An adjustment to the Company’s 2003 sale of its timber properties in the Timber segment, which reduced 2004 earnings by $0.8 million after tax.million.
 
2003 Events

• The Company’s Timber segment completed the sale of approximately 70,000 acres of its timber property, recording an after tax gain of $102.2 million;
• The Company’s Exploration and Production segment completed the sale of its Southeast Saskatchewan oil and gas properties in Canada, recording an after tax loss of $39.6 million;
• The Company’s Exploration and Production segment recorded after tax impairment charges of $28.9 million related to its Canadian oil and gas assets;
• An impairment in the amount of $8.3 million, representing the cumulative effect of a change in accounting for goodwill in the Company’s International segment; and
• A reduction in the amount of $0.6 million, representing the cumulative effect of a change in accounting for plugging and abandonment costs in the Company’s Exploration and Production segment.

     For a more complete discussion of the cumulative effect of changes in accounting, refer to Note A — Summary of Significant Accounting Policies in Item 8 of this report.

Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.

2003 Compared with 2002

     The Company’s earnings were $178.9 million in 2003 compared with earnings of $117.7 million in 2002. The increase in earnings of $61.2 million was primarily the result of higher earnings in the Timber, Utility, and Pipeline and Storage segments partially offset by lower earnings in the Energy Marketing segment and losses in the Exploration and Production and International segments, as shown in the table below. This earnings fluctuation was impacted by the 2003 events listed above. Also, in 2002, earnings included a non-cash impairment of the Company’s investment in the Independence Pipeline project in the Pipeline and Storage segment in the amount of $9.9 million (after tax). Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.

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Earnings (Loss) by Segment
              
Year Ended September 30

200420032002



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

             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Utility $49,815  $39,197  $46,718 
Pipeline and Storage  55,633   60,454   47,726 
Exploration and Production  20,971   50,659   54,344 
Energy Marketing  5,798   5,077   5,535 
Timber  5,704   5,032   5,637 
             
Total Reportable Segments  137,921   160,419   159,960 
All Other  359   (2,616)  1,530 
Corporate(1)  (189)  (4,288)  (7,225)
             
Total Earnings from Continuing Operations $138,091  $153,515  $154,265 
             
Earnings from Discontinued Operations     35,973   12,321 
             
Total Consolidated $138,091  $189,488  $166,586 
             
(1)Includes earnings from the former International segment’s activity other than the activity from the Czech Republic operations included in Earnings from Discontinued Operations.
UTILITY

Revenues

Utility Operating Revenues
              
Year Ended September 30

200420032002



(Thousands)
Retail Revenues:            
 Residential $808,740  $801,984  $538,345 
 Commercial  137,092   137,905   86,963 
 Industrial  17,454   23,263   18,332 
   
   
   
 
   963,286   963,152   643,640 
   
   
   
 
Off-System Sales  106,841   107,220   68,606 
Transportation  80,563   86,374   83,267 
Other  1,951   6,237   (1,292)
   
   
   
 
  $1,152,641  $1,162,983  $794,221 
   
   
   
 
             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Retail Revenues:            
Residential $993,928  $868,292  $808,740 
Commercial  166,779   145,393   137,092 
Industrial  13,484   13,998   17,454 
             
   1,174,191   1,027,683   963,286 
             
Off-System Sales        106,841 
Transportation  92,569   83,669   80,563 
Other  14,003   5,715   1,951 
             
  $1,280,763  $1,117,067  $1,152,641 
             


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Utility Throughput — million cubic feet (MMcf)
              
Year Ended September 30

200420032002



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

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  Year Ended September 30 
  2006  2005  2004 
 
Retail Sales:            
Residential  59,443   66,903   70,109 
Commercial  10,681   11,984   12,752 
Industrial  985   1,387   2,261 
             
   71,109   80,274   85,122 
             
Off-System Sales        16,839 
Transportation  57,950   59,770   60,565 
             
   129,059   140,044   162,526 
             
Degree Days
                     
Percent (Warmer)
Colder Than

Year Ended September 30NormalActualNormalPrior Year





2004:  Buffalo   6,729   6,572   (2.3)%  (7.9)%
   Erie   6,277   6,086   (3.0)%  (10.1)%
2003:  Buffalo   6,815   7,137   4.7%  22.9%
   Erie   6,135   6,769   10.3%  26.9%
2002:  Buffalo   6,847   5,808   (15.2)%  (12.6)%
   Erie   6,146   5,334   (13.2)%  (16.0)%

                     
           Percent (Warmer)
 
           Colder Than 
Year Ended September 30
    Normal  Actual  Normal  Prior Year 
 
2006:  Buffalo   6,692   5,968   (10.8)%  (9.4)%
   Erie   6,243   5,688   (8.9)%  (8.9)%
2005:  Buffalo   6,692   6,587   (1.6)%  0.2%
   Erie   6,243   6,247   0.1%  2.6%
2004:  Buffalo   6,729   6,572   (2.3)%  (7.9)%
   Erie   6,277   6,086   (3.0)%  (10.1)%
20042006 Compared with 20032005

Operating revenues for the Utility segment decreased $10.3increased $163.7 million in 20042006 compared with 2003.2005. This increase largely resulted largely from a decrease$146.5 million increase in transportationretail gas sales revenues. Transportation revenues of $5.8and other revenues also increased by $8.9 million and a decrease$8.3 million, respectively.
The increase in otherretail gas sales revenues of $4.3 million. Transportation revenues decreased because of lower volumes being transported as a result of fuel switching, a general economic downturn infor the Utility segment’s service territory and warmer weather, as shown in the degree day table above. Retail revenues did not change significantly from the prior year as the impact to revenues of lower retail sales volumessegment was largely offset bya function of the recovery of higher gas costs (gas costs are recovered dollar for dollar in revenues), which more than offset the revenue impact of lower retail sales volumes, as shown in the table above. See further discussion of purchased gas below under the heading “Purchased Gas.” Warmer weather, as shown in the table above, and greater conservation by customers due to higher natural gas commodity prices, were the principal reasons for the decrease in retail sales volumes.
The increase in transportation revenues was primarily due to a $5.9 million increase in the New York jurisdiction’s calculation of the symmetrical sharing component of the gas adjustment rate. The symmetrical sharing component is a mechanism included in Distribution Corporation’s New York rate settlement that shares with customers 90% of the difference between actual revenues received from large volume customers and the level of revenues that were projected to be received during the rate year. Of the $5.9 million increase, $3.9 million was due to anout-of-period adjustment recorded in fiscal year 2006 when it was determined that certain credits that had been included in the calculation should have been removed during the implementation of a previous rate case. The adjustment related to fiscal years 2002 through 2005.
The impact of the August 2005 New York rate case settlement was to increase operating revenues by $19.1 million (of which $12.4 million was an increase to other operating revenues). This increase consisted of a base rate increase, the implementation of a merchant function charge, the elimination of certain bill credits, and the elimination of the gross receipts tax surcharge. The settlement also allowed Distribution Corporation to continue to utilize certain refunds from upstream pipeline companies and certain other credits (referred to as the “cost mitigation reserve”) to offset certain specific expense items. In 2005, Distribution Corporation utilized


32


$7.8 million of the cost mitigation reserve, which increased other operating revenues, to recover previous under-collections of pension and post-retirement expenses. The impact of that increase in other operating revenues was offset by an equal amount of operation and maintenance expense (thus there was no earnings impact). Distribution Corporation did not record any entries involving the cost mitigation reserve in 2006. Other operating revenues was also impacted by twoout-of-period regulatory adjustments recorded during 2005. The first adjustment related to the final settlement with the Staff of the NYPSC of the earnings sharing liability for the 2001 to 2003 time period. As a result of that settlement, the New York rate jurisdiction recorded additional earnings sharing expense (as an offset to other operating revenues) of $0.9 million. The second adjustment related to a regulatory liability recorded for previous over-collections of New York State gross receipts tax. In preparing for the implementation of the settlement agreement in New York, the Company determined that it needed to adjust that regulatory liability by $3.1 million (of which $1.0 million was recorded as a reduction of other operating revenues and $2.1 million was recorded as additional interest expense) related to fiscal years 2004 and prior. These adjustments did not recur in 2006.
In the Pennsylvania jurisdiction, the impact of the base rate increase, which became effective in mid-April 2005, was to increase operating revenues by $7.5 million. This increase is included within both retail and transportation revenues in the table above.
2005 Compared with 2004
Operating revenues for the Utility segment’ssegment decreased $35.6 million in 2005 compared with 2004. This resulted primarily from the absence of off-system sales revenues of $106.8 million, offset by an increase of $64.4 million in retail revenues. Effective September 22, 2004, Distribution Corporation stopped making off-system sales as a result of the FERC’s Order 2004, “Standards of Conduct for Transmission Providers.” However, due to profit sharing with retail customers, the margins resulting from off-system sales have been minimal and there was not a material impact to margins in 2005. The increase in retail revenues was primarily the result of the recovery of higher gas costs (gas costs are recovered dollar for dollar in revenues), colder weather in the Pennsylvania jurisdiction.jurisdiction and the impact of base rate increases in both New York and Pennsylvania. The recovery of higher gas costs resulted from a much higher cost of purchased gas. See further discussion of purchased gas below under the heading “Purchased Gas.” Warmer weather andLower retail sales volumes, due primarily to lower customer usage per account, werepartially offset the major factors in the decreaseincrease in retail sales volumes. The decrease inrevenues associated with the recovery of higher gas costs and the base rate increases. Also, retail industrial sales volumes can be attributedrevenue declined due to fuel switching and production declines of certain large volume industrial customers as a result of a general economic downturn in the Utility segment’s service territory.

The decreaseincrease in other operating revenues of $3.8 million is largely related to amounts recorded pursuant to rate settlements with the three-year rate settlement approved by the NYPSC which ended on September 30, 2003. As part of the three-year rate settlement,NYPSC. In accordance with these settlements, Distribution Corporation was allowed to utilize certain refunds from upstream pipeline companies and certain other credits (referred to as the “cost mitigation reserve”) to offset certain specific expense items. In 2003, Distribution Corporation utilized $7.6 million of the cost mitigation reserve by recording $7.6 million of other operating revenues. While the three-year rate settlement was extended for an additional year, the provisions of the settlement which gave rise to the other operating revenues in 2003 did not continue in 2004, causing other operating revenues to decrease by $7.6 million in 2004. The impact of utilizing a portion of the cost mitigation reserve in revenues in 2003 was offset by an equal amount of operation and maintenance expense and interest expense (thus there is no earnings impact). Partially offsetting this decrease in revenues, in accordance with the three-year rate settlement which ended on September 30, 2003, Distribution Corporation recorded a refund provision of $4.0 million as a reduction of other operating revenues. While the provisions of the settlement were extended for a one-year period, as previously discussed, this refund provision did not recur in 2004 because the New York rate jurisdiction’s earnings did not exceed the sharing threshold. The refund provision relates to a 50% sharing with customers of earnings over a predetermined amount.

     Effective September 22, 2004, Distribution Corporation stopped making off-system sales as a result of the FERC’s Order 2004, “Standards of Conduct for Transmission Providers,”items, as discussed more fully in the Rate Matters section below. As a result of this decision, Distribution Corporation most likely will not have any off-system sales in 2005.* However, due to profit sharing with retail customers, the margins resulting from off-system sales have been minimal and there should be no material impact to margins in 2005.*

2003 Compared with 2002

     Operating revenues for the Utility segment increased $368.8 million in 2003 compared with 2002. This resulted from an increase in retail and off-system gas sales revenues of $319.5 million and $38.6 million, respectively. Transportation and other revenues also increased by $3.1 million and $7.5 million, respectively.

25


     The increase in retail gas sales revenues for the Utility segment was largely a function of the recovery of higher gas costs, coupled with an increase in retail sales volumes, as shown above. The increase in retail sales volumes was primarily the result of colder weather, as shown in the degree day table above. Off-system sales revenues increased because of higher gas prices, which more than offset lower volumes. However, due to profit sharing with retail customers, the margins resulting from off-system sales were minimal. Colder weather also caused transportation revenues and volumes to increase.

     The increase in other operating revenues is largely related to the three-year rate settlement which ended on September 30, 2003, as discussed above. In 2003, Distribution Corporation utilized $7.6 million of the cost mitigation reserve by recording $7.6 million of other operating revenues, compared to $2.2 million in 2002. In both years, the impact of reversing a portion of the cost mitigation reserve was offset by an equal amount of operation and maintenance expense and interest expense (thus there is no earnings impact). The increase in other operating revenues also reflects a $1.3 million decrease in refund provisions. In accordance with the three-year rate settlement discussed above, Distribution Corporation recorded refund provisions related to a 50% sharing with customers of earnings over a predetermined amount. The refund provisions associated with this earnings sharing mechanism were $4.0 million and $5.3 million in 2003 and 2002, respectively.

Earnings

2004 Compared with 2003

     The Utility segment’s earnings in 2004 were $46.7 million, a decrease of $10.1 million when compared with earnings of $56.8 million in 2003. The major factors driving this decrease were an increase in pension and other post-retirement expenses of $9.9 million after tax, higher bad debt expenses of $3.8 million after tax, warmer weather in the Pennsylvania jurisdiction ($2.5 million after tax), and lower usage per customer account in the New York jurisdiction ($2.2 million after tax). These negative factors were partially offset by the absence of a refund provision in the New York jurisdiction in 2004 related to an earnings sharing mechanism in the New York jurisdiction ($2.6 million after tax), as discussed above. Other offsetting factors included a base rate increase in the Pennsylvania jurisdiction of $1.5 million after tax and lower interest expense of $4.7 million after tax.

     The increase in pension and other post-retirement expenses referred to above can be attributed largely to three factors. First, in accordance with the one-year settlement extension commencing on October 1, 2003 in the New York rate jurisdiction (referred to above), the Company was required to record an additional $8.0 million before tax ($5.2 million after tax) of pension and other post-retirement expense for the year ended September 30, 2004 without a corresponding increase in revenues. Second, the Utility segment recorded $2.2 million of expense after tax associated with the settlement of a pension obligation. Third, pension and other post-retirement expenses in the Pennsylvania rate jurisdiction increased by $2.5 million after tax as the rate settlement in that jurisdiction reflected higher pension funding amounts and the amortization of previous other post-retirement deferrals.

     The impact of weather on the Utility segment’s New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC, which covers the eight month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. In 2004, the WNC preserved $1.0 million of earnings since the weather was warmer than normal in the New York service territory. For 2003, the WNC reduced earnings by approximately $3.8 million because it was colder than normal in the New York service territory.

2003 Compared with 2002

     The Utility segment’s earnings in 2003 were $56.8 million, an increase of $7.3 million when compared with earnings of $49.5 million in 2002. The major factor driving this increase was the impact of colder weather in the Utility segment’s Pennsylvania jurisdiction, which contributed approximately $5.6 million to

26


the increase in earnings. The remainder of the increase was primarily attributable to lower interest expense, primarily on deferred gas costs (which declined approximately $1.0 million after tax).

     In 2003, the WNC reduced earnings by approximately $3.8 million because it was colder than normal in the New York service territory. For 2002, the WNC preserved earnings of approximately $9.9 million because it was warmer than normal in the New York service territory.

Purchased Gas

The cost of purchased gas is the Company’s single largest operating expense. Annual variations in purchased gas costs are attributed directly to changes in gas sales volumes, the price of gas purchased and the operation of purchased gas adjustment clauses.

Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation and six other upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers, and for storage service with Supply Corporation and three nonaffiliated companies. In addition, Distribution Corporation satisfies a portion of its gas requirements through spot market purchases. Changes in wellhead prices have a direct impact on the cost of purchased gas. Distribution Corporation’s average cost of purchased gas, including the cost of transportation and storage, was $7.30$12.07 per thousand cubic feet (Mcf)Mcf in 2004,2006, an increase of 5%31% from the average cost of $6.94$9.19 per Mcf in 2003.2005. The average cost of purchased gas in 20032005 was 48%26% higher than the average cost of $4.68$7.30 per Mcf in 2002.2004. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.


33


Earnings
2006 Compared with 2005
The Utility segment’s earnings in 2006 were $49.8 million, an increase of $10.6 million when compared with earnings of $39.2 million in 2005.
In the New York jurisdiction, earnings increased by $9.2 million, primarily due to the positive impact of the rate case settlement in this jurisdiction that became effective August 2005 ($13.7 million). In addition, the increase in the New York jurisdiction’s calculation of the symmetrical sharing component of the gas adjustment rate, including theout-of-period adjustment discussed above, contributed $3.9 million to earnings. Twoout-of-period regulatory adjustments recorded during fiscal year 2005 that did not recur during 2006, as discussed above, also contributed an additional $2.6 million to earnings. The first adjustment, related to the final settlement with the Staff of the NYPSC of the earnings sharing liability for the fiscal 2001 through 2003 time period, increased earnings in fiscal 2006 by $0.6 million. The second adjustment, related to a regulatory liability recorded for previous over-collections of New York State gross receipts tax, increased earnings in fiscal 2006 by $2.0 million. The increase in earnings due to the New York rate case settlement, the symmetrical sharing component of the gas adjustment rate, and the twoout-of-period regulatory adjustments recorded in 2005, was partially offset by a decline in margin associated with lower weather-normalized usage by customers ($2.3 million), higher operation expenses ($2.5 million), higher interest expense ($2.7 million), and a higher effective income tax rate ($3.2 million). The higher effective income tax rate is due to positive tax adjustments recorded in 2005 that did not recur in 2006. The increase in operation expenses consisted primarily of higher pension expense offset by lower bad debt expense.
In the Pennsylvania jurisdiction, earnings increased by $1.4 million, due to the positive impact of the rate case settlement in this jurisdiction that became effective April 2005 ($4.9 million), and lower operation expenses ($1.8 million). The decrease in operation expenses consisted primarily of lower bad debt expense offset partially by higher pension expense. These increases to earnings were partially offset by the impact of warmer than normal weather in Pennsylvania ($3.0 million), lower weather-normalized usage by customer ($0.6 million), higher interest expense ($0.8 million), and a higher effective tax rate ($1.3 million).
The decrease in bad debt expense reflects the fact that in the fourth quarter of 2005, the New York and Pennsylvania jurisdictions increased the allowance for uncollectible accounts to reflect the increase in final billed account balances and the increased aging of outstanding active receivables heading into the heating season. A similar adjustment was not required in 2006.
The impact of weather on the Utility segment’s New York rate jurisdiction is tempered by a WNC. The WNC, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. In 2006, the WNC preserved earnings of approximately $6.2 million because it was warmer than normal in the New York service territory. In 2005, the WNC did not have a significant impact on earnings.
2005 Compared with 2004
The Utility segment’s earnings in 2005 were $39.2 million, a decrease of $7.5 million when compared with earnings of $46.7 million in 2004. The major factors driving this decrease were lower weather-normalized usage per customer account in both the New York and Pennsylvania jurisdictions ($8.2 million) and an increase in bad debt expenses of $6.7 million. The increase in bad debt expenses is attributable to the increase in the allowance for uncollectible accounts to reflect the increase in final billed balances, as well as the increased age of outstanding receivables heading into the heating season. These negative factors were partially offset by the impact of base rate increases in both New York and Pennsylvania ($3.9 million) and the recording of accrued interest on a pension related asset in accordance with the New York rate case settlement agreement ($2.4 million), as well as the impact of colder than normal weather in Pennsylvania ($1.0 million). The earnings impact of the twoout-of-period regulatory adjustments discussed above was largely offset by lower interest expense on borrowings due to lower debt balances.


34


In 2005, the WNC did not have a significant impact on earnings. For 2004, the WNC preserved earnings of approximately $1.0 million because it was warmer than normal in the New York service territory.
PIPELINE AND STORAGE

Revenues

Pipeline and Storage Operating Revenues
             
Year Ended September 30

200420032002



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

             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Firm Transportation $118,551  $117,146  $120,443 
Interruptible Transportation  4,858   4,413   3,084 
             
   123,409   121,559   123,527 
             
Firm Storage Service  66,718   65,320   63,962 
Interruptible Storage Service  39   267   20 
             
   66,757   65,587   63,982 
             
Other  24,186   28,713   22,198 
             
  $214,352  $215,859  $209,707 
             
Pipeline and Storage Throughput — (MMcf)
             
Year Ended September 30

200420032002



Firm Transportation  338,991   340,925   290,507 
Interruptible Transportation  12,692   10,004   7,315 
   
   
   
 
   351,683   350,929   297,822 
   
   
   
 

27


             
  Year Ended September 30 
  2006  2005  2004 
 
Firm Transportation  363,379   357,585   338,991 
Interruptible Transportation  11,609   14,794   12,692 
             
   374,988   372,379   351,683 
             
20042006 Compared with 20032005

Operating revenues for the Pipeline and Storage segment increased $8.3decreased $1.5 million in 20042006 as compared with 2003. The acquisition2005. This decrease consisted of Empire from Duke Energy Corporation on February 6, 2003 was a significant factor contributing to the revenue increase. For 2004, Empire recorded operating$4.5 million decrease in other revenues of $33.4offset by a $1.8 million ($32.3 millionincrease in firm transportation revenues, $0.3 million inand interruptible transportation revenues and $0.8a $1.2 million increase in firm and interruptible storage service revenues. The decrease in other revenues). For the period of February 6, 2003revenues is primarily due to September 30, 2003, Empire recorded operating revenues of $20.9a $2.6 million ($19.8 million in firm transportation revenues, $0.8 million in interruptible transportation revenues and $0.3 million in other revenues). Another factor contributing to the increase in operating revenues in the Pipeline and Storage segment was a $5.0 million increasedecrease in revenues from unbundled pipeline sales, included in other revenues in the table above due to higherlower natural gas commodity prices, and higher volumes. These increases to operating revenues were partially offset by lower intercompany rental income of approximately $6.5as well as a $0.7 million and lowerdecrease in cashout revenues of $1.3 million, both of which are included in other revenues in the table above. Cashout revenues represent a cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper.revenues. Cashout revenues are completely offset by purchased gas expense. The increase in firm and interruptible transportation revenues is due to additional contracts with customers and the renewal of contracts at higher rates, both of which reflect the increased demand for transportation services due to market conditions resulting from the effects of hurricane damage to production and pipeline infrastructure in the Gulf of Mexico during the fall of 2005. While Supply Corporation’s transportation volumes increased during the year, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight fixed-variable rate design.

The increase in storage revenues reflects the renewal of storage contracts at higher rates.

20032005 Compared with 20022004

Operating revenues for the Pipeline and Storage segment increased $34.0$6.2 million in 20032005 as compared with 2002. For 2003, the acquisition of Empire was a significant factor contributing2004. This increase is primarily attributable to the revenue increase. For the period of February 6, 2003 to September 30, 2003, Empire recorded operating revenues of $20.9 million. Another factor contributing to the increase in operating revenues in the Pipeline and Storage segment was a $6.5 million increase inhigher revenues from unbundled pipeline sales of $5.5 million included in other revenues in the table above, due primarily to higher natural gas commodity pricesprices. Higher cashout revenues of $1.1 million, reported as part of other revenues in the table above, also contributed to the increase. Cashout revenues are completely offset by purchased gas expense. In addition, interruptible transportation revenues increased by $1.3 million, primarily due to an increase in Supply Corporation’s gathering revenues, and volumes.firm


35


storage revenues increased $1.4 million, primarily due to higher rate agreements contracted with Supply Corporation customers. Offsetting these increases, the decrease in firm transportation revenues of $3.3 million reflects the cancellation of contracts with Supply Corporation by certain large usage non-affiliated customers ($2.6 million) and the Utility segment’s cancellation of a portion of its firm transportation with Supply Corporation in April 2005 ($0.6 million). In addition, firm transportation revenues decreased by $1.0 million because Supply Corporation no longer charges customers a surcharge for its membership to the Gas Research Institute (GRI). The decrease in revenues resulting from cancellation of the GRI surcharge was completely offset by lower operation expense. While Supply Corporation’s transportation volumes increased during the year, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight fixed-variable rate design.

Offsetting the decreases in Supply Corporation’s firm transportation revenues was a $1.0 million increase in Empire’s firm transportation revenues, primarily due to an increase in transportation volumes.

Earnings

20042006 Compared with 20032005

The Pipeline and Storage segment’s earnings in 20042006 were $47.7$55.6 million, an increasea decrease of $2.5$4.9 million when compared with earnings of $45.2$60.5 million in 2003.2005. The increase can be attributed primarily todecrease reflects the non-recurrence of two events, a $2.6 million gain on a FERC approved sale of base gas in 2005 and a $3.9 million gain associated with insurance proceeds received in prior years for which a contingency was resolved in 2005. Both of these items were recorded in Other Income. It also reflects the earnings impact of the increase inassociated with lower revenues from unbundled pipeline sales ($1.7 million) and higher operation expenses ($0.6 million). These earnings decreases were offset by the positive earnings impact of $3.2higher transportation and storage revenues ($2.0 million), lower depreciation due to the non-recurrence of a write-down of the Company’s former corporate office in 2005 ($0.9 million), and the earnings benefit associated with a lower effective tax rate ($1.7 million).
2005 Compared with 2004
The Pipeline and Storage segment’s earnings in 2005 were $60.5 million, after tax, discussed above, as well asan increase of $12.8 million when compared with earnings of $47.7 million in 2004. Contributing to the increased earnings contributionincrease was a gain of $3.9 million associated with the insurance proceeds received in prior years for which a contingency was resolved during 2005. The other main factors contributing to the increase were higher revenues from Empire of $2.8 million. Also, Supply Corporationunbundled pipeline sales ($3.6 million), lower interest expense decreased by $1.9 million after tax. Offsetting these increases, Supply Corporation recorded $1.8($2.4 million), $2.0 million of expense after taxthat did not recur in 2005 associated with the settlement of a pension obligation recognized in 2004. Supply Corporation also experienced an earnings impact2004, as well as a $2.6 million gain on the FERC approved sale of base gas in March, 2005. An increase in the reserve for preliminary project costs associated with higher operation and maintenance expense of $1.5 million after tax.

2003 Compared with 2002

     The Pipeline and Storage segment’s earnings in 2003 were $45.2 million, an increase of $15.5 million when compared with earnings of $29.7 million in 2002. A major factor in the earnings increase was the fact that 2002 included an after tax impairment charge of $9.9 millionEmpire Connector project ($15.2 million pre tax) related to the Company’s investment in Independence Pipeline Company (a partnership discontinued in 2002 that had proposed to construct and operate a 400-mile pipeline to transport natural gas from Defiance, Ohio to Leidy, Pennsylvania). Higher revenues from unbundled pipeline sales ($4.2 million after tax) were also a contributor to the earnings increase. The Empire acquisition in February 2003 contributed $3.0 million to 2003 earnings.

28


1.8 million) partially offset these increases.

EXPLORATION AND PRODUCTION

Revenues

Exploration and Production Operating Revenues
             
Year Ended September 30

200420032002



(Thousands)
Gas (after Hedging) $167,127  $150,982  $148,467 
Oil (after Hedging)  119,564   147,101   152,746 
Gas Processing Plant  28,614   28,879   16,995 
Other  1,815   1,308   6,627 
Intrasegment Elimination(1)  (23,422)  (22,956)  (13,855)
   
   
   
 
  $293,698  $305,314  $310,980 
   
   
   
 
             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Gas (after Hedging) $184,268  $181,713  $167,127 
Oil (after Hedging)  148,293   107,801   119,564 
Gas Processing Plant  42,252   36,350   28,614 
Other  3,771   (2,733)  1,815 
Intrasegment Elimination(1)  (31,704)  (29,706)  (23,422)
             
  $346,880  $293,425  $293,698 
             


36


(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 iswas made to reduce the gas processing plant’s purchased gasPurchased Gas expense.

Production Volumes
              
Year Ended September 30

200420032002



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

29


             
  Year Ended September 30 
  2006  2005  2004 
 
Gas Production(MMcf)
            
Gulf Coast  9,110   12,468   17,596 
West Coast  3,880   4,052   4,057 
Appalachia  5,108   4,650   5,132 
Canada  7,673   8,009   6,228 
             
   25,771   29,179   33,013 
             
Oil Production(Mbbl)
            
Gulf Coast  685   989   1,534 
West Coast  2,582   2,544   2,650 
Appalachia  69   36   20 
Canada  272   300   324 
             
   3,608   3,869   4,528 
             
Average Prices
              
Year Ended September 30

200420032002



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


             
  Year Ended September 30 
  2006  2005  2004 
 
Average Gas Price/Mcf
            
Gulf Coast $8.01  $7.05  $5.61 
West Coast $7.93  $6.85  $5.54 
Appalachia $9.53  $7.60  $5.91 
Canada $7.14  $6.15  $4.87 
Weighted Average $8.04  $6.86  $5.51 
Weighted Average After Hedging(1) $7.15  $6.23  $5.06 
Average Oil Price/Barrel (bbl)
            
Gulf Coast $64.10  $49.78  $35.31 
West Coast(2) $56.80  $42.91  $31.89 
Appalachia $65.28  $48.28  $31.30 
Canada $51.40  $42.97  $30.94 
Weighted Average $57.94  $44.72  $32.98 
Weighted Average After Hedging(1) $41.10  $27.86  $26.40 
(1)Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note EF — Financial Instruments in Item 8 of this report.
 
(2)Includes low gravity oil which generally sells for a lower price.

20042006 Compared with 20032005

Operating revenues for the Exploration and Production segment decreased $11.6increased $53.5 million in 20042006 as compared with 2003.2005. Oil production revenue after hedging decreased $27.5increased $40.5 million due primarily to a 2,209 Mbbl decline in production offset partly by higher


37


weighted average prices after hedging ($4.5613.24 per barrel). Most of theThis increase was offset slightly by a decrease in oil production occurred in Canada (a 2,058 Mbbl decrease) as a result of the September 2003 sale of the Company’s Southeast Saskatchewan properties, which is discussed below.(261,000 barrels). Gas production revenue after hedging increased $16.1$2.6 million. Increases in the weighted average price of gas after hedging ($0.590.92 per Mcf) more than offset an overall decrease in gas production. Most of theproduction (3,408 MMcf). The decrease in gas production occurred primarily in the Gulf Coast (an 845(a 3,358 MMcf decline), which is consistent withpartly attributable to last fall’s hurricane damage and partly attributable to the expected decline rates for the Company’s production in the region. Lower West Coast production (a 410 MMcf decline), down mainlyOther revenues increased $6.5 million largely due to the non-recurrence of a decline$5.1 millionmark-to-market adjustment, recorded in this segment’s South Lost Hills wells, was more than offset by a 454 MMcf increase2005, for losses on certain derivative financial instruments that no longer qualified as effective hedges due to the anticipated delays in Canadian gas production. The increase in Canadianoil and gas production is attributable to additional drilling in East Central Alberta. The decline in the South Lost Hills wells was attributable to the maturing of the wells.

volumes caused by Hurricane Rita.

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.

20032005 Compared with 20022004

Operating revenues for the Exploration and Production segment decreased $5.7$0.3 million in 20032005 as compared with 2002.2004. Oil production revenue after hedging decreased $5.6$11.8 million due to a 925,000 barrel659 Mbbl decline in production offset partly by higher weighted average prices after hedging ($1.901.46 per barrel). Most of the decrease in oil production occurred in the Gulf Coast Region (a 545 Mbbl decrease). Gas production revenue after hedging increased $2.5$14.6 million. Increases in the weighted average price of gas after hedging ($0.891.17 per Mcf) more than offset an overall decrease in gas production.production (3,834 MMcf). Most of the decrease in gas production occurred in the Gulf Coast (a 7,3355,128 MMcf decline). The Company had anticipated some of thisdecreases in Gulf Coast oil and gas production are consistent with the expected decline in gas and oil production due to reduced activityrates in the region. This decrease in Gulf Coast region. Other factors in the overallgas production decrease included an outside-operated offshore pipeline leak that required four key producing blocks to be shut-in for ten days, andwas partially offset by a decline in drilling activity in Canada related to a decision to sell the

30


Company’s Southeast Saskatchewan properties. Also, earlier in the year certain production in the Gulf Coast region was shut-in during Hurricane Lili and some of those wells did not return to pre-hurricane production levels. Gas processing plant revenues increased $11.9 million due to higher gas prices (because there is a similar1,781 MMcf increase in purchasedCanadian gas expense,production. The increase in Canadian gas production is attributable to the impact on earnings is insignificant).Sukunka 60-E well, in which the Company has a 20% working interest. Other revenues decreased $5.3$4.5 million largely due to the Exploration and Production segment experiencing negative a $5.1 millionmark-to-market adjustments adjustment for losses on certain derivative financial instruments that no longer qualified as effective hedges due to the anticipated delays in oil and gas production volumes caused by Hurricane Rita. These volumes were originally forecast to be produced in the first quarter of $1.9 million during 2003 compared2006.
Refer to positive mark-to-market adjustments onfurther discussion of derivative financial instruments of $2.7 million in 2002.the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.

Earnings

20042006 Compared with 20032005

The Exploration and Production segment’s earnings in 20042006 were $54.3$21.0 million, an increasea decrease of $86.2$29.7 million when compared with a lossearnings of $31.9$50.7 million in 2003. Earnings2005. The decrease is primarily the result of the impairment charges of $68.6 million on this segment’s Canadian oil and gas producing properties. Also, lower oil and gas production decreased earnings by $18.5 million. Further contributing to the decrease were impacted byhigher lease operating expenses ($3.2 million), higher general and administrative and other operating costs ($2.0 million) and higher depletion expense ($2.5 million). The increase in lease operating expenses was primarily in the West Coast region due to higher steaming costs associated with heavy crude oil production in the California Midway-Sunset and North Lost Hills fields. The higher steaming costs are due to an increase in the price for natural gas purchased in the field and used in the steaming operations, primarily in the second quarter of fiscal 2006, compared to the second quarter of fiscal 2005. Beginning in April 2006, a few events.scrubber facility in the Midway-Sunset field was in full operation and is burning waste gas rather than purchased gas to generate the steam for its thermal recovery project. It is anticipated that the scrubber facility will reduce steaming costs in the future.* The increase in depletion expense was mainly due to higher finding and development costs in the Canadian region, coupled with a 10.5 Bcfe downward revision of the proved reserve estimate (resulting in an increase to the per unit depletion rate) in this region in 2006. Partially offsetting these decreases, higher oil and gas prices, as discussed above, contributed $46.5 million to earnings. Also, the non-recurrence of the 2005mark-to-market adjustment discussed under Revenues above, contributed $3.3 million to earnings and strong cash flow provided higher interest income ($2.6 million). In 2003,the second quarter of 2006, a $5.1 million benefit to earnings


38


was realized for an adjustment to a deferred income tax balance. Under GAAP, a company may recognize the benefit of certain expected future income tax deductions as a deferred tax asset only if it anticipates sufficient future taxable income to utilize those deductions. As a result of the rise in commodity prices, the Company soldincreased its Southeast Saskatchewanforecast of future taxable income in the Exploration and Production segment’s Canadian division and, as a result, recorded a deferred tax asset for certain drilling costs that it now expects to deduct on future income tax returns. In the third quarter of 2006, a $6.1 million benefit to earnings related to income taxes was recognized. The Company reversed a valuation allowance ($2.9 million) associated with the capital loss carryforward that resulted from the 2003 sale of certain of Seneca’s oil properties, recording an afterand also recognized a tax lossbenefit of $39.6$3.2 million related to the favorable resolution of certain open tax issues.
2005 Compared with 2004
The Exploration and Production segment’s earnings in 2005 were $50.7 million, a decrease of $3.6 million when compared with earnings of $54.3 million in 2004. Lower oil and gas production, as discussed above, decreased earnings by $23.9 million. InAlso, in 2004, the Company recorded an adjustment to the sale of its Southeast Saskatchewan properties whichthat increased 2004 earnings by $4.6 million. WhenIn 2005, the transaction closedCompany recorded amark-to-market adjustment, as discussed above under “Revenues”, that decreased 2005 earnings by $3.3 million. Higher lease operating and depletion expenses also decreased 2005 earnings by $2.1 million and $0.6 million, respectively. The increase in September 2003,lease operating expenses resulted mainly from increased Canadian production and higher steaming costs associated with heavy crude oil production in the initial proceeds received were subjectWest Coast Region. Depletion expense increased despite a drop in production mostly due to an adjustment based on actual working capitalincrease in the per unit depletion rate, which was largely the result of the higher finding and the resolutiondevelopment costs experienced by Seneca in 2005. All of certain income tax matters. Those itemsthese factors, which collectively resulted in a $34.5 million decrease in 2005 earnings, were resolved with the buyer in 2004 and, as a result, the Company received an additional $4.6 million of sales proceeds. The Company recorded impairment charges of $28.9 million after tax in 2003 related to its Canadianpartially offset by higher oil and gas properties.prices, as discussed above, that contributed $25.9 million to earnings. Also, contributing to the increase was2005 earnings benefited from higher interest income ($1.8 million) and lower interest expense ($1.2 million). The fluctuations in interest income and interest expense reflect the fact that the loss in 2003 included a charge of $0.6 million representing the cumulative effect of a change in accounting for plugging and abandonment costs. These events sum up to $73.7 million of the overall earnings increase of $86.2 million. The remaining increase can be attributed to decreases in depletion, lease operating, and interest expense of $6.2 million after tax, $15.9 million after tax, and $1.7 million after tax, respectively, which more than offset the earnings impact of a $7.4 million decrease in oil and gas revenues, discussed above, and a $3.2 million increase in income tax expense due to a higher effective tax rate. The decrease in depletion and lease operating expenses primarily reflects the absence of the Company’s former Southeast Saskatchewan properties from results of operations in 2004. The decrease in interest expense was the result of lower debt balances. The higher effective tax rate resulted from the elimination of cross-border intercompany loans in September 2003 as a result of the sale of the Southeast Saskatchewan properties.

2003 Compared with 2002

     The Exploration and Production segment experienced a loss of $31.9 million in 2003, a decrease of $58.8 million when compared with earnings of $26.9 million in 2002. The main reason for this decrease was the loss of $39.6 million recorded upon the sale of the Company’s Southeast Saskatchewan oil and gas properties. During 2003, the Company reviewed the economics of its non-regulated business including certain oil and gas properties. The Southeast Saskatchewan properties were identified as a candidate for sale given their overall marginal contribution to earnings. Impairment charges of $28.9 million after tax recorded in 2003 related to the Company’s Canadian oil and gas assets also contributed to the decrease. Lower oil and gas revenues, as discussed above, decreased earnings by approximately $2.0 million. As an offset, the Exploration and Production segment experienced lower depletion expense of $2.9 million after tax (attributablehas been operating solely within its own cash flow from operations. Short-term borrowings have been eliminated and excess cash has been invested, resulting in higher interest income. This excess cash will be used to the production decline)fund operations and lowerfuture capital expenditures.* Lower general and administrative expenses, of $2.1 million after tax (attributablelargely due to cost-cutting efforts in Canada). Another offsetting factor was a lower effective income tax rate, which benefittedlegal costs, also increased 2005 earnings by approximately $3.4 million.

31


INTERNATIONAL

Revenues

International Operating Revenues

             
Year Ended September 30

200420032002



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

International Heating and Electric Volumes

             
Year Ended September 30

200420032002



Heating Sales (Gigajoules)(1)  8,538,554   8,766,567   8,689,887 
Electricity Sales (megawatt hours)  936,877   973,968   972,832 


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

2004 Compared with 2003

     Operating revenues for the International segment increased $9.4 million in 2004 as compared with 2003. Substantially all of this increase can be attributed to an increase in the value of the Czech koruna compared to the U.S. dollar.

2003 Compared with 2002

     Operating revenues for the International segment increased $18.8 million in 2003 as compared with 2002. Substantially all of this increase can be attributed to an increase in the value of the Czech koruna compared to the U.S. dollar.

Earnings

2004 Compared with 2003

     The International segment’s earnings in 2004 were $6.0 million, an increase of $15.6 million when compared with a loss of $9.6 million in 2003. Earnings were impacted by two events. During 2004, the government in the Czech Republic enacted legislation that gradually reduces the corporate statutory income tax rate from 31% to 24% over a three-year period commencing January 1, 2004. In accordance with accounting principles generally accepted in the United States of America (GAAP), the Company recorded the full benefit resulting from the change in the income tax rate ($5.2 million) as a reduction to deferred income tax expense during 2004. During 2003, the Company recorded a $8.3 million impairment charge resulting from the Company’s change in accounting for goodwill, as discussed below. These two events account for $13.5 million of the earnings increase in the International segment. An increase in the value of the Czech koruna compared to the U.S. dollar improved earnings by approximately $1.1 million.

2003 Compared with 2002

     The International segment experienced a loss of $9.6 million in 2003 compared with a loss of $4.4 million in 2002. This decrease can be attributed primarily to an $8.3 million impairment charge, resulting from the Company’s change in accounting for goodwill. The Company’s goodwill balance as of October 1, 2002 totaled $8.3 million and was related to the Company’s investments in the Czech Republic,

32


which are included in the International segment. In accordance with SFAS 142, “Goodwill and Other Intangible Assets” (SFAS 142), the Company stopped amortization of goodwill and tested its goodwill for impairment as of October 1, 2002. The Company used discounted cash flows to estimate the fair value of its goodwill at October 1, 2002 and determined that the goodwill had no remaining value. Based on projected restructuring in the Czech Republic electricity market, the Company could not be assured that the level of future cash flows from the Company’s investments in the Czech Republic would attain the level that was originally forecasted.* In accordance with SFAS 142, this impairment was reported as a cumulative effect of a change in accounting in the quarter ending December 31, 2002. Partially offsetting the negative impact of the impairment, an increase in the value of the Czech koruna compared to the U.S. dollar reduced the 2003 loss by approximately $1.0 million. Lower operating costs at the U.S. level (primarily lower project development costs and pension costs) further reduced the 2003 loss by approximately $1.0 million.

ENERGY MARKETING

Revenues

Energy Marketing Operating Revenues
             
Year Ended September 30

200420032002



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

             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Natural Gas (after Hedging) $496,769  $329,560  $283,747 
Other  300   154   602 
             
  $497,069  $329,714  $284,349 
             
Energy Marketing Volumes
             
Year Ended September 30

200420032002



Natural Gas — (MMcf)  41,651   45,135   33,042 

             
  Year Ended September 30 
  2006  2005  2004 
 
Natural Gas — (MMcf)  45,270   40,683   41,651 
20042006 Compared with 20032005

     Operating revenues for the Energy Marketing segment decreased $20.3 million in 2004 as compared with 2003. This decrease primarily reflects lower gas sales revenue due to lower throughput, which was the result of warmer weather and the loss of several large volume but low margin customers to other marketers.

2003 Compared with 2002

Operating revenues for the Energy Marketing segment increased $153.4$167.4 million in 20032006 as compared with 2002. This2005. The increase primarily reflects higher natural gas sales revenuecommodity prices that were recovered through revenues, and, to a lesser extent, an increase in throughput. The increase in throughput was due to the


39


addition of certain large commercial and industrial customers, which more than offset any decrease in throughput due to warmer weather and greater conservation by customers due to higher natural gas commodity prices. Higher volumes, which
2005 Compared with 2004
Operating revenues for the Energy Marketing segment increased $45.4 million in 2005 as compared with 2004. The increase primarily reflects an increase in the price of natural gas. Volumes were principally the result of the addition of several high volume but low margin customers and colder weather, also contributeddown compared to the increase in operating revenues.

prior year due to the loss of certain lower margin wholesale customers.

Earnings

20042006 Compared with 20032005

The Energy Marketing segmentsegment’s earnings in 20042006 were $5.5$5.8 million, an increase of $0.7 million when compared with earnings of $5.1 million in 2005. Despite warmer weather and greater conservation by customers, gross margin increased due to a number of factors, including higher volumes and the marketing flexibility associated with stored gas. The Energy Marketing segment’s contracts for significant storage and transportation volumes provided operational flexibility resulting in increased sales throughput and earnings. The increase in gross margin more than offset an increase in operation expense.
2005 Compared with 2004
The Energy Marketing segment’s earnings in 2005 were $5.1 million, a decrease of $0.4 million when compared with earnings of $5.9$5.5 million in 2003. While margins on gas sales improved slightly, this increase was offset by expenses associated with the settlement of a pension obligation and a higher effective tax rate.

2003 Compared with 2002

2004. The Energy Marketing segment earnings in 2003 were $5.9 million, a decrease of $2.7 million when compared with earnings of $8.6 million in 2002. This decrease primarily reflects lower margins oncaused by a reduction in the benefit of storage gas sales,

33


primarily dueand, to end of winter local distribution company operational constraints, combined with price volatility and weather related demand swings.a lesser extent, lower throughput.

TIMBER

Revenues

Timber Operating Revenues
             
Year Ended September 30

200420032002



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

             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Log Sales $23,077  $22,478  $21,790 
Green Lumber Sales  7,123   7,296   5,923 
Kiln Dry Lumber Sales  32,809   29,651   27,416 
Other  2,020   1,861   841 
             
  $65,029  $61,286  $55,970 
             
Timber Board Feet
             
Year Ended September 30

200420032002



(Thousands)
Log Sales  6,848   8,764   8,174 
Green Lumber Sales  9,552   11,913   12,878 
Kiln Dry Lumber Sales  15,020   13,300   10,794 
   
   
   
 
   31,420   33,977   31,846 
   
   
   
 

             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Log Sales  9,527   7,601   6,848 
Green Lumber Sales  10,454   10,489   9,552 
Kiln Dry Lumber Sales  16,862   15,491   15,020 
             
   36,843   33,581   31,420 
             
20042006 Compared with 20032005

     Operating revenues for the Timber segment did not change significantly in 2004 as compared with 2003. The decrease in log sales of $5.6 million was principally due to the Company’s August 2003 sale of approximately 70,000 acres of timber properties discussed below. However, kiln dry lumber sales increased $5.6 million due to an increase in activity at the Company’s mill operations. As a result of the sale of the timber properties, a larger percentage of timber processed in the Company’s mills is now purchased from third parties.

2003 Compared with 2002

Operating revenues for the Timber segment increased $8.8$3.7 million in 2003,2006 as compared with 2002. The2005. This increase can largely be chiefly attributed to higheran increase in kiln dry lumber sales of $3.2 million principally due to an increase in kiln dry cherry lumber sales volumes of 2.0 million board feet. Other kiln dry lumber sales volumes


40


decreased by 0.6 million board feet, but there was little impact to revenues. The addition of two new kilns in February 2005 allowed for greater processing capacity in 2006 as compared to 2005 since the kilns were in operation for all of 2006. Higher log sales revenue of $0.6 million also contributed to the increase in revenues. An increase in cherry export log sales as a result of greater market demand and an increase in saw log sales were the primary factors contributing to the increase. Offsetting these increases was a decline in cherry veneer log sales due to lower volumes of cherry veneer logs that command higher than average prices. Higherharvested because of unfavorable weather conditions.
2005 Compared with 2004
Operating revenues for the Timber segment increased $5.3 million in 2005 as compared with 2004. This increase can be partially attributed to an increase in kiln dry lumber sales also contributedof $2.2 million largely due to the increase. Partially offsetting thean increase in logcherry lumber sales andvolumes of 1.6 million board feet. While there was a decline in kiln dry lumber sales volumes from other species (1.1 million board feet), the revenue from those species is not significant. Cherry kiln dry lumber revenues decreased $2.5represent over 90% of the Timber segment’s total kiln dry lumber revenues. The increase in volume is a result of the addition of two new kilns as discussed above, allowing for an increase in the amount of kiln dry lumber that can be processed. In addition, green lumber sales also increased by $1.4 million due to increased sales of maple green lumber primarily because 2002 includedas a $2.4 million gain on the saleresult of standing timber.

favorable weather conditions that allowed for an increase in harvesting.

Earnings

20042006 Compared with 20032005

The Timber segment earnings in 20042006 were $5.6$5.7 million, a decreasean increase of $106.9$0.7 million when compared with earnings of $112.5$5.0 million in 2003. This2005. Higher margins from kiln dry lumber sales and cherry export log sales accounted for the earnings fluctuationincrease.
2005 Compared with 2004
The Timber segment earnings in 2005 were $5.0 million, a decrease of $0.6 million when compared with earnings of $5.6 million in 2004. Increases in the cost of goods sold during 2005 due to a greater amount of timber being harvested on purchased stumpage, which has a higher cost basis than other raw material sources, is largelyprimarily responsible for the earnings decline. Also contributing to the decline were overall increases in operating expenses due to higher utility costs. Partially offsetting these declines in earnings were the increased sales of kiln dry lumber and green lumber discussed above, as well as the favorable earnings impact associated with the non-recurrence of a reflection of$0.8 million loss recorded in 2004 related to the Company’s fiscal 2003 sale of timber properties discussed below. In 2003, the Company recorded a gain of $102.2 million after tax on that sale.properties. In 2004, the Company received final timber cruise information of the properties it sold in 2003 and, based on that information, determined that property records pertaining to $1.3 million ($0.8 million after tax) of timber property were not properly shown as having been transferred to the purchaser. As a result, the Company

34


removed those assets from its property records and adjusted the previously recognized gain downward by recognizing a pre tax loss of $1.3$0.8 million. The combination
ALL OTHER AND CORPORATE OPERATIONS
All Other and Corporate Operations primarily includes the operations of these two events caused earnings to be lower by $103.0 million. The remainder ofHorizon LFG, Horizon Power, former International segment activity other than the decrease is attributable to lower sales of cherry logs in 2004. While kiln dry lumber sales increased, this benefit was largely offset by an increase in costs associated with purchased timber.

2003 Compared with 2002

     The Timber segment earnings in 2003 were $112.5 million, an increase of $102.8 million when compared with earnings of $9.7 million in 2002. The increase wasactivity from the Czech Republic operations, and corporate operations. Horizon LFG owns and operates short-distance landfill gas pipeline companies. Horizon Power’s activity primarily due to the sale of approximately 70,000 acres of timber properties on August 1, 2003 for approximately $186.0 million. As a result of the sale, the Company recorded a gain of approximately $102.2 million after tax. After the August sale, the Company had approximately 87,000 acres of timber property remaining.

OPERATIONS OF UNCONSOLIDATED SUBSIDIARIES

     The Company’s unconsolidated subsidiaries consistconsists 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 CompanyESNE. Horizon Power has a 50% ownership interest in each of these entities. The income from these equity method investments is reported as Operations of Unconsolidated Subsidiaries on the Consolidated Statement of Income. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE generates electricity from an 80-megawatt, combined-cycle,combined cycle, natural gas-fired power plant in North East, Pennsylvania. Horizon Power also owns a gas-powered turbine and other assets which it had planned to use in the development of a co-generation plant. The Company is in the process of selling these


41


assets. The former International segment activity primarily consists of project development activities, the largest being projects in Italy and Bulgaria.
Earnings
2006 Compared with 2005
All Other and Corporate operations experienced income of $0.2 million in 2006, which was $7.1 million greater than a loss of $6.9 million in 2005. The increase is due primarily to the non-recurrence of $4.5 million of impairment charges recorded in 2005, as discussed below. Also contributing to the increase were higher interest income ($4.7 million) during 2006, resulting primarily from the investment of proceeds from the sale of U.E. in July 2005, combined with higher average interest rates in 2006 versus 2005. These increases were partially offset by higher operating expenses ($1.3 million) and lower margins on landfill gas sales ($0.5 million).
2005 Compared with 2004
All Other and Corporate operations experienced a loss of $6.9 million in 2005, which was $1.2 million greater than a loss of $5.7 million in 2004. During 2005, Horizon Power recorded a $2.7 million impairment in the value of its 50% investment in ESNE. Management determined that there was a decline in the fair market value of ESNE sells its electricity intothat was other than temporary in nature given continuing high commodity prices for natural gas and the negative impact these prices had on operations. ESNE has experienced losses over the last few years. It also recorded a $1.8 million impairment of the gas-powered turbine mentioned above. This impairment was based on a review of current market prices for similar turbines. However, these impairments were partially offset by higher equity method income from Horizon Power’s investments in Seneca Energy and Model City ($1.4 million). Horizon LFG’s earnings decreased by $1.3 million due to lower margins on gas sales. The overall decreases experienced by Horizon Power and Horizon LFG were partially offset by a $1.7 million improvement in the losses experienced by the former International segment, largely due to lower project development costs, and a $1.2 million improvement in earnings of Corporate operations.
INTEREST INCOME
Interest income was $3.8 million higher in 2006 compared to 2005. As discussed in the earnings discussion by segment above, the main reasons for this increase were strong cash flow from operations, the investment of proceeds from the sale of U.E. in July 2005 and higher average annual interest rates. Additionally, interest income on a pension related asset in accordance with the New York power grid. In 2002,rate case settlement agreement increased by $0.5 million.
Interest income was $4.7 million higher in 2005 compared to 2004. As discussed in the Company wrote off it’s 33 1/3% equity method investment in Independence Pipeline Company. The write-off amounted to $15.2 million ($9.9 million after tax) and is recorded onearnings discussion by segment above, the Consolidated Statementmain reason for this increase was the accrual of Income as Impairment of Investment in Partnership. Aside from this impairment, income from unconsolidated subsidiaries has been relatively small, amounting to $0.8 million, $0.5 million and $0.2$3.7 million in 2004, 2003interest on a pension related asset in accordance with the New York rate case settlement agreement that was completed in 2005.
OTHER INCOME
Other income was $9.9 million lower in 2006 compared to 2005. As discussed in the earnings discussion by segment above, the main reasons for this decrease included non-recurring gains recorded during 2005 in the Pipeline and 2002, respectively.Storage segment related to the sale of base gas ($2.6 million), and the disposition of insurance proceeds ($3.9 million) received in prior years for which a contingency was resolved.
Other income was $9.8 million higher in 2005 compared to 2004. As discussed in the earnings discussion by segment above, the main reasons for this increase included a $2.6 million gain in the Pipeline and Storage segment associated with a FERC approved sale of base gas in 2005 and a $3.9 million gain in the Pipeline and Storage segment associated with insurance proceeds received in prior years for which a contingency was resolved during 2005.


42


INTEREST CHARGES

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

Interest on long-term debt was $8.9decreased $0.6 million lower in 2004 compared to 2003; however, interest on long-term debt was $2.22006 and $9.7 million higher in 2003 compared to 2002.2005. The decrease in 2004 resulted mainly from2005 was primarily the result of a lower average amount of long-term debt outstanding and lower weighted average interest rates. The increase in 2003 resulted mainly from a higher average amount of long-term debt outstanding which more than offset lower weighted average interest rates.

outstanding.

Other interest charges decreased $5.5were $3.1 million lower in 2004 and $2.8 million in 2003.2006 compared to 2005. The decrease resulted primarily from the non-recurrence of $2.1 million of interest expense, discussed below, recorded by the Utility segment in both years was primarily the result of lower weighted average interest rates on short-term debt combined with2005 and a lower average amount of short-term debt outstanding.

35


outstanding during 2006.

Other interest charges were $2.3 million higher in 2005 compared to 2004. The increase resulted mainly from $2.1 million of interest expense recorded by the Utility segment as part of an adjustment to a regulatory liability recorded for previous over-collections of New York State gross receipts tax.
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

200420032002



(Millions)
Provided by Operating Activities $444.3  $326.8  $345.6 
Capital Expenditures  (172.3)  (152.2)  (232.4)
Investment in Subsidiaries, Net of Cash Acquired     (228.8)   
Investment in Partnerships     (0.4)  (0.5)
Net Proceeds from Sale of Timber Properties     186.0    
Net Proceeds from Sale of Oil and Gas Producing Properties  7.1   78.5   22.1 
Other Investing Activities  2.0   12.1   5.0 
Short-Term Debt, Net Change  38.6   (147.6)  (224.8)
Long-Term Debt, Net Change  (243.1)  20.7   139.6 
Issuance of Common Stock  23.8   17.0   10.9 
Dividends Paid on Common Stock  (89.1)  (84.5)  (81.0)
Effect of Exchange Rates on Cash  3.4   1.6   1.5 
   
   
   
 
Net Increase (Decrease) in Cash and Temporary Cash Investments $14.7  $29.2  $(14.0)
   
   
   
 

             
  Year Ended September 30 
  2006  2005  2004 
  (Millions) 
 
Provided by Operating Activities $471.4  $317.3  $437.1 
Capital Expenditures  (294.2)  (219.5)  (172.3)
Net Proceeds from Sale of Foreign Subsidiary     111.6    
Net Proceeds from Sale of Oil and Gas Producing Properties     1.4   7.1 
Other Investing Activities  (3.2)  3.2   2.0 
Change in Short-Term Debt     (115.4)  38.6 
Reduction of Long-Term Debt  (9.8)  (13.3)  (243.1)
Issuance of Common Stock  23.3   20.3   23.8 
Dividends Paid on Common Stock  (98.2)  (94.1)  (89.1)
Dividends Paid to Minority Interest     (12.7)   
Excess Tax Benefits Associated with Stock- Based Compensation Awards  6.5       
Shares Repurchased under Repurchase Plan  (85.2)      
Effect of Exchange Rates on Cash  1.4   1.3   3.5 
             
Net Increase in Cash and Temporary Cash Investments $12.0  $0.1  $7.6 
             
OPERATING CASH FLOW

Internally generated cash from operating activities consists of net income available for common stock, adjusted for noncashnon-cash expenses, noncashnon-cash income and changes in operating assets and liabilities. NoncashNon-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, (in 2003), deferred income taxes, impairment of investment in partnership, (in 2002),deferred income taxes, income or loss from unconsolidated subsidiaries net of cash distributions, minority interest in foreign subsidiaries, gain or loss on sale of timber properties, gain or loss on sale of oil and gas producing properties, and cumulative effectgain on the sale of changes in accounting.

discontinued operations.

Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of


43


weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation’s straight fixed-variable rate design.

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

Net cash provided by operating activities totaled $444.3$471.4 million in 2004,2006, an increase of $117.5$154.1 million compared with the $326.8$317.3 million provided by operating activities in 2003. Most of this increase occurred2005. Higher oil and gas revenues in the UtilityExploration and Production segment largely attributablewere primarily responsible for the increase. A decrease in hedging collateral deposits at September 30, 2006 in the Exploration and Production and Energy Marketing segments also contributed to the increase. Hedging collateral deposits serve as collateral for open positions on exchange-traded futures contracts, exchange-traded options andover-the-counter swaps and collars. The decrease from the prior year is reflective of lower natural gas cost recovery timing differences.

36


prices and a smaller number of derivative financial instruments outstanding at September 30, 2006 verses September 30, 2005. These increases were partially offset by the loss of positive cash flow from the Company’s former Czech Republic operations, which were sold in July 2005.

INVESTING CASH FLOW

Expenditures for Long-Lived Assets

     Expenditures for long-lived assets include additions to property, plant and equipment (capital expenditures) and investments in corporations (stock acquisitions) or partnerships, net of any cash acquired.

The Company’s expenditures for long-lived assets totaled $172.3$294.2 million in 2004.2006. The table below presents these expenditures:
     
Year Ended
September 30, 2004

Total Expenditures
For Long-Lived
Assets

(Millions)
Utility $55.4 
Pipeline and Storage  23.2 
Exploration and Production  77.7 
International  7.5 
Timber  2.8 
All Other and Corporate  5.7 
   
 
  $172.3 
   
 

     
  Year Ended
 
  September 30,
 
  2006 
  Total Expenditures
 
  For Long-Lived
 
  Assets 
  (Millions) 
 
Utility $54.4 
Pipeline and Storage  26.0 
Exploration and Production  208.3 
Timber  2.3 
All Other and Corporate  3.2 
     
  $294.2 
     
Utility

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

Pipeline and Storage

The majority of the Pipeline and Storage segment’s capital expenditures were made for additions, improvements and replacements to this segment’s transmission and gas storage systems.

Exploration and Production

The Exploration and Production segment’s capital expenditures were primarily well drilling and completion expenditures and included approximately $31.4$41.8 million for the Canadian region, $19.4$103.4 million for the Gulf Coast region $17.4($102.8 million for the off-shore program in the Gulf of Mexico), $36.1 million for the West Coast region and $9.5$27.0 million for the Appalachian region. The significant amount spent in the Gulf Coast region is related to high commodity prices, which has improved the economics of investment in the area, plus


44


projected royalty relief. These amounts included approximately $12.1$55.6 million spent to develop proved undeveloped reserves.

International

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

Timber

The majority of the Timber segment’ssegment capital expenditures were made for purchases of equipment for this segment’sHighland’s sawmill and kiln operations.

All Other and Corporate

     The majority of the All Other and Corporate capital expenditures were for capital improvements to the Company’s new corporate headquarters.

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Estimated Capital Expenditures

The Company’s estimated capital expenditures for the next three years are:*
             
Year Ended September 30,

200520062007



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

             
  Year Ended September 30 
  2007  2008  2009 
  (Millions) 
 
Utility $56.0  $56.0  $57.0 
Pipeline and Storage  62.0   110.0   84.0 
Exploration and Production(1)  212.0   207.0   243.0 
Timber  4.0   1.0   1.0 
             
  $334.0  $374.0  $385.0 
             

(1)Includes estimated expenditures for the years ended September 30, 2005, 20062007, 2008 and 20072009 of approximately $14$23 million, $27$22 million and $29$25 million, respectively, to develop proved undeveloped reserves.

Estimated capital expenditures for the Utility segment in 20052007 will be concentrated in the areas of main and service line improvements and replacements and, to a minorlesser extent, the installationpurchase of new services.equipment.*

Estimated capital expenditures for the Pipeline and Storage segment in 20052007 will be concentrated in the replacement of transmission and storage lines, reconditioning of storage wells and improvements of compressor stations.* The estimated capital expenditures for 2007 also includes $39.0 million for the replacement of storage and transmission lines.*

Empire Connector project as discussed below.

The Company also continues to explore various opportunities to expand its capabilities to transport gas to the East Coast, either through the Supply Corporation or Empire systems or in partnership with others. As announced in February 2004,In October 2005, Empire filed an application with the Company is pursuing aFERC for the authority to build and operate the Empire Connector project to expand its natural gas pipeline operations to serve new markets in New York and elsewhere in the Northeast by extending the Empire State Pipeline.* This The application also asks that Empire’s existing business and facilities be brought under FERC jurisdiction, and that FERC approve rates for Empire’s existing and proposed extension project wouldservices. Assuming the proposed Millennium Pipeline is constructed, the Empire Connector will provide an upstream supply link for Phase I of the Millennium Pipeline and will transport Canadian and other natural gas supplies to downstream customers, including KeySpan Gas East Corporation, which has entered into a precedent agreementagreements to be a major shipper, subject tosubscribe for at least 150 MDth per day of natural gas transportation service through the satisfaction of various conditions.Empire State Pipeline and the Millennium Pipeline systems.* The pipeline extensionEmpire Connector will be designed to move at leastup to approximately 250 MMcfMDth of natural gas per day.* The preliminary estimate ofIn July 2006, Empire revised the costplanned in-service date for developing the Empire extension project is $140 million and theConnector to extend beyond its original November 2007 target. The new targeted in-service date is lateNovember 2008, or sooner if feasible.* FERC issued on July 20, 2006 a preliminary determination regarding non-environmental aspects of the application, in calendarresponse to which Empire made a request for rehearing on August 21, 2006. Empire anticipates that FERC will issue a final certificate authorizing construction and operation of the project on or about December 2006, after which Empire will have to decide whether it will accept the final approval on the terms contained therein.* Refer to the Rate and Regulatory Matters section that follows for further discussion of this matter. The forecasted expenditures for this project over the next three years are as follows: $39.0 million in 2007, $85.0 million in 2008, and $22.0 million in 2009.* These expenditures are included as Pipeline and Storage estimated capital expenditures do not include any expenditures forin the Empire extension project.table above. The Company anticipates financing this project with cash on handand/or through the use of the Company’s bi-lateral lines of credit.* As of September 30, 2004,2006, the Company had incurred approximately $0.6$6.0 million in


45


costs (all of which have been reserved) related to this project.

Of this amount, $2.0 million, $3.4 million and $0.6 million were incurred during the years ended September 30, 2006, 2005 and 2004, respectively.

The Company also has plans to expand Supply Corporation’s existing interconnect with Empire at Pendleton, New York. Compression will be added to allow Supply Corporation transportation and storage volumes to be delivered to Empire, which is operated at higher pressures than Supply Corporation’s system.* The Pendleton Compression project will be a key strategic expansion for Supply Corporation, allowing access to both Empire and Millennium markets to the east, as well as for Empire, providing its shippers with access to storage services and Supply Corporation’s array of interconnects. Supply Corporation is in the process of negotiating customer agreement(s), and expects to complete design and launch the regulatory approval process in late 2006.* There have been no costs incurred by the Company related to this project as of September 30, 2006, and the forecasted expenditures for this project over the next three years are as follows: $0 in 2007, $3.0 million in 2008, and $1.0 million in 2009.* These expenditures are included as Pipeline and Storage estimated capital expenditures in the table above. The target in-service date for the Pendleton Compression project is contingent upon the Millennium/Empire Connector timeline.* Accordingly, Supply Corporation anticipates that most of the capital spending associated with this expansion will occur in fiscal 2008.*
Supply Corporation continues to view the Tuscarora Extension project as an important link to Millennium and potential storage development in the Corning, New York area.* The new pipeline, which would expand the Supply Corporation system from its Tuscarora storage field to the intersection of the proposed Millennium and Empire Connector pipelines, will be designed initially to transport up to approximately 130 MDth of natural gas per day. It may also provide Supply Corporation with the opportunity to increase the deliverability of the existing Tuscarora storage field.* The project timeline relies on market development, and should the market mature, the Company anticipates financing the Tuscarora Extension with cash on handand/or through the use of the Company’s bi-lateral lines of credit.* There have been no costs incurred by the Company related to this project as of September 30, 2006, and the forecasted expenditures for this project over the next three years are as follows: $0 in 2007 and 2008, and $39.0 million in 2009.* These expenditures are included as Pipeline and Storage estimated capital expenditures in the table above. The Company has not yet filed an application with the FERC for the authority to build and operate the Tuscarora Extension.
Estimated capital expenditures in 20052007 for the Exploration and Production segment include approximately $32.0$34.0 million for Canada, $29.0$100.0 million for the Gulf Coast region ($28.098.0 million on the off-shore program in the Gulf of Mexico), $20.0$43.0 million for the West Coast region and $12.0$35.0 million for the Appalachian region.*

     The estimated

Estimated capital expenditures for the International segment in 2005 will be concentrated on improvements and replacements within the district heating and power generation plants in the Czech Republic.* The estimated capital expenditures do not include any expenditures for the Company’s European power development projects. Currently, any costs incurred on these power development projects are expensed. The Company’s European power development projects currently include one project in Italy and one project in Bulgaria. In Italy, the Company has signed a joint development agreement with an Italian utility for the construction of a 400-megawatt combined-cycle natural gas fired electric generating plant. The estimated cost of this project is $200.0 million to $210.0 million. In Bulgaria, the Company is pursuing the opportunity to construct, own and operate two new 100-megawatt gas-fired combined-cycle plants. The estimated cost of this project is $200.0 million to $220.0 million. Whether the Company moves forward to construct these projects will depend on successful negotiation of various operating agreements as well as the availability of funds from banks or other financial institutions to cover a significant amount of the construction costs.* The respective projects would serve as collateral for such financing arrangements.*

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     Estimated capital expenditures2007 in the Timber segment will be concentrated on the construction or purchase of new facilitiesequipment and equipmentimprovements to facilities for this segment’s lumber yard, sawmill and kiln operations.*

     Estimated capital expenditures in the All Other and Corporate category will be concentrated on the purchase of equipment for a 55-megawatt electric generation facility in Buffalo, New York combined with capital improvements to the Company’s corporate headquarters.

The Company continuously evaluates capital expenditures and investments in corporations, partnerships and partnerships.other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, timber or natural gas storage facilities and the expansion of natural gas transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.*

FINANCING CASH FLOW

     In February 2004 and August 2004, the Company repaid $125.0 million of maturing 7.75% debentures at par and $100.0 million of maturing 6.82% medium-term notes at par, respectively.

The Company used available cash anddid not have any outstanding short-term borrowingsnotes payable to repay this debt.

     Consolidated short-term debt increased $38.6 million during 2004. Although a certain amount of short-term borrowings were initially used to repaybanks or commercial paper at September 30, 2006. However, the maturing debt discussed above, the Company was able to use cash flow from operations to repay most of this additional short-term debt. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporationsand/or partnerships,gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At September 30, 2004, the Company had outstanding short-term notes payable to banks and commercial paper of $26.5 million and $130.3 million, respectively. The Company has SEC authorization under the Holding Company Act to borrow and have outstanding as much as $750.0 million of short-term debt at any time through December 31, 2005. As for bank loans, the Company maintains a number of individual (bi-lateral) uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. Each of theseThese credit lines, which aggregate


46


to $400.0$445.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed.renewed, or replaced by similar lines.* The total amount available to be issued under the Company’s commercial paper program is $200.0$300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $220.0 million. Of$300.0 million that amount, $110.0 million is committed to the Company through September 25, 2005 and $110.0 million is committed to the Companyextends through September 30, 2005. The Company anticipates that it will be able to replace this facility at or before its maturity.*

2010.

Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter exceed ..625 from October 1, 2003September 30, 2005 through September 30, 2004 and .60 from October 1, 2004 and thereafter.2010. At September 30, 2004,2006, the Company’s debt to capitalization ratio (as calculated under the facility) was .51..44. The constraints specified in the committed credit facility would permit an additional $576.0 million$1.56 billion in short-termand/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio would exceed .60..65. If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible.* However, the Company expects that it could borrow under its uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.*

Under the Company’s existing indenture covenants, at September 30, 2004,2006, the Company would have been permitted to issue up to a maximum of $713.0 million$1.03 billion in additional long-term unsecured indebtedness at then current market interest rates (further limited by the debt to capitalization ratio constraints noted in

39


the previous paragraph) in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands.*

The Company’s 1974 indenture, pursuant to which $399.0 million (or 35%36%) of the Company’s long-term debt (as of September 30, 2004)2006) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

The Company’s $220.0$300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries failsfail to make a payment when due of any principal or interest on any other indebtedness aggregating $20.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $20.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2004,2006, the Company had no debt outstanding under the committed credit facility.

The Company’s embedded cost of long-term debt was 6.4% at both September 30, 20042006 and 6.5% at September 30, 2003.2005. Refer to “Interest Rate Risk” in this Item for a more detailed break-downbreakdown of the Company’s embedded cost of long-term debt.

     The Company also has authorization from the SEC, in an order under the Holding Company Act, to issue long-term debt securities and equity securities in an aggregate amount of up to $1.5 billion during the order’s authorization period, which commenced in November 2002 and extends to December 31, 2005.

The Company has an effective registration statement on file with the SEC under which it has available capacity to issue an additional $550.0 million of debt and equity securities under the Securities Act of 1933, and within the authorization granted by the SEC under the Holding Company Act.1933. The Company may sell all or a portion of the remaining registered securities if warranted by market conditions and the Company’s capital requirements. Any offer and sale of the above mentioned $550.0 million of debt and equity securities will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.
On December 8, 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. As of


47


September 30, 2006, the Company has repurchased 2,526,550 shares under this program, funded with cash provided by operating activities. In the future, it is expected that this share repurchase program will continue to be funded with cash provided by operating activitiesand/or through the use of the Company’s bi-lateral lines of credit.* It is expected that open market repurchases will continue from time to time depending on market conditions.*
OFF-BALANCE SHEET ARRANGEMENTS

The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating and capital leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Utility and the Pipeline and Storage segments, having a remaining lease commitment of approximately $34.3$44.0 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters, computer equipment and other items and are accounted for as operating leases. The Company’s unconsolidated subsidiaries, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $10.0$7.1 million. The Company has guaranteed 50%, or $5.0$3.5 million, of these capital lease commitments.

40


CONTRACTUAL OBLIGATIONS

The following table summarizes the Company’s expected future contractual cash obligations as of September 30, 2004,2006, and the twelve-month periods over which they occur:
                              
Payments by Expected Maturity Dates

20052006200720082009ThereafterTotal







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

                             
  Payments by Expected Maturity Dates 
  2007  2008  2009  2010  2011  Thereafter  Total 
  (Millions) 
 
Long-Term Debt, including interest expense(1) $93.7  $266.0  $154.7  $51.8  $238.9  $776.7  $1,581.8 
Operating Lease Obligations $8.1  $7.2  $6.0  $4.3  $2.7  $15.7  $44.0 
Capital Lease Obligations $1.1  $0.9  $0.5  $0.4  $0.4  $0.2  $3.5 
Purchase Obligations:                            
Gas Purchase Contracts(2) $742.8  $149.4  $17.7  $6.9  $6.5  $64.7  $988.0 
Transportation and Storage Contracts $50.7  $45.8  $31.2  $10.7  $3.4  $4.1  $145.9 
Other $25.0  $2.9  $2.0  $2.0  $1.8  $4.6  $38.3 
(1)Refer to Note E — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense.
(2)Gas prices are variable based on the NYMEX prices adjusted for basis.

The Company has made certain other guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the consolidated balance sheet in accordance with the Financial Accounting Standards Board’s Statement of Financial Accounting Standards (SFAS) No.SFAS 133 “Accounting for Derivative Instruments and Hedging Activities” (see Item 7, MD&A under the heading “Critical Accounting PoliciesEstimates — Accounting for Derivative Financial Instruments”); (ii) NFR obligations to purchase gas or to purchase gas transportation/storage services where the amounts due on those obligations each month are included on the consolidated balance sheet as a current liability; and (iii) other obligations which are reflected on the consolidated balance sheet. The Company believes that the likelihood it would be required to make payments under the guarantees is remote, and therefore has not included them onin the table above.*

OTHER MATTERS

     The

In addition to the legal proceedings disclosed in Item 3 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. Also in the normal course of business, the Company is involved inThese other matters may include, for example, negligence claims and tax, regulatory andor other governmental audits, inspections, investigations andor other proceedings thatproceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatorythese normal-course matters


48


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,in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor to have a material adverse effect on the financial condition of the Company.*

The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) that covers substantially all domestic employeesapproximately 77% of the Company.Company’s domestic employees. The Company has been making contributions to the Retirement Plan over the last several years and anticipates that it will continue making contributions to the Retirement Plan.* During 2004,2006, the Company contributed $37.1$20.9 million to the Retirement Plan. The Company anticipates that the annual contribution to the Retirement Plan in 20052007 will be in the range of $25.0$15.0 million to $35.0$20.0 million.* The Company expects that all subsidiaries having domestic employees covered by the Retirement Plan will make contributions to the Retirement Plan.* The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments or through short-term borrowings or through cash from operations.*

The Company provides health care and life insurance benefits for substantially all domestic retired employees under a post-retirement benefit plan (Post-Retirement Plan). The Company has been making contributions to the Post-Retirement Plan over the last several years and anticipates that it will continue making contributions to the Post-Retirement Plan.* During 2004,2006, the Company contributed $39.7$39.3 million to

41


the Post-Retirement Plan. The Company anticipates that the annual contribution to the Post-Retirement Plan in 20052007 will be in the range of $30.0$35.0 million to $40.0$45.0 million.* The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments.*

A capital loss carryover of $25.1 million exists at September 30, 2006, which expires if not utilized by September 30, 2008. Although realization is not assured, management determined that it is more likely than not that the entire deferred tax asset associated with this carryover will be realized during the carryover period. As such, the valuation allowance of $2.9 million was reversed during 2006 as discussed under “Exploration and Production” in the Results of Operations section above.
A deferred tax asset of $9.0 million relating to Canadian operations exists at September 30, 2006. Although realization is not assured, management determined that it is more likely than not that future taxable income will be generated in Canada to fully utilize this asset, and as such, no valuation allowance was provided.
MARKET RISK SENSITIVE INSTRUMENTS

Energy Commodity Price Risk

The Company, in its Exploration and Production segment, Energy Marketing segment, Pipeline and Storage segment, and All Other category, uses various derivative financial instruments (derivatives), including price swap agreements, no cost collars, options and futures contracts, as part of the Company’s overall energy commodity price risk management strategy. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas and crude oil, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from or pay to the respective counterparties at September 30, 20042006 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.NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average


49


settlement prices by expected maturity date as of September 30, 2004.2006. At September 30, 2004,2006, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2009.
 
Natural Gas Price Swap Agreements
                         
Expected Maturity Dates

20052006200720082009Total






Notional Quantities (Equivalent Bcf)  11.3   8.4   1.8   1.2   0.3   23.0 
Weighted Average Fixed Rate (per Mcf) $5.47  $5.68  $5.02  $4.80  $4.81  $5.47 
Weighted Average Variable Rate (per Mcf) $7.12  $6.74  $6.13  $5.58  $5.50  $6.81 
Natural Gas Price Swap Agreements
 
Crude Oil Price Swap Agreements
                 
Expected Maturity Dates

200520062007Total




Notional Quantities (Equivalent bbls)  2,743,000   1,755,000   540,000   5,038,000 
Weighted Average Fixed Rate (per bbl)  $30.51   $33.27   $35.55   $32.01 
Weighted Average Variable Rate (per bbl)  $46.74   $41.31   $38.41   $43.95 

                 
  Expected Maturity Dates 
  2007  2008  2009  Total 
 
Notional Quantities (Equivalent Bcf)  3.9   2.8   0.7   7.4 
Weighted Average Fixed Rate (per Mcf) $6.95  $7.26  $8.63  $7.24 
Weighted Average Variable Rate (per Mcf) $7.29  $8.37  $8.84  $7.85 

Crude Oil Price Swap Agreements
             
  Expected Maturity Dates 
  2007  2008  Total 
 
Notional Quantities (Equivalent bbls)  855,000   45,000   900,000 
Weighted Average Fixed Rate (per bbl) $37.03  $39.00  $37.13 
Weighted Average Variable Rate (per bbl) $65.47  $68.90  $65.64 
At September 30, 2004,2006, the Company would have had to pay its respective counterparties an aggregate of approximately $25.0$7.4 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have had to pay an aggregate of approximately $57.2$27.6 million to its counterparties to terminate the crude oil price swap agreements outstanding at September 30, 2004.

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2006.

At September 30, 2003,2005, the Company had natural gas price swap agreements covering 13.118.8 Bcf at a weighted average fixed rate of $4.24$5.73 per Mcf. The Company also had crude oil price swap agreements covering 2,184,0002,835,000 bbls at a weighted average fixed rate of $25.44$35.09 per bbl. The increasedecrease in natural gas price swap agreements from September 20032005 to September 20042006 is largely a result ofattributable to management’s decision to hedge farther into the futureutilize more no cost collars as a means of hedging natural gas production in the Exploration and Production segment given the high commodity prices available. It is also a reflection of management’s decision to usesegment. The decrease in crude oil price swap agreements instead ofis primarily due to the fact that the Company has not been entering into new swap agreements for its West Coast crude oil no cost collarsproduction. This decision is related to the price, or “basis,” differential that exists between the Company’s West Coast heavy sour crude oil and the West Texas Intermediate light sweet crude oil that is quoted on the NYMEX. The Company has been unable to hedge against changes in the Exploration and Production segment, as discussed below.

basis differential.

The following table discloses the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas and crude oil price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2004,2006, the Company had not entered into any natural gas or crude oil no cost collars extending beyond 2006.2008.
 
No Cost Collars
              
Expected Maturity Dates

20052006Total



Natural Gas            
 Notional Quantities (Equivalent Bcf)  5.1   0.4   5.5 
 Weighted Average Ceiling Price (per Mcf)  $8.31  $7.88   $8.28 
 Weighted Average Floor Price (per Mcf)  $4.94  $4.77   $4.93 
Crude Oil            
 Notional Quantities (Equivalent bbls)  105,000      105,000 
 Weighted Average Ceiling Price (per bbl)  $28.56      $28.56 
 Weighted Average Floor Price (per bbl)  $25.00      $25.00 
             
  Expected Maturity Dates 
  2007  2008  Total 
 
Natural Gas            
Notional Quantities (Equivalent Bcf)  5.7   1.4   7.1 
Weighted Average Ceiling Price (per Mcf) $17.45  $16.45  $17.25 
Weighted Average Floor Price (per Mcf) $8.12  $8.83  $8.26 


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  2007 
 
Crude Oil    
Notional Quantities (Equivalent bbls)  180,000 
Weighted Average Ceiling Price (per bbl) $77.00 
Weighted Average Floor Price (per bbl) $70.00 
At September 30, 2004,2006, the Company would have had to payreceived an aggregate of approximately $1.6$10.4 million to terminate the natural gas no cost collars outstanding at that date. The Company would have had to pay an aggregate of approximately $2.1received $0.9 million to terminate the crude oil no cost collars outstanding at that date.

September 30, 2006.

At September 30, 2003,2005, the Company had natural gas no cost collars covering 3.78.5 Bcf at a weighted average floor price of $3.46$7.54 per Mcf and a weighted average ceiling price of $7.21$15.62 per Mcf. The Company also had crude oil no cost collars covering 1,290,000 bbls at a weighted average floor price of $23.91 per bbl and a weighted average ceiling price of $28.00 per bbl. The increase in natural gas no cost collars from September 2003 to September 2004 is a result of management’s decision to hedge farther out into the future in the Exploration and Production segment given the high commodity prices available. The decrease in crude oil no cost collars from September 2003 to September 2004 is a result of management’s decision to use crude oil price swap agreements instead of crude oil no cost collars to hedge future crude oil production in the Exploration and Production segment. With the current commodity price environment, management determined that it could better meet its commodity price objectives through the use of price swap agreements.

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Options

The following table discloses the notional quantities and weighted average strike prices by expected maturity dates for options used by the Exploration and Production segment to manage natural gas price risk. The put options provide for the Company to receive monthly payments from other parties when a variable price falls below an established floor or “strike” price. The call options provide for the Company to pay monthly payments to other parties when a variable price rises above an established ceiling or “strike” price. At September 30, 2004, the Company held no options with maturity dates extending beyond 2006.

              
Expected Maturity Dates

20052006Total



Natural Gas Put Options Purchased            
 Notional Quantities (Equivalent Bcf)  0.8   0.3   1.1 
 Weighted Average Strike Price (per Mcf) $6.05  $5.83  $5.99 
Natural Gas Call Options Sold            
 Notional Quantities (Equivalent Bcf)  0.8   0.3   1.1 
 Weighted Average Strike Price (per Mcf) $7.84  $8.69  $8.06 

     At September 30, 2004, the Company would have received from the respective counterparties an aggregate of approximately $0.2 million to terminate the put options outstanding at that date. The Company would have had to pay an aggregate of approximately $1.0 million to terminate the call options outstanding at that date. The Company did not have any options outstanding crude oil no cost collars at September 30, 2003.

2005. The decrease in natural gas collars from September 2005 to September 2006 is due to management’s decision to curtail hedging activity in the fourth quarter of 2006 due to the forecast of a more active hurricane season in 2006. In 2005, the Company recognized a $5.1 millionmark-to-market adjustment related to derivative financial instruments that no longer qualified as effective hedges due to production delays caused by Hurricane Rita, and management wanted to prevent this from recurring in 2006. When the hurricane season did not turn out to be as active as everyone had forecasted, the pricing strip at that time was so low that management elected to hold off on some of the hedging. Management is reviewing that policy and is in the process of looking at layering in more hedges in the future.*

The following table discloses the net contract volumes purchased (sold), weighted average contract prices and weighted average settlement prices by expected maturity date for futures contracts used to manage natural gas price risk. At September 30, 2004,2006, the Company held no futures contracts with maturity dates extending beyond 2007.2012.
 
Futures Contracts
                 
Expected Maturity Dates

200520062007Total




Net Contract Volumes Purchased (Sold) (Equivalent Bcf)  (3.5)  (0.4)  0.1   (3.8)
Weighted Average Contract Price (per Mcf) $6.16  $6.29  $5.88  $6.17 
Weighted Average Settlement Price (per Mcf) $7.74  $6.96  $6.33  $7.69 

                             
  Expected Maturity Dates 
  2007  2008  2009  2010  2011  2012  Total 
 
Net Contract Volumes Purchased (Sold)                            
(Equivalent Bcf)  7.2   (0.1)  (0.1)     (1)  (1)  7.0 
Weighted Average Contract Price (per Mcf) $9.63  $9.85  $9.57   NA  $6.99  $8.68  $9.67 
Weighted Average Settlement Price (per Mcf) $10.02  $9.58  $9.14   NA  $6.91  $9.29  $9.89 
(1)The Energy Marketing segment has purchased 4 and 6 futures contracts (1 contract = 2,500 Dth) for 2011 and 2012, respectively.
At September 30, 2004,2006, the Company would have had to pay $6.2$4.9 million to terminate these futures contracts.

At September 30, 2003,2005, the Company had futures contracts covering 3.62.2 Bcf (net longshort position) at a weighted average contract price of $5.60$8.63 per Mcf.
The change from aincrease in net long position at September 30, 2003positions in 2006 was due to a net short position at September 30, 2004 can largely be explained by the high commodity price environment experienced bydecrease in natural gas prices in the Energy Marketing segmentsummer months which led to an increase in 2004. With high commodity prices, customers have been reluctant to enter into fixed price sales commitments. With fewer fixed price salesThese commitments were hedged with long positions in the Energy Marketing segment has purchased fewer contracts since it no longer faces as great a risk of commodity price increases.

futures market.

The Company may be exposed to credit risk on some of the derivatives disclosed above. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check and then, on an ongoing basis, monitors counterparty credit exposure. Management has obtained guarantees from the parent companies of the respective counterparties to its derivatives. At September 30, 2004,2006, the Company used sevensix counterparties for its over the counter derivatives. At September 30, 2004,2006, no individual counterparty represented greater than 20%39% of total credit risk (measured as volumes hedged by an individual counterparty as

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a percentage of the Company’s total volumes hedged).

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All of the counterparties (or the parent of the counterparty) were rated as investment grade entities at September 30, 2006.

Exchange Rate Risk

     The International segment’s investment in the Czech Republic is valued in Czech korunas, and, as such, this investment is subject to currency exchange risk when the Czech korunas are translated into U.S. dollars.

The Exploration and Production segment’s investment in Canada is valued in Canadian dollars, and, as such, this investment is subject to currency exchange risk when the Canadian dollars are translated into U.S. dollars. This exchange rate risk to the Company’s investmentsinvestment in the Czech Republic and Canada results in increases or decreases to the Cumulative Foreign Currency Translation Adjustment (CTA),CTA, a component of Accumulated Other Comprehensive Income/Loss on the Consolidated Balance Sheets. When the foreign currency increases in value in relation to the U.S. dollar, there is a positive adjustment to CTA. When the foreign currency decreases in value in relation to the U.S. dollar, there is a negative adjustment to CTA.

Interest Rate Risk

The Company’s exposure to interest rate risk arises primarily from its borrowing under short-term debt instruments. At September 30, 2004, these instruments consisted of domestic short-term bank loans and commercial paper totaling $156.8 million. The interest rate on these short-term bank loans and commercial paper approximated 1.8% at September 30, 2004.

The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt as well as the other long-term debt of certain of the Company’s subsidiaries. The interest rates for the variable rate debt are based on those in effect at September 30, 2004:

                             
Principal Amounts by Expected Maturity Dates

20052006200720082009ThereafterTotal







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


(1) $41.4 million is variable rate debt; $9.9 million is fixed rate debt.
(2) Weighted average interest rate excludes the impact of an interest rate collar on $41.4 million of variable rate debt.

     The Company uses an interest rate collar to limit interest rate fluctuations on $41.4$22.8 million of variable rate debt included in Other Notes in the table above.below. To mitigate this risk, the Company uses an interest rate collar to limit interest rate fluctuations. Under the interest rate collar the Company makes quarterly payments to (or receives payments from) another party when a variable rate falls below an established floor rate (the Company pays the counterparty) or exceeds an established ceiling rate (the Company receives payment from the counterparty). Under the terms of the collar, which extends until 2009, the variable rate is based on London InterBank Offered Rate.LIBOR. The floor rate of the collar is 5.15% and the ceiling rate is 9.375%. The Company would have had to pay $2.2$0.1 million to terminate the interest rate collar at September 30, 2004.2006.

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, 2006:
                             
  Principal Amounts by Expected Maturity Dates 
  2007  2008  2009  2010  2011  Thereafter  Total 
  (Dollars in millions) 
 
National Fuel Gas Company
                            
Long-Term Fixed Rate Debt $  $200.0  $100.0  $  $200.0  $595.7  $1,095.7 
Weighted Average Interest Rate Paid     6.3%  6.0%     7.5%  6.2%  6.4%
Fair Value = $1,125.2                            
Other Notes
                            
Long-Term Debt(1) $22.9  $  $  $  $  $  $22.9 
Weighted Average Interest Rate Paid(2)  6.5%                 6.5%
Fair Value = $22.9                            
(1)$22.8 million is variable rate debt. It is the Company’s intention to pay off these notes within one year. As such, the notes have been classified as current.
(2)Weighted average interest rate excludes the impact of an interest rate collar on $22.8 million of variable rate debt.
RATE AND REGULATORY MATTERS
Energy Policy Act
On August 8, 2005, President Bush signed into law the Energy Policy Act, which, among other things, included PUHCA 2005. PUHCA 2005 repealed PUHCA 1935 effective February 8, 2006. Since that date, the Company has been free from PUHCA 1935’s broad regulatory provisions, including provisions relating to the


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issuance of securities, sales and acquisitions of securities and utility assets, intra-company transactions and limitations on diversification. PUHCA 2005, among other things, grants the FERC and state public utility regulatory commissions access to certain books and records of companies in holding company systems. On December 8, 2005, the FERC issued Order 667 to implement PUHCA 2005. The FERC clarified certain aspects of Order 667 in OrderRATE MATTERS667-A,

issued on April 24, 2006. On June 15, 2006, pursuant to the FERC’s regulations, the Company filed a “notification of holding company status” with the FERC. Also on that date, the Company filed an “exemption request” with the FERC, requesting exemption of the Company and its subsidiaries from the FERC’s regulations under PUHCA 2005. The exemption request has been granted by operation of law pursuant to the FERC’s regulations.

Utility Operation

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

New York Jurisdiction

     On October 11, 2000, the NYPSC approved a settlement agreement (Agreement) between Distribution Corporation, Staff of the Department of Public Service, the New York State Consumer Protection Board and Multiple Intervenors (an advocate for large commercial and industrial customers) (collectively, “Parties”) that established rates for the three-year period ending September 30, 2003. On July 25, 2003, the Parties and other interests executed a settlement agreement (Settlement) to extend the terms of the Agreement and Distribution Corporation’s restructuring plan one year commencing October 1, 2003. The Settlement was approved by the NYPSC in an order issued on September 18, 2003. As approved, the Settlement continued existing base rates, but reduced the level above which earnings are shared 50/50 with customers from the previous 11.5% return on equity to 11.0%. In addition, the Settlement increased the combined pension and other post-retirement benefit expense by $8.0 million, without a corresponding increase in revenues. Most other features of Distribution Corporation’s service remained largely unchanged. In April 2004, Distribution Corporation commenced confidential settlement negotiations with the NYPSC and other parties concerning, among other things, its revenue requirement for the year ending September 30, 2005. Those settlement discussions failed to produce an agreement prior to the expiration of the Settlement.

On August 27, 2004, Distribution Corporation filedcommenced a rate case by filing proposed tariff amendments and supporting testimony designedrequesting approval to increase its annual revenues by $41.3 million beginning October 1, 2004. The rate request was filed to address throughput reductionsVarious parties opposed the filing. On April 15, 2005, Distribution Corporation, the parties and increased operating costs such as uncollectibles and personnel expenses.others executed an agreement settling all outstanding issues. In accordance with standard rate case procedure,an order issued July 22, 2005, the NYPSC suspended Distribution Corporation’s filingapproved the April 15, 2005 settlement agreement, substantially as provided by law in order to allow timefiled, for an investigation and hearings. Following hearings and further proceedings, the Commission will issue an order approving, rejecting or modifying Distribution Corporation’s rate request for an anticipated effective date of late July,August 1, 2005. Distribution Corporation is unable to ascertain the outcomeThe settlement agreement provides for a rate increase of $21 million by means of the rate proceeding at this time. The existingelimination of bill credits ($5.8 million) and an increase in base rates and other provisions($15.2 million). For the two-year term of the Settlement that expiredagreement and thereafter, the return on September 30, 2004 will continue toequity level above which earnings must be in effect until the Commission issues an order concerning Distribution Corporation’sshared with rate request.

     On June 1, 2004, Distribution Corporation submitted a filing to the NYPSC supporting the removal of a $5 million annual bill credit originally established under the terms of the Agreement. The filing requested removal of the bill credit effective October 1, 2004. On September 28, 2004, the NYPSC issued an order rejecting Distribution Corporation’s request for the stated reason that Distribution Corporation’s earnings were adequate, in the NYPSC’s opinion, without removal of the bill credit. Distribution Corporationpayers is contemplating further action on the NYPSC’s order.

     In another order issued on September 28, 2004, the NYPSC directed the continuation, with modification, of four programs under the Settlement that were scheduled to expire on September 30, 2004. The effect of the NYPSC’s order was to unilaterally extend the terms of the Settlement without Distribution Corporation’s consent. Although the NYPSC’s order stated that it provided for funding of the programs, Distribution Corporation petitioned Supreme Court, Albany County for an injunction to allow the programs to expire on their own terms. Distribution Corporation’s petition was partially successful, and the proceeding remains pending.

     On September 20, 2001, the NYPSC issued an order under which Distribution Corporation was directed to show cause why an action for penalties of $19.0 million should not be commenced against it for alleged violations of consumer protection requirements. On December 3, 2001, Distribution Corporation filed its response which vigorously asserted that the allegations lacked merit. Distribution Corporation continues to so believe. On July 28, 2004, the NYPSC concluded the investigation of issues raised in the order without

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11.5%.

assessing any fines or penalties. As part of the settlement of the NYPSC’s investigation, Distribution Corporation will commit $1.5 million to a new program designed to assist low-income customers who are transitioning from public assistance. Distribution Corporation has also agreed to incur costs up to $0.3 million for an audit of customer service practices. The NYPSC has agreed not to seek any penalties should any violations be uncovered during the audit. For a discussion of related legal matters, refer to Item 3, “Legal Proceedings.”

Pennsylvania Jurisdiction

On April 16, 2003,June 1, 2006, Distribution Corporation filed a requestproposed tariff amendments with the PaPUC to increase annual operating revenues by $16.5$25.9 million to cover increases in the cost of providing service to be effective June 15, 2003.July 30, 2006. The PaPUC suspended the effective daterate request was filed to January 15, 2004. Distribution Corporation filed this request for several reasons including increases in theaddress increased costs associated with Distribution Corporation’s ongoing construction program as well as increases in operating costs, particularly uncollectible accountsaccounts. Following standard regulatory procedure, the PaPUC issued an order on July 20, 2006 instituting a rate proceeding and personnel expenses.suspending the proposed tariff amendments until March 2, 2007.* On October 16, 2003,2, 2006, the parties, reached a settlement of all issues. The settlement was submitted to the Administrative Law Judge, who, on November 17, 2003, issued a decision recommending adoptionincluding Distribution Corporation, Staff of the settlement.PaPUC and intervenors, executed an agreement (Settlement) proposing to settle all issues in the rate proceeding. The settlement provides forSettlement includes an increase in revenues of $14.3 million to non-gas revenues, an agreement not to file a base rate increase of $3.5 millioncase until January 28, 2008 at the earliest and authorizes deferral accounting for pension and other post-retirement benefit expenses.an early implementation date. The settlementSettlement was approved by the PaPUC at its meeting on December 18, 2003,November 30, 2006, and new rates becamewill become effective January 15, 2004.

1, 2007.

On September 15, 2004, Distribution Corporation filed revised tariffs withJune 8, 2006, the PaPUC to increase annual revenues by $22.8 million to cover increases in the cost of service to be effective November 14, 2004. The rate request was filed to address throughput reductions and increased operating costs such as uncollectibles and personnel expenses. Applying standard procedure, the PaPUC suspended Distribution Corporation’s tariff filing to perform an investigation and hold hearings. With this suspension, the effective date was changed to June 14, 2005 and the proceeding remains pending.

Pipeline and Storage

     Supply Corporation currently does not have a rate case on file with the FERC. Management will continue to monitor Supply Corporation’s financial position to determine the necessity of filing a rate case in the future.

     On November 25, 2003, the FERCNTSB issued Order 2004 “Standards of Conduct for Transmission Providers” (“Order 2004”). Order 2004 was clarified in Order 2004-A on April 16, 2004 and Order 2004-B on August 2, 2004. Order 2004, which went into effect September 22, 2004, regulates the conduct of transmission providers (such as Supply Corporation) with their “energy affiliates.” The FERC broadened the definition of “energy affiliates” to include any affiliate of a transmission provider if that affiliate engages in or is involved in transmission (gas or electric) transactions, or manages or controls transmission capacity, or buys, sells, trades or administers natural gas or electric energy or engages in financial transactions relating to the sale or transmission of natural gas or electricity. Supply Corporation’s principal energy affiliates will be Seneca, NFR and, possibly, Distribution Corporation.* Order 2004 provides that companies may request waivers, which the Company has done with respectsafety recommendations to Distribution Corporation as a result of an investigation of a natural gas explosion that occurred on Distribution Corporation’s system in Dubois, Pennsylvania in August 2004. The explosion destroyed a residence, resulting in the death of two people who lived there, and is awaiting rulings. Order 2004 also provides an exemption for local distribution companies that are affiliated with interstate pipelines (such as Distribution Corporation), butdamaged a number of other houses in the exemption is limited, with very minor exceptions, to local distribution corporations that do not make any off-system sales and do not purchase gas in ways FERC considers to be “financial or futures transactions or hedging.” While Distribution Corporation stopped making such off-system sales effective September 22, 2004, some of its gas purchase arrangements might be considered by FERC to be “financial or futures transactions or hedging.” Supply Corporationimmediate vicinity.

The NTSB and Distribution Corporation would like to continue operating as they do, whether by waiver, amendment or further clarificationdiffer in their assessment of the new rules, or by complying withprobable cause of the requirements applicable ifexplosion. The NTSB determined that the probable cause was the fracture of a defective “butt-fusion joint” which had joined two sections of plastic pipe, and the failure of Distribution Corporation wereto have an energy affiliate. Treatingadequate program to inspect butt-fusion joints and replace those joints not meeting its inspection criteria. Distribution Corporation as an energy affiliate, without any waivers, would require changeshad submitted to the NTSB a proposed determination of probable cause that was substantially different, namely, that the probable cause was the improper excavation and backfill operations of a third party working in the way Supply Corporation andvicinity of Distribution Corporation’s pipeline. Distribution Corporation operatealso had raised issues concerning the testing standards employed in the NTSB investigation. Distribution Corporation is presently reviewing alternatives by which would decrease efficiency, but probably would not increase capital or operating expenses to an extent that would be material to the financial conditionseek review of the Company.* Until there is further clarification fromNTSB’s findings and conclusions to ensure that the FERC on the scope of theseNTSB considered all


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exemptions
relevant evidence, including the report of Distribution Corporation’s third-party plastic pipe expert and rulings onother relevant evidence, in reaching its determination of probable cause.
The NTSB’s safety recommendations to Distribution Corporation involved revisions to its butt-fusion procedures for joining plastic pipe, and revisions to its procedures for qualifying personnel who perform plastic fusions. Although not required by law to do so, Distribution Corporation is presently implementing those recommendations.
The NTSB also issued safety recommendations to the Company’s waiver requests,PaPUC and certain other parties. The recommendation to the CompanyPaPUC was to require an analysis of the integrity of butt-fusion joints in Distribution Corporation’s system and replacement of those joints that are determined to have unacceptable characteristics. Distribution Corporation is working cooperatively with the Staff of the PaPUC to permit the PaPUC to undertake the analysis recommended by the NTSB. Specifically, Distribution has done the following, in agreement with the PaPUC Staff:
(i)Distribution Corporation uncovered a limited number of butt-fusions at two locations designated by the PaPUC Staff;
(ii)Commencing July 6, 2006, Distribution Corporation has uncovered additional butt-fusions throughout its Pennsylvania service area as it has uncovered facilities for other purposes; when a butt-fusion has been uncovered, Distribution Corporation has notified the designated PaPUC Staff representative to permit inspection of the quality of the fusion. Distribution Corporation has removed a number of fusions for further evaluation.
Distribution Corporation met with the PaPUC Staff in August 2006 to review findings to date and to discuss further procedures to facilitate the analysis. Distribution Corporation and the PaPUC Staff agreed to submit several of the butt-fusion specimens removed during the inspection process to an independent testing laboratory to assess the integrity of the fusions (and to provide an evaluation of the sampling procedure employed). Distribution Corporation and the PaPUC Staff have agreed upon procedures to test the butt-fusion specimens. Distribution Corporation anticipates that it will continue to meet with the PaPUC Staff to review findings pertaining to this matter and address any integrity concerns that may be identified.* At this time, Distribution Corporation is unable to predict the ultimate impact Order 2004outcome of the analysis or of any negotiations or proceedings that may result from it. Distribution Corporation’s response to the actions of the PaPUC will havedepend on its assessment of the validity of the PaPUC’s analysis and conclusions.
Without admitting liability, Distribution Corporation has settled all significant third-party claims against it related to the explosion, for amounts that are immaterial in the aggregate to the Company. As previously mentioned, Distribution Corporation stopped making off-systemhas been committed to providing safe and reliable service throughout its service territory and firmly believes, based on information presently known, that its system continues to be safe and reliable. According to the Plastics Pipe Institute, plastic pipe today accounts for over 90% of the pipe installed for the natural gas distribution industry in the United States and Canada. Distribution Corporation, along with many other natural gas utilities operating in the United States, has relied extensively upon the use of plastic pipe in its natural gas distribution system since the 1970s.
Pipeline and Storage
On April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office of Consumer Advocate filed a complaint and a motion for summary disposition against Supply Corporation with the FERC under Sections 5(a) and 13 of the Natural Gas Act (NGA). The complainants alleged that Supply Corporation’s rates were unjust and unreasonable, and that Supply Corporation was permitted to retain more gas from shippers than is necessary for fuel and loss. As a result, the complainants alleged, Supply Corporation has excess annual earnings of approximately $30 million to $35 million.
In their complaint, the complainants asked FERC (i) to find that Supply Corporation’s rates are unjust and unreasonable, and (ii) to institute proceedings to determine the just and reasonable rates Supply Corporation will be authorized to charge prospectively. The complainants also asked FERC in their complaint (i) to determine whether Supply Corporation has the authority to make sales effective September 22, 2004. The Companyof gas retained from shippers, and (ii) if FERC concludes that Supply Corporation does not expecthave such authority, to direct Supply Corporation to show


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cause why it should not be required to disgorge profits associated with such sales. In their motion for summary disposition, the complainants asked FERC (i) to find summarily that changethe rate at which Supply Corporation is permitted to haveretain gas from shippers for fuel and loss is unjust and unreasonable, (ii) to require Supply Corporation to make a material effect oncompliance filing providing detailed information regarding its fuel and loss retention and use, and (iii) to establish just and reasonable fuel and loss percentages for Supply Corporation.
On June 23, 2006, FERC denied the Company’s resultscomplainants’ motion for summary disposition, set the matter for hearing and referred the complaint to a settlement Administrative Law Judge. On August 8, 2006, a presiding Administrative Law Judge was appointed and discovery activity began. On August 22, 2006, the presiding Administrative Law Judge established a procedural schedule under which he would issue an initial recommended decision by August 8, 2007. Discovery and settlement activity continued. On September 26, 2006, the presiding Administrative Law Judge granted Supply Corporation’s unopposed motion to suspend the procedural schedule because the active parties had reached a settlement in principle.
On November 17, 2006, Supply Corporation filed a motion asking FERC to approve an uncontested settlement of operations,the proceeding. The proposed settlement would be implemented when and if FERC approves the settlement, but if approved would be effective as margins resulting from off-system salesof December 1, 2006. The principal elements of the settlement are minimal as a result of profit sharing with retailfollows:
(i)All participants have reached a negotiated resolution of all the issues raised or which could have been raised in the proceeding, including the claim that Supply Corporation should disgorge all previous efficiency gas sales profits.
(ii)Supply Corporation’s gas retention allowances on transportation services will decrease from 2% to 1.4%, which will reduce Supply Corporation’s future revenue from sales of excess “efficiency gas.” For example, if pre-settlement Supply Corporation received 100 Dth of gas for transportation under its firm transportation rate schedule, Supply Corporation would retain 2 Dth for fuel, loss and company use. Post-settlement, Supply Corporation would retain a total of 1.4 Dth for the combination of fuel, company use and “lost and unaccounted for” (LAUF). Supply Corporation may continue to sell the excess retained gas, if any, that is not consumed or lost in operations (the “efficiency gas”) and keep the proceeds. However, any profit from the purchase and sale of gas to cash out shipper imbalances will continue to be accounted for separately and refunded to customers. Supply Corporation will publicly file at FERC a semi-annual report disclosing, among other things, the quantity, price and accounting treatment of all sales of efficiency gas. The amount of net revenue from Supply Corporation’s future sales of efficiency gas will depend upon the quantity of efficiency gas that becomes available for sale and the prices which Supply Corporation receives from selling that gas.*
(iii)Supply Corporation’s annual depreciation rate for transmission plant will decrease to 2.9%, and its annual depreciation rate for storage plant will decrease to 2.23%. This will result in a decrease to Supply Corporation’s depreciation expense by $5.623 million per year from the pre-settlement level of annual depreciation expense.*
(iv)The settlement does not change Supply Corporation’s rates other than its gas retention allowances. No general rate cases or NGA Section 5 complaint may be filed by the settling parties to be effective before December 1, 2011. However, Supply Corporation may file limited NGA Section 4 rate cases as permitted by FERC for matters of general applicability to all pipelines (such as passing through some possible future greenhouse gas tax), and may propose seasonal rates.
(v)Supply Corporation’s Other Post-Retirement Benefits Rate Allowance (the amount deemed to be recovered each year in rates to fund the Post-Retirement Plan benefits described in Note G — Retirement Plan and Other Post-Retirement Benefits) will increase from about $4.736 million to $11.0 million per year. Supply Corporation will contribute its entire Other Post-Retirement Benefits Rate Allowance to the VEBA trusts and 401(h) account described in that Note G. About $2.5 million per year of the Other Post-Retirement Benefits Rate Allowance will be applied to fully amortize over the next five years Supply Corporation’s entire other post-retirement benefits regulatory asset balance at December 1, 2006, which had been deferred for recovery under a 1995 rate case settlement. To the extent the remainder of the Other Post-


55


Retirement Benefits Rate Allowance differs from the SFAS 106 expense that Supply Corporation actually accrues for the Post-Retirement Plan, that difference will be deferred for future recovery or refund as a regulatory asset or liability. See Note G — Retirement Plan and Other Post-Retirement Benefits for extensive disclosure on the Post-Retirement Plan.
(vi)Supply Corporation’s tariff provisions on discounting gas retention allowances will be amended so as to be consistent with FERC’s current policy limiting “fuel discounts.” Certain pre-settlement discounts in gas retention allowances will also be incorporated into the tariff. The discounting changes described in this subparagraph (vi) are not expected to change Supply Corporation’s earnings as compared to pre-settlement discounting practices.*
This matter will be resolved at FERC by either (i) FERC approval of a settlement, or (ii) the hearing process described above, in the course of which the presiding judge would issue initial recommended decision(s) which would be considered by FERC.* In that event, FERC would issue an order that would either be consistent or inconsistent with any recommended decision, after which any new rates would go into effect.* Supply Corporation expects the proposed settlement to be approved.* If this matter goes to hearing, Supply Corporation will vigorously oppose the complaint.*
Empire currently does not have a rate case on file with the NYPSC. Management will continue to monitor its financial position in the New York jurisdiction to determine the necessity of filing a rate case in the future.

Among the issues that will be resolved in connection with Empire’s FERC application to build the Empire Connector are the rates and terms of service that would become applicable to all of Empire’s business, effective upon Empire accepting the FERC certificate and placing its new facilities into service (currently targeted for November 2008, or sooner if feasible). At that time, Empire would become an interstate pipeline subject to FERC regulation.*
A preliminary determination was issued in the Empire Connector FERC proceeding on July 20, 2006, resolving the rate and other non-environmental issues subject to the outcome of pending rehearing requests and any future appeals, and requiring Empire to make a compliance filing with respect to certain non-environmental issues. Empire made its compliance filing on September 18, 2006. This filing developed initial rates applicable to Empire’s existing services (as they would look under FERC regulation), based on a derived annual cost of service of $30.4 million. Included in this derived cost of service is a change of Empire’s transmission plant annual depreciation rate from 4% to 2.5%, resulting in a reduction of $3.3 million in the filed-for cost of service. This depreciation change would have no impact on earnings because the resulting decrease in revenue would be matched by a decrease in depreciation expense. The initial rates developed from this cost of service are under a straight fixed variable rate design, where all fixed elements of cost of service would be recovered under a fixed monthly reservation charge, and costs which vary with throughput would be recovered in charges per Dth of throughput. This rate design would eliminate most of the revenue variability associated with weather.*
On September 13, 2006 the New York State Department of Environmental Conservation issued an Air State Facility Permit for the Oakfield compressor station, a part of the Empire Connector project. On October 13, 2006, FERC issued a final supplemental environmental impact statement on the Empire Connector project and the other related downstream projects, indicating that FERC has not identified any environmental reasons why those projects could not be built, and that it is the preferred alternative. The next steps at FERC would be the issuance and acceptance of Certificates of Public Convenience and Necessity on all the related projects, followed by additional environmental permits from the U.S. Army Corps of Engineers and state environmental agencies.* The Company expects that all the necessary permits will be obtained and accepted, firm service agreements signed, acceptable proposals for materials and construction-related services will be received and accepted, and the Empire Connector project will be built and in service by November 2008. *
ENVIRONMENTAL MATTERS

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


56


Company’s policy to accrue estimated environmentalclean-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 remainingclean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be $14.0$3.8 million.* This liability has been recorded on the Consolidated Balance Sheet at September 30, 2004.2006. The Company expects to recover its environmentalclean-up costs from a combination of rate recovery and insurance proceeds.* Other than discussed in Note GH (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.* The Company is subject to various federal, state and local laws and regulations (including those of the Czech Republic and Canada) relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures.

For further discussion refer to Item 8 at Note GH — Commitments and Contingencies under the heading “Environmental Matters.”

NEW ACCOUNTING PRONOUNCEMENTS

In September 2004,March 2005, the SECFASB issued Staff Accounting Bulletin No. 106 (SAB 106). SAB 106 addresses the applicationFIN 47, an interpretation of SFAS No.143. FIN 47 provides additional guidance on the term “conditional asset retirement obligation” as used in SFAS 143, “Accountingand in particular the standard clarifies when a Company must record a liability for a conditional asset retirement obligation. The Company has adopted FIN 47 as of September 30, 2006. Refer to Item 8 at Note B — Asset Retirement Obligations” (SFAS 143) to companies that followObligations for further disclosure regarding the full-cost methodimpact of FIN 47 on the Company’s consolidated financial statements.
In May 2005, the FASB issued SFAS 154. SFAS 154 replaces APB 20 and SFAS 3 and changes the requirements for the accounting for oil and gas property acquisition, explorationreporting of a change in accounting principle. The Company’s financial condition and development costs.results of operations will only be impacted by SFAS 154 if there are any accounting changes or corrections of errors in the future. For afurther discussion of SAB 106SFAS 154 and its impact on the Company, refer to Item 8 at Note A — Summary of Significant Accounting Policies.
In June 2006, the FASB issued FIN 48, an interpretation of SFAS 109. FIN 48 clarifies the accounting for uncertainty in income taxes and reduces the diversity in current practice associated with the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return by defining a “more-likely-than-not” threshold regarding the sustainability of the position. The Company is currently evaluating the impact of FIN 48 on its consolidated financial statements. For further discussion of FIN 48 and its impact on the Company, refer to Item 8 at Note A — Summary of Significant Accounting Policies.
In September 2006, the FASB issued SFAS 157. SFAS 157 provides guidance for using fair value to measure assets and liabilities. The pronouncement serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. The Company is currently evaluating the impact that the adoption of SFAS 157 will have on its consolidated financial statements. For further discussion of SFAS 157 and its impact on the Company, refer to Item 8 at Note A — Summary of Significant Accounting Policies.
In September 2006, the FASB issued SFAS 158, an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R. SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of Company’s fiscal year, with limited exceptions. The Company is required to recognize the funded status of its benefit plans and the disclosure requirements of SFAS 158 by the fourth quarter of fiscal 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be adopted by the Company by the end of fiscal 2009. If the Company recognized the funded status of its pension and post-retirement benefit plans at September 30, 2006, the Company’s Consolidated Balance Sheet would reflect a liability of $220.8 million instead of the prepaid pension and post-retirement costs of $64.1 million and pension and post-retirement liabilities of $32.9 million that are currently presented on the balance sheet at September 30, 2006. The Company expects that it will record a regulatory asset for the majority of this liability with the remainder reflected in accumulated other comprehensive income (loss). The difference between what the Company


57


currently records on its Consolidated Balance Sheet for its pension and post-retirement benefit obligations and what it will be required to record under SFAS 158 is due to certain unrecognized actuarial gains and losses and unrecognized prior service costs for both the pension and other post-retirement benefit plans as well as an unrecognized transition obligation for the other post-retirement benefit plan. These amounts are not required to be recorded on the Company’s Consolidated Balance Sheet under the current accounting standards, but were instead amortized over a period of time.
EFFECTS OF INFLATION

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

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

The Company is including the following cautionary statement in thisForm 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, those which are designated with an asterisk (“*”) and those which are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions, are “forward-looking” statements as defined in the Private Securities

48


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 laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations;
2. Changes in economic conditions, including economic disruptions caused by terrorist activities, or acts of war;war or major accidents;
 
 2.3. Changes in demographic patterns and weather conditions, including the occurrence of severe weather;
3. Changes in the availability and/or price of natural gas, oil and coal;weather such as hurricanes;
 
 4.Changes in the availabilityand/or price of natural gas or oil and the effect of such changes on the accounting treatment or valuation of derivative financial instruments or the Company’s natural gas and oil reserves;
5. Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
6. Changes in the availabilityand/or price of derivative financial instruments;
7. Changes in the price differentials between various types of oil;
8. Failure of the price differential between heavy sour crude oil and light sweet crude oil to return to its historical norm;


58


9. Inability to obtain new customers or retain existing ones;
5.10. Significant changes in competitive factors affecting the Company;
 
6.11. Governmental/regulatory actions, initiatives and proceedings, including those affectinginvolving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained gas), affiliate relationships, industry and rate structure, franchises, permits,franchise renewal, and environmental/safety requirements;
 
7.12. Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;
 
8.13. Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs;costs or plans, including changes in the plans of the sponsors of the proposed Millennium Pipeline with respect to that project;
 
9.14. The nature and projected profitability of pending and potential projects and other investments;

10.15. Occurrences affecting the Company’s ability to obtain funds from operations or from issuances of debt or equity securities to finance needed capital expenditures and other investments;investments, including any downgrades in the Company’s credit ratings;
 
11.16. Uncertainty of oil and gas reserve estimates;
 
12.17. Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties;
 
13.18. Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves;
 
14.19. Significant changes from expectations in the Company’s actual production levels for natural gas or oil;
 
15. Changes in the availability and/or price of derivative financial instruments;
16. Changes in the price of natural gas or oil and the effect of such changes on the accounting treatment or valuation of financial instruments for the Company’s natural gas and oil reserves;
17. Inability of the various counterparties to meet their obligations with respect to the Company’s financial instruments;
18.20. 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;
 
19.21. Significant changes in tax rates or policies or in rates of inflation or interest;
 
20.22. 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;

49


21.23. Changes in accounting principles or the application of such principles to the Company;
 
22. Changes in laws and regulations to which the Company is subject, including tax, environmental and employment laws and regulations;
23.24. The cost and effects of legal and administrative claims against the Company;
 
24.25. Changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefit plans;
 
25.26. Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide post-retirement benefits; or
 
26.27. Increasing costs of insurance, changes in coverage and the ability to obtain insurance.

The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
 
Item 7AQuantitative and Qualitative Disclosures About Market Risk

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


59

50


 
Item 8Financial Statements and Supplementary Data
 
Index to Financial Statements
Index to Financial Statements
 
Page

Financial Statements:
    
 Page
Financial Statements:
 5261
 5363
 5464
 5565
 5666
 5767
Financial Statement Schedules:  
For the three years ended September 30, 20042006  
 100113

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
Supplementary data that is included in Note LM — Quarterly Financial Data (unaudited) and Note NO — Supplementary Information for Oil and Gas Producing Activities, appears under this Item, and reference is made thereto.


60

51


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of National Fuel Gas Company:
We have completed integrated audits of National Fuel Gas Company’s fiscal 2006 and 2005 consolidated financial statements and of its internal control over financial reporting as of September 30, 2006, and an audit of its fiscal 2004 consolidated financial statements in accordance with the standards of the Public Company

Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule
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, 20042006 and 2003,2005, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 20042006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     As discussed

Internal control over financial reporting
Also, in Note our opinion, management’s assessment, included in “Management’s Report on Internal Control Over Financial Reporting” appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of September 30, 2006 based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2006, based on criteria established inInternal Control — Integrated Frameworkissued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the consolidatedmaintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements the Company adopted Statementin accordance with generally accepted accounting principles, and that receipts and expenditures of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, and No. 143, Accounting for Asset Retirement Obligations, on October 1, 2002.


61

PRICEWATERHOUSECOOPERS LLP

Buffalo, New York

December 9, 2004

52


the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Buffalo, New York
December 7, 2006


62


NATIONAL FUEL GAS COMPANY

REINVESTED IN THE BUSINESS
               
Year Ended September 30

200420032002



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

             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands of dollars, except per common
 
  share amounts) 
 
INCOME
            
Operating Revenues
 $2,311,659  $1,923,549  $1,907,968 
             
Operating Expenses
            
Purchased Gas  1,267,562   959,827   949,452 
Operation and Maintenance  413,726   404,517   385,519 
Property, Franchise and Other Taxes  69,942   69,076   68,978 
Depreciation, Depletion and Amortization  179,615   179,767   174,289 
Impairment of Oil and Gas Producing Properties  104,739       
             
   2,035,584   1,613,187   1,578,238 
Loss on Sale of Timber Properties        (1,252)
Gain on Sale of Oil and Gas Producing Properties        4,645 
             
Operating Income
  276,075   310,362   333,123 
Other Income (Expense):
            
Income from Unconsolidated Subsidiaries  3,583   3,362   805 
Impairment of Investment in Partnership     (4,158)   
Interest Income  10,275   6,496   1,771 
Other Income  2,825   12,744   2,908 
Interest Expense on Long-Term Debt  (72,629)  (73,244)  (82,989)
Other Interest Expense  (5,952)  (9,069)  (6,763)
             
Income from Continuing Operations Before Income Taxes
  214,177   246,493   248,855 
Income Tax Expense  76,086   92,978   94,590 
             
Income from Continuing Operations
  138,091   153,515   154,265 
Discontinued Operations:
            
Income from Operations, Net of Tax     10,199   12,321 
Gain on Disposal, Net of Tax     25,774    
             
Income from Discontinued Operations
     35,973   12,321 
             
Net Income Available for Common Stock
  138,091   189,488   166,586 
             
EARNINGS REINVESTED IN THE BUSINESS
            
Balance at Beginning of Year  813,020   718,926   642,690 
             
   951,111   908,414   809,276 
Share Repurchases  66,269       
Dividends on Common Stock  98,829   95,394   90,350 
             
Balance at End of Year
 $786,013  $813,020  $718,926 
             
Earnings Per Common Share:
            
Basic:            
Income from Continuing Operations $1.64  $1.84  $1.88 
Income from Discontinued Operations     0.43   0.15 
             
Net Income Available for Common Stock
 $1.64  $2.27  $2.03 
             
Diluted:            
Income from Continuing Operations $1.61  $1.81  $1.86 
Income from Discontinued Operations     0.42   0.15 
             
Net Income Available for Common Stock
 $1.61  $2.23  $2.01 
             
Weighted Average Common Shares Outstanding:
            
Used in Basic Calculation  84,030,118   83,541,627   82,045,535 
Used in Diluted Calculation  86,028,466   85,029,131   82,900,438 
             
See Notes to Consolidated Financial Statements


63

53


NATIONAL FUEL GAS COMPANY

CONSOLIDATED BALANCE SHEETS
           
At September 30,

20042003


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

         
  At September 30 
  2006  2005 
  (Thousands of dollars) 
 
ASSETS
Property, Plant and Equipment
 $4,703,040  $4,423,255 
Less — Accumulated Depreciation, Depletion and Amortization  1,825,314   1,583,955 
         
   2,877,726   2,839,300 
         
Current Assets
        
Cash and Temporary Cash Investments  69,611   57,607 
Hedging Collateral Deposits  19,676   77,784 
Receivables — Net of Allowance for Uncollectible Accounts of $31,427 and $26,940, Respectively  144,254   141,408 
Unbilled Utility Revenue  25,538   20,465 
Gas Stored Underground  59,461   64,529 
Materials and Supplies — at average cost  36,693   33,267 
Unrecovered Purchased Gas Costs  12,970   14,817 
Prepaid Pension and Post-Retirement Benefit Costs  64,125   14,404 
Other Current Assets  63,723   67,351 
Deferred Income Taxes  23,402   83,774 
         
   519,453   575,406 
         
Other Assets
        
Recoverable Future Taxes  79,511   85,000 
Unamortized Debt Expense  15,492   17,567 
Other Regulatory Assets  76,917   47,028 
Deferred Charges  3,558   4,474 
Other Investments  88,414   80,394 
Investments in Unconsolidated Subsidiaries  11,590   12,658 
Goodwill  5,476   5,476 
Intangible Assets  31,498   42,302 
Fair Value of Derivative Financial Instruments  11,305    
Deferred Income Taxes  9,003    
Other  4,388   15,677 
         
   337,152   310,576 
         
Total Assets
 $3,734,331  $3,725,282 
         
 
CAPITALIZATION AND LIABILITIES
Capitalization:
        
Comprehensive Shareholders’ Equity
        
Common Stock, $1 Par Value        
Authorized — 200,000,000 Shares; Issued and Outstanding — 83,402,670 Shares and 84,356,748 Shares, Respectively $83,403  $84,357 
Paid In Capital  543,730   529,834 
Earnings Reinvested in the Business  786,013   813,020 
         
Total Common Shareholders’ Equity Before Items Of Other Comprehensive Income (Loss)  1,413,146   1,427,211 
Accumulated Other Comprehensive Income (Loss)  30,416   (197,628)
         
Total Comprehensive Shareholders’ Equity
  1,443,562   1,229,583 
Long-Term Debt, Net of Current Portion
  1,095,675   1,119,012 
         
Total Capitalization
  2,539,237   2,348,595 
         
Current and Accrued Liabilities
        
Notes Payable to Banks and Commercial Paper      
Current Portion of Long-Term Debt  22,925   9,393 
Accounts Payable  133,034   155,485 
Amounts Payable to Customers  23,935   1,158 
Dividends Payable  25,008   24,445 
Interest Payable on Long-Term Debt  18,420   18,438 
Other Accruals and Current Liabilities  27,040   44,596 
Fair Value of Derivative Financial Instruments  39,983   209,072 
         
   290,345   462,587 
         
Deferred Credits
        
Deferred Income Taxes  544,502   489,720 
Taxes Refundable to Customers  10,426   11,009 
Unamortized Investment Tax Credit  6,094   6,796 
Cost of Removal Regulatory Liability  85,076   90,396 
Other Regulatory Liabilities  75,456   66,339 
Pension and Other Post-Retirement Liabilities  32,918   143,687 
Asset Retirement Obligation  77,392   41,411 
Other Deferred Credits  72,885   64,742 
         
   904,749   914,100 
         
Commitments and Contingencies
      
         
Total Capitalization and Liabilities
 $3,734,331  $3,725,282 
         
See Notes to Consolidated Financial Statements


64

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NATIONAL FUEL GAS COMPANY

CONSOLIDATED STATEMENTSTATEMENTS OF CASH FLOWS
                
Year Ended September 30

200420032002



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

             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands of dollars) 
 
Operating Activities
            
Net Income Available for Common Stock $138,091  $189,488  $166,586 
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:            
Gain on Sale of Discontinued Operations     (27,386)   
Loss on Sale of Timber Properties        1,252 
Gain on Sale of Oil and Gas Producing Properties        (4,645)
Impairment of Oil and Gas Producing Properties  104,739       
Depreciation, Depletion and Amortization  179,615   193,144   189,538 
Deferred Income Taxes  (5,230)  40,388   40,329 
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions  1,067   (1,372)  (19)
Impairment of Investment in Partnership     4,158    
Minority Interest in Foreign Subsidiaries     2,645   1,933 
Excess Tax Benefits Associated with Stock-Based Compensation Awards  (6,515)      
Other  4,829   7,390   9,839 
Change in:            
Hedging Collateral Deposits  58,108   (69,172)  (7,151)
Receivables and Unbilled Utility Revenue  (7,397)  (21,857)  8,887 
Gas Stored Underground and Materials and Supplies  1,679   1,934   13,662 
Unrecovered Purchased Gas Costs  1,847   (7,285)  21,160 
Prepayments and Other Current Assets  (39,572)  (42,409)  35,647 
Accounts Payable  (23,144)  48,089   (5,134)
Amounts Payable to Customers  22,777   (1,996)  2,462 
Other Accruals and Current Liabilities  (17,754)  18,715   2,082 
Other Assets  (22,700)  (13,461)  (4,829)
Other Liabilities  80,960   (3,667)  (34,450)
             
Net Cash Provided by Operating Activities
  471,400   317,346   437,149 
             
Investing Activities
            
Capital Expenditures  (294,159)  (219,530)  (172,341)
Net Proceeds from Sale of Foreign Subsidiary     111,619    
Net Proceeds from Sale of Oil and Gas Producing Properties  13   1,349   7,162 
Other  (3,230)  3,238   1,974 
             
Net Cash Used in Investing Activities
  (297,376)  (103,324)  (163,205)
             
Financing Activities
            
Change in Notes Payable to Banks and Commercial Paper     (115,359)  38,600 
Excess Tax Benefits Associated with Stock-Based Compensation Awards  6,515       
Shares Repurchased under Repurchase Plan  (85,168)      
Reduction of Long-Term Debt  (9,805)  (13,317)  (243,085)
Proceeds from Issuance of Common Stock  23,339   20,279   23,763 
Dividends Paid on Common Stock  (98,266)  (94,159)  (89,092)
Dividends Paid to Minority Interest     (12,676)   
             
Net Cash Used in Financing Activities
  (163,385)  (215,232)  (269,814)
             
Effect of Exchange Rates on Cash
  1,365   1,276   3,451 
             
Net Increase in Cash and Temporary Cash Investments
  12,004   66   7,581 
Cash and Temporary Cash Investments At Beginning of Year
  57,607   57,541   49,960 
             
Cash and Temporary Cash Investments At End of Year
 $69,611  $57,607  $57,541 
             
Supplemental Disclosure of Cash Flow Information Cash Paid For:
            
Interest
 $78,003  $84,455  $90,705 
Income Taxes
 $54,359  $83,542  $30,214 
             
See Notes to Consolidated Financial Statements


65

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NATIONAL FUEL GAS COMPANY

CONSOLIDATED STATEMENTSTATEMENTS OF COMPREHENSIVE INCOME
             
Year Ended September 30

200420032002



(Thousands of dollars)
Net Income Available for Common Stock $166,586  $178,944  $117,682 
   
   
   
 
Other Comprehensive Income (Loss), Before Tax:            
Minimum Pension Liability Adjustment  56,612   (86,170)  (52,977)
Foreign Currency Translation Adjustment  21,466   54,472   24,278 
Reclassification Adjustment for Realized Foreign Currency Translation Gain in Net Income     (9,607)   
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period  3,629   2,419   (2,086)
Unrealized Loss on Derivative Financial Instruments Arising During the Period  (129,934)  (47,777)  (42,584)
Reclassification Adjustment for Realized (Gain) Loss on Derivative Financial Instruments in Net Income  49,142   69,809   (20,063)
   
   
   
 
Other Comprehensive Income (Loss), Before Tax  915   (16,854)  (93,432)
   
   
   
 
Income Tax Expense (Benefit) Related to Minimum Pension Liability Adjustment  19,814   (30,159)  (18,542)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period  1,270   847   (730)
Income Tax Benefit Related to Unrealized Loss on Derivative Financial Instruments Arising During the Period  (49,113)  (18,594)  (17,341)
Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gain) Loss on Derivative Financial Instruments in Net Income  18,182   26,953   (8,040)
   
   
   
 
Income Taxes — Net  (9,847)  (20,953)  (44,653)
   
   
   
 
Other Comprehensive Income (Loss)  10,762   4,099   (48,779)
   
   
   
 
Comprehensive Income $177,348  $183,043  $68,903 
   
   
   
 

             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands of dollars) 
 
Net Income Available for Common Stock $138,091  $189,488  $166,586 
             
Other Comprehensive Income (Loss), Before Tax:            
Minimum Pension Liability Adjustment  165,914   (83,379)  56,612 
Foreign Currency Translation Adjustment  7,408   14,286   21,466 
Reclassification Adjustment for Realized Foreign Currency Translation Gain in Net Income  (716)  (37,793)   
Unrealized Gain on Securities Available for Sale Arising During the Period  2,573   2,891   3,629 
Reclassification Adjustment for Realized Gains On Securities Available for Sale in Net Income     (651)   
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period  90,196   (206,847)  (129,934)
Reclassification Adjustment for Realized Loss on Derivative Financial Instruments in Net Income  91,743   97,689   49,142 
             
Other Comprehensive Income (Loss), Before Tax:  357,118   (213,804)  915 
             
Income Tax Expense (Benefit) Related to Minimum Pension Liability Adjustment  58,070   (29,183)  19,814 
Income Tax Expense Related to Foreign Currency Translation Adjustment     112    
Reclassification Adjustment for Income Tax Expense on Foreign Currency Translation Adjustment in Net Income     (112)   
Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period  894   1,012   1,270 
Reclassification Adjustment for Income Tax Expense on Realized Gains from Securities Available for Sale in Net Income     (228)   
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period  34,772   (79,059)  (49,113)
Reclassification Adjustment for Income Tax Benefit on Realized Loss on Derivative Financial Instruments In Net Income  35,338   36,507   18,182 
             
Income Taxes — Net  129,074   (70,951)  (9,847)
             
Other Comprehensive Income (Loss)  228,044   (142,853)  10,762 
             
Comprehensive Income $366,135  $46,635  $177,348 
             
See Notes to Consolidated Financial Statements


66

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note A — Summary of Significant Accounting Policies
 
Principles of Consolidation

Principles of Consolidation
The Company consolidates its majority owned subsidiaries.entities. 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 AmericaGAAP 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

Reclassification

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

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,GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note BC — 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
The Company’s Utility segment records revenue as bills are rendered, except that service supplied but not billed is reported as unbilled utility revenue and is included in operating revenues for the year in which service is furnished. The Company’s Pipeline and Storage International and Energy Marketing segments record revenue as bills are rendered for service supplied on a calendar month basis. The International segment also records monthly revenue on an estimated basis for certain heating customers. The customers make estimated payments on a monthly basis and a final true-up and bill is rendered at the end of the calendar year. The Company’s Timber segment records revenue on lumber and log sales as products are shipped.

The Company’s Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company’s ownership interest in the producing well. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance.
 
Regulatory Mechanisms

Allowance for Uncollectible Accounts
The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age and other specific information about customer accounts. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered.
Regulatory Mechanisms
The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.


67

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note BC — Regulatory Matters for further discussion.

The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a weather normalization clause (WNC),WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is more than 2.2% warmer than normal results in a surcharge being added to customers’ current bills, while weather that is more than 2.2% colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues.

In the Pipeline and Storage segment, the allowed rates that Supply Corporation bills its customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs in fixed monthly reservation charges. The allowed rates that Empire bills its customers are based on a modified-fixed variable rate design, which allows recovery of most fixed costs in fixed monthly reservation charges. To distinguish between the two rate designs, the modified fixed-variable rate design recovers return on equity and income taxes through variable charges whereas straight fixed-variable recovers all fixed costs, including return on equity and income taxes, through its monthly reservation charge. Because of the difference in rate design, changes in throughput due to weather variations do not have a significant impact on Supply Corporation’s revenues but may have a significant impact on Empire’s revenues.
 
Property, Plant and Equipment

Property, Plant and Equipment
The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service in the regulated businesses, as required by regulatory authorities.

Oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. All costs directly associated with property acquisition, exploration and development activities are capitalized, up to certain specified limits. If capitalized costs exceed these limits at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The Company’s capitalized costs exceeded the full cost ceiling for the Company’s Canadian properties at June 30, 20032006 and September 30, 2003. The2006. As such, the Company recognized pre-tax impairments of $31.8 million and $11.0$62.4 million at June 30, 20032006 and $42.3 million at September 30, 2003, respectively.

2006.

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.

58
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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Depreciation, Depletion and Amortization
 
Depreciation, Depletion and Amortization

For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unevaluated oil and gas properties is excluded from this computation. For timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. For all other property, plant and equipment, depreciation, depletion and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment:
         
As of September 30

20042003


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

         
  As of September 30 
  2006  2005 
  (Thousands) 
 
Utility $1,493,991  $1,462,527 
Pipeline and Storage  962,831   960,066 
Exploration and Production  1,899,777   1,665,774 
Energy Marketing  1,123   1,108 
Timber  116,281   114,352 
All Other and Corporate  33,338   29,275 
         
  $4,507,341  $4,233,102 
         
Average depreciation, depletion and amortization rates are as follows:
             
Year Ended September 30

200420032002



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


             
  Year Ended September 30 
  2006  2005  2004 
 
Utility  2.8%  2.8%  2.8%
Pipeline and Storage  4.0%  4.1%  4.1%
Exploration and Production, per Mcfe(1) $2.00  $1.74  $1.49 
Energy Marketing  4.8%  7.6%  8.7%
Timber  5.6%  6.2%  6.5%
All Other and Corporate  4.1%  4.3%  6.2%
(1)Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note NO — Supplementary Information for Oil and Gas Producing Properties, depletion of oil and gas producing properties amounted to $1.47, $1.30$1.98, $1.72 and $1.16$1.47 per Mcfe of production in 2004, 20032006, 2005 and 2002,2004, respectively.

59


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Cumulative Effect of Changes in Accounting

Effective October 1, 2002,Goodwill

The Company has recognized goodwill of $5.5 million as of September 30, 2006 and 2005 on its consolidated balance sheet related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with SFAS 142, which requires the Company adopted SFAS 143. SFAS 143 requires entities to recordtest goodwill for impairment annually. At September 30, 2006 and 2005, the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted toEmpire was greater than its present value each period and the capitalized cost is depreciated over the useful life of the related asset. In the Company’s case, SFAS 143 changed the accounting for plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells. In prior fiscal years, the Company accounted for plugging and abandonment costs using the Securities and Exchange Commission’s full cost accounting rules. SFAS 143 was calculated retroactively to determine the cumulative effect through October 1, 2002. This cumulative effect reduced earnings $0.6 million, net of income tax. If the new method of accounting for plugging and abandonment costs had been effective for 2002, there would not have been a material change to net income available for common stock. A reconciliation of the Company’s asset retirement obligation calculated in accordance with SFAS 143 is shown below ($000s):
         
Year Ended
September 30

20042003


(Thousands)
Balance at Beginning of Year $27,493  $36,090 
Liabilities Incurred and Revisions of Estimates  3,510   242 
Liabilities Settled  (831)  (13,227)
Accretion Expense  1,933   2,602 
Exchange Rate Impact  187   1,786 
   
   
 
Balance at End of Year $32,292  $27,493 
   
   
 

     In the Company’s Utility and Pipeline and Storage segment, costs of removal are collected from customers through depreciation expense. These removal costs are not a legal retirement obligation in accordance with SFAS 143. Rather, they represent a regulatory liability. However, SFAS 143 requires thatbook value. As such, costs of removal be reclassified from accumulated depreciation to other regulatory liabilities. At September 30, 2004 and 2003, the costs of removal reclassified to other regulatory liabilities amounted to $82.0 million and $76.8 million, respectively.

Effective October 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). In accordance with SFAS 142, the Company stopped amortization of goodwill and tested it for impairment as of October 1, 2002. The Company’s goodwill balance as of October 1, 2002 totaled $8.3 million and was related to the Company’s investments in the Czech Republic, which are included in the International segment. As a result of the impairment test, the Company recognized an impairment of $8.3 million. The Company used discounted cash flows to estimate the fair value of its goodwill and determined that the goodwill had no remaining value. Based on projected restructuring in the Czech electricity market, the Company couldwas considered not be assured that the level of future cash flows from the Company’s investments in the Czech Republic would attain the level that was originally forecasted. In accordance with SFAS 142, this impairment was reported as a cumulative effect of change in accounting. Goodwill amortization amounted to $0.6 million in 2002.impaired.

 
Financial Instruments

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 EF — Financial Instruments for further discussion.

60
69


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

For effective cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. Any ineffectiveness associated with the cash flow hedges is recorded in the Consolidated Statements of Income. The Company did not experience any material ineffectiveness with regard to its cash flow hedges during 2004, 20032006 or 2002.2004. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues, purchased gas expense or interest expense on the Consolidated Statements of Income. At September 30, 2005, it was determined that certain derivative financial instruments no longer qualified as effective cash flow hedges due to anticipated delays in oil and gas production volumes caused by Hurricane Rita. These volumes were originally forecast to be produced in the first quarter of 2006. As such, at September 30, 2005, the Company reclassified $5.1 million in accumulated losses on such derivative financial instruments from accumulated other comprehensive income (loss) on the Consolidated Balance Sheet to other 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 Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged.hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. The Company did not experience any material ineffectiveness with regard to its fair value hedges during 2004, 20032006, 2005 or 2002.2004.
 
Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss)

The components of Accumulated Other Comprehensive Income (Loss) are as follows:
         
Year Ended
September 30

20042003


(Thousands)
Minimum Pension Liability Adjustment $(53,648) $(90,446)
Cumulative Foreign Currency Translation Adjustment  51,516   30,050 
Net Unrealized Loss on Derivative Financial Instruments  (56,733)  (6,872)
Net Unrealized Gain on Securities Available for Sale  4,090   1,731 
   
   
 
Accumulated Other Comprehensive Loss $(54,775) $(65,537)
   
   
 

         
  Year Ended September 30 
  2006  2005 
  (Thousands) 
 
Minimum Pension Liability Adjustment $  $(107,844)
Cumulative Foreign Currency Translation Adjustment  34,701   28,009 
Net Unrealized Loss on Derivative Financial Instruments  (11,510)  (123,339)
Net Unrealized Gain on Securities Available for Sale  7,225   5,546 
         
Accumulated Other Comprehensive Income (Loss) $30,416  $(197,628)
         
At September 30, 2004,2006, it is estimated that $45.4 million of the $11.5 million net unrealized loss on derivative financial instruments shown in the table above $12.7 million will be reclassified into the Consolidated Statement of Income during 2005.2007. The remaining unrealized gain on derivative financial instruments of $1.2 million will be reclassified into the Consolidated Statement of Income in subsequent years. As disclosed in Note EF — Financial Instruments, the Company’s derivative financial instruments extend out to 2009.2012.


70


NATIONAL FUEL GAS COMPANY
 
Gas Stored Underground — Current

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Gas Stored Underground — Current
In the Utility segment, gas stored underground — current in the amount of $46.6$29.5 million is carried at lower of cost or market, on a last-in, first-out (LIFO)LIFO method. Based upon the average price of spot market gas purchased in September 2004,2006, including transportation costs, the current cost of replacing this inventory of gas stored underground-currentunderground — current exceeded the amount stated on a LIFO basis by approximately $113.3$136.0 million at September 30, 2004.2006. All other gas stored underground — current, which is in the Energy Marketing segment, is carried at lower of cost or market on an average cost method.

61


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Unamortized Debt Expense

Purchased Timber Rights

In the Timber segment, the Company purchases the right to harvest timber from land owned by other parties. These rights, which extend from several months to several years, are purchased to ensure a consistent supply of timber for the Company’s sawmill and kiln operations. The historical value of timber rights expected to be harvested during the following year are included in Materials and Supplies on the Consolidated Balance Sheets while the historical value of timber rights expected to be harvested beyond one year are included in Other Assets on the Consolidated Balance Sheets. The components of the Company’s purchased timber rights are as follows:
         
  Year Ended September 30 
  2006  2005 
  (Thousands) 
 
Materials and Supplies $13,174  $10,610 
Other Assets  3,218   11,510 
         
  $16,392  $22,120 
         
Unamortized Debt Expense
Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related debt. Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment.
 
Foreign Currency Translation

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

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
Consolidated Statements of foreign subsidiaries as these amounts are considered to be permanently reinvested outside the United States.Cash Flows
 
Consolidated Statement of Cash Flows

For purposes of the Consolidated StatementStatements of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.


71


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Hedging Collateral Account
Cash and temporary cash investments includes cash held in margin accounts to serveserves as collateral for open positions on exchange-traded futures contracts, exchange-traded options andover-the-counter swaps and exchange-traded options. Thecollars.
Other Current Assets
Other Current Assets consist of prepayments in the amounts held in margin accounts amounted to $8.6of $25.7 million and $1.5$23.9 million at September 30, 20042006 and 2003,2005, respectively, federal income taxes receivable in the amounts of $7.5 million and $27.1 million at September 30, 2006 and 2005, respectively, state income taxes receivable in the amounts of $7.4 million and $2.6 million at September 30, 2006 and 2005, respectively, and fair values of firm commitments in the amounts of $23.1 million and $13.7 million at September 30, 2006 and 2005, respectively.
 
Earnings Per Common Share

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 StatementStatements of Income reflectsreflect the potential dilution as a result of these stock options as determined using the Treasury Stock Method. Stock options that are antidilutive are excluded from the calculation of diluted earnings per common share. For 2004, 2003 and 2002, 2,296,828, 7,789,688 and 5,260,6332006, 119,241 stock options respectively, were excluded as being antidilutive.

62


NATIONAL FUEL GAS COMPANY There were no stock options excluded as being antidilutive for 2005. For 2004, 2,296,828 stock options were excluded as being antidilutive.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Stock-Based Compensation

Share Repurchases

The Company accountsconsiders all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is settled as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note E — Capitalization and Short-Term Borrowings for further discussion of the share repurchase program.
Stock-Based Compensation
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, 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. Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant.
Prior to October 1, 2005, the Company accounted for its stock-based compensation usingunder the intrinsic value method specified by Accounting Principles Board Opinion No.recognition and measurement principles of APB 25 “Accounting for Stock Issued to Employees” and related interpretations. Under that method, no compensation expense was recognized for options granted under the plansCompany’s stock option and stock award plans. The Company did record, in accordance with APB 25, compensation expense for the market value of restricted stock on the date of the award over the periods during which the vesting restrictions existed.


72


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Effective October 1, 2005, the Company adopted SFAS 123R, which requires the measurement and recognition of compensation cost at fair value for all share-based payments, including stock options. The Company has chosen to use the modified version of prospective application, as allowed by SFAS 123R. Using the modified prospective application, the Company is recording compensation cost for the portion of awards granted prior to October 1, 2005 for which the requisite service had not been rendered and is recognizing such compensation cost as the requisite service is rendered on or after October 1, 2005. Such compensation expense is based on the grant-date fair value of the awards as calculated for the Company’s disclosure using a Binomial option-pricing model under SFAS 123. Any new awards, modifications to awards, repurchases of awards, or cancellations of awards subsequent to September 30, 2005 will follow the provisions of SFAS 123R, with compensation expense being calculated using the Black-Scholes-Merton closed form model. The Company has chosen the Black-Scholes-Merton closed form model since it is easier to administer than the Binomial option-pricing model. Furthermore, since the Company does not have complex stock-based compensation awards, it does not believe that compensation expense would be materially different under either model. There were 317,000, 700,000 and 87,000 stock-based compensation awards granted during the years ended September 30, 2006, 2005 and 2004, respectively. Stock-based compensation expense for the years ended September 30, 2006, September 30, 2005, and September 30, 2004 2003was approximately $1,705,000 ($442,000 of which relates to the application of the non-substantive vesting period approach discussed below), $517,000 and 2002. Had$835,000, respectively. Stock-based compensation expense been determined basedis included in operation and maintenance expense on fair valuethe Consolidated Statement of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2006, 2005 and 2004 was approximately $653,000, $206,000 and $333,000, respectively. There were no capitalized stock-based compensation costs during the years ended September 30, 2006 and September 30, 2005.
Prior to the adoption of SFAS 123R, the Company followed the nominal vesting period approach under the disclosure requirements of SFAS 123 for determining the vesting period for awards with retirement-eligible provisions, which recognized stock-based compensation expense over the nominal vesting period. As a result of the adoption of SFAS 123R, the Company currently applies the non-substantive vesting period approach for determining the vesting period of such awards. Under this approach, the retention of the award is not contingent on providing subsequent service and the vesting period would begin at the grant dates, whichdate and end at the retirement-eligible date. For the year ended September 30, 2006, the Company recognized an additional $442,000 ($288,000 net of tax) of stock-based compensation expense by applying the non-substantive vesting approach. For the year ended September 30, 2005, stock-based compensation expense would have been $4,282,000 ($2,752,000 net of tax) for pro forma recognition purposes had the non-substantive vesting period approach been used. The pro forma stock-based compensation expense would have been $2,670,000 ($1,798,000 net of tax) under the non-substantive vesting period approach for the year ended September 30, 2004. Pro forma stock-based compensation expense following the nominal vesting period approach is shown in the accounting treatment specified by SFAS 123, “Accounting for Stock-Based Compensation,”table below.


73


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table illustrates the Company’seffect on net income and earnings per share would have been reducedof the Company had the Company applied the fair value recognition provisions of SFAS 123 relating to stock-based employee compensation for the years ended September 30, 2005 and 2004:
         
  Year Ended September 30 
  2005  2004 
  (Thousands, except per share amounts) 
 
Net Income, Available for Common Stock, As Reported $189,488  $166,586 
Add: Stock-Based Employee Compensation Expense Included in Reported Net Income, Net of Tax(1)  336   543 
Deduct: Total Stock-Based Employee Compensation Expense Determined Under Fair Value Based Methods for all Awards, Net of Related Tax Effects  (2,782)  (1,861)
         
Pro Forma Net Income Available for Common Stock $187,042  $165,268 
         
Earnings Per Common Share:        
Basic — As Reported $2.27  $2.03 
Basic — Pro Forma $2.24  $2.01 
Diluted — As Reported $2.23  $2.01 
Diluted — Pro Forma $2.20  $1.99 
(1)Stock-based compensation expense in 2005 and 2004 represented compensation expense related to restricted stock awards. The pre-tax expense was $517,000 and $835,000, respectively, for the years ended September 30, 2005 and 2004.
Stock Options
The total intrinsic value of stock options exercised during the years ended September 30, 2006, September 30, 2005, and September 30, 2004 totaled approximately $30.9 million, $19.8 million, and $12.4 million, respectively. For 2006, 2005 and 2004, the amount of cash received by the Company from the exercise of such stock options was approximately $30.1 million, $24.8 million, and $16.4 million, respectively. The Company realizes tax benefits related to the pro forma amounts below:
              
Year Ended September 30

200420032002



(Thousands, except per share amounts)
Net Income Available for Common Stock As Reported $166,586  $178,944  $117,682 
Deduct: Total Compensation Expense Determined Based on Fair Value at the Grant Dates  1,318   3,105   4,641 
   
   
   
 
Pro Forma Net Income Available for Common Stock $165,268  $175,839  $113,041 
   
   
   
 
Earnings Per Common Share:            
 Basic — As Reported $2.03  $2.21  $1.47 
 Basic — Pro Forma $2.01  $2.18  $1.42 
 Diluted — As Reported $2.01  $2.20  $1.46 
 Diluted — Pro Forma $1.99  $2.16  $1.40 

exercise of stock options on a calendar year basis as opposed to a fiscal year basis. As such, for stock options exercised during the quarters ended December 31, 2005, December 31, 2004, and December 31, 2003, the Company realized a tax benefit of $0.9 million, $1.1 million, and $0.1 million, respectively. For stock options exercised during the period of January 1, 2006 through September 30, 2006, the Company will realize a tax benefit of approximately $11.4 million in the quarter ended December 31, 2006. For stock options exercised during the period of January 1, 2005 through September 30, 2005, the Company realized a tax benefit of approximately $6.3 million in the quarter ended December 31, 2005. For stock options exercised during the period of January 1, 2004 through September 30, 2004, the Company realized a tax benefit of approximately $4.8 million in the quarter ended December 31, 2004. The weighted average grant date fair value per share of options granted in 2006, 2005 and 2004 2003is $6.68 per share, $4.59 per share, and 2002$4.66 per share, respectively. For the years ended September 30, 2006, 2005 and 2004, 89,665, 1,375,105 and 729,156 stock options became fully vested, respectively. The total fair value of these stock options was $4.66, $4.17approximately $0.4 million, $6.2 million and $4.32, respectively. These$3.3 million, respectively, for the years ended September 30, 2006, 2005 and 2004. As of September 30, 2006, unrecognized compensation expense related to stock options totaled approximately $0.9 million, which will be recognized over a weighted average fair values were estimated on the dateperiod of grant usingone year. For a binomialsummary of transactions during 2006 involving option pricing model with the following weighted average assumptions:

             
Year Ended September 30

200420032002



Quarterly Dividend Yield  1.12%  1.10%  1.07%
Annual Standard Deviation (Volatility)  21.77%  22.24%  21.83%
Risk Free Rate  4.61%  3.33%  4.88%
Expected Term — in Years  7.0   6.5   5.5 
shares for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
New Accounting Pronouncements

     In September 2004, the SEC issued SAB 106. SAB 106 addresses the application of SFAS 143 to companies that follow the full cost method of accounting for oil and gas property acquisition, exploration and development costs. SAB 106 states that after adoption of SFAS 143, the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation. The Company adopted SAB 106 for purposes of the full cost ceiling calculation at September 30, 2004. The adoption of SAB 106 did not have any impact on the Company’s financial statements and did not have a material effect on the results of the ceiling test calculation.
74

63


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The fair value of options at the date of grant was estimated using a Binomial option-pricing model for options granted prior to October 1, 2005 and the Black-Scholes-Merton closed form model for options granted after September 30, 2005. The following weighted average assumptions were used in estimating the fair value of options at the date of grant:
             
  Year Ended September 30 
  2006  2005  2004 
 
Risk Free Interest Rate  5.08%  4.46%  4.61%
Expected Life (Years)  7.0   7.0   7.0 
Expected Volatility  17.71%  17.76%  21.77%
Expected Dividend Yield (Quarterly)  0.83%  1.00%  1.12%
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the option. The expected life and expected volatility are based on historical experience.
For grants prior to October 1, 2005, the Company used a forfeiture rate of 13.6% for calculating stock-based compensation expense related to stock options and this rate is based on the Company’s historical experience of forfeitures on unvested stock option grants. For grants during the year ended September 30, 2006, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
Restricted Share Awards
For a summary of transactions during 2006 involving restricted share awards, refer to Note E — Capitalization and Short-Term Borrowings.
As of September 30, 2006, unrecognized compensation expense related to restricted share awards totaled approximately $577,000, which will be recognized over a weighted average period of 2.1 years.
During 2006, a modification was made to a restricted share award involving one employee. The modification accelerated the vesting date of 4,000 shares from December 7, 2006 to July 1, 2006. The incremental compensation expense, totaling approximately $32,000, was included with the total stock-based compensation expense for the year ended September 30, 2006.
New Accounting Pronouncements
In March 2005, the FASB issued FIN 47, an interpretation of SFAS 143. FIN 47 provides clarification of the term “conditional asset retirement obligation” as used in SFAS 143, defined as a legal obligation to perform an asset retirement activity in which the timingand/or method of settlement are conditional on a future event that may or may not be within the control of the Company. Under this standard, a company must record a liability for a conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. FIN 47 also serves to clarify when a company would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation. The Company has adopted FIN 47 as of September 30, 2006. Refer to Note B — Asset Retirement Obligations for further disclosure regarding the impact of FIN 47 on the Company’s consolidated financial statements.
In May 2005, the FASB issued SFAS 154. SFAS 154 replaces APB 20 and SFAS 3 and changes the requirements for the accounting for and reporting of a change in accounting principle. The Company is required to adopt SFAS 154 for accounting changes and corrections of errors that occur in 2007. The Company’s financial condition and results of operations will only be impacted by SFAS 154 if there are any accounting changes or corrections of errors in the future.


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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In June 2006, the FASB issued FIN 48, an interpretation of SFAS 109. FIN 48 clarifies the accounting for uncertainty in income taxes and reduces the diversity in current practice associated with the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return by defining a “more-likely-than-not” threshold regarding the sustainability of the position. The Company is required to adopt FIN 48 by the first quarter of fiscal 2008. The Company is currently evaluating the impact of FIN 48 on its consolidated financial statements.
In September 2006, the FASB issued SFAS 157, “Fair Value Measurements”. SFAS 157 provides guidance for using fair value to measure assets and liabilities. The pronouncement serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. SFAS 157 is to be applied whenever another standard requires or allows assets or liabilities to be measured at fair value. The pronouncement is effective as of the Company’s first quarter of fiscal 2009. The Company is currently evaluating the impact that the adoption of SFAS 157 will have on its consolidated financial statements.
In September 2006, the FASB also issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” (an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R). SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. The Company is required to recognize the funded status of its benefit plans and the disclosure requirements of SFAS 158 by the fourth quarter of fiscal 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be adopted by the Company by the end of fiscal 2009. If the Company recognized the funded status of its pension and post-retirement benefit plans at September 30, 2006, the Company’s consolidated balance sheet would reflect a liability of $220.8 million instead of the prepaid pension and post-retirement costs of $64.1 million and pension and post-retirement liabilities of $32.9 million that are currently presented on the balance sheet at September 30, 2006. The Company expects that it will record a regulatory asset for the majority of this liability with the remainder reflected in accumulated other comprehensive income (loss).
Note B — Asset Retirement Obligations
Effective October 1, 2002, the Company adopted SFAS 143. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon the adoption of SFAS 143, the Company recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells.
On September 30, 2006, the Company adopted FIN 47, an interpretation of SFAS 143. FIN 47 provides clarification of the term “conditional asset retirement obligation” as used in SFAS 143, defined as a legal obligation to perform an asset retirement activity in which the timingand/or method of settlement are conditional on a future event that may or may not be within the control of the Company. Under this standard, if the fair value of a conditional asset retirement obligation can be reasonably estimated, a company must record a liability and a corresponding asset for the conditional asset retirement obligation representing the present value of that obligation at the date the obligation was incurred. FIN 47 also serves to clarify when a company would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation.


76


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As a result of the adoption of FIN 47, the Company identified future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. The Company also identified asset retirement obligations for certain costs connected with the retirement of distribution mains and services pipeline systems in the Utility segment and with the transmission mains and other components in the pipeline systems in the Pipeline and Storage segment. These retirement costs within the distribution and transmission systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for theclean-up of PCB contamination associated with the removal of certain pipe.
A reconciliation of the Company’s asset retirement obligation calculated in accordance with SFAS 143 is shown below ($000s):
             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Balance at Beginning of Year $41,411  $32,292  $27,493 
Additions — Adoption of FIN 47  23,234       
Liabilities Incurred and Revisions of Estimates  11,244   8,343   3,510 
Liabilities Settled  (1,303)  (1,938)  (831)
Accretion Expense  2,671   2,448   1,933 
Exchange Rate Impact  135   266   187 
             
Balance at End of Year $77,392  $41,411  $32,292 
             
As a result of the implementation of FIN 47 as of September 30, 2006, the Company recorded additional asset retirement obligations of $23.2 million and corresponding long-lived plant assets, net of accumulated depreciation, of $3.5 million. These assets will be depreciated over their respective remaining depreciable life. The remaining $19.7 million represents the cumulative accretion and depreciation of the asset retirement obligations that would have been recognized if this interpretation had been in effect at the inception of the obligations. Of this amount, the Company recorded an increase to regulatory assets of $9.0 million and a reduction to cost of removal regulatory liability of $10.7 million. The cost of removal regulatory liability represents amounts collected from customers through depreciation expense in the Company’s Utility and Pipeline and Storage segments. These removal costs are not a legal retirement obligation in accordance with SFAS 143. Rather, they represent a regulatory liability. However, SFAS 143 requires that such costs of removal be reclassified from accumulated depreciation to other regulatory liabilities. At September 30, 2006 and 2005, the costs of removal reclassified to other regulatory liabilities amounted to $85.1 million and $90.4 million, respectively.
Pursuant to FIN 47, the financial statements for periods prior to September 30, 2006 have not been restated. If FIN 47 had been in effect, the Company would have recorded additional asset retirement obligations of $21.9 million at September 30, 2005, and $20.6 million at October 1, 2004.


77


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note C — Regulatory Matters
 
Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

The Company has recorded the following regulatory assets and liabilities:
          
At September 30

20042003


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


         
  At September 30 
  2006  2005 
  (Thousands) 
 
Regulatory Assets(1):
        
Recoverable Future Taxes (Note D) $79,511  $85,000 
Pension and Post-Retirement Benefit Costs(2) (Note G)  47,368   27,135 
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A)  12,970   14,817 
Environmental Site Remediation Costs(2) (Note H)  12,937   13,054 
Asset Retirement Obligation(2) (Note B)  9,018    
Unamortized Debt Expense (Note A)  8,399   9,088 
Other(2)  7,594   6,839 
         
Total Regulatory Assets  177,797   155,933 
         
Regulatory Liabilities:
        
Cost of Removal Regulatory Liability (Note B)  85,076   90,396 
New York Rate Settlements(3)  40,881   53,205 
Amounts Payable to Customers (See Regulatory Mechanisms in Note A)  23,935   1,158 
Tax Benefit on Medicare Part D Subsidy(3)  13,791    
Pension and Post-Retirement Benefit Costs(3) (Note G)  13,063   12,751 
Taxes Refundable to Customers (Note D)  10,426   11,009 
Deferred Insurance Proceeds(3)  7,516    
Other(3)  205   383 
         
Total Regulatory Liabilities  194,893   168,902 
         
Net Regulatory Position $(17,096) $(12,969)
         
(1)The Company recovers the cost of its regulatory assets but, with the exception of Unrecovered Purchased Gas Costs, does not earn a return on them.
 
(2)Included in Other Regulatory Assets on the Consolidated Balance Sheets.
 
(3)Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.

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


78


NATIONAL FUEL GAS COMPANY
 
New York Rate Settlements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

New York Rate Settlements
With respect to utility services provided in New York, the Company has entered into rate settlements approved by the State of New York Public Service Commission (NYPSC).NYPSC. The rate settlements provide forhave given rise to several significant liabilities, which are described as follows:
Gross Receipts Tax Over-Collections — In accordance with NYPSC policies, Distribution Corporation deferred the difference between the revenues it collects under a sharing mechanism, whereby earnings above an 11.5% (11.0%, effective October 1, 2003) return on equity are to be shared equally between shareholdersNew York State gross receipts tax surcharge and customers. Asits actual New York State income tax expense. Distribution Corporation’s cumulative gross receipts tax revenues exceeded its New York State income tax expense, resulting in a result of this sharing mechanism, the Company had liabilities of $12.0 million and $11.4 millionregulatory liability at September 30, 20042006 and 2003,2005 of $19.8 million and $34.3 million, respectively. Other aspectsUnder the terms of its 2005 rate settlement, Distribution Corporation will pass back that regulatory liability to rate payers over a twenty-four month period that began August 1, 2005. Further, the gross receipts tax surcharge that gave rise to the regulatory liability was eliminated from Distribution Corporation’s tariff (New York State income taxes are now recovered as a component of base rates).
Cost Mitigation Reserve (“CMR”) — The CMR is a regulatory liability that can be used to offset certain expense items specified in Distribution Corporation’s rate settlements. The source of the settlements include a special reserve of $3.5 million and $5.4 million at September 30, 2004 and 2003, respectively, to be applied againstCMR is principally the Company’s incremental costs resulting from the

64


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NYPSC’s gas restructuring effort and a “cost mitigation reserve” of $5.6 million and $8.2 million at September 30, 2004 and 2003, respectively. The cost mitigation reserve is an accumulation of certain refunds from upstream pipeline companiescompanies. During 2005, under the terms of the 2005 rate settlement, Distribution Corporation transferred the remaining balance in a generic restructuring reserve (which had been established in a prior rate settlement) and certain credits which can be usedthe balances it had accumulated under various earnings sharing mechanisms to offset certain specific expense items.the CMR. The balance in the CMR at September 30, 2006 and 2005 amounted to $7.6 million and $7.0 million, respectively.

Other — The 2005 settlement also established a reserve to fund area development projects. The balance in the area development projects reserve at September 30, 2006 and 2005 amounted to $3.9 million and $3.8 million, respectively (Distribution Corporation established the reserve at September 30, 2005 by transferring $3.8 million from the CMR discussed above). Various other regulatory liabilities have also been created through the New York rate settlements and amounted to $4.9$9.6 million and $5.9$8.1 million at September 30, 20042006 and 2005, respectively.
Tax Benefit on Medicare Part D Subsidy
The Company has established a regulatory liability for the tax benefit it will receive under the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 respectively.(the Act). The Act provides a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In the Company’s Utility and Pipeline and Storage segments, the rate payer funds the Company’s post-retirement benefit plans. As such, any tax benefit received under the Act must be flowed-through to the rate payer. Refer to Note G — Retirement Plan and Other Post-Retirement Benefits for further discussion of the Act and its impact on the Company.
Deferred Insurance Proceeds
The Company, in its Utility and Pipeline and Storage segments, received $7.5 million in environmental insurance settlement proceeds. Such proceeds have been deferred as a regulatory liability to be applied against any future environmental claims that may be incurred. The proceeds have been classified as a regulatory liability in recognition of the fact that rate payers funded the premiums on the former insurance policies.


79


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note CD — Income Taxes

The components of federal, state and foreign income taxes included in the Consolidated StatementStatements of Income are as follows:
               
Year Ended September 30

200420032002



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

             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Operating Expenses:            
Current Income Taxes —            
Federal $65,593  $40,062  $42,679 
State  13,511   14,413   7,871 
Foreign  2,212   1,503   206 
Deferred Income Taxes —            
Federal  19,111   27,412   29,559 
State  9,024   2,280   9,620 
Foreign  (33,365)  7,308   4,655 
             
   76,086   92,978   94,590 
Other Income:            
Deferred Investment Tax Credit  (697)  (697)  (697)
Discontinued Operations            
Operations     9,310   (1,479)
Gain on Sale     1,612    
             
Total Income Taxes $75,389  $103,203  $92,414 
             
The U.S. and foreign components of income (loss) before income taxes are as follows:
             
Year Ended September 30

200420032002



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

65


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
U.S.  $293,887  $223,113  $232,928 
Foreign  (80,407)  69,578   26,072 
             
  $213,480  $292,691  $259,000 
             

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

200420032002



(Thousands)
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% $90,650  $106,923  $66,060 
Increase (Reduction) in Taxes Resulting from:            
 State Income Taxes  11,369   16,232   7,379 
 Foreign Tax Differential  (1,166)  3,318   (481)
 Foreign Tax Rate Reduction  (5,174)      
 Miscellaneous  (3,265)  75   (1,898)
   
   
   
 
Total Income Taxes $92,414  $126,548  $71,060 
   
   
   
 
             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% $74,718  $102,442  $90,650 
Increase in Taxes Resulting from:            
State Income Taxes  14,648   10,850   11,369 
Foreign Tax Differential  (3,718)  (4,845)  (1,166)
Foreign Tax Rate Reduction        (5,174)
Reversal of Capital Loss Valuation Allowance  (2,877)      
Miscellaneous  (7,382)  (5,244)  (3,265)
             
Total Income Taxes $75,389  $103,203  $92,414 
             

     Legislation was enacted
80


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The foreign tax differential amount shown above for 2006 includes a $5.1 million deferred tax benefit relating to additional future tax deductions forecasted in Canada and the Czech Republic which reducesamount for 2005 includes tax effects relating to the corporate statutory income tax rate from 31% to 24% overdisposition of a three-year period.foreign subsidiary. The foreign tax rate reduction amount shown above reflects afor 2004 relates to the reduction in deferredof the statutory income taxes that were provided in prior years when a higher statutory tax rate was in effect.

the Czech Republic. The miscellaneous amount shown above for 2006 includes a net reversal of $3.2 million relating to a tax contingency reserve.

Significant components of the Company’s deferred tax liabilities and assets are as follows:
          
At September 30

20042003


(Thousands)
Deferred Tax Liabilities:        
 Property, Plant and Equipment $568,114  $519,578 
 Other  37,051   21,532 
   
   
 
Total Deferred Tax Liabilities  605,165   541,110 
   
   
 
Deferred Tax Assets:        
 Minimum Pension Liability Adjustment  (28,887)  (48,701)
 Capital Loss Carryover  (12,546)  (18,607)
 Unrealized Hedging Losses  (33,890)  (4,509)
 Other  (74,624)  (52,368)
   
   
 
   (149,947)  (124,185)
 Valuation Allowance  2,877   6,357 
   
   
 
Total Deferred Tax Assets  (147,070)  (117,828)
   
   
 
Total Net Deferred Income Taxes $458,095  $423,282 
   
   
 

         
  At September 30 
  2006  2005 
  (Thousands) 
 
Deferred Tax Liabilities:        
Property, Plant and Equipment $569,677  $567,850 
Other  37,865   52,436 
         
Total Deferred Tax Liabilities  607,542   620,286 
         
Deferred Tax Assets:        
Minimum Pension Liability Adjustment     (58,069)
Capital Loss Carryover  (8,786)  (9,145)
Unrealized Hedging Losses  (4,653)  (75,657)
Other  (82,006)  (74,346)
         
   (95,445)  (217,217)
Valuation Allowance     2,877 
         
Total Deferred Tax Assets  (95,445)  (214,340)
         
Total Net Deferred Income Taxes $512,097  $405,946 
         
Presented as Follows:        
Net Deferred Tax Asset — Current $(23,402) $(83,774)
Net Deferred Tax Asset — Non-Current  (9,003)   
Net Deferred Tax Liability — Non-Current  544,502   489,720 
         
Total Net Deferred Income Taxes $512,097  $405,946 
         
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $11.1$10.4 million and $13.5$11.0 million at September 30, 20042006 and 2003,2005, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $83.8$79.5 million and $84.8$85.0 million at September 30, 20042006 and 2003,2005, respectively.

66


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The Company has undistributed earnings of foreign subsidiaries that relate to its operations in the Czech Republic. These earnings are considered to be permanently reinvested outside the United States and, accordingly, no U.S. income taxes have been provided thereon. In the event such earnings are distributed, the Company may be subject to U.S. income taxes and foreign withholding taxes, net of allowable foreign tax credits or deductions. At September 30, 2004, such undistributed earnings totaled $49.6 million. In addition, there was a $35.8 million positive cumulative translation adjustment attributable to this investment, and similarly, no U.S. income taxes have been provided thereon.

The American Jobs Creation Act of 2004, was signed into law on October 22, 2004. The Company is reviewing the aspects of this legislation2004, included a provision which affect, or will affect, the Company’s various segments, including the provision providingprovided a substantially reduced tax rate of 5.25% on certain dividends received from foreign affiliates. This provision is effective, at the election ofDuring 2005, the Company forreceived a dividend of $72.8 million from a foreign dividends received in either 2005 or 2006.

affiliate and recorded a tax of $3.8 million on such dividend.

A capital loss carryover of $36$25.1 million exists at September 30, 2004,2006, which expires if not utilized by September 30, 2008. Although realization is not assured, management estimatesdetermined that a portion ofit is more likely than not that the entire deferred tax asset associated with this carryover will be realized during the carryover period, and a valuation allowance is recorded for the remaining portion. Adjustments toperiod. As such, the valuation allowance may be necessary in the future if estimates of capital gain income are revised.$2.9 million was reversed during 2006.

67
81


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A deferred tax asset of $9.0 million relating to Canadian operations exists at September 30, 2006. Although realization is not assured, management determined that it is more likely than not that future taxable income will be generated in Canada to fully utilize this asset, and as such, no valuation allowance was provided.
Note DE — Capitalization and Short-Term Borrowings
Summary of Changes in Common Stock Equity
                     
           Earnings
  Accumulated
 
           Reinvested
  Other
 
        Paid
  in
  Comprehensive
 
  Common Stock  In
  the
  Income
 
  Shares  Amount  Capital  Business  (Loss) 
  (Thousands, except per share amounts) 
 
Balance at September 30, 2003  81,438  $81,438  $478,799  $642,690  $(65,537)
Net Income Available for Common Stock              166,586     
Dividends Declared on Common Stock ($1.10 Per Share)              (90,350)    
Other Comprehensive Income, Net of Tax                  10,762 
Common Stock Issued Under Stock and Benefit Plans(1)  1,552   1,552   27,761         
                     
Balance at September 30, 2004  82,990   82,990   506,560   718,926   (54,775)
Net Income Available for Common Stock              189,488     
Dividends Declared on Common Stock ($1.14 Per Share)              (95,394)    
Other Comprehensive Loss, Net of Tax                  (142,853)
Cancellation of Shares  (2)  (2)  (52)        
Common Stock Issued Under Stock and Benefit Plans(1)  1,369   1,369   23,326         
                     
Balance at September 30, 2005  84,357   84,357   529,834   813,020   (197,628)
Net Income Available for Common Stock              138,091     
Dividends Declared on Common Stock ($1.18 Per Share)              (98,829)    
Other Comprehensive Income, Net of Tax                  228,044 
Share-Based Payment Expense(2)          1,705         
Common Stock Issued Under Stock and Benefit Plans(1)  1,572   1,572   28,564         
Share Repurchases  (2,526)  (2,526)  (16,373)  (66,269)    
                     
Balance at September 30, 2006  83,403  $83,403  $543,730  $786,013(3) $30,416 
                     
 
Summary of Changes in Common Stock Equity
                     
EarningsAccumulated
Common StockReinvestedOther

Paid Inin theComprehensive
SharesAmountCapitalBusinessIncome (Loss)





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


(1)Paid in Capital includes tax benefits of $6.5 million, $3.7 million and $1.5 million for September 30, 2006, 2005 and 2004, respectively, associated with the exercise of stock options.
(2)As of October 1, 2005, Paid in Capital includes compensation costs associated with stock option and restricted stock awards, in accordance with SFAS 123R. The expense is included within Net Income Available For Common Stock, net of tax benefits.
(3)The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2004, $644.52006, $692.7 million of accumulated earnings was free of such limitations.


82


NATIONAL FUEL GAS COMPANY
 
Common Stock

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Common Stock
The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent.

68


During 2006, the Company issued 2,292,639 original issue shares of common stock as a result of stock option exercises and 16,000 original issue shares for restricted stock awards (non-vested stock as defined in SFAS 123R). Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise pricesNATIONAL FUEL GAS COMPANYand/or applicable withholding taxes. During 2006, 744,567 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company also has a Director Stock Program under which it issues shares of the Company common stock to its non-employee directors as partial consideration for their services as directors. Under this program, the Company issued 8,400 original issue shares of common stock to the non-employee directors of the Company during 2006.
 
Shareholder Rights Plan

On December 8, 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. During 2006, the Company repurchased 2,526,550 shares under this program, funded with cash provided by operating activities. At September 30, 2006, the Company had made commitments to repurchase an additional 99,100 shares of common stock. These commitments were settled and recorded as a reduction of the Company’s outstanding shares of common stock in October 2006.
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 thetwo-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


83


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

69


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Stock Option and Stock Award Plans

Stock Option and Stock Award Plans
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, restricted stock, performance units or performance shares. Stock options under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option is exercisable less than one year or more than ten years after the date of each grant.


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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Transactions involving option shares for all plans are summarized as follows:
         
Number of
Shares SubjectWeighted Average
to OptionExercise Price


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


                 
        Weighted
    
        Average
    
  Number of
     Remaining
  Aggregate
 
  Shares Subject
  Weighted Average
  Contractual
  Intrinsic
 
  to Option  Exercise Price  Life (Years)  Value 
           (In thousands) 
 
Outstanding at September 30, 2005  10,996,893  $23.78         
Granted in 2006  317,000  $35.21         
Exercised in 2006  (2,292,639) $21.77         
Forfeited in 2006  (5,000) $24.94         
                 
Outstanding at September 30, 2006  9,016,254  $24.69   4.21  $105,096 
                 
Option shares exercisable at September 30, 2006  8,643,753  $24.32   4.01  $103,999 
                 
Option shares available for future grant at September 30, 2006(1)  434,911             
                 
(1)In connection with exercising these options, 557,410, 200,708 and 43,834 shares were surrendered and canceled during 2004, 2003 and 2002, respectively.
(2) Including 3,097,172 non-qualified stock options issued in November 2001. The Company canceled 3,097,172 stock appreciation rights (SARs) in November 2001 and issued 3,097,172 non-qualified stock options. The Company eliminated all future awards of SARs.
(3) Including shares available for restricted stock grants.

The following table summarizes information about options outstanding at September 30, 2004:
                     
Options OutstandingOptions Exercisable


Weighted
NumberAverageWeightedNumberWeighted
OutstandingRemainingAverageExercisableAverage
Range of Exercise Priceat 9/30/04Contractual LifeExercise Priceat 9/30/04Exercise Price






$13.90-$16.68  441,060   1.0  $14.23   441,060  $14.23 
$16.69-$19.46  1,139,558   2.0  $18.38   1,139,558  $18.38 
$19.47-$22.24  2,545,696   5.0  $21.26   2,432,296  $21.25 
$22.25-$25.02  6,073,297   5.3  $23.34   5,354,957  $23.19 
$25.03-$27.80  2,296,828   6.3  $27.63   2,226,497  $27.68 

70


2006:

                     
  Options Outstanding  Options Exercisable 
     Weighted
          
  Number
  Average
  Weighted
  Number
  Weighted
 
  Outstanding
  Remaining
  Average
  Exercisable
  Average
 
  at
  Contractual
  Exercise
  at
  Exercise
 
Range of Exercise Price
 9/30/06  Life  Price  9/30/06  Price 
 
$18.55-$22.26  1,598,641   3.3  $21.31   1,568,641  $21.32 
$22.27-$25.97  4,500,219   3.5  $23.33   4,480,718  $23.32 
$25.98-$29.68  2,600,394   5.3  $27.85   2,594,394  $27.85 
$29.69-$33.39               
$33.40-$37.10  317,000   9.6  $35.21       
NATIONAL FUEL GAS COMPANYRestricted Share Awards

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the periods during which the vesting restrictions exist.period. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective.

The following table summarizes
85


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Transactions involving option shares for all plans are summarized as follows:
         
  Number of
  Weighted Average
 
  Restricted
  Fair Value per
 
  Share Awards  Award 
 
Restricted Share Awards Outstanding at September 30, 2005  64,928  $24.46 
Granted in 2006  16,000  $34.94 
Vested in 2006  (38,600) $24.43 
         
Restricted Share Awards Outstanding at September 30, 2006  42,328  $28.44 
         
Vesting restrictions for the awards of restricted stock over the past three years:
             
Year Ended September 30

200420032002



Shares of Restricted Stock Awarded        100,000 
Weighted Average Market Price of Stock on Award Date       $24.50 

     As of September 30, 2004, 98,528outstanding shares of non-vested restricted stock were outstanding. Vesting restrictionsat September 30, 2006 will lapse as follows: 2005 — 33,600 shares; 2006 — 34,600 shares; 2007 — 29,00025,000 shares; 2008 — 2,500 shares; 2009 — 4,500 shares; 2010 — 5,828 shares; and 20102011 — 1,3284,500 shares.

Compensation expense related to restricted stock under the Company’s stock plans was $0.7 million, $1.0 million and $0.7 million for the years ended September 30, 2004, 2003 and 2002, respectively.

 
Redeemable Preferred Stock

Redeemable Preferred Stock

As of September 30, 2004,2006, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.
 
Long-Term Debt

Long-Term Debt

The outstanding long-term debt is as follows:
          
At September 30

20042003


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


         
  At September 30 
  2006  2005 
  (Thousands) 
 
Medium-Term Notes(1):        
6.0% to 7.50% due May 2008 to June 2025 $749,000  $749,000 
Notes(1):        
5.25% to 6.50% due March 2013 to September 2022(2)  346,665   347,222 
         
   1,095,665   1,096,222 
         
Other Notes:        
Secured(3)  22,766   32,100 
Unsecured  169   83 
         
Total Long-Term Debt  1,118,600   1,128,405 
Less Current Portion  22,925   9,393 
         
  $1,095,675  $1,119,012 
         
(1)These debentures, medium-term notes and notes are unsecured.
 
(2)At September 30, 20042006 and 2003, $97,272,0002005, $96,665,000 and $97,400,000,$97,222,000, respectively, of these notes were callable at par at any time after September 15, 2006. The change in the amount outstanding from year to year is

71


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

attributable to the estates of individual note holders exercising put options due to the death of an individual note holder.
 
(3)These notes constitute “project financing” and are secured by the various project documentation and natural gas transportation contracts related to the Empire State Pipeline. The interest rate on these notes is a variable rate based on LIBOR. It is the Company’s intention to pay off these notes within one year. As such, the notes have been classified as current.


86


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of September 30, 2004,2006, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $14.3 million in 2005, $14.3 million in 2006, $9.3$22.9 million in 2007, $209.3$200.0 million in 2008, $104.1$100.0 million in 2009, zero in 2010, $200.0 million in 2011, and $796.3$595.7 million thereafter.
 
Short-Term Borrowings

Short-Term Borrowings
The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. As for the former, the Company maintains a number of individual (bi-lateral) uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. Each of theseThese credit lines, which aggregate to $400.0$445.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed.renewed, or replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $200.0$300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $220.0 million. Of that amount, $110.0$300.0 million, is committed to the Company through September 25, 2005, and $110.0 millionwhich is committed to the Company through September 30, 2005.

2010.

At September 30, 2004,2006 and September 30, 2005, the Company had no outstanding short-term notes payable to banks andor commercial paper of $26.5 million and $130.3 million, respectively. All of this debt was domestic. At September 30, 2003, the Company had outstanding notes payable to banks and commercial paper of $55.2 million and $63.0 million, respectively.

The weighted average interest rate on notes payable to banks was 1.82% and 1.27% at September 30, 2004 and 2003, respectively. The weighted average interest rate on commercial paper was 1.85% and 1.18% at September 30, 2004 and 2003, respectively.paper.

 
Debt Restrictions

Debt Restrictions
Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio (as calculated under that facility) will not exceed .65 at the last day of any fiscal quarter exceed .625 from October 1, 2003September 30, 2005 through September 30, 2004 and .60 from October 1, 2004 and thereafter.2010. At September 30, 2004,2006, the Company’s debt to capitalization ratio (as calculated under the facility) was .51..44. The constraints specified in the committed credit facility would permit an additional $576.0 million$1.56 billion in short-termand/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio would exceed .60..65. If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its committed and uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.

Under the Company’s existing indenture covenants, at September 30, 2004,2006, the Company would have been permitted to issue up to a maximum of $713.0 million$1.03 billion in additional long-term unsecured indebtedness at then current market interest rates (further limited by the debt to capitalization ratio constraints noted in the previous paragraph) in addition to being able to issue new indebtedness to replace maturing debt.

The Company’s 1974 indenture pursuant to which $399.0 million (or 35%36%) of the Company’s long-term debt (as of September 30, 2004)2006) was issued contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the

72


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Company fails (i) to pay any scheduled principal or interest or any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

The Company’s $220.0$300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $20.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $20.0 million or


87


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2004,2006, the Company had no debt outstanding under the committed credit facility.

Note EF — Financial Instruments
 
Fair Values

Fair Values

The fair market value of the Company’s long-term debt is estimated based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
                 
At September 30

2004200420032003
CarryingFairCarryingFair
AmountValueAmountValue




(Thousands)
Long-Term Debt $1,147,577  $1,199,189  $1,389,510  $1,520,606 

                 
  At September 30 
  2006 Carrying
  2006 Fair
  2005 Carrying
  2005 Fair
 
  Amount  Value  Amount  Value 
  (Thousands) 
 
Long-Term Debt $1,118,600  $1,148,089  $1,128,405  $1,181,599 
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay.

Temporary cash investments, notes payable to banks and commercial paper are stated at cost, which approximates their fair value due to the short-term maturities of those financial instruments. Investments in life insurance are stated at their cash surrender values as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
 
Other Investments

Other Investments
Other investments includes cash surrender values of insurance contracts and marketable equity securities. The cash surrender values of the insurance contracts amounted to $56.1$62.5 million and $53.5$59.6 million at September 30, 20042006 and 2003,2005, respectively. The fair value of the equity mutual fund was $7.8$12.9 million and $4.8$9.8 million at September 30, 20042006 and 2003,September 30, 2005, respectively. The gross unrealized gain on thethis equity mutual fund was $0.1$1.0 million and $0.4 million at September 30, 2004, as compared with a gross unrealized loss of $0.6 million at2006 and September 30, 2003.2005, respectively. During 2005, the Company sold all of its interest in one equity mutual fund for $8.5 million and reinvested the proceeds in another equity mutual fund. The Company recognized a gain of $0.7 million on the sale of the equity mutual fund. The fair value of the stock of an insurance company was $8.7$12.7 million and $5.7$10.5 million at September 30, 20042006 and 2003,2005, respectively. The gross unrealized gain on this stock was $6.2$10.3 million and $3.2$8.1 million at September 30, 20042006 and 2003,2005, respectively. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.

73


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Derivative Financial Instruments

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 or natural gas price quoted on the New York Mercantile Exchange (NYMEX)NYMEX or a quoted natural gas price in “Inside FERC.” The majority of these derivative financial instruments are accounted for as cash flow hedges and are used to lock in a price for the anticipated sale of natural gas and crude oil production in the Exploration and Production segment and the All Other category. The Energy Marketing segment accounts for these derivative financial instruments as fair value hedges and uses them to hedge against falling prices, a risk to which they are


88


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

exposed on their fixed price gas purchase commitments. The Energy Marketing segment also uses these derivative financial instruments to hedge against rising prices, a risk to which they are exposed on their fixed price sales commitments. At September 30, 2004,2006, the Company had natural gas price swap agreements covering a notional amount of 23.07.4 Bcf extending through 2009 at a weighted average fixed rate of $5.47$7.24 per Mcf. Of this amount, 3.31.1 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $5.51$6.98 per Mcf. The remaining 19.76.3 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $5.47$7.29 per Mcf. At September 30, 2006, the Company would have had to pay a net $7.4 million to terminate the price swap agreements. The Company also had crude oil price swap agreements covering a notional amount of 5,038,000900,000 bbls extending through 20072008 at a weighted average fixed rate of $32.01$37.13 per bbl. At September 30, 2004,2006, the Company would have had to pay a net $82.2$27.6 million to terminate the price swap agreements.

Under the no cost collars, the Company receives monthly payments from (or makes payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). The variable price is either a crude oil price quoted on the NYMEX or a quoted natural gas price in “Inside FERC.” These derivative financial instruments are accounted for as cash flow hedges and are used to lock in a price range for the anticipated sale of natural gas and crude oil production in the Exploration and Production segment. At September 30, 2004,2006, the Company had no cost collars on natural gas covering a notional amount of 5.57.1 Bcf extending through 20062008 with a weighted average floor price of $4.93$8.26 per Mcf and a weighted average ceiling price of $8.28$17.25 per Mcf. TheAt September 30, 2006, the Company alsowould have received $10.4 million to terminate the no cost collars. At September 30, 2006, the Company had no cost collars on crude oil covering a notional amount of 105,000180,000 bbls extending through 20052007 with a weighted average floor price of $25.00$70.00 per bbl and a weighted average ceiling price of $28.56$77.00 per bbl. At September 30, 2004, the Company would have had to pay $3.7 million to terminate the no cost collars.

     At September 30, 2004, the Company, in the Exploration and Production segment, had purchased natural gas put options and sold natural gas call options extending through 2006. The call options sold by the Company cover a notional amount of 1.1 Bcf at a weighted average strike price of $8.06 per Mcf. The put options purchased by the Company cover a notional amount of 1.1 Bcf at a weighted average strike price of $5.99 per Mcf. These derivative financial instruments are accounted for as cash flow hedges. The call options are used to establish a ceiling price (the Company makes payments to the counterparty when a variable price rises above the ceiling price) for the anticipated sale of natural gas in the Exploration and Production segment. At September 30, 2004, the Company would have had to pay $1.0 million to terminate these call options. The put options are used to establish a floor price (the Company receives payment from the counterparty when a variable price falls below the floor price) for the anticipated sale of natural gas in the Exploration and Production segment. At September 30, 2004,2006, the Company would have received $0.2$0.9 million to terminate these put options.

no cost collars.

At September 30, 2004,2006, the Company had long (purchased) futures contracts covering 3.514.5 Bcf of gas extending through 20072012 at a weighted average contract price of $6.13$9.20 per Mcf. Of this amount, 3.1 Bcf is

74


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

They are accounted for as fair value hedges. Theyhedges and are used by the Company’s Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed due to the fixed price gas sales commitments that it enters into with commercial and industrial customers. The remaining 0.4 Bcf is accounted for as cash flow hedges. The Company would have received $5.1had to pay $22.4 million to terminate these futures contracts at September 30, 2004.

2006.

At September 30, 2004,2006, the Company had short (sold) futures contracts covering 7.37.5 Bcf of gas extending through 20062009 at a weighted average contract price of $6.19$10.57 per Mcf. Of this amount, 5.94.7 Bcf is accounted for as cash flow hedges as these contracts relate to the anticipated sale of natural gas by the Energy Marketing segment, the Exploration and Production segment and the All Other category.segment. The remaining 1.42.8 Bcf is accounted for as fair value hedges, since these contracts hedge against falling prices, a risk to which the Energy Marketing segment is exposed on its gas storage inventory and fixed price gas purchase commitments.hedges. The Company would have had to pay $11.3received $17.5 million to terminate these futures contracts at September 30, 2004.

2006.

The Company may be exposed to credit risk on some of the derivative financial instruments discussed above. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on an ongoing basis monitors counterparty credit exposure. Management has obtained guarantees from the parent companies of the respective counterparties to its derivative financial instruments. At September 30, 2004,2006, the Company used sevensix counterparties for its over the counter derivative financial instruments. At September 30, 2004,2006, no individual counterparty represented greater than 20%39% of total credit risk (measured as volumes hedged by an individual counterparty as a percentage of the Company’s total volumes hedged).

All of the counterparties (or the parent of the counterparty) were rated as investment grade entities at September 30, 2006.

The Company uses an interest rate collar to limit interest rate fluctuations on certain variable rate debt in the Pipeline and Storage segment. Under the interest rate collar the Company makes quarterly payments to (or receives payments from) another party when a variable rate falls below an established floor rate (the Company


89


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

pays the counterparty) or exceeds an established ceiling rate (the Company receives payment from the counterparty). Under the terms of the collar, which extends until 2009, the variable rate is based on London InterBank Offered Rate.LIBOR. The floor rate of the collar is 5.15% and the ceiling rate is 9.375%. At September 30, 20042006 the notional amount on the collar was $44.3$25.7 million. The Company would have had to pay $2.2$0.1 million to terminate the interest rate collar at September 30, 2004.

2006.

Note FG — Retirement Plan and Other Post-Retirement Benefits

The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan) that covers substantially allapproximately 77% of the 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)VEBA trusts for its Post-Retirement Plan. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ post-retirement health care and life insurance benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its Post-Retirement Plan. They are separate accounts inwithin the Retirement Plan used to pay retiree medical benefits for the associated participants in the Retirement Plan. Contributions are tax-deductible when made and investments accumulate tax-free. Retirement Plan and Post-Retirement Plan assets primarily consist of equity and fixed income investments or units in commingled funds or money market funds.

75


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The Company recovers certain of its net periodic pension and post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization. For financial reporting purposes, to the extent there is recovery in rates, the difference between the amounts of pension cost and post-retirement benefit cost recoverable in rates and the amounts of such costs as determined under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate. The regulatory treatment of a substantial amount of these regulatory assets and liabilities is governed by policy statements issued by the regulatory commissions having jurisdiction over the Utility and Pipeline and Storage segments. Pension and post-retirement benefit costs reflect the amount recovered from customers in rates during the year. Under the NYPSC’s policies, the Company segregates the amount of such costs collected in rates, but not yet contributed to the Retirement and Post-Retirement Plans, into a regulatory liability account. This liability accrues interest at the NYPSC-mandated interest rate, and this interest cost is included in pension and post-retirement benefit costs. For purposes of disclosure, the liability also remains in the disclosed pension and post-retirement benefit liability amount because it has not yet been contributed.

The expected returns on plan assets of the Retirement Plan and Post-Retirement Plan are applied to the market-related value of plan assets of the respective plans. ForThe market-related values of the Retirement Plan the market-related value of assets recognizes the performance of its portfolio over five years and reduces the effects of short-term market fluctuations. The market-related value of Post-Retirement Plan assets is setare equal to market value.

76


value as of the measurement date.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


Year Ended September 30Year Ended September 30


200420032002200420032002






(Thousands)
Change in Benefit Obligation
                        
Benefit Obligation at Beginning of Period $694,960  $625,470  $580,046  $467,418  $393,851  $304,548 
Service Cost  14,598   13,043   11,639   6,027   5,844   4,658 
Interest Cost  40,565   40,967   40,720   26,393   26,124   21,617 
Plan Participants’ Contributions           627   682   610 
Amendments        420          
Actuarial (Gain) Loss  (19,593)  51,302   28,880   (62,146)  57,983   76,972 
Benefits Paid  (36,998)  (35,822)  (36,235)  (16,316)  (17,066)  (14,554)
   
   
   
   
   
   
 
Benefit Obligation at End of Period
 $693,532  $694,960  $625,470  $422,003  $467,418  $393,851 
   
   
   
   
   
   
 
Change in Plan Assets
                        
Fair Value of Assets at Beginning of Period $491,333  $485,927  $536,625  $166,494  $150,293  $161,959 
Actual Return on Plan Assets  81,946   6,145   (29,898)  38,960   390   (18,181)
Employer Contribution  37,085   35,083   15,435   39,720   32,195   20,459 
Plan Participants’ Contributions           627   682   610 
Benefits Paid  (36,998)  (35,822)  (36,235)  (16,316)  (17,066)  (14,554)
   
   
   
   
   
   
 
Fair Value of Assets at End of Period
 $573,366  $491,333  $485,927  $229,485  $166,494  $150,293 
   
   
   
   
   
   
 
Reconciliation of Funded Status
                        
Funded Status $(120,166) $(203,627) $(139,543) $(192,518) $(300,924) $(243,558)
Unrecognized Net Actuarial Loss  159,554   222,250   132,064   108,943   212,242   157,247 
Unrecognized Transition (Asset) Obligation        (3,716)  64,144   71,272   78,399 
Unrecognized Prior Service Cost  9,171   10,274   11,451   20   26   30 
   
   
   
   
   
   
 
Net Amount Recognized at End of Period $48,559  $28,897  $256  $(19,411) $(17,384) $(7,882)
   
   
   
   
   
   
 
Amounts Recognized in the Balance Sheets Consist of:
                        
 Accrued Benefit Liability $(91,587) $(153,240) $(75,116) $(27,263)* $(23,163)* $(20,375)*
 Prepaid Benefit Cost  14,536   10,782   10,944   7,852   5,779   12,493 
 Regulatory Assets  33,904   21,934             
 Intangible Assets  9,171   10,274   11,451          
 Accumulated Other Comprehensive Loss (Pre-Tax)  82,535   139,147   52,977          
   
   
   
   
   
   
 
Net Amount Recognized at End of Period $48,559  $28,897  $256  $(19,411) $(17,384) $(7,882)
   
   
   
   
   
   
 
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
                        
Discount Rate  6.25%  6.00%  6.75%  6.25%**  6.00%  6.75%
Expected Return on Plan Assets  8.25%  8.25%  8.50%  8.25%  8.25%  8.50%
Rate of Compensation Increase  6.11%  6.11%  6.11%  6.11%  6.11%  6.11%
shown in the tables below. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is June 30, 2006, 2005 and 2004, respectively.
                         
  Retirement Plan  Other Post-Retirement Benefits 
  Year Ended September 30  Year Ended September 30 
  2006  2005  2004  2006  2005  2004 
  (Thousands) 
 
Change in Benefit Obligation
                        
Benefit Obligation at Beginning of Period $825,204  $693,532  $694,960  $546,273  $422,003  $467,418 
Service Cost  16,416   13,714   14,598   8,029   6,153   6,027 
Interest Cost  40,196   42,079   40,565   26,804   25,783   26,393 
Plan Participants’ Contributions           1,559   1,017   627 
Actuarial (Gain) Loss  (108,112)  115,128   (19,593)  (115,052)  110,663   (62,146)
Benefits Paid  (41,497)  (39,249)  (36,998)  (21,682)  (19,346)  (16,316)
                         
Benefit Obligation at End of Period
 $732,207  $825,204  $693,532  $445,931  $546,273  $422,003 
                         


90


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                         
  Retirement Plan  Other Post-Retirement Benefits 
  Year Ended September 30  Year Ended September 30 
  2006  2005  2004  2006  2005  2004 
  (Thousands) 
 
Change in Plan Assets
                        
Fair Value of Assets at Beginning of Period $616,462  $573,366  $491,333  $271,636  $229,485  $166,494 
Actual Return on Plan Assets  68,649   56,201   81,946   34,785   20,577   38,960 
Employer Contribution  20,907   26,144   37,085   39,326   39,903   39,720 
Plan Participants’ Contributions           1,559   1,017   627 
Benefits Paid  (41,497)  (39,249)  (36,998)  (21,682)  (19,346)  (16,316)
                         
Fair Value of Assets at End of Period
 $664,521  $616,462  $573,366  $325,624  $271,636  $229,485 
                         
Reconciliation of Funded Status
                        
Funded Status $(67,686) $(208,742) $(120,166) $(120,307) $(274,637) $(192,518)
Unrecognized Net Actuarial Loss  107,626   257,553   159,554   54,487   205,423   108,943 
Unrecognized Transition Obligation           49,890   57,017   64,144 
Unrecognized Prior Service Cost  7,185   8,142   9,171   12   17   20 
                         
Net Amount Recognized at End of Period $47,125  $56,953  $48,559  $(15,918) $(12,180) $(19,411)
                         
Amounts Recognized in the Balance Sheets Consist of:
                        
Accrued Benefit Liability $  $(117,103) $(43,147) $(32,918) $(26,584) $(27,263)
Prepaid Benefit Cost  47,125         17,000   14,404   7,852 
Intangible Assets     8,142   9,171          
Accumulated Other Comprehensive Loss (Pre-Tax)     165,914   82,535          
                         
Net Amount Recognized at End of Period $47,125  $56,953  $48,559  $(15,918) $(12,180) $(19,411)
                         
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
                        
Discount Rate  6.25%  5.00%  6.25%  6.25%  5.00%  6.25%*
Expected Return on Plan Assets  8.25%  8.25%  8.25%  8.25%  8.25%  8.25%
Rate of Compensation Increase  5.00%  5.00%  5.00%  5.00%  5.00%  5.00%
Components of Net Periodic Benefit Cost
                        
Service Cost $16,416  $13,714  $14,598  $8,029  $6,153  $6,027 
Interest Cost  40,196   42,079   40,565   26,804   25,783   26,393 
Expected Return on Plan Assets  (49,943)  (49,545)  (48,281)  (22,302)  (18,862)  (14,898)
Amortization of Prior Service Cost  957   1,029   1,103   4   4   4 
Amortization of Transition Amount           7,127   7,127   7,127 
Recognition of Actuarial Loss  23,108   10,473   9,438   23,402   12,467   17,092 
Net Amortization and Deferral for Regulatory Purposes  (6,409)  1,988   722   (11,084)  (410)  (9,731)
                         
Net Periodic Benefit Cost $24,325  $19,738  $18,145  $31,980  $32,262  $32,014 
                         
Other Comprehensive (Income) Loss (Pre-Tax) Attributable to Change In Additional Minimum Liability Recognition $(165,914) $83,379  $(56,612) $  $  $ 
                         

91


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                         
  Retirement Plan  Other Post-Retirement Benefits 
  Year Ended September 30  Year Ended September 30 
  2006  2005  2004  2006  2005  2004 
  (Thousands) 
 
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30
                        
Discount Rate  5.00%  6.25%  6.00%  5.00%  6.25%  6.25%*
Expected Return on Plan Assets  8.25%  8.25%  8.25%  8.25%  8.25%  8.25%
Rate of Compensation Increase  5.00%  5.00%  5.00%  5.00%  5.00%  5.00%

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

** The weighted average discount rate was 6.0% through 12/8/2003. Subsequent to 12/8/2003, the discount rate used was 6.25%.

77


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                         
Retirement PlanOther Post-Retirement Benefits


Year Ended September 30Year Ended September 30


200420032002200420032002






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


The weighted average discount rate was 6.0% through 12/8/2003. Subsequent to 12/8/2003, the discount rate used was 6.25%.

The Net Periodic Benefit cost in the table above includes the effects of regulation. The Company recovers pension and post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under SFAS 87 and SFAS 106 as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and post-retirement regulatory assets) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.
In accordance with the provisions of SFAS No. 87, “Employers’ Accounting for Pensions,” the Company recorded an additional minimum pension liability at September 30, 2004, 20032005 and 20022004 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 iswas recorded net of the related tax benefit as accumulated other comprehensive loss. The pre-tax amount ofAt September 30, 2006, the Company reversed the additional minimum pension liability, intangible asset and accumulated other comprehensive loss isrecorded in prior years since the fair value of the plan assets exceeded the accumulated benefit obligation at September 30, 2006. The pre-tax amounts of the change in accumulated other comprehensive (income) loss at September 30, 2006, 2005 and 2004 are shown in the table above. The projected benefit obligation, accumulated benefit obligation and fair value of assets for the retirement plan were as follows:
             
200420032002



Projected Benefit Obligation $693,532  $694,960  $625,470 
Accumulated Benefit Obligation $616,513  $611,858  $550,099 
Fair Value of Plan Assets $573,366  $491,333  $485,927 

             
  2006  2005  2004 
 
Projected Benefit Obligation $732,207  $825,204  $693,532 
Accumulated Benefit Obligation $660,026  $733,565  $616,513 
Fair Value of Plan Assets $664,520  $616,462  $573,366 
The effect of the discount rate change for the Retirement Plan in 2004,2006 was to decrease the projected benefit obligation by $20.2 million. The effects of the discount rate changes in 2003 and 2002 were to increase the Benefit Obligation of the Retirement Plan by $57.4 million and $34.0 million as$113.1 million. The effect of the end of each period, respectively.

discount rate change for the Retirement Plan in 2005 was to increase the projected benefit obligation by $113.0 million. The discount rate change for the Retirement Plan in 2004 caused the projected benefit obligation to decrease by $20.2 million.

The Company made cash contributions totaling $37.1$20.9 million to the Retirement Plan during the year ended September 30, 2004.2006. The Company expects that the annual contribution to the Retirement Plan in 20052007 will be in the range of $25.0$15.0 million to $35.0$20.0 million. The following benefit payments, which reflect expected future service, are expected to be paid during the next five years and the five years thereafter: $45.2 million in 2007; $46.1 million in 2008; $47.3 million in 2009; $48.7 million in 2010; $50.0 million in 2011; and $275.6 million in the five years thereafter.

7892


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$40.5

The Retirement Plan covers certain domestic employees hired before July 1, 2003. Employees hired after June 30, 2003 are eligible for a Retirement Savings Account benefit provided under the Company’s defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account benefit have been $0.2 million through September 30, 2006 (with $0.1 million of costs occurring in 2005; $42.3fiscal 2006). Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans were $4.1 million, in 2006; $44.3$4.2 million, in 2007; $46.2and $4.2 million in 2008; $48.6 million in 2009;for the years ended September 30, 2006, 2005 and $279.3 million in the five years thereafter.

2004, respectively.

In addition to the Retirement Plan discussed above, the Company also has a nonqualifiedNon Qualified benefit plan that covers a group of management employees designated by the Chief Executive Officer of the Company. This plan provides for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit cost associated with this plan was $5.4 million, $4.3 million and $13.7 million $5.1 millionin 2006, 2005 and $8.5 million in 2004, 2003 and 2002, respectively. The accumulated benefit obligation for this plan was $18.2$26.5 million and $40.0$25.2 million at September 30, 20042006 and 2003,2005, respectively. The projected benefit obligation for the plan was $35.7$44.5 million and $48.3$47.6 million at September 30, 20042006 and 2003,2005, respectively. The actuarial valuations for this plan were determined based on a discount rate of 6.25%, 6.0%5.0% and 6.75%6.25% as of September 30, 2004, 20032006, 2005 and 20022004, respectively; a weighted rate of compensation increase of 10.0% as of September 30, 2004,2006, 2005 and 8.11% as of September 30, 2003 and 2002;2004; and an expected long-term rate of return on plan assets of 8.25%, at September 30, 20042006, 2005 and 2003, and 8.5% at September 30, 2002. 2004.
In January 2004, a participant of the Non Qualified benefit plan received a $23.0$23 million lump sum payment under a provision of an agreement previously entered into between the Company and the participant. Under GAAP, this payment was considered a partial settlement of the projected benefit obligation of the plan. Accordingly, GAAP required that a pro rata portion of this plan’s unrecognized actuarial lossesloses resulting from experience different from that assumed and from changes in assumptionsassumption be currently recognized. Therefore, $9.9 million before tax ($6.4 million, after tax) was recognized as a settlement expense (included in Operation and Maintenance Expense) on the income statement.

The effect of the discount rate change in 2006 was to decrease the other post-retirement benefit obligation by $77.5 million. Effective July 1, 2006, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to decrease the other post-retirement benefit obligation by $1.7 million. A change in the disability assumption decreased the other post-retirement benefit obligation by $1.4 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2006 by $34.4 million.
The effect of the discount rate change in 2005 was to increase the other post-retirement benefit obligation by $78.2 million. Effective July 1, 2005, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $21.7 million. Also effective July 1, 2005, the percent of active female participants who are assumed to be married at retirement was changed. The effect of this assumption change was to decrease the other post-retirement benefit obligation by $6.9 million. Other actuarial experience increased the other post-retirement benefit obligation in 2005 by $17.9 million.
On December 8, 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. This Act introduces a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In accordance with FASB Staff PositionFAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, since the Company is assumed to continue to provide a prescription drug benefit to retirees in the point of service and indemnity plans that is at least actuarially equivalent to Medicare Part D, the impact of the Act was reflected as of December 8, 2003. The discount rate was changed from 6.0% to 6.25% per annum as of the remeasurement date, which resulted in a decrease in the benefit obligation of $15.9 million.million in 2004. The accumulatedother post-retirement benefit obligation decreased by $42.9 million and the Net Periodic Post-Retirement Benefit Cost


93


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

decreased by $4.2 million as a result of the Act. The effect of the subsidy by Net Periodic Post-Retirement Benefit Cost component is shown below and is reflected within Components of Net Periodic Benefit Cost shown in the table above.
     
Effect of Subsidy

Service Cost $(286,527)
Interest Cost  (1,500,001)
Net Amortization and Deferral of Actuarial (Gain) Loss  (2,372,270)
   
 
Net Periodic Post-Retirement Benefit Cost $(4,158,798)
   
 

The estimated gross amount of subsidy receipts is as follows:

     
First Year $ 
Second Year $(649,599)
Third Year $(1,475,809)
Fourth Year $(1,672,331)
Fifth Year $(1,861,515)
Next Five Years $(11,935,959)

79


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Act for 2004. Effective July 1, 2004, the Medicare Part B Reimbursement trend assumption was changed. The effect of this change was to decrease the Accumulated Post-Retirement Benefit Obligationother post-retirement benefit obligation by $3.5 million for 2004.

The effectsestimated gross benefit payments and gross amount of the discount rate changes in 2003 and 2002 were to increase the Other Post-Retirement Benefit Obligation by $45.1 million and $21.7 millionsubsidy receipts are as of the end of each period, respectively. The prescription drug aging assumptions and related factors were changed in 2003 to better reflect anticipated future experience. The effect of the changed prescription drug assumptions was to decrease the Accumulated Post-Retirement Benefit Obligation by $22.6 million. Other actuarial experience increased the Accumulated Post-Retirement Benefit Obligation in 2003 by $35.1 million. In 2002, the impact of changes in health care trend assumptions to better reflect anticipated future experiences was an increase in the Accumulated Post-Retirement Benefit Obligation of $57.9 million.

follows:

         
  Benefit Payments  Subsidy Receipts 
 
First Year $22,994,788  $(1,475,584)
Second Year $24,993,192  $(1,712,545)
Third Year $26,857,371  $(1,959,704)
Fourth Year $28,913,929  $(2,191,014)
Fifth Year $30,877,647  $(2,413,305)
Next Five Years $175,465,690  $(15,964,373)
The annual rate of increase in the per capita cost of covered medical care benefits for both Pre and Post age 65 participants was assumed to be 12.0% for 2002, 11.0% for 2003, 10.0% for 2004 and gradually decline to 5.5% by2004. In 2005, the year 2010 and remain level thereafter. TheCompany began making separate estimates of the annual rate of increase forin the per capita cost of covered medical care benefits provided by healthcare maintenance organizationsfor Pre and Post age 65 participants. The rate of increase for Pre age 65 participants was assumed to be 12.0% in 2002, 11.0% in 2003, 10.0% in 200410% while the rate of increase for Post age 65 participants was assumed to be 7.5%. In 2006, the rate of increase for Pre age 65 participants was 9% and was assumed to gradually decline to 5.5%5.0% by the year 20102014. The rate of increase for the Post age 65 participants was 7.0% and remain level thereafter.was assumed to gradually decline to 5.0% by the year 2014. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed to be 15.0% for 2002, 13.5% for 2003 and 12.0% for 2004, 12.5% for 2005, 11.0% for 2006, and gradually decline to 5.5%5.0% by the year 20102014 and remain level thereafter. The annual rate of increase in the per capita Medicare Part B Reimbursement was assumed to be 8.0% for 2002, 7.0% for 2003, 9.25% for 2004, 6.0% for 2005, and gradually decline5.25% for 2006. The annual rate of increase for the Medicare Part B Reimbursement is expected to fluctuate between 0% and 5.0% over the next 10 years and reach 5.0% by the year 2013 and remain level thereafter.

2016.

The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the Other Post-Retirement Benefit Obligation as of October 1, 20042006 would be increased by $57.4$57.3 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 20042006 by $5.8$6.1 million. If the health care cost trend rates were decreased by 1% in each year, the Other Post-Retirement Benefit Obligation as of October 1, 20042006 would be decreased by $47.4$47.5 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 20042006 by $4.7$4.9 million.

The Company made cash contributions including payments made directly to participants totaling $39.7$39.3 million to the Other Post-Retirement Benefit Plan during the year ended September 30, 2004.2006. The Company expects that the annual contribution to the Other Post-Retirement Benefit Plan in 20052006 will be in the range of $30.0$35.0 million to $40.0$45.0 million.

The Company’s retirement planRetirement Plan weighted average asset allocations at September 30, 2004, 20032006, 2005 and 20022004 by asset category are as follows:
                 
Percentage of Plan
Assets at
September 30
Target Allocation
Asset Category2005200420032002





Equity Securities  60-65%   61%  53%  55%
Fixed Income Securities  25-30%   28%  32%  29%
Other  10-15%   11%  15%  16%
       
   
   
 
Total      100%  100%  100%
       
   
   
 
                 
     Percentage of Plan
 
  Target Allocation
  Assets at September 30 
Asset Category
 2007  2006  2005  2004 
 
Equity Securities  60-75%  67%  63%  61%
Fixed Income Securities  20-35%  26%  28%  28%
Other  0-15%  7%  9%  11%
                 
Total      100%  100%  100%
                 

80
94


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company’s post-retirement planPost-Retirement Plan weighted average asset allocations at September 30, 2004, 20032006, 2005 and 20022004 by asset category are as follows:
                 
Percentage of Plan
Assets at
September 30
Target Allocation
Asset Category2005200420032002





Equity Securities  93%   91%  85%  90%
Fixed Income Securities  3%   1%  1%  0%
Other  4%   8%  14%  10%
       
   
   
 
Total      100%  100%  100%
       
   
   
 

                 
     Percentage of Plan
 
  Target Allocation
  Assets at September 30 
Asset Category
 2007  2006  2005  2004 
 
Equity Securities  85-100%  93%  92%  91%
Fixed Income Securities  0-15%  1%  2%  1%
Other  0-15%  6%  6%  8%
                 
Total      100%  100%  100%
                 
The Company’s assumption regarding the expected long-term rate of return on plan assets is 8.25%. The return assumption reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets.

The long-term investment objective of the pensionRetirement Plan trust and the Post-Retirement Plan VEBA trusts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition.

Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis.

The discount rate which is used to present value the future benefit payment obligations of the Retirement Plan, the Non-Qualified benefit plan, and the Post-Retirement Plan is 6.25% as of September 30, 2006. This rate is equal to the Moody’s Aa Long-Term Corporate Bond index, rounded to the nearest 25 basis points. The duration of the securities underlying that index (approximately 13 years) reasonably matches the expected timing of anticipated future benefit payments (approximately 12 years).
Note GH — Commitments and Contingencies
 
Environmental Matters

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

It is the Company’s policy to accrue estimated environmentalclean-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 remainingclean-up costs related to the sites described below in paragraphs (i) and (ii) will be $14.0$3.8 million. This liability has been recorded on the Consolidated Balance Sheet at September 30, 2004.2006. The Company expects to recover its environmentalclean-up costs from a combination of rate recovery and insurance proceeds (refer to Note C — Regulatory Matters for further discussion of the insurance proceeds). Other than as discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, adverse changes in environmental regulations, new information or other factors could impact the Company.
 
(i) Former Manufactured Gas Plant Sites

(i) Former Manufactured Gas Plant Sites
The Company has incurred or is incurringclean-up costs at five former manufactured gas plant sites in New York and Pennsylvania. Remediation is substantially complete at a site where the Company has been designated by the New York Department of Environmental Conservation (DEC) as a potentially responsible party (PRP). The Company is engaged in litigation regarding that site with the DEC and the party who bought the site from the Company’s predecessor.continues to be responsible for future ongoing maintenance at one


95


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

site. At a second site remediationin New York, the Company settled its environmental obligations related to this site during 2005. No future liability is complete.anticipated at this site. At a third site, the Companyremediation is negotiating with the DEC for clean-up under a voluntary program.complete and long-term maintenance and monitoring activities are ongoing. A fourth site, which allegedly contains, among other things, manufactured gas plant waste, is in the investigation stage. Remediation hasand post-remedial construction care and maintenance have been completed at a fifth site; however, post-remedial construction caresite, and maintenance is ongoing.

81


NATIONAL FUEL GAS COMPANYthe Company has been released from any future liability related to this site by the Pennsylvania Department of Environmental Protection.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
(ii) Third Party Waste Disposal Sites

(ii) Third Party Waste Disposal Sites

The Company has been identified by the DECDepartment of Environmental Conservation (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 costs subject to an ongoing final payments pending.reallocation process among five PRPs. At a second waste disposal site, settlement was reached in the amount of $9.3 million to be allocated among five PRPs. The allocation process is currently being determined. Further negotiations remain in process for additional settlements related to this site.
 
(iii) Other

(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 anyclean-up costs at this site nor has it been able to reasonably estimate the probability or extent of potential liability.
 
Other

Other
The Company, in its Utility segment, Energy Marketing segment, and All Other category, has entered into contractual commitments in the ordinary course of business, including commitments to purchase capacity on nonaffiliated pipelinesgas, transportation, and storage service to meet customer gas supply needs. Substantially all of these contracts (representing 88% of contracted demand capacity) expire within the next five years. Costs incurred underThe future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $793.5 million in 2007, $195.2 million in 2008, $48.9 million in 2009, $17.6 million in 2010, $9.9 million in 2011, and $68.8 million thereafter. In the Utility segment, these contractscosts are purchased gas costs, subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.

The Company has entered into leases for the use of buildings, vehicles, construction tools, meters, computer equipment and other items. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $8.1 million in 2007, $7.2 million in 2008, $6.0 million in 2009, $4.3 million in 2010, $2.7 million in 2011, and $15.7 million thereafter.
The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note BC — 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 regulatorythese normal-course 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,period in which they are currently


96


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

resolved, they are not expected to change materially the Company’s present liquidity position, nor to have a material adverse effect on the financial condition of the Company.

Note HI — Discontinued Operations
On July 18, 2005, the Company completed the sale of its entire 85.16% interest in U.E., a district heating and electric generation business in the Bohemia region of the Czech Republic, to Czech Energy Holdings, a.s. for sales proceeds of approximately $116.3 million. The sale resulted in the recognition of a gain of approximately $25.8 million, net of tax, at September 30, 2005. Market conditions during 2005, including the increasing value of the Czech currency as compared to the U.S. dollar, caused the value of the assets of U.E. to increase, providing an opportunity to sell the U.E. operations at a profit for the Company. As a result of the decision to sell its majority interest in U.E., the Company began presenting the Czech Republic operations, which are primarily comprised of U.E., as discontinued operations in June 2005. U.E. was the major component of the Company’s International segment. With this change in presentation, the Company discontinued all reporting for an International segment.
The following is selected financial information of the discontinued operations for U.E.:
         
  Year Ended September 30 
  2005  2004 
  (Thousands) 
 
Operating Revenues $124,840  $123,425 
Operating Expenses  103,155   112,178 
         
Operating Income  21,685   11,247 
         
Other Income  2,048   1,992 
Interest Expense  (558)  (838)
         
Income before Income Taxes and Minority Interest  23,175   12,401 
         
Income Tax Expense  10,331   (1,853)
Minority Interest, Net of Taxes  2,645   1,933 
         
Income from Discontinued Operations  10,199   12,321 
         
Gain on Disposal, Net of Taxes of $1,612  25,774    
         
Income from Discontinued Operations $35,973  $12,321 
Note J — Business Segment Information

The Company has sixfive reportable segments: Utility, Pipeline and Storage, Exploration and Production, International, Energy Marketing, and Timber. The breakdown of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.

The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.

The Pipeline and Storage segment operations are regulated. The FERC regulates the operations of Supply Corporation and the NYPSC regulates the operations of Empire, an intrastate pipeline which was acquired on

82


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

February 6, 2003 (see Note J — Acquisitions).Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR) and pipeline companies in the northeastern United States markets. Empire transports natural gas from the United States/Canadian border near Buffalo, New York into Central New York just north of Syracuse, New York. Empire


97


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

transports gas to major industrial companies, utilities (including Distribution Corporation) and power producers. In June 2002, the Company wrote off its 33 1/3% equity method investment in Independence Pipeline Company, a partnership that had proposed to construct and operate a 400-mile pipeline to transport natural gas from Defiance, Ohio to Leidy, Pennsylvania. As shown in the table below, this impairment amounted to $15.2 million.

The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, in the Gulf Coast region of Texas, Louisiana and Alabama and in the provinces of Alberta, Saskatchewan and British Columbia in Canada. Seneca’s production is, for the most part, sold to purchasers located in the vicinity of its wells. On September 30, 2003, Seneca sold its southeast Saskatchewan oil and gas properties for a loss of $58.5 million, as shown in the table below for the year ended September 30, 2003.million. Proved reserves associated with the properties sold were 19.4 million barrels of oil and 0.3 Bcf of natural gas. When the transaction closed, the initial proceeds received were subject to an adjustment based on working capital and the resolution of certain income tax matters. In 2004, those items were resolved with the buyer and, as a result, the Company received an additional $4.6 million of sales proceeds.

     The International segment’s operations are carried out by Horizon. Horizon engages in foreign energy projects through the investment of its indirect subsidiariesproceeds, 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 plantsshown in the northern Bohemia region.

table below for the year ended September 30, 2004.

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

The Timber segment’s operations are carried out by the Northeast division of Seneca and by Highland. This segment has timber holdings (primarily high quality hardwoods) in the northeastern United States and several sawmills and kilns in Pennsylvania. On August 1, 2003, the Company sold approximately 70,000 acres of timber property in Pennsylvania and New York. A gain of $168.8 million was recognized on the sale of this timber property, as shown in the table below for the year ended September 30, 2003.property. During 2004, the Company received final timber cruise information of the properties it sold and, based on that information, determined that property records pertaining to $1.3 million of timber property were not properly shown as having been transferred to the purchaser. As a result, the Company removed those assets from its property records and adjusted the previously recognized gain downward by recognizing a pretax loss of $1.3 million.

million, as shown in the table for the year ended September 30, 2004.

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.
As disclosed in Note I — Discontinued Operations, the Company completed the sale of its majority interest in U.E., a district heating and electric generation business in the Czech Republic, on July 18, 2005. As a result of the sale of its majority interest in U.E., the Company discontinued all reporting for an International segment and previous period segment information has been restated to reflect this change. All Czech Republic operations have been reported as discontinued operations. Any remaining international activity has been included in corporate operations.

83
98


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                                         
Year Ended September 30, 2004

PipelineExplorationTotalCorporate and
andandEnergyReportableIntersegmentTotal
UtilityStorageProductionInternationalMarketingTimberSegmentsAll OtherEliminationsConsolidated










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

                                     
  Year Ended September 30, 2006 
                       Corporate
    
     Pipeline
  Exploration
        Total
     and
    
     and
  and
  Energy
     Reportable
  All
  Intersegment
  Total
 
  Utility  Storage  Production  Marketing  Timber  Segments  Other  Eliminations  Consolidated 
  (Thousands) 
 
Revenue from External Customers $1,265,695  $132,921  $346,880  $497,069  $65,024  $2,307,589  $3,304  $766  $2,311,659 
Intersegment Revenues��$15,068  $81,431  $  $  $5  $96,504  $9,444  $(105,948) $ 
Interest Income $4,889  $454  $8,682  $445  $747  $15,217  $22  $(4,964) $10,275 
Interest Expense $26,174  $6,620  $50,457  $227  $3,095  $86,573  $2,555  $(10,547) $78,581 
Depreciation, Depletion and Amortization $40,172  $36,876  $94,738  $53  $6,495  $178,334  $789  $492  $179,615 
Income Tax Expense (Benefit) $35,699  $33,896  $(2,808) $3,748  $3,277  $73,812  $969  $1,305  $76,086 
Income from Unconsolidated Subsidiaries $  $  $  $  $  $  $3,583  $  $3,583 
Significant Non-Cash Item:                                    
Impairment of Oil and Gas Producing Properties $  $  $104,739  $  $  $104,739  $  $  $104,739 
Segment Profit (Loss): Net Income (Loss) $49,815  $55,633  $20,971  $5,798  $5,704  $137,921  $359  $(189) $138,091 
Expenditures for Additions to Long-Lived Assets $54,414  $26,023  $208,303  $16  $2,323  $291,079  $85  $2,995  $294,159 
                   
                                     
                                     
  At September 30, 2006 
  (Thousands)
 
 
Segment Assets $1,471,422  $767,889  $1,209,969  $78,977  $159,421  $3,687,678  $64,287  $(17,634) $3,734,331 

                                     
  Year Ended September 30, 2005 
                       Corporate
    
     Pipeline
  Exploration
        Total
     and
    
     and
  and
  Energy
     Reportable
  All
  Intersegment
  Total
 
  Utility  Storage  Production  Marketing  Timber  Segments  Other  Eliminations  Consolidated 
  (Thousands) 
 
Revenue from External Customers $1,101,572  $132,805  $293,425  $329,714  $61,285  $1,918,801  $4,748  $  $1,923,549 
Intersegment Revenues $15,495  $83,054  $  $  $1  $98,550  $8,606  $(107,156) $ 
Interest Income $4,111  $76  $4,661  $783  $438  $10,069  $19  $(3,592) $6,496 
Interest Expense $22,900  $7,128  $48,856  $11  $2,764  $81,659  $1,726  $(1,072) $82,313 
Depreciation, Depletion and Amortization $40,159  $38,050  $90,912  $41  $6,601  $175,763  $3,537  $467  $179,767 
Income Tax Expense (Benefit) $23,102  $39,068  $28,353  $3,210  $2,271  $96,004  $(1,425) $(1,601) $92,978 
Income from Unconsolidated Subsidiaries $  $  $  $  $  $  $3,362  $  $3,362 
Significant Non-Cash Item:                                    
Impairment of Investment in Partnership $  $  $  $  $  $  $(4,158)(1) $  $(4,158)
Segment Profit (Loss): Income (Loss) from Continuing Operations $39,197  $60,454  $50,659  $5,077  $5,032  $160,419  $(2,616) $(4,288) $153,515 
Expenditures for Additions to Long-Lived Assets from Continuing Operations $50,071  $21,099  $122,450  $58  $18,894  $212,572  $463  $618  $213,653 
                                     
  At September 30, 2005 
  (Thousands)
 
 
Segment Assets $1,401,128  $782,546  $1,213,525  $90,468  $162,052  $3,649,719  $73,354  $2,209  $3,725,282 

8499


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                                         
Year Ended September 30, 2003

PipelineExplorationTotalCorporate and
andandEnergyReportableIntersegmentTotal
UtilityStorageProductionInternationalMarketingTimberSegmentsAll OtherEliminationsConsolidated










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

(Thousands)
Segment Assets $1,411,808  $812,846  $969,512  $247,721  $54,134  $125,915  $3,621,936  $77,195  $19,929  $3,719,060 


(1)Amount represents the impairment in the value of the Company’s 50% investment in ESNE, a partnership that owns an 80-megawatt, combined cycle, natural gas-fired power plant in the town of North East, Pennsylvania.
                                     
  Year Ended September 30, 2004 
     Pipeline
  Exploration
        Total
     Corporate and
    
     and
  and
  Energy
     Reportable
  All
  Intersegment
  Total
 
  Utility  Storage  Production  Marketing  Timber  Segments  Other  Eliminations  Consolidated 
  (Thousands) 
 
Revenue from External Customers $1,137,288  $122,970  $293,698  $284,349  $55,968  $1,894,273  $13,695  $  $1,907,968 
Intersegment Revenues $15,353  $86,737  $  $  $2  $102,092  $  $(102,092) $ 
Interest Income $552  $217  $1,831  $521  $312  $3,433  $15  $(1,677) $1,771 
Interest Expense $21,945  $10,933  $50,642  $33  $2,218  $85,771  $919  $3,062  $89,752 
Depreciation, Depletion and Amortization $39,101  $37,345  $89,943  $102  $6,277  $172,768  $1,071  $450  $174,289 
Income Tax Expense (Benefit) $31,393  $30,968  $28,899  $3,964  $3,320  $98,544  $829  $(4,783) $94,590 
Income from Unconsolidated Subsidiaries $  $  $  $  $  $  $805  $  $805 
Significant Item:                                    
Loss on Sale of Timber Properties $  $  $  $  $1,252  $1,252  $  $  $1,252 
Significant Item:                                    
Gain on Sale of Oil and Gas Producing Properties $  $  $4,645  $  $  $4,645  $  $  $4,645 
Segment Profit (Loss): Income (Loss) from Continuing Operations $46,718  $47,726  $54,344  $5,535  $5,637  $159,960  $1,530  $(7,225) $154,265 
Expenditures for Additions to Long-Lived Assets from Continuing Operations $55,449  $23,196  $77,654  $10  $2,823  $159,132  $200  $5,511  $164,843 
                                     
  At September 30, 2004 
  (Thousands)
 
 
Segment Assets $1,355,964  $783,145  $1,078,217  $68,599  $140,992  $3,426,917  $77,013  $213,673(1) $3,717,603 
(1)Amount includes the acquisition$268,119 of allassets of the partnership interests in Toro Partners, L.P. and is disclosed informer International segment, the majority of which has been discontinued with the sale of U.E. (See Note JI — Acquisitions.Discontinued Operations).
             
  For the Year Ended September 30 
Geographic Information
 2006  2005  2004 
  (Thousands) 
 
Revenues from External Customers (1):
            
United States $2,242,155  $1,860,684  $1,867,335 
Canada  69,504   62,865   40,633 
             
  $2,311,659  $1,923,549  $1,907,968 
             

85
100


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                                          
Year Ended September 30, 2002

PipelineExplorationTotalCorporate and
andandEnergyReportableIntersegmentTotal
UtilityStorageProductionInternationalMarketingTimberSegmentsAll OtherEliminationsConsolidated










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

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

86


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

             
For the Year Ended September 30

Geographic Information200420032002




(Thousands)
Revenues from External Customers(1):
            
United States $1,867,335  $1,818,980  $1,293,239 
Czech Republic  123,425   114,070   95,315 
Canada  40,633   102,421   75,942 
   
   
   
 
  $2,031,393  $2,035,471  $1,464,496 
   
   
   
 
             
At September 30

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


             
  At September 30 
  2006  2005  2004 
  (Thousands) 
 
Long-Lived Assets:
            
United States $3,117,644  $2,978,680  $2,941,779 
Canada  97,234   171,196   143,042 
Assets of Discontinued Operations        228,179 
             
  $3,214,878  $3,149,876  $3,313,000 
             

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

Note IK — 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).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 September 2005, the Company recorded an impairment of $4.2 million of its equity investment in ESNE due to a decline in the fair market value of ESNE. This impairment was recorded in accordance with APB 18.
A summary of the Company’s investments in unconsolidated subsidiaries at September 30, 20042006 and 20032005 is as follows:
         
At September 30

20042003


(Thousands)
ESNE $10,045  $11,113 
Seneca Energy  5,169   4,445 
Model City  1,230   867 
   
   
 
  $16,444  $16,425 
   
   
 
         
  At September 30 
  2006  2005 
  (Thousands) 
 
ESNE $4,486  $5,298 
Seneca Energy  5,366   5,839 
Model City  1,738   1,521 
         
  $11,590  $12,658 
         

Note J — Acquisitions101

     On February 6, 2003, the Company acquired Empire from a subsidiary of Duke Energy Corporation for $189.2 million in cash (including cash acquired) plus $57.8 million of project debt. Empire’s results of operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on February 6, 2003. Empire is a 157-mile, 24-inch pipeline that begins at the United States/ Canadian border at the Niagara River near Buffalo, New York, which is within the Company’s service territory, and terminates in Central New York just north of Syracuse, New York. Empire has almost all of its capacity under contract, with a substantial portion being long-term contracts. Empire

87


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

delivers natural gas supplies to major industrial companies, utilities (including the Company’s Utility segment), and power producers. The Company believes that the acquisition of Empire better positions the Company to bring Canadian gas supplies into the East Coast markets of the United States as demand for natural gas along the East Coast increases. Details of the acquisition are as follows (all figures in thousands):

     
Assets Acquired (see Condensed Balance Sheet below) $257,397 
Liabilities Assumed (see Condensed Balance Sheet below)  (68,192)
Cash Acquired at Acquisition  (8,053)
   
 
Cash Paid, Net of Cash Acquired $181,152 
   
 
Condensed Balance Sheet:
      
Property, Plant and Equipment $220,792 
Current Assets  14,984 
Goodwill  5,476 
Intangible Assets (see Note K)  8,580 
Other Assets  7,565 
   
 
 Total Assets $257,397 
   
 
Equity $189,205 
Long-Term Debt, Net of Current Portion  48,433 
   
 
 Total Capitalization  237,638 
Current Liabilities  15,265 
Other Liabilities  4,494 
   
 
 Total Capitalization and Liabilities $257,397 
   
 

On June 3, 2003, the Company acquired for approximately $47.8 million in cash (including cash acquired) all of the partnership interests in Toro, which owns and operates short-distance landfill gas pipeline companies that purchase, transport and resell landfill gas to customers in six states located primarily in the Midwestern United States. Toro’s results of operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on June 3, 2003. The existing landfill gas purchase and sale agreements at these facilities remained in place. The Company believes there are opportunities for expansion at many of these locations. The acquisition consisted of approximately $15.3 million in property, plant and equipment, $31.9 million in intangible assets (as discussed in Note K), $1.1 million of current assets and $0.5 million of current liabilities. Details of the acquisition are as follows (all figures in thousands):

     
Assets Acquired $48,319 
Liabilities Assumed  (497)
Cash Acquired at Acquisition  (160)
   
 
Cash Paid, Net of Cash Acquired $47,662 
   
 

Note KL — Intangible Assets

As a result of the Empire and Toro acquisitions, discussed in Note J — Acquisitions, the Company acquired certain intangible assets during 2003. In the case of the Empire acquisition, the intangible assets represent the fair value of various long-term transportation contracts with Empire’s customers. In the case of

88


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the Toro acquisition, the intangible assets represent the fair value of various long-term gas purchase contracts with the various landfills. These intangible assets are being amortized over the lives of the transportation and gas purchase contracts with no residual value at the end of the amortization period. The weighted-average amortization period for the gross carrying amount of the transportation contracts is 8 years. The weighted-average amortization period for the gross carrying amount of the gas purchase contracts is 20 years. Details of these intangible assets are as follows:

                  
At September 30, 2004At September 30, 2003


Gross CarryingAccumulatedNet Carrying
AmountAmortizationAmountNet Carrying Amount




Intangible Assets Subject to Amortization                
 Long-Term Transportation Contracts $8,580  $(1,782) $6,798  $7,867 
 Long-Term Gas Purchase Contracts  31,864   (1,839)  30,025   31,522 
Intangible Assets Not Subject to Amortization                
 Retirement Plan Intangible Asset (see Note F)  9,171      9,171   10,275 
   
   
   
   
 
  $49,615  $(3,621) $45,994  $49,664 
   
   
   
   
 
Aggregate Amortization Expense                
 For the Year Ended September 30, 2004 $2,567             
 For the Year Ended September 30, 2003 $1,054             

follows (in thousands):

                 
     At September
 
  At September 30, 2006  30, 2005 
  Gross Carrying
     Net Carrying
  Net Carrying
 
  Amount  Accumulated Amortization  Amount  Amount 
 
Intangible Assets Subject to Amortization:                
Long-Term Transportation Contracts $8,580  $(3,920) $4,660  $5,729 
Long-Term Gas Purchase Contracts  31,864   (5,026)  26,838   28,431 
Intangible Assets Not Subject to Amortization:                
Retirement Plan Intangible Asset (see Note G)           8,142 
                 
  $40,444  $(8,946) $31,498  $42,302 
                 
Aggregate Amortization Expense                
For the Year Ended
September 30, 2006
 $2,663             
For the Year Ended
September 30, 2005
 $2,663             
For the Year Ended
September 30, 2004
 $2,567             
The gross carrying amount of intangible assets subject to amortization at September 30, 2006 remained unchanged from September 30, 2005. The only activity with regard to intangible assets subject to amortization was amortization expense as shown on the table above. Amortization expense for the long-term transportation contracts is estimated to be $1.1 million annually for 2005, 2006, 2007 and 2008. Amortization expense is estimated to be $0.5 million for 2009.in 2009 and $0.4 million in 2010 and 2011. Amortization expense for the long-term gas purchase contracts is estimated to be $1.6 million annually for 2005, 2006, 2007, 2008, 2009, 2010 and 2009.

2011.

Note LM — 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 StatementStatements of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal

89


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis.

                     
Net
Income
AvailableEarnings Per
forCommon Share
OperatingOperatingCommon
Quarter EndedRevenuesIncomeStockBasicDiluted






2004

(Thousands, except per common share amounts)
9/30/2004 $278,197  $27,675  $7,754  $0.09  $0.09 
6/30/2004 $419,006  $72,324  $32,563(1) $0.40  $0.39 
3/31/2004 $801,677  $148,554  $77,055(2) $0.94  $0.93 
12/31/2003 $532,513  $95,817  $49,214(3) $0.60  $0.60 
                     
2003

9/30/2003 $297,170  $122,674  $58,146(4) $0.71  $0.71 
6/30/2003 $449,530  $35,411  $2,219(5) $0.03  $0.03 
3/31/2003 $809,065  $156,703  $80,538  $1.00  $0.99 
12/31/2002 $479,706  $99,628  $38,041(6) $0.47  $0.47 


102


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                                     
              Net
             
           Income
  Income
             
        Income
  (Loss)
  Available
  Earnings from
       
        from
  from
  for
  Continuing Operations per
       
Quarter
 Operating
  Operating
  Continuing
  Discontinued
  Common
  Common Share  Earnings per Common Share 
Ended
 Revenues  Income  Operations  Operations  Stock  Basic  Diluted  Basic  Diluted 
  (Thousands, except per common share amounts) 
 
2006
                                    
9/30/2006 $294,469  $18,444  $1,968  $  $1,968(1) $0.02  $0.02  $0.02  $0.02 
6/30/2006 $415,452  $8,541  $111  $  $111(2) $  $  $  $ 
3/31/2006 $890,981  $138,967  $78,594  $  $78,594(3) $0.93  $0.91  $0.93  $0.91 
12/31/2005 $710,757  $110,123  $57,418  $  $57,418(4) $0.68  $0.67  $0.68  $0.67 
2005
                                    
9/30/2005 $287,064  $34,926  $18,311(5) $30,900(6) $49,211(5)(6) $0.22  $0.21  $0.58  $0.57 
6/30/2005 $400,359  $63,028  $26,393  $(7,237)(7) $19,156(7) $0.32  $0.31  $0.23  $0.23 
3/31/2005 $735,842  $120,667  $63,981(8) $6,702  $70,683(8) $0.77  $0.75  $0.85  $0.83 
12/31/2004 $500,284  $91,741  $44,830  $5,608  $50,438  $0.54  $0.53  $0.61  $0.60 

(1)Includes expense of $0.8 million related to an adjustment to the gain on sale of timber properties recognized in 2003.
(2) Includes expense of $6.4 million due to the recognition of a pension settlement loss and income of $4.6 million due to an adjustment to the loss on sale of oil and gas properties recognized in 2003.
(3) Includes income of $5.2 million related to tax rate changes in the Czech Republic.
(4) Includes expense of $6.3 million related to the impairment of oil and gas producing properties, loss of $39.6 million related to the sale of oil and gas producing properties, and a gain of $102.2 million from the sale of timber properties.
(5) Includes expense of $22.6$29.1 million related to the impairment of oil and gas producing properties.
 
(6) (2)Includes expense of $8.3$39.5 million related to the cumulative effectimpairment of changeoil and gas producing properties and income of $6.1 million related to income tax adjustments.
(3)Includes income of $5.1 million related to income tax adjustments.
(4)Includes income of $2.6 million related to a regulatory adjustment.
(5)Includes a $3.9 million gain associated with insurance proceeds received in accounting (SFAS 142)prior years for which a contingency was resolved during the quarter, $3.3 million of expense related to certain derivative financial instruments that no longer qualified as effective hedges, $2.7 million of expense related to the impairment of an investment in a partnership, and an$1.8 million of expense related to the impairment of $0.6a gas-powered turbine.
(6)Includes a $25.8 million gain related to the sale of U.E. and income of $6.0 million due to the cumulative effectreversal of change in accounting (SFAS 143).deferred income taxes related to U.E.
(7)Includes $6.0 million of previously unrecorded deferred income tax expense related to U.E.
(8)Includes a $2.6 million gain on a FERC approved sale of base gas.

103


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note MN — Market for Common Stock and Related Shareholder Matters (unaudited)

At September 30, 2004,2006, there were 19,063 holders17,767 registered shareholders of Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note DE — Capitalization and Short-Term Borrowings. The quarterly price ranges

90


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(based (based on intra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 20042006 and 2003,2005, are shown below:

             
Price Range

Dividends
Quarter EndedHighLowDeclared




2004
            

            
9/30/2004 $28.43  $24.84  $.280 
6/30/2004 $25.57  $23.75  $.280 
3/31/2004 $26.48  $24.26  $.270 
12/31/2003 $25.01  $21.71  $.270 
2003
            

            
9/30/2003 $27.51  $22.51  $.270 
6/30/2003 $26.90  $21.60  $.270 
3/31/2003 $22.25  $18.97  $.260 
12/31/2002 $21.86  $17.95  $.260 

             
  Price Range    
Quarter Ended
 High  Low  Dividends Declared 
 
2006
            
9/30/2006 $39.16  $34.95  $.30 
6/30/2006 $36.75  $31.33  $.30 
3/31/2006 $35.43  $30.60  $.29 
12/31/2005 $35.27  $29.25  $.29 
2005
            
9/30/2005 $36.00  $27.74  $.29 
6/30/2005 $29.49  $26.20  $.29 
3/31/2005 $29.75  $26.66  $.28 
12/31/2004 $29.18  $27.01  $.28 
Note NO — 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 
  2006  2005 
  (Thousands) 
 
Proved Properties(1) $1,884,049  $1,650,788 
Unproved Properties  41,930   39,084 
         
   1,925,979   1,689,872 
Less — Accumulated Depreciation, Depletion and Amortization  929,921   721,397 
         
  $996,058  $968,475 
         
 
Capitalized Costs Relating to Oil and Gas Producing Activities
         
At September 30

20042003


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


(1)Includes asset retirement costs of $22.2$42.2 million and $18.1$30.8 million at September 30, 20042006 and 2003,2005, respectively.


104


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Costs related to unproved properties are excluded from amortization as they represent unevaluated properties that require additional drilling to determine the existence of oil and gas reserves. Following is a summary of such costs excluded from amortization at September 30, 2004:2006:
                     
  Total
             
  as
             
  of
             
  September
             
  30,
  Year Costs Incurred 
  2006  2006  2005  2004  Prior 
  (Thousands) 
 
Acquisition Costs $41,930  $27,497  $6,078  $981  $7,374 
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
                     
Year Costs Incurred
Total as of
September 30, 2004200420032002Prior





(Thousands)
Acquisition Costs $27,277  $7,650  $6,748  $2,884  $9,995 
             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
United States
            
Property Acquisition Costs:            
Proved $5,339  $287  $(8)
Unproved  8,844   1,215   3,529 
Exploration Costs  64,087   32,456   10,503 
Development Costs  87,738   49,016   31,881 
Asset Retirement Costs  10,965   8,051   2,292 
             
   176,973   91,025   48,197 
             
Canada
            
Property Acquisition Costs:            
Proved  (427)  (1,551)  29 
Unproved  6,492   4,668   3,167 
Exploration Costs  20,778   22,943   22,624 
Development Costs  14,385   12,198   5,500 
Asset Retirement Costs  279   292   1,218 
             
   41,507   38,550   32,538 
             
Total
            
Property Acquisition Costs:            
Proved  4,912   (1,264)  21 
Unproved  15,336   5,883   6,696 
Exploration Costs  84,865   55,399   33,127 
Development Costs  102,123   61,214   37,381 
Asset Retirement Costs  11,244   8,343   3,510 
             
  $218,480  $129,575  $80,735 
             
For the years ended September 30, 2006, 2005 and 2004, the Company spent $55.6 million, $19.2 million and $12.1 million, respectively, developing proved undeveloped reserves.

91
105


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Results of Operations for Producing Activities
 
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
              
Year Ended September 30

200420032002



(Thousands)
United States
            
Property Acquisition Costs:            
 Proved $(8) $(13) $9,316 
 Unproved  3,529   1,920   698 
Exploration Costs  10,503   17,947   25,583 
Development Costs  31,881   23,649   51,792 
Asset Retirement Costs  2,292   242    
   
   
   
 
   48,197   43,745   87,389 
Canada
            
Property Acquisition Costs:            
 Proved  29   181   (536)
 Unproved  3,167   6,217   2,804 
Exploration Costs  22,624   6,641   8,779 
Development Costs  5,500   17,745   15,332 
Asset Retirement Costs  1,218       
   
   
   
 
   32,538   30,784   26,379 
Total
            
Property Acquisition Costs:(1)            
 Proved  21   168   8,780 
 Unproved  6,696   8,137   3,502 
Exploration Costs  33,127   24,588   34,362 
Development Costs  37,381   41,394   67,124 
Asset Retirement Costs  3,510   242    
   
   
   
 
  $80,735  $74,529  $113,768 
   
   
   
 
             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands, except per Mcfe amounts) 
 
United States
            
Operating Revenues:            
Natural Gas (includes revenues from sales to affiliates of $106, $77 and $72, respectively) $152,451  $151,004  $151,570 
Oil, Condensate and Other Liquids  195,050   160,145   139,301 
             
Total Operating Revenues(1)  347,501   311,149   290,871 
Production/Lifting Costs  41,354   38,442   39,677 
Accretion Expense  2,412   2,220   1,756 
Depreciation, Depletion and Amortization ($1.74, $1.58 and $1.41 per Mcfe of production)  66,488   67,097   73,396 
Income Tax Expense  88,104   74,110   65,337 
             
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)  149,143   129,280   110,705 
             
Canada
            
Operating Revenues:            
Natural Gas  54,819   49,275   30,359 
Oil, Condensate and Other Liquids  13,985   12,875   10,018 
             
Total Operating Revenues(1)  68,804   62,150   40,377 
Production/Lifting Costs  14,628   12,683   8,176 
Accretion Expense  258   228   177 
Depreciation, Depletion and Amortization ($2.95, $2.36 and $1.83 per Mcfe of production)  27,439   23,108   14,922 
Impairment of Oil and Gas Producing Properties(2)  104,739       
Income Tax Expense (Benefit)  (31,987)  8,577   5,235 
             
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)  (46,273)  17,554   11,867 
             

92
106


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended September 30, 2004, 2003 and 2002, the Company spent $12.1 million, $1.7 million and $18.2 million, respectively, developing proved undeveloped reserves.
             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands, except per Mcfe amounts) 
 
Total
            
Operating Revenues:            
Natural Gas (includes revenues from sales to affiliates of $106, $77 and $72, respectively)  207,270   200,279   181,929 
Oil, Condensate and Other Liquids  209,035   173,020   149,319 
             
Total Operating Revenues(1)  416,305   373,299   331,248 
Production/Lifting Costs  55,982   51,125   47,853 
Accretion Expense  2,670   2,448   1,933 
Depreciation, Depletion and Amortization ($1.98, $1.72 and $1.47 per Mcfe of production)  93,927   90,205   88,318 
Impairment of Oil and Gas Producing Properties(2)  104,739       
Income Tax Expense  56,117   82,687   70,572 
             
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $102,870  $146,834  $122,572 
             

 
Results of Operations for Producing Activities
              
Year Ended September 30,

200420032002



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

93


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              
Year Ended September 30,

200420032002



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


(1)Exclusive of hedging gains and losses. See further discussion in Note EF — Financial InstrumentsInstruments.
 
(2)See discussion of impairment in Note A — Summary of Significant Accounting PoliciesPolicies.

 
Reserve Quantity Information (unaudited)

Reserve Quantity Information (unaudited)

The Company’s proved oil and gas reserves are located in the United States and Canada. The estimated quantities of proved reserves disclosed in the table below are based upon estimates by qualified Company geologists and engineers and are audited by independent petroleum engineers. Such estimates are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
                         
Gas MMcf

U.S.

Gulf CoastWest CoastAppalachianTotalTotal
RegionRegionRegionU.S.CanadaCompany






Proved Developed and Undeveloped Reserves:                        
September 30, 2001  89,858   98,498   78,457   266,813   55,567   322,380 
Extensions and Discoveries  6,530   5,770   4,242   16,542   20,263   36,805 
Revisions of Previous Estimates  1,613   (26,063)  342   (24,108)  (20,676)  (44,784)
Production  (25,776)  (4,889)  (4,402)  (35,067)  (6,387)  (41,454)
Sales of Minerals in Place  (14,361)     (365)  (14,726)     (14,726)
   
   
   
   
   
   
 
September 30, 2002  57,864   73,316   78,274   209,454   48,767   258,221 
Extensions and Discoveries  10,538      5,844   16,382   11,641   28,023 
Revisions of Previous Estimates  (2,278)  1,213   2,224   1,159   (2,211)  (1,052)
Production  (18,441)  (4,467)  (5,123)  (28,031)  (5,774)  (33,805)
Sales of Minerals in Place              (270)  (270)
   
   
   
   
   
   
 
                         
  Gas MMcf 
  U. S.       
  Gulf
  West
             
  Coast
  Coast
  Appalachian
  Total
     Total
 
  Region  Region  Region  U.S.  Canada  Company 
 
Proved Developed and Undeveloped Reserves:                        
September 30, 2003  47,683   70,062   81,219   198,964   52,153   251,117 
Extensions and Discoveries  2,632      3,784   6,416   15,925   22,341 
Revisions of Previous Estimates  (4,984)  1,831   (1,111)  (4,264)  (11,004)  (15,268)
Production  (17,596)  (4,057)  (5,132)  (26,785)  (6,228)  (33,013)
Sales of Minerals in Place  (1)  (392)     (393)     (393)
                         

94107


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                         
Gas MMcf

U.S.

Gulf CoastWest CoastAppalachianTotalTotal
RegionRegionRegionU.S.CanadaCompany






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

U.S.

Gulf CoastWest CoastAppalachianTotalTotal
RegionRegionRegionU.S.CanadaCompany






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

                         
  Gas MMcf 
  U. S.       
  Gulf
  West
             
  Coast
  Coast
  Appalachian
  Total
     Total
 
  Region  Region  Region  U.S.  Canada  Company 
 
September 30, 2004  27,734   67,444   78,760   173,938   50,846   224,784 
Extensions and Discoveries  17,165      5,461   22,626   4,849   27,475 
Revisions of Previous Estimates  6,039   7,067   3,733   16,839   (1,600)  15,239 
Production  (12,468)  (4,052)  (4,650)  (21,170)  (8,009)  (29,179)
Sales of Minerals in Place        (179)  (179)     (179)
                         
September 30, 2005  38,470   70,459   83,125   192,054   46,086   238,140 
Extensions and Discoveries  11,763   1,815   11,132   24,710   6,229   30,939 
Revisions of Previous Estimates  679   5,757   (7,776)  (1,340)  (11,096)  (12,436)
Production  (9,110)  (3,880)  (5,108)  (18,098)  (7,673)  (25,771)
Purchases of Minerals in Place     1,715      1,715      1,715 
Sales of Minerals in Place              (12)  (12)
                         
September 30, 2006  41,802   75,866   81,373   199,041   33,534   232,575 
                         
Proved Developed Reserves:                        
September 30, 2003  45,402   54,180   81,218   180,800   42,745   223,545 
September 30, 2004  25,827   53,035   78,760   157,622   46,223   203,845 
September 30, 2005  23,108   58,692   83,125   164,925   43,980   208,905 
September 30, 2006  32,345   64,196   81,373   177,914   33,534   211,448 

                         
  Oil Mbbl 
  U.S.       
     West
             
  Gulf Coast
  Coast
  Appalachian
  Total
     Total
 
  Region  Region  Region  U.S.  Canada  Company 
 
Proved Developed and Undeveloped Reserves:                        
September 30, 2003  3,383   63,852   138   67,373   2,391   69,764 
Extensions and Discoveries  19      18   37   181   218 
Revisions of Previous Estimates  213   (17)  11   207   (144)  63 
Production  (1,534)  (2,650)  (20)  (4,204)  (324)  (4,528)
Sales of Minerals in Place  (1)  (303)     (304)     (304)
                         
September 30, 2004  2,080   60,882   147   63,109   2,104   65,213 
Extensions and Discoveries  99      63   162   204   366 
Revisions of Previous Estimates  105   (1,253)  3   (1,145)  (186)  (1,331)
Production  (989)  (2,544)  (36)  (3,569)  (300)  (3,869)
Sales of Minerals in Place              (122)  (122)
                         

95108


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                         
  Oil Mbbl 
  U.S.       
     West
             
  Gulf Coast
  Coast
  Appalachian
  Total
     Total
 
  Region  Region  Region  U.S.  Canada  Company 
 
September 30, 2005  1,295   57,085   177   58,557   1,700   60,257 
Extensions and Discoveries  39   172   108   319   128   447 
Revisions of Previous Estimates  595   (80)  57   572   101   673 
Production  (685)  (2,582)  (69)  (3,336)  (272)  (3,608)
Purchases of Minerals in Place     274      274      274 
Sales of Minerals in Place              (25)  (25)
                         
September 30, 2006  1,244   54,869   273   56,386   1,632   58,018 
                         
Proved Developed Reserves:                        
September 30, 2003  2,533   40,079   139   42,751   2,391   45,142 
September 30, 2004  2,061   38,631   148   40,840   2,104   42,944 
September 30, 2005  1,229   41,701   177   43,107   1,700   44,807 
September 30, 2006  1,217   42,522   273   44,012   1,632   45,644 

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

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited)
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, it is based on year-end prices and costs adjusted only for existing contractual changes, and it assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.

109


NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
               
Year Ended September 30,

200420032002



(Thousands)
United States
            
Future Cash Inflows $3,728,168  $2,684,286  $2,764,556 
 Less:            
  Future Production Costs  676,361   579,321   546,182 
  Future Development Costs  124,298   116,639   117,999 
  Future Income Tax Expense at Applicable Statutory Rate  995,327   613,893   653,347 
   
   
   
 
 Future Net Cash Flows  1,932,182   1,374,433   1,447,028 
 Less:            
  10% Annual Discount for Estimated Timing of Cash Flows  996,813   641,185   665,941 
   
   
   
 
 Standardized Measure of Discounted Future Net Cash Flows  935,369   733,248   781,087 
   
   
   
 
             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
United States
            
Future Cash Inflows $3,911,059  $6,138,522  $3,728,168 
Less:            
Future Production Costs  758,258   777,417   676,361 
Future Development Costs  205,497   188,795   124,298 
Future Income Tax Expense at Applicable Statutory Rate  1,019,307   1,868,548   995,327 
             
Future Net Cash Flows  1,927,997   3,303,762   1,932,182 
Less:            
10% Annual Discount for Estimated Timing of Cash Flows  1,066,338   1,812,230   996,813 
             
Standardized Measure of Discounted Future Net Cash Flows  861,659   1,491,532   935,369 
             

96
110


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
               
Year Ended September 30,

200420032002



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

             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Canada
            
Future Cash Inflows  197,227   601,210   343,026 
Less:            
Future Production Costs  92,234   136,338   111,519 
Future Development Costs  11,520   12,197   13,222 
Future Income Tax Expense at Applicable Statutory Rate  (151)  137,524   60,610 
             
Future Net Cash Flows  93,624   315,151   157,675 
Less:            
10% Annual Discount for Estimated Timing of Cash Flows  19,375   108,508   46,945 
             
Standardized Measure of Discounted Future Net Cash Flows  74,249   206,643   110,730 
             
Total
            
Future Cash Inflows  4,108,286   6,739,732   4,071,194 
Less:            
Future Production Costs  850,492   913,755   787,880 
Future Development Costs  217,017   200,992   137,520 
Future Income Tax Expense at Applicable Statutory Rate  1,019,156   2,006,072   1,055,937 
             
Future Net Cash Flows  2,021,621   3,618,913   2,089,857 
Less:            
10% Annual Discount for Estimated Timing of Cash Flows  1,085,713   1,920,738   1,043,758 
             
Standardized Measure of Discounted Future Net Cash Flows $935,908  $1,698,175  $1,046,099 
             

97111


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
              
Year Ended September 30,

200420032002



(Thousands)
United States
            
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $733,248  $781,087  $605,350 
 Sales, Net of Production Costs  (251,194)  (227,219)  (163,548)
 Net Changes in Prices, Net of Production Costs  592,326   11,130   441,085 
 Purchases of Minerals in Place         
 Sales of Minerals in Place  (5,554)     (27,197)
 Extensions and Discoveries  16,638   29,266   42,970 
 Changes in Estimated Future Development Costs  (40,042)  (35,062)  (42,069)
 Previously Estimated Development Costs Incurred  32,653   36,423   45,310 
 Net Change in Income Taxes at Applicable Statutory Rate  (166,055)  24,796   (126,263)
 Revisions of Previous Quantity Estimates  (5,107)  (3,572)  (32,646)
 Accretion of Discount and Other  28,456   116,399   38,095 
   
   
   
 
Standardized Measure of Discounted Future Net Cash Flows at End of Year  935,369   733,248   781,087 
   
   
   
 
Canada
            
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year  85,157   245,095   181,439 
 Sales, Net of Production Costs  (32,201)  (56,862)  (41,023)
 Net Changes in Prices, Net of Production Costs  29,230   8,167   111,148 
 Purchases of Minerals in Place         
 Sales of Minerals in Place     (120,960)  (3,084)
 Extensions and Discoveries  36,986   28,241   29,813 
 Changes in Estimated Future Development Costs  (8,491)  (14,045)  18,151 
 Previously Estimated Development Costs Incurred  5,055   29,657   12,361 
 Net Change in Income Taxes at Applicable Statutory Rate  (2,640)  (6,280)  (6,910)
 Revisions of Previous Quantity Estimates  (19,369)  (41,205)  (88,571)
 Accretion of Discount and Other  17,003   13,349   31,771 
   
   
   
 
Standardized Measure of Discounted Future Net Cash Flows at End of Year  110,730   85,157   245,095 
   
   
   
 
             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
United States
            
Standardized Measure of Discounted Future            
Net Cash Flows at Beginning of Year $1,491,532  $935,369  $733,248 
Sales, Net of Production Costs  (306,147)  (272,707)  (251,194)
Net Changes in Prices, Net of Production Costs  (941,545)  1,093,353   592,326 
Purchases of Minerals in Place  7,607       
Sales of Minerals in Place     (762)  (5,554)
Extensions and Discoveries  66,975   100,102   16,638 
Changes in Estimated Future Development Costs  (83,750)  (89,805)  (40,042)
Previously Estimated Development Costs Incurred  67,048   25,038   32,653 
Net Change in Income Taxes at Applicable Statutory Rate  404,176   (362,956)  (166,055)
Revisions of Previous Quantity Estimates  4,850   25,055   (5,107)
Accretion of Discount and Other  150,913   38,845   28,456 
             
Standardized Measure of Discounted Future Net Cash Flows at End of Year  861,659   1,491,532   935,369 
             
Canada
            
Standardized Measure of Discounted Future            
Net Cash Flows at Beginning of Year  206,643   110,730   85,157 
Sales, Net of Production Costs  (54,176)  (49,467)  (32,201)
Net Changes in Prices, Net of Production Costs  (180,216)  174,985   29,230 
Purchases of Minerals in Place         
Sales of Minerals in Place  (238)  (3,751)   
Extensions and Discoveries  10,369   31,028   36,986 
Changes in Estimated Future Development Costs  (3,282)  (11,007)  (8,491)
Previously Estimated Development Costs Incurred  4,450   12,032   5,055 
Net Change in Income Taxes at Applicable Statutory Rate  82,966   (51,541)  (2,640)
Revisions of Previous Quantity Estimates  (15,478)  (5,990)  (19,369)
Accretion of Discount and Other  23,211   (376)  17,003 
             
Standardized Measure of Discounted Future Net Cash Flows at End of Year  74,249   206,643   110,730 
             

98
112


NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
              
Year Ended September 30,

200420032002



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

99


             
  Year Ended September 30 
  2006  2005  2004 
  (Thousands) 
 
Total
            
Standardized Measure of Discounted Future            
Net Cash Flows at Beginning of Year  1,698,175   1,046,099   818,405 
Sales, Net of Production Costs  (360,323)  (322,174)  (283,395)
Net Changes in Prices, Net of Production Costs  (1,121,761)  1,268,338   621,556 
Purchases of Minerals in Place  7,607       
Sales of Minerals in Place  (238)  (4,513)  (5,554)
Extensions and Discoveries  77,344   131,130   53,624 
Changes in Estimated Future Development Costs  (87,032)  (100,812)  (48,533)
Previously Estimated Development Costs Incurred  71,498   37,070   37,708 
Net Change in Income Taxes at Applicable Statutory Rate  487,142   (414,497)  (168,695)
Revisions of Previous Quantity Estimates  (10,628)  19,065   (24,476)
Accretion of Discount and Other  174,124   38,469   45,459 
             
Standardized Measure of Discounted Future Net Cash Flows at End of Year $935,908  $1,698,175  $1,046,099 
             

Schedule II — Valuation and Qualifying Accounts
                     
AdditionsAdditions
Balance atCharged toCharged toBalance at
BeginningCosts andOtherEnd of
Descriptionof PeriodExpensesAccounts(1)Deductions(2)Period






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


                     
     Additions
          
  Balance
  Charged
  Additions
     Balance
 
  at
  to
  Charged
     at
 
  Beginning
  Costs
  to
     End
 
  of
  and
  Other
     of
 
Description
 Period  Expenses  Accounts  Deductions(3)  Period 
  (Thousands) 
 
Year Ended September 30, 2006
                    
Allowance for Uncollectible Accounts $26,940  $29,088  $907(1) $25,508  $31,427 
Deferred Tax Valuation Allowance $2,877  $(2,877) $  $  $ 
                     
Year Ended September 30, 2005
                    
Allowance for Uncollectible Accounts $17,440  $31,113  $2,480(2) $24,093  $26,940 
Deferred Tax Valuation Allowance $2,877  $  $  $  $2,877 
                     
Year Ended September 30, 2004
                    
Allowance for Uncollectible Accounts $17,943  $20,328  $  $20,831  $17,440 
Deferred Tax Valuation Allowance $6,357  $(3,480) $  $  $2,877 
                     
(1)Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate settlement.
(2)Represents amounts reclassified from regulatory asset and regulatory liability accounts under various rate settlements.settlements ($4.5 million). Also includes amounts removed with the sale of U.E. (-$2.02 million).
 
(2) (3)Amounts represent net accounts receivable written-off.

113


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

None
 
Item 9AControls and Procedures

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

Evaluation of Disclosure Controls and Procedures

The term “disclosure controls and procedures” is defined inRules 13a-15(e) and15d-15(e) of under the Securities Exchange Act of 1934 (Exchange Act).Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within required time periods. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Treasurer,Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and TreasurerPrincipal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the endSeptember 30, 2006.
Management’s Report on Internal Control over Financial Reporting
The management of the period covered by this report.

Changes in Internal Controls Over Financial Reporting

     The Company maintains a system ofis responsible for establishing and maintaining adequate internal control over financial reporting thatas defined inRules 13a-15(f) and15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance thatregarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

The Company’s transactions are properly authorized,management assessed the Company’s assets are safeguarded against unauthorized or improper use, and the Company’s transactions are properly recorded and reported to permit preparationeffectiveness of the Company’s internal control over financial reporting as of September 30, 2006. In making this assessment, management used the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control — Integrated Framework.  Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of September 30, 2006.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in conformity with GAAP. this Annual Report onForm 10-K, has issued a report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2006. The report appears in Part II, Item 8 of this Annual Report onForm 10-K.
Changes in Internal Control over Financial Reporting
There were no changes in the Company’s internal control over financial reporting that occurred during the period covered by this reportquarter ended September 30, 2006 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

100


 
Item 9BOther Information

None

PART III
 
Item 10Directors and Executive Officers of the Registrant

The information required by this item concerning the directors of the Company is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its February 17, 200515, 2007 Annual


114


Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004.2006. The information concerning directors is set forth in the definitive Proxy Statement under the captionsheadings entitled “Nominees for Election as Directors for Three-Year Terms to Expire in 2008,2010,” “Directors Whose Terms Expire in 2007,2009,” “Directors Whose Terms Expire in 2006,2008,” and “Compliance with Section 16(a) of the Securities Exchange Act of 1934” and is incorporated herein by reference. Information concerning the Company’s executive officers can be found in Part I, Item 1, of this report.

The Company has adopted a Code of Business Conduct and Ethics that applies to the Company’s directors, officers and employees and has posted such Code of Business Conduct and Ethics on the Company’s website,www.nationalfuelgas.com, together with certain other corporate governance documents. Copies of the Company’s Code of Business Conduct and Ethics, charters of important committees, and Corporate Governance Guidelines will be made available free of charge upon written request to Investor Relations, National Fuel Gas Company, 6363 Main Street, Williamsville, New York 14221.
The Company intends to satisfy the disclosure requirement under Item 5.05 ofForm 8-K
regarding an amendment to, or a waiver from, a provision of its code of ethics that applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, and that relates to any element of the code of ethics definition enumerated in paragraph (b) of Item 406 of the SEC’sRegulation S-K, by posting such information on its website,www.nationalfuelgas.com.
 
Item 11Executive Compensation

The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its February 17, 200515, 2007 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004.2006. The information concerning executive compensation is set forth in the definitive Proxy Statement under the captionsheadings “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 12Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Equity Compensation Plan Information

The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its February 17, 200515, 2007 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004.2006. The equity compensation plan information is set forth in the definitive Proxy Statement under the captionheading “Equity Compensation Plan Information” and is incorporated herein by reference.

Security Ownership and Changes in Control
 
  (a)Security Ownership of Certain Beneficial Owners

The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its February 17, 200515, 2007 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004.2006. The information concerning security ownership of certain beneficial owners is set forth in the definitive Proxy Statement under the captionheading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.

101


 
  (b)Security Ownership of Management

The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its February 17, 200515, 2007 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004.2006. The information concerning security ownership of management is set forth in the definitive Proxy Statement under the captionheading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.


115


  (c)Changes in Control

None
 
Item 13Certain Relationships and Related Transactions

The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its February 17, 200515, 2007 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004.2006. The information regarding certain relationships and related transactions is set forth in the definitive Proxy Statement under the captionheading “Compensation Committee Interlocks and Insider Participation” and is incorporated herein by reference.
 
Item 14Principal Accountant Fees and Services

The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its February 17, 200515, 2007 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004.2006. The information concerning principal accountant fees and services is set forth in the definitive Proxy Statement under the captionheading “Audit Fees” and is incorporated herein by reference.

PART IV
 
Item 15Exhibits and Financial Statement Schedules

(a)1.  Financial Statements

Financial statements filed as part of this report are listed in the index included in Item 8 of thisForm 10-K, and reference is made thereto.

(a)2.  Financial Statement Schedules

Financial statement schedules filed as part of this report are listed in the index included in Item 8 of thisForm 10-K, and reference is made thereto.

(a)3.  Exhibits
     
Exhibit
NumberDescription of Exhibits

Number

Exhibits
 3(i)  Articles of Incorporation:
   Restated Certificate of Incorporation of National Fuel Gas Company dated September 21, 1998 (Exhibit 3.1,Form 10-K for fiscal year ended September 30, 1998 in File No. 1-3880)
 Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 3(ii),Form 8-K dated March 14, 2005 in File No. 1-3880)
3(ii)  By-Laws:
   National Fuel Gas Company By-Laws as amended on December 9, 2004 (Exhibit 3(ii),Form 8-K dated December 9, 2004 in File No. 1-3880)
   (4)4  Instruments Defining the Rights of Security Holders, Including Indentures:
   Indenture, dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 2(b) in File No. 2-51796)

102


Exhibit
NumberDescription of Exhibits


   Third Supplemental Indenture, dated as of December 1, 1982,to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(4) in File No.33-49401)
   Eleventh Supplemental Indenture, dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b),Form 8-K dated February 14, 1992 in File No. 1-3880)


116


Exhibit
Description of
Number
Exhibits
   Twelfth Supplemental Indenture, dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c),Form 8-K dated June 18, 1992 in File No. 1-3880)
   Thirteenth Supplemental Indenture, dated as of March 1, 1993,1,1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(14) in File No.33-49401)
   Fourteenth Supplemental Indenture, dated as of July 1, 1993,to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880)
   Fifteenth Supplemental Indenture, dated as of September 1, 1996,1,1996, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
   Indenture dated as of October 1, 1999, between the Company and The Bank of New York (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
   Officers Certificate Establishing Medium-Term Notes, dated October 14, 1999 (Exhibit 4.2,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
   Amended and Restated Rights Agreement, dated as of April 30, 1999,30,1999, between the Company and HSBC Bank USA (Exhibit(Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 1999 in File No. 1-3880)
   Certificate of Adjustment, dated September 7, 2001, to the Amended and Restated Rights Agreement dated as of April 30, 1999,30,1999, between the Company and HSBC Bank USA (Exhibit 4, Form8-K dated September 7, 2001 in File No. 1-3880)
   Officers Certificate establishing 6.50% Notes due 2022, dated September 18, 2002 (Exhibit 4,Form 8-K dated October 3, 2002 in File No. 1-3880)
   Officers Certificate establishing 5.25% Notes due 2013, dated February 18, 2003 (Exhibit 4,Form 10-Q for the quarterly period ended March 31, 2003 in File No. 1-3880)
  (10)10  Material Contracts:
  (ii)  Contracts upon which the Company’s business is substantially dependent:other than compensatory plans, contracts or arrangements:
   CreditForm of Indemnification Agreement, dated as of September 30, 2002, among2006, between the Company the Lenders and JPMorgan Chase Bankeach Director (Exhibit 10.1,Form 10-K for fiscal year ended8-K dated September 30, 200218, 2006 in File No. 1-3880)
   First Amendment to Credit Agreement, dated as of August 19, 2005, among the Company, the Lenders Party Thereto and JPMorgan Chase Bank, dated September 29, 2003N.A., as Administrative Agent (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 20032005 in File No. 1-3880)
Compensatory plans, contracts or arrangements:
   Second Amendment to Credit Agreement, among the Company, the Lenders and JPMorgan Chase Bank, dated September 26, 2004 (Exhibit 99, Form 8-K dated September 30, 2004 in File No. 1-3880)
 (iii)Compensatory plans for officers:
Retirement Benefit Agreement, dated September 22, 2003, between the Company and David F. Smith (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 2003 in File No. 1-3880)
Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, among the Company, National Fuel Gas Distribution Corporation and each of Philip C. Ackerman, Anna Marie Cellino, Joseph P. Pawlowski,Paula M, Ciprich, Donna L. DeCarolis, James D. Ramsdell, Dennis J. Seeley, David F. Smith and Ronald J. Tanski (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880)

103


Exhibit
NumberDescription of Exhibits


   Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, among the Company, National Fuel Gas Supply Corporation and each of Bruce H. Hale and John R. Pustulka (Exhibit 10.2,Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880)
   Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, among the Company, Seneca Resources Corporation and James A. Beck (Exhibit 10.3, Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880)
National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993 (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880)
   Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880)
   Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 11, 1996 (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
   Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 18, 1996 (Exhibit 10,Form 10-Q for the quarterly period ended December 31, 1996 in File No. 1-3880)


117


Exhibit
Description of
Number
Exhibits
   National Fuel Gas Company 1993 Award and Option Plan, amended through June 14, 2001 (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2001 in File No. 1-3880)
   National Fuel Gas Company 1993 Award and Option Plan, amended through September 8, 2005 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
Administrative Rules with Respect to At Risk Awards under the 1993 Award and Option Plan (Exhibit 10.14,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
National Fuel Gas Company 1997 Award and Option Plan, amended through June 14, 2001September 8, 2005 (Exhibit 10.2, 10.3,Form 10-K for fiscal year ended September 30, 20012005 in File No. 1-3880)
   Amendment toForm of Award Notice under National Fuel Gas Company Deferred Compensation1997 Award and Option Plan (Exhibit 10.1,Form 8-Kdated June 15, 2001 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 2001March 28, 2005 in File No. 1-3880)
   Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated May 16, 2006 in File No. 1-3880)
Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan amended and restated as of September 8, 2005 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
Description of performance goals for Chief Executive Officer under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10,Form 10-Q for the quarterly period ended December 31, 2004 in File No. 1-3880)
Description of performance goals for Chief Executive Officer under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2005 in File No. 1-3880)
Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated, effective March 9, 2005 (Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 2005 in File No. 1-3880)
National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7, Form 10-KForm10-K for fiscal year ended September 30, 1994 in File No. 1-3880)
   Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880)
Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
   Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880)
National Fuel Gas Company Deferred Compensation Plan, as amended and restated through March 20, 1997 (Exhibit(Exhibit 10.3,Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
   Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 16, 1997 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
   Amendment No. 2 to the National Fuel Gas Company Deferred Compensation Plan, dated March 13, 1998 (Exhibit 10.1, Form 10-KForm10-K for fiscal year ended September 30, 1998 in File No. 1-3880)
   Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated February 18, 1999 (Exhibit10.1,Form 10-Q for the quarterly period ended March 31, 1999 in File No. 1-3880)
   Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 15, 2001 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 2001 in File No. 1-3880)
Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated October 21, 2005 (Exhibit 10.5,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
Form of Letter Regarding Deferred Compensation Plan and Internal Revenue Code Section 409A, dated July 12, 2005 (Exhibit 10.6,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
National Fuel Gas Company Tophat Plan, effective March 20, 1997 (Exhibit 10,Form 10-Q for the quarterly period ended June 30, 1997 in File No. 1-3880)
   Amendment No. 1 to National Fuel Gas Company Tophat Plan, dated April 6, 1998 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 1998 in File No. 1-3880)


118


Exhibit
Description of
Number
Exhibits
   Amendment No. 2 to National Fuel Gas Company Tophat Plan, dated December 10, 1998 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880)
   Amended Restated Split Dollar Insurance Agreement, effective June 15, 2000, among the Company, Bernard J. Kennedy,Form of Letter Regarding Tophat Plan and Joseph B. Kennedy, as Trustee of the Trust under the AgreementInternal Revenue Code Section 409A, dated January 9, 1998July 12, 2005 (Exhibit 10.1, 10.7,Form 10-Q10-K for the quarterly periodfiscal year ended JuneSeptember 30, 20002005 in File No. 1-3880)
   Contingent Benefit Agreement effective June 15, 2000, between theNational Fuel Gas Company Tophat Plan, Amended and Bernard J. KennedyRestated December 7, 2005 (Exhibit 10.2, 10.1,Form 10-Q for the quarterly period ended June 30, 2000December 31, 2005 in File No. 1-3880

104


     
Exhibit
NumberDescription of Exhibits


   Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 17, 1997 between the Company and Philip C. Ackerman (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
   Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Philip C. Ackerman, dated March 23, 1999 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
   Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and Joseph P. Pawlowski (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
   Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Joseph P. Pawlowski, dated March 23, 1999 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
   Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and Dennis J. Seeley (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
   Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Dennis J. Seeley, dated March 29, 1999 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
   Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997, between the Company and Bruce H. Hale (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
   Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and Bruce H. Hale, dated March 29, 1999 (Exhibit 10.12, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
   Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and David F. Smith (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
   Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
 10.1 National Fuel Gas Company Parameters for Executive Life Insurance Plan
   National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880)
 10.2 National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement (I), dated September 1, 2003
   National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
   Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated September 18, 1997 (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
   Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated December 10, 1998 (Exhibit 10.2, Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880)
   Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16, 1999 (Exhibit 10.15, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)

105


     
Exhibit
NumberDescription of Exhibits


   Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 5, 2001 (Exhibit 10.4, Form 10-K/A for fiscal year ended September 30, 2001, in File No. 1-3880)
   Retirement Supplement Agreement, dated January 11, 2002, between the Company and Joseph P. Pawlowski (Exhibit 10.6, Form 10-K/A for fiscal year ended September 30, 2001 in File No. 1-3880)
   Amendment No. 1 to Retirement Supplement Agreement, dated March 11, 2004, between the Company and Joseph P. Pawlowski (Exhibit 10(iii), Form 10-Q for the quarterly period ended March 31, 2004 in File No. 1-3880)
   Administrative Rules with Respect to At Risk Awards under the 1993 Award and Option Plan (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
   Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan (Exhibit A, Definitive Proxy Statement, Schedule 14(A) filed January 10, 2002 in File No. 1-3880)
 10.3 Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated, effective September 9, 2004
   Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
 10.4 Retirement and Consulting Agreement, dated September 5, 2001, between the Company and Bernard J. Kennedy
 (12) Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 1998 through 2003
 (21) Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report on Form 10-K
 (23) Consents of Experts:
 23.1 Consent of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation
 23.2 Consent of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc.
 23.3 Consent of Independent Accountants
 (31) Rule 13a-15(e)/15d-15(e) Certifications
 31.1 Written statements of Chief Executive Officer pursuant to Rule 13a-15(e)/15d-15(e) of the Exchange Act.
 31.2 Written statements of Principal Financial Officer pursuant to Rule 13a-15(e)/15d-15(e) of the Exchange Act.
 (32) Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 (99) Additional Exhibits:
 99.1 Report of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation
 99.2 Report of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc.
 99.3 Company Maps
   The Company agrees to furnish to the SEC upon request the following instruments with respect to long-term debt that the Company has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(ii)(A):
    Secured Credit Agreement, dated as of June 5, 1997, among the Empire State Pipeline, as borrower, Empire State Pipeline, Inc., the Lenders party thereto, JPMorgan Chase Bank (f/k/a The Chase Manhattan Bank), as administrative agent, and Chase Securities, as arranger.
    First Amendment to Secured Credit Agreement, dated as of May 28, 2002, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, and JPMorgan Chase Bank, as administrative agent.
    Second Amendment to Secured Credit Agreement, dated as of February 6, 2003, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, as amended, and JPMorgan Chase Bank, as administrative agent.

106


Exhibit1-3880)
NumberDescription of Exhibits


   Incorporated herein by reference as indicated.Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 17, 1997 between the Company and Philip C. Ackerman (Exhibit 10.5,Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
   Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Philip C. Ackerman, dated March 23, 1999 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
 All other exhibits are omitted because they are not applicable orAmended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the required information is shown elsewhereCompany and Dennis J. Seeley (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1999 in this Annual Report on File No. 1-3880)
Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Dennis J. Seeley, dated March 29, 1999 (Exhibit 10.10,Form 10-K.10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997, between the Company and Bruce H. Hale (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and Bruce H. Hale, dated March 29, 1999 (Exhibit 10.12,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and David F. Smith (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
National Fuel Gas Company Parameters for Executive Life Insurance Plan (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2004 in File No. 1-3880)
National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880)
Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated September 18, 1997 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated December 10, 1998 (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880)
Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16, 1999 (Exhibit 10.15,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 5, 2001 (Exhibit 10.4,Form 10-K/A for fiscal year ended September 30, 2001, in File No. 1-3880)
National Fuel Gas Company and Participating Subsidiaries 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)


119

107


     
Exhibit
 Description of
Number
 
Exhibits
 
   National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement (I), dated September 1, 2003 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2004 in File No. 1-3880)
   National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 8-K dated June 3, 2005 in File No. 1-3880)
   Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
   Retirement Benefit Agreement for David F. Smith, dated September 22, 2003,between the Company and David F. Smith (Exhibit 10.2,Form10-K for fiscal year ended September 30, 2003 in File No. 1-3880)
   Amendment No. 1 to the Retirement Benefit Agreement for David F. Smith, dated September 8, 2005, between the Company and David F. Smith (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
   Description of performance goals for certain executive officers (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2005 in File No. 1-3880)
   Retirement Agreement, dated August 1, 2005, between the Company and Bruce H. Hale (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
   Commission Agreement, dated August 1, 2005, between the Company and Bruce H. Hale (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880)
   Description of bonuses awarded to executive officer (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 1-3880)
   Description of performance goals for certain executive officers (Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 1-3880)
   Noncompete and Restrictive Covenant Agreement, dated February 1, 2006, between the Company and Dennis J. Seeley (Exhibit 10.3,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 1-3880)
   Description of salaries of certain executive officers (Exhibit 10.4,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 1-3880)
   Description of assignment of interests in certain life insurance policies (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880)
   Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.2,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880)
   Description of agreement between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.3,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880)
 10.1 Agreement, dated September 24, 2006, between the Company and Philip C. Ackerman regarding death benefit
   Retirement Agreement, dated July 1, 2006, between the Company and James A. Beck (Exhibit 10.4,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880)
   Contract for Consulting Services, dated July 1, 2006, between the Company and James A. Beck (Exhibit 10.5,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880)
 12  Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 2002 through 2006
 21  Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report onForm 10-K
 23  Consents of Experts:
 23.1 Consent of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation
 23.2 Consent of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc.
 23.3 Consent of Independent Registered Public Accounting Firm
 31  Rule 13a-15(e)/15d-15(e) Certifications


120


     
Exhibit
 Description of
Number
 
Exhibits
 
 31.1 Written statements of Chief Executive Officer pursuant toRule 13a-15(e)/15d-15(e) of the Exchange Act.
 31.2 Written statements of Principal Financial Officer pursuant toRule 13a-15(e)/15d-15(e) of the Exchange Act.
 32••  Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 99  Additional Exhibits:
 99.1 Report of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation
 99.2 Report of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc.
 99.3 Company Maps
   The Company agrees to furnish to the SEC upon request the following instruments with respect to long-term debt that the Company has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A):
    Secured Credit Agreement, dated as of June 5, 1997, among the Empire State Pipeline, as borrower, Empire State Pipeline, Inc., the Lenders party thereto, JPMorgan Chase Bank (f/k/a The Chase Manhattan Bank), as administrative agent, and Chase Securities, as arranger.
    First Amendment to Secured Credit Agreement, dated as of May 28, 2002, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, and JPMorgan Chase Bank, as administrative agent.
    Second Amendment to Secured Credit Agreement, dated as of February 6, 2003, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, as amended, and JPMorgan Chase Bank, as administrative agent.
   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 onForm 10-K.
 ••  In accordance with Item 601(b) (32) (ii) ofRegulation S-K and SEC Release Nos.33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is ‘‘furnished” and not deemed ‘‘filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference.


121


SIGNATURESSignatures

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)

National Fuel Gas Company
(Registrant)
 By /s/  P. C. ACKERMANAckerman

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

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

7, 2006

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
SignatureTitle
TitleDate



 
/s/  P. C. ACKERMAN

Ackerman
P. C. Ackerman
 Chairman of the Board, President, Chief Executive Officer and Director Date: December 9, 20047, 2006
 
/s/  R. T. BRADY

Brady
R. T. Brady
 Director Date: December 9, 20047, 2006
 
/s/  R. D. CASH

Cash
R. D. Cash
 Director Date: December 9, 20047, 2006
 
/s/  R. E. KIDDER

Kidder
R. E. Kidder
 Director Date: December 9, 20047, 2006
 
/s/  B. S. LEE

B. S. LeeC. G. Matthews
     C. G. Matthews
 Director Date: December 9, 20047 2006
 
/s/  G. L. MAZANEC

Mazanec
G. L. Mazanec
 Director Date: December 9, 20047, 2006
 
/s/  R. G. Reiten
     R. G. Reiten
DirectorDate: December 7, 2006
/s/  J. F. RIORDAN

Riordan
J. F. Riordan
 Director Date: December 9, 20047, 2006
 
/s/  R. J. TANSKI

Tanski
R. J. Tanski
 Treasurer and Principal Financial Officer Date: December 9, 20047, 2006
 
/s/  K. M. CAMIOLO

Camiolo
K. M. Camiolo
 Controller and Principal Accounting Officer Date: December 9, 20047, 2006


122

108