This~~This~~ Form 10-K contains “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements included in thisForm 10-K at ~~Item~~item 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 1	*Business*

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 ~~six~~five reportable business segments.

1. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation sells natural gas or provides natural gas transportation services to approximately ~~732,000~~727,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.

2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation, and Empire State Pipeline (Empire), a New York joint venture between two wholly-owned ~~entities~~subsidiaries 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

~~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.

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.

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 ~~87,000~~100,000 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 ~~six~~five 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 found~~The 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 provides~~formed 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 Act~~PUHCA 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 by~~certain books and records of companies in holding company systems. Pursuant to the ~~Securities~~FERC’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-Regulatory~~C-Regulatory Matters.

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

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-Regulatory~~C-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-Regulatory~~C-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 ~~2004~~2006 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 ~~2004~~2006 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 ~~3,868~~3,888 MDth or ~~5.6%~~5.7% of the total firm storage capacity. Nonaffiliated customers have contracted for the remaining ~~36,995~~36,655 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 time~~term. 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 successful~~neither issued nor received any contract termination notices in ~~marketing~~2006, 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 ~~2,232~~1,995 MDth per day (contracted transportation capacity). The Utility segment accounts for approximately ~~1,122~~1,092 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 ~~1,032~~804 MDth or ~~46.2%~~40.3% of contracted transportation capacity ~~are~~is subject to firm contracts with nonaffiliated customers.

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 deadline~~in 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 contracted~~transportation 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 be~~have been terminated effective ~~before the end of 2005.~~in 2007. Based on contract expirations and termination notices received ~~before the deadline~~in 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 ~~such~~available transportation ~~service previously~~capacity (at discounted rates when necessary), and expects its success to ~~continue to do so.~~continue.*

Empire has service agreements for the ~~2004-2005~~2006-2007 winter period for all of its firm transportation capacity, which totals approximately ~~562~~575 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 ~~transportation~~contracted capacity is ~~contracted~~ on aan annual long-term basis. ~~None~~Annual long-term agreements representing 0.5% of ~~these transportation~~Empire’s firm contracted capacity expire in 2007. Approximately 3.4% of Empire’s firm contracted capacity is under multi-year seasonal contracts, ~~could be terminated~~none 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 ~~total~~firm contracted capacity, and the Energy Marketing segment accounts for approximately ~~10 MDth per day or 1.8%~~1.7% of Empire’s ~~total~~firm 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 ~~2004~~2006 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 ~~International~~Energy Marketing Segment

The ~~International~~Energy Marketing segment contributed approximately ~~3.6%~~4.2% of the Company’s ~~2004~~2006 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 ~~2004~~2006 net income available for common stock.

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.

All Other Category and Corporate Operations

The All Other category and Corporate operations contributed ~~approximately 0.5%~~less than 1% of the Company’s ~~2004~~2006 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 served~~for 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 market~~these 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 market~~2006 purchases. Purchases from ~~Conoco Phillips Company~~Chevron Natural Gas (16%), ~~Cinergy Marketing~~ConocoPhillips Company (15%), Total Gas & ~~Trading, L.P. (13%), BP Energy Company~~Power 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 market~~2006 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-Business~~Note J-Business Segment Information and ~~N-Supplementary~~Note 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 ~~2004~~2006 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.

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 ~~deregulation~~natural 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 removing~~since 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.

The electric industry has been moving toward a more competitive environment as a result of ~~the Federal Energy Policy Act of~~changes 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 ~~continues~~has 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 ~~heading~~headings “Investing Cash ~~Flow.~~Flow” and “Rate and Regulatory Matters.”

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 originate~~originates and ~~act~~acts as operator on ~~most~~certain of its prospects, seeks to minimize the risk of exploratory efforts through partnership-type arrangements, ~~apply the latest~~utilizes technology for both exploratory studies and drilling operations, and ~~focus on~~seeks market niches ~~that suit their~~based 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 competition~~Competition in this area is well developed with regard to price and services from ~~both~~ local, regional and, ~~regional~~more 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 nationally~~in 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 ~~revenues~~margins in New York is mitigated by a ~~weather normalization clause~~WNC, which ~~is designed to adjust~~covers the ~~rates of retail customers to reflect the impact of deviations~~eight-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

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 ~~species~~or 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.

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 ~~2,918~~1,993 full-time employees at September 30, ~~2004,~~2006, with ~~2,055~~1,970 employees in all of its U.S. operations and ~~863~~23 employees in its ~~international operations.~~Canadian operations at SECI. This is a decrease of ~~3.9%~~2.5% from the ~~3,037~~2,044 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. Other~~2009, 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.

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 Material~~During 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 Corporation~~the Company since ~~July 1999; Senior Vice~~February 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. ~~Seeley~~Smith 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.

~~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 ~~since~~from July ~~2001;~~2001 through January 2006; and Controller of Distribution Corporation from February 1997 through March ~~2004; Treasurer~~2004.

Matthew D. Cabell (48)		President of ~~Distribution Corporation since April 2004; Treasurer~~Seneca effective December 11, 2006. Mr. Cabell previously served as Executive Vice President and ~~Secretary~~General Manager of ~~Supply Corporation since April 2004; Secretary~~Marubeni Oil & Gas (USA) Inc., an exploration and ~~Treasurer~~production company with assets of ~~Horizon since February 1997; and~~over $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 President~~General Counsel of Distribution Corporation ~~from June 1994 to July 2001.~~since February 1997.
~~Bruce H. Hale~~
Donna L. DeCarolis ~~(55)~~(47)		President of ~~Horizon Power~~NFR 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 Corporation~~NFR from ~~February 1997~~May 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.

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

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.

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.

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

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

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 1B	*Unresolved Staff Comments*

None


Item 2	*Properties*

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

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 ~~14,781~~14,809 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 ~~2,575~~2,528 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 ~~75,306~~75,361 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 ~~87,000~~100,000 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 ~~2004~~2006 peak day sendout, including transportation service, of ~~1,756.3~~1,542.4 MMcf, which occurred on ~~January 15, 2004.~~February 18, 2006. Withdrawals from storage of ~~736.2~~545.2 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-Supplementary~~O-Supplementary Information for Oil and Gas Producing Activities.

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. Natural~~natural gas reserves decreased from ~~251~~238 Bcf at September 30, ~~2003~~2005 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 ~~69,764~~65,213 Mbbl at September 30, 2004 to ~~65,213 Mbbl. These decreases are~~60,257 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, ~~2004~~2006 were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Ralph E. Davis Associates, Inc. Seneca reports its oil and gas reserve information on an annual basis to the Energy Information Administration (EIA), a

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

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

Production
For the Year Ended
September 30
2004 2003 2002
United States

Gulf Coast Region
Average Sales Price per Mcf of Gas $ 5.61 $ 5.41 $ 2.89
Average Sales Price per Barrel of Oil $ 35.31 $ 29.17 $ 22.83
Average Sales Price per Mcf of Gas (after hedging) $ 4.78 $ 4.22 $ 3.69
Average Sales Price per Barrel of Oil (after hedging) $ 31.51 $ 27.88 $ 22.51
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ 0.60 $ 0.56 $ 0.60
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) 73 75 100
West Coast Region
Average Sales Price per Mcf of Gas $ 5.54 $ 5.01 $ 2.86
Average Sales Price per Barrel of Oil $ 31.89 $ 26.12 $ 19.94
Average Sales Price per Mcf of Gas (after hedging) $ 5.72 $ 5.12 $ 2.86
Average Sales Price per Barrel of Oil (after hedging) $ 22.86 $ 23.67 $ 20.09
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ 1.05 $ 1.00 $ 0.81
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) 55 59 63
Appalachian Region
Average Sales Price per Mcf of Gas $ 5.91 $ 5.07 $ 3.74
Average Sales Price per Barrel of Oil $ 31.30 $ 28.77 $ 23.76
Average Sales Price per Mcf of Gas (after hedging) $ 5.72 $ 5.10 $ 3.74
Average Sales Price per Barrel of Oil (after hedging) $ 31.30 $ 28.77 $ 23.76
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ 0.54 $ 0.43 $ 0.53
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) 14 14 12


	For the Year Ended September 30
	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

For the Year Ended
September 30
2004 2003 2002
Total United States

Average Sales Price per Mcf of Gas $ 5.66 $ 5.28 $ 2.99
Average Sales Price per Barrel of Oil $ 33.13 $ 27.16 $ 21.03
Average Sales Price per Mcf of Gas (after hedging) $ 5.11 $ 4.52 $ 3.58
Average Sales Price per Barrel of Oil (after hedging) $ 26.06 $ 25.11 $ 21.01
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ 0.76 $ 0.72 $ 0.67
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) 142 148 175
Canada

Average Sales Price per Mcf of Gas $ 4.87 $ 4.67 $ 2.29
Average Sales Price per Barrel of Oil $ 30.94 $ 26.41 $ 19.94
Average Sales Price per Mcf of Gas (after hedging) $ 4.87 $ 4.20 $ 3.59
Average Sales Price per Barrel of Oil (after hedging) $ 30.94 $ 15.85 $ 18.11
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ 1.00 $ 1.65 $ 1.29
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) 22 55 64
Total Company

Average Sales Price per Mcf of Gas $ 5.51 $ 5.18 $ 2.88
Average Sales Price per Barrel of Oil $ 32.98 $ 26.90 $ 20.63
Average Sales Price per Mcf of Gas (after hedging) $ 5.06 $ 4.47 $ 3.58
Average Sales Price per Barrel of Oil (after hedging) $ 26.40 $ 21.84 $ 19.94
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ 0.80 $ 0.97 $ 0.84
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) 164 203 239


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


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


	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
Gulf West
Coast Coast Appalachian Total Total
At September 30, 2004 Region Region Region U.S. Canada Company
Developed Acreage — Gross 102,270 9,839 508,466 620,575 109,194 729,769
— Net 76,549 9,469 481,732 567,750 74,302 642,052
Undeveloped Acreage — Gross 206,619 — 464,525 671,144 421,690 1,092,834
— Net 115,909 — 440,004 555,913 316,820 872,733


	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), 130,707~~191,159 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 ~~721,295~~657,020 acres thereafter ~~(594,044~~(528,525 net acres).

Drilling Activity
Productive Dry
For the Year Ended September 30 2004 2003 2002 2004 2003 2002
United States

Gulf Coast Region
Net Wells Completed — Exploratory — 1.25 1.27 0.50 — 3.67
— Development 0.65 2.10 0.31 — — —
West Coast Region
Net Wells Completed — Exploratory — — — — — —
— Development 49.00 30.97 47.99 — — 2.00
Appalachian Region
Net Wells Completed — Exploratory — 3.00 3.00 3.00 0.10 1.00
— Development 41.00 58.00 27.00 — — 0.10
Total United States
Net Wells Completed — Exploratory — 4.25 4.27 3.50 0.10 4.67
— Development 90.65 91.07 75.30 — — 2.10
Canada

Net Wells Completed — Exploratory 52.85 5.00 0.20 6.08 2.50 4.00
— Development 10.50 17.16 33.70 — 5.00 7.90
Total

Net Wells Completed — Exploratory 52.85 9.25 4.47 9.58 2.60 8.67
— Development 101.15 108.23 109.00 — 5.00 10.00


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


	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.


Item 3	*Legal Proceedings*

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

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

In an action instituted in the New York State Supreme Court, Kings County on February 18, 2003 against Distribution Corporation and Paul J. Hissin, an unaffiliated third party, plaintiff Donna Fordham-Coleman, as administratrix of the estate of Velma Arlene Fordham, alleges that Distribution Corporation’s denial of natural gas service in November 2000 to the plaintiff’s decedent, Velma Arlene Fordham, caused the decedent’s death in February 2001. The plaintiff ~~seeks~~sought damages for wrongful death and pain and suffering, plus punitive damages. Distribution Corporation ~~has~~ denied plaintiff’s material allegations, ~~set up~~asserted seven affirmative defenses ~~in separate verified answers~~ and ~~filed~~asserted a cross-claim against the co-defendant. Distribution Corporation believes, and ~~will~~has vigorously ~~assert~~asserted, 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

judgment dismissing plaintiff’s claims for wrongful death and punitive damages. The ~~litigation~~Court 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 stages~~Court 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 order~~safety recommendations to ~~Seneca to halt its timber harvesting operations on 21,000 acres in Cameron, Elk~~Distribution 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 purposes~~investigation of ~~determining whether its earth disturbing activities meet~~a 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 aggregation~~heading “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 ~~these~~the 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~~

outcome of these matters, and it is possible that the ~~outcomes, individually or in the aggregate~~outcome could be material to results of operations or cash flow for a particular quarter or annual period.*

For a discussion of various environmental and other matters, refer to Item 7, MD&A and Item 8 at Note 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 in~~These other matters may include, for example, negligence claims and tax, regulatory ~~and~~or other governmental audits, inspections, investigations ~~and~~or other ~~proceedings that~~proceedings. 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 regulatory~~these 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 4	*Submission of Matters to a Vote of Security Holders*

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

2006.

PART II


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

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

On July 1, ~~2004,~~2006, the Company issued a total of ~~1,800~~2,100 unregistered shares of Company common stock to the ~~six~~seven 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.

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

Total 311,325 $ 27.43 — —


					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.


Item 6	*Selected Financial Data(1)*

Year Ended September 30
2004 2003 2002 2001 2000
(Thousands)
Summary of Operations

Operating Revenues $ 2,031,393 $ 2,035,471 $ 1,464,496 $ 2,059,836 $ 1,412,416

Operating Expenses:
Purchased Gas 949,452 963,567 462,857 1,002,466 488,383
Fuel Used in Heat and Electric Generation 65,722 61,029 50,635 54,968 54,893
Operation and Maintenance 413,593 386,270 394,157 364,318 350,383
Property, Franchise and Other Taxes 72,111 82,504 72,155 83,730 78,878
Depreciation, Depletion and Amortization 189,538 195,226 180,668 174,914 142,170
Impairment of Oil and Gas Producing Properties — 42,774 — 180,781 —

1,690,416 1,731,370 1,160,472 1,861,177 1,114,707
Gain (Loss) on Sale of Timber Properties (1,252 ) 168,787 — — —
Gain (Loss) on Sale of Oil and Gas Producing Properties 4,645 (58,472 ) — — —

Operating Income 344,370 414,416 304,024 198,659 297,709
Other Income (Expense):
Income from Unconsolidated Subsidiaries 805 535 224 1,794 1,669
Impairment of Investment in Partnership — — (15,167 ) — —
Other Income 6,671 6,887 7,017 10,639 6,366
Interest Expense on Long-Term Debt (83,827 ) (92,766 ) (90,543 ) (81,851 ) (67,195 )
Other Interest Expense (6,763 ) (12,290 ) (15,109 ) (25,294 ) (32,890 )

Income Before Income Taxes and Minority Interest in Foreign Subsidiaries 261,256 316,782 190,446 103,947 205,659
Income Tax Expense 92,737 128,161 72,034 37,106 77,068
Minority Interest in Foreign Subsidiaries (1,933 ) (785 ) (730 ) (1,342 ) (1,384 )

Income Before Cumulative Effect of Changes in Accounting 166,586 187,836 117,682 65,499 127,207
Cumulative Effect of Changes in Accounting — (8,892 ) — — —

Net Income Available for Common Stock $ 166,586 $ 178,944 $ 117,682 $ 65,499 $ 127,207


	Year Ended September 30
	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

Year Ended September 30
2004 2003 2002 2001 2000
(Thousands)
Per Common Share Data

Basic Earnings per Common Share $ 2.03 $ 2.21 ⁽²⁾ $ 1.47 $ 0.83 $ 1.63
Diluted Earnings per Common Share $ 2.01 $ 2.20 ⁽²⁾ $ 1.46 $ 0.82 $ 1.61
Dividends Declared $ 1.10 $ 1.06 $ 1.03 $ 0.99 $ 0.95
Dividends Paid $ 1.09 $ 1.05 $ 1.02 $ 0.97 $ 0.94
Dividend Rate at Year-End $ 1.12 $ 1.08 $ 1.04 $ 1.01 $ 0.96
At September 30:
Number of Common Shareholders
19,063 19,217 20,004 20,345 21,164

Net Property, Plant and Equipment(Thousands)

Utility $ 1,048,428 $ 1,028,393 $ 960,015 $ 945,693 $ 939,753
Pipeline and Storage 696,487 705,927 487,793 483,222 474,972
Exploration and Production 923,730 925,833 1,072,200 1,081,622 998,852
International 227,905 219,199 207,191 178,250 172,602
Energy Marketing 80 171 125 262 360
Timber 82,838 87,600 110,624 90,453 95,607
All Other 21,172 22,042 6,797 1,209 1,241
Corporate 6,124 1,883 — 2 4

Total Net Plant $ 3,006,764 $ 2,991,048 $ 2,844,745 $ 2,780,713 $ 2,683,391

Total Assets(Thousands)
$ 3,711,798 $ 3,719,060 $ 3,401,309 $ 3,445,231 $ 3,251,031

Capitalization(Thousands)

Comprehensive Shareholders’ Equity $ 1,253,701 $ 1,137,390 $ 1,006,858 $ 1,002,655 $ 987,437
Long-Term Debt, Net of Current Portion 1,133,317 1,147,779 1,145,341 1,046,694 953,622

Total Capitalization $ 2,387,018 $ 2,285,169 $ 2,152,199 $ 2,049,349 $ 1,941,059


	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


	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 ~~accounting~~accounting.

(3)		Includes net plant of ~~($0.11) basic~~the 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 7	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

OVERVIEW

The Company is a diversified energy company consisting of ~~six~~five 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;~~

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.

~~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 out~~district 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 and~~follows.

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 properties~~segment. 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 extension~~had 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 Pipeline~~Connector 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 link~~originally 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 I~~FERC 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 ~~recognized~~also began repurchasing outstanding shares of common stock during the ~~concerns about its debt~~quarter 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 after~~repurchase up to an aggregate amount of 8 million shares. Through September 30, 2006, the ~~Empire acquisition~~Company had repurchased 2,526,550 shares. These matters are discussed further in the Capital Resources and ~~therefore sold these timber properties~~Liquidity 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 used~~filing 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 finance~~achieve 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

~~Another event, which occurred~~

reached a settlement in ~~2003~~principle. 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 pipelines~~Regulatory 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 ~~POLICIES~~ESTIMATES

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 ~~policies~~estimates whereby judgments or uncertainties could affect the application of ~~those~~accounting policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Item 8 at Note A — Summary of Significant Accounting Policies.

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

The Company believes that determining the amount of the Company’s proved reserves is a critical accounting estimate. Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the ~~full-cost~~full 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 Rule~~S-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

value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to ~~write-down~~write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. The Company recorded non-cash impairments relating to its Canadian properties in 2003 which amounted to $28.9 million (after tax) and resulted from downward revisions to crude oil reserves (related 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 costs~~third 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 to~~2006. 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

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 on~~recognized 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

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

~~2004~~2006 Compared with ~~2003~~2005

The Company’s earnings were ~~$166.6~~$138.1 million in ~~2004~~2006 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 ~~Timber~~Exploration and ~~Utility~~Production and Pipeline and Storage segments ~~partially~~ offset somewhat by higher earnings in the ~~Exploration~~Utility segment, Energy Marketing segment, Timber segment, and ~~Production, International,~~All Other category and ~~Pipeline and Storage~~

~~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

after tax amounts. Earnings from continuing operations and discontinued operations were impacted by several events in ~~2004~~2006 and ~~2003,~~2005, including:


	*~~2004~~2006 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;


	•	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.

Earnings (Loss) by Segment
Year Ended September 30
2004 2003 2002
(Thousands)
Utility $ 46,718 $ 56,808 $ 49,505
Pipeline and Storage 47,726 45,230 29,715
Exploration and Production 54,344 (31,930 ) 26,851
International 5,982 (9,623 ) (4,443 )
Energy Marketing 5,535 5,868 8,642
Timber 5,637 112,450 9,689

Total Reportable Segments 165,942 178,803 119,959
All Other 1,530 193 (885 )
Corporate (886 ) (52 ) (1,392 )

Total Consolidated $ 166,586 $ 178,944 $ 117,682


	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
2004 2003 2002
(Thousands)
Retail Revenues:
Residential $ 808,740 $ 801,984 $ 538,345
Commercial 137,092 137,905 86,963
Industrial 17,454 23,263 18,332

963,286 963,152 643,640

Off-System Sales 106,841 107,220 68,606
Transportation 80,563 86,374 83,267
Other 1,951 6,237 (1,292 )

$ 1,152,641 $ 1,162,983 $ 794,221


	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

Utility Throughput — million cubic feet (MMcf)
Year Ended September 30
2004 2003 2002
Retail Sales:
Residential 70,109 76,449 64,639
Commercial 12,752 14,177 11,549
Industrial 2,261 3,537 3,715

85,122 94,163 79,903

Off-System Sales 16,839 17,999 21,541
Transportation 60,565 64,232 61,909

162,526 176,394 163,353


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


						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	)%

~~2004~~2006 Compared with ~~2003~~2005

Operating revenues for the Utility segment ~~decreased $10.3~~increased $163.7 million in ~~2004~~2006 compared with ~~2003.~~2005. This increase largely resulted ~~largely~~ from a ~~decrease~~$146.5 million increase in ~~transportation~~retail gas sales revenues. Transportation revenues ~~of $5.8~~and other revenues also increased by $8.9 million and ~~a decrease~~$8.3 million, respectively.

The increase in ~~other~~retail 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 in~~for 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 by~~a 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

$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’s~~segment 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 and~~Lower retail sales volumes, due primarily to lower customer usage per account, ~~were~~partially offset the ~~major factors in the decrease~~increase in retail ~~sales volumes. The decrease in~~revenues associated with the recovery of higher gas costs and the base rate increases. Also, retail industrial sales ~~volumes can be attributed~~revenue 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 ~~decrease~~increase 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.

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

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

~~Earnings~~

~~2004 Compared with 2003~~

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

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

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

~~2003 Compared with 2002~~

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

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

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

Purchased Gas

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

Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation and six other upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers, and for storage service with Supply Corporation and three nonaffiliated companies. In addition, Distribution Corporation satisfies a portion of its gas requirements through spot market purchases. Changes in wellhead prices have a direct impact on the cost of purchased gas. Distribution Corporation’s average cost of purchased gas, including the cost of transportation and storage, was ~~$7.30~~$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 ~~2003~~2005 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.

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.

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
2004 2003 2002
(Thousands)
Firm Transportation $ 120,443 $ 109,508 $ 88,082
Interruptible Transportation 3,084 3,944 3,315

123,527 113,452 91,397

Firm Storage Service 63,962 63,223 62,733
Interruptible Storage Service 20 36 7

63,982 63,259 62,740

Other 22,198 24,709 13,247

$ 209,707 $ 201,420 $ 167,384


	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
2004 2003 2002
Firm Transportation 338,991 340,925 290,507
Interruptible Transportation 12,692 10,004 7,315

351,683 350,929 297,822


	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

~~2004~~2006 Compared with ~~2003~~2005

Operating revenues for the Pipeline and Storage segment ~~increased $8.3~~decreased $1.5 million in ~~2004~~2006 as compared with ~~2003. The acquisition~~2005. 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 $33.4~~offset by a $1.8 million ~~($32.3 million~~increase in firm ~~transportation revenues, $0.3 million in~~and interruptible transportation revenues and ~~$0.8~~a $1.2 million increase in firm and interruptible storage service revenues. The decrease in other ~~revenues). For the period of February 6, 2003~~revenues is primarily due to ~~September 30, 2003, Empire recorded operating revenues of $20.9~~a $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 ~~higher~~lower natural gas ~~commodity~~ prices, ~~and higher volumes. These increases to operating revenues were partially offset by lower intercompany rental income of approximately $6.5~~as well as a $0.7 million ~~and lower~~decrease 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.

~~2003~~2005 Compared with ~~2002~~2004

Operating revenues for the Pipeline and Storage segment increased ~~$34.0~~$6.2 million in ~~2003~~2005 as compared with ~~2002. For 2003, the acquisition of Empire was a significant factor contributing~~2004. 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 prices~~prices. 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

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

~~2004~~2006 Compared with ~~2003~~2005

The Pipeline and Storage segment’s earnings in ~~2004~~2006 were ~~$47.7~~$55.6 million, ~~an increase~~a 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 to~~decrease 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 in~~associated 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 ~~$3.2~~higher 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 as~~an increase of $12.8 million when compared with earnings of $47.7 million in 2004. Contributing to the ~~increased earnings contribution~~increase 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 Corporation~~unbundled 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 tax~~that did not recur in 2005 associated with the settlement of a pension obligation recognized in ~~2004. Supply Corporation also experienced an earnings impact~~2004, 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 million~~Empire 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.

1.8 million) partially offset these increases.

EXPLORATION AND PRODUCTION

Revenues

Exploration and Production Operating Revenues
Year Ended September 30
2004 2003 2002
(Thousands)
Gas (after Hedging) $ 167,127 $ 150,982 $ 148,467
Oil (after Hedging) 119,564 147,101 152,746
Gas Processing Plant 28,614 28,879 16,995
Other 1,815 1,308 6,627
Intrasegment Elimination(1) (23,422 ) (22,956 ) (13,855 )

$ 293,698 $ 305,314 $ 310,980


	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


(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 gas~~Purchased Gas expense.

Production Volumes
Year Ended September 30
2004 2003 2002
Gas Production(MMcf)

Gulf Coast 17,596 18,441 25,776
West Coast 4,057 4,467 4,889
Appalachia 5,132 5,123 4,402
Canada 6,228 5,774 6,387

��

33,013 33,805 41,454

Oil Production(Mbbl)

Gulf Coast 1,534 1,473 1,815
West Coast 2,650 2,872 3,004
Appalachia 20 10 9
Canada 324 2,382 2,834

4,528 6,737 7,662


	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
2004 2003 2002
Average Gas Price/ Mcf

Gulf Coast $ 5.61 $ 5.41 $ 2.89
West Coast $ 5.54 $ 5.01 $ 2.86
Appalachia $ 5.91 $ 5.07 $ 3.74
Canada $ 4.87 $ 4.67 $ 2.29
Weighted Average $ 5.51 $ 5.18 $ 2.88
Weighted Average After Hedging(1) $ 5.06 $ 4.47 $ 3.58
Average Oil Price/ Barrel (bbl)

Gulf Coast $ 35.31 $ 29.17 $ 22.83
West Coast(2) $ 31.89 $ 26.12 $ 19.94
Appalachia $ 31.30 $ 28.77 $ 23.76
Canada $ 30.94 $ 26.41 $ 19.94
Weighted Average $ 32.98 $ 26.90 $ 20.63
Weighted Average After Hedging(1) $ 26.40 $ 21.84 $ 19.94


	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.

~~2004~~2006 Compared with ~~2003~~2005

Operating revenues for the Exploration and Production segment ~~decreased $11.6~~increased $53.5 million in ~~2004~~2006 as compared with ~~2003.~~2005. Oil production revenue after hedging ~~decreased $27.5~~increased $40.5 million due primarily to ~~a 2,209 Mbbl decline in production offset partly by~~ higher

weighted average prices after hedging ($~~4.56~~13.24 per barrel). ~~Most of the~~This 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~~$2.6 million. Increases in the weighted average price of gas after hedging ($~~0.59~~0.92 per Mcf) more than offset an overall decrease in gas ~~production. Most of the~~production (3,408 MMcf). The decrease in gas production occurred primarily in the Gulf Coast ~~(an 845~~(a 3,358 MMcf decline), which is ~~consistent with~~partly 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 mainly~~Other 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 increase~~2005, 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 Canadian~~oil 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.

~~2003~~2005 Compared with ~~2002~~2004

Operating revenues for the Exploration and Production segment decreased ~~$5.7~~$0.3 million in ~~2003~~2005 as compared with ~~2002.~~2004. Oil production revenue after hedging decreased ~~$5.6~~$11.8 million due to a ~~925,000 barrel~~659 Mbbl decline in production offset partly by higher weighted average prices after hedging ($~~1.90~~1.46 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~~$14.6 million. Increases in the weighted average price of gas after hedging ($~~0.89~~1.17 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 ~~7,335~~5,128 MMcf decline). The ~~Company had anticipated some of this~~decreases in Gulf Coast oil and gas production are consistent with the expected decline ~~in gas and oil production due to reduced activity~~rates in the region. This decrease in Gulf Coast ~~region. Other factors in the overall~~gas production ~~decrease included an outside-operated offshore pipeline leak that required four key producing blocks to be shut-in for ten days, and~~was partially offset by a ~~decline in drilling activity in Canada related to a decision to sell the~~

Company’s Southeast Saskatchewan properties. Also, earlier in the year certain production in the Gulf Coast region was shut-in during Hurricane Lili and some of those wells did not return to pre-hurricane production levels. Gas processing plant revenues increased $11.9 million due to higher gas prices (because there is a similar1,781 MMcf increase in ~~purchased~~Canadian 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 compared~~2006.

Refer to ~~positive mark-to-market adjustments on~~further 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

~~2004~~2006 Compared with ~~2003~~2005

The Exploration and Production segment’s earnings in ~~2004~~2006 were ~~$54.3~~$21.0 million, ~~an increase~~a decrease of ~~$86.2~~$29.7 million when compared with ~~a loss~~earnings of ~~$31.9~~$50.7 million in ~~2003. Earnings~~2005. 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 by~~higher 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

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 ~~sold~~increased its ~~Southeast Saskatchewan~~forecast 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 after~~and also recognized a tax ~~loss~~benefit 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 ~~which~~that increased 2004 earnings by $4.6 million. ~~When~~In 2005, the ~~transaction closed~~Company 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 subject~~West Coast Region. Depletion expense increased despite a drop in production mostly due to an ~~adjustment based on actual working capital~~increase in the per unit depletion rate, which was largely the result of the higher finding and ~~the resolution~~development costs experienced by Seneca in 2005. All of ~~certain income tax matters. Those items~~these 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 was~~2005 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 (attributable~~has 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 ~~lower~~future capital expenditures.* Lower general and administrative expenses, ~~of $2.1 million after tax (attributable~~largely due to ~~cost-cutting efforts in Canada). Another offsetting factor was a~~ lower ~~effective income tax rate, which benefitted~~legal costs, also increased 2005 earnings by ~~approximately $3.4 million.~~

~~INTERNATIONAL~~

~~Revenues~~

~~International Operating Revenues~~

Year Ended September 30
2004 2003 2002
(Thousands)
Heating $ 88,395 $ 80,752 $ 65,386
Electricity 30,949 29,386 26,960
Other 4,081 3,932 2,969

$ 123,425 $ 114,070 $ 95,315

~~International Heating and Electric Volumes~~

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

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

~~2004 Compared with 2003~~

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

~~2003 Compared with 2002~~

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

~~Earnings~~

~~2004 Compared with 2003~~

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

~~2003 Compared with 2002~~

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

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

ENERGY MARKETING

Revenues

Energy Marketing Operating Revenues
Year Ended September 30
2004 2003 2002
(Thousands)
Natural Gas (after Hedging) $ 283,747 $ 304,390 $ 151,219
Other 602 270 38

$ 284,349 $ 304,660 $ 151,257


	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
2004 2003 2002
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

~~2004~~2006 Compared with ~~2003~~2005

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 ~~2003~~2006 as compared with ~~2002. This~~2005. The increase primarily reflects higher natural gas ~~sales revenue~~commodity prices that were recovered through revenues, and, to a lesser extent, an increase in throughput. The increase in throughput was due to the

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 contributed~~down compared to the ~~increase in operating revenues.~~

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

Earnings

~~2004~~2006 Compared with ~~2003~~2005

The Energy Marketing ~~segment~~segment’s earnings in ~~2004~~2006 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,~~

~~primarily due~~and, 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
2004 2003 2002
(Thousands)
Log Sales $ 21,790 $ 27,341 $ 21,528
Green Lumber Sales 5,923 6,200 6,567
Kiln Dry Lumber Sales 27,416 21,814 15,976
Other 841 871 3,336

$ 55,970 $ 56,226 $ 47,407


	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
2004 2003 2002
(Thousands)
Log Sales 6,848 8,764 8,174
Green Lumber Sales 9,552 11,913 12,878
Kiln Dry Lumber Sales 15,020 13,300 10,794

31,420 33,977 31,846


	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

~~2004~~2006 Compared with ~~2003~~2005

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. The~~2005. This increase can ~~largely~~ be chiefly attributed to ~~higher~~an 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

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. Higher~~harvested 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 contributed~~of $2.2 million largely due to ~~the increase. Partially offsetting the~~an increase in ~~log~~cherry lumber sales ~~and~~volumes 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 $2.5~~represent 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 included~~as a ~~$2.4 million gain on the sale~~result of ~~standing timber.~~

favorable weather conditions that allowed for an increase in harvesting.

Earnings

~~2004~~2006 Compared with ~~2003~~2005

The Timber segment earnings in ~~2004~~2006 were ~~$5.6~~$5.7 million, ~~a decrease~~an increase of ~~$106.9~~$0.7 million when compared with earnings of ~~$112.5~~$5.0 million in ~~2003. This~~2005. Higher margins from kiln dry lumber sales and cherry export log sales accounted for the earnings ~~fluctuation~~increase.

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 ~~largely~~primarily 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

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 of~~Horizon 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 was~~activity 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 consist~~consists of equity method investments in Seneca Energy, ~~II, LLC (Seneca Energy),~~ Model City ~~Energy, LLC (Model City)~~ and ~~Energy Systems North East, LLC (ESNE). The Company~~ESNE. 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

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 into~~that 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 on~~earnings discussion by segment above, the ~~Consolidated Statement~~main 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, 2003~~interest 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.

INTEREST CHARGES

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

Interest on long-term debt ~~was $8.9~~decreased $0.6 million ~~lower~~ in ~~2004 compared to 2003; however, interest on long-term debt was $2.2~~2006 and $9.7 million ~~higher~~ in ~~2003 compared to 2002.~~2005. The decrease in ~~2004 resulted mainly from~~2005 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 $5.5~~were $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 with~~2005 and a lower average amount of short-term debt ~~outstanding.~~

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
2004 2003 2002
(Millions)
Provided by Operating Activities $ 444.3 $ 326.8 $ 345.6
Capital Expenditures (172.3 ) (152.2 ) (232.4 )
Investment in Subsidiaries, Net of Cash Acquired — (228.8 ) —
Investment in Partnerships — (0.4 ) (0.5 )
Net Proceeds from Sale of Timber Properties — 186.0 —
Net Proceeds from Sale of Oil and Gas Producing Properties 7.1 78.5 22.1
Other Investing Activities 2.0 12.1 5.0
Short-Term Debt, Net Change 38.6 (147.6 ) (224.8 )
Long-Term Debt, Net Change (243.1 ) 20.7 139.6
Issuance of Common Stock 23.8 17.0 10.9
Dividends Paid on Common Stock (89.1 ) (84.5 ) (81.0 )
Effect of Exchange Rates on Cash 3.4 1.6 1.5

Net Increase (Decrease) in Cash and Temporary Cash Investments $ 14.7 $ 29.2 $ (14.0 )


	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 ~~noncash~~non-cash expenses, ~~noncash~~non-cash income and changes in operating assets and liabilities. ~~Noncash~~Non-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 effect~~gain 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

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 occurred~~2005. Higher oil and gas revenues in the ~~Utility~~Exploration and Production segment ~~largely attributable~~were 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.~~

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

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’s~~segment capital expenditures were made for purchases of equipment for ~~this segment’s~~Highland’s sawmill and kiln operations.

~~All Other and Corporate~~

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

Estimated Capital Expenditures

The Company’s estimated capital expenditures for the next three years are:*
Year Ended September 30,
2005 2006 2007
(Millions)
Utility $ 54.0 $ 52.0 $ 51.0
Pipeline and Storage 22.0 22.0 22.0
Exploration and Production(1) 93.0 91.0 89.0
International 15.0 26.0 29.0
Timber 2.0 1.0 1.0
All Other and Corporate 5.0 — —

$ 191.0 $ 192.0 $ 192.0

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, 2006~~2007, 2008 and ~~2007~~2009 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 ~~2005~~2007 will be concentrated in the areas of main and service line improvements and replacements and, to a ~~minor~~lesser extent, the ~~installation~~purchase of new ~~services.~~equipment.*

Estimated capital expenditures for the Pipeline and Storage segment in ~~2005~~2007 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 a~~FERC 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 would~~services. 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 ~~agreement~~agreements to ~~be a major shipper, subject to~~subscribe 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 extension~~Empire Connector will be designed to move ~~at least~~up to approximately 250 ~~MMcf~~MDth of natural gas per day.* ~~The preliminary estimate of~~In July 2006, Empire revised the ~~cost~~planned in-service date for ~~developing~~ the Empire ~~extension project is $140 million and the~~Connector to extend beyond its original November 2007 target. The new targeted in-service date is ~~late~~November 2008, or sooner if feasible.* FERC issued on July 20, 2006 a preliminary determination regarding non-environmental aspects of the application, in ~~calendar~~response 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 for~~in 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

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 ~~2005~~2007 for the Exploration and Production segment include approximately ~~$32.0~~$34.0 million for Canada, ~~$29.0~~$100.0 million for the Gulf Coast region ($~~28.0~~98.0 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.*

~~Estimated capital expenditures~~2007 in the Timber segment will be concentrated on the ~~construction or~~ purchase of new ~~facilities~~equipment and ~~equipment~~improvements 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 and~~did not have any outstanding short-term ~~borrowings~~notes 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 repay~~banks 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 these~~These 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~~$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 Company~~extends 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, 2003~~September 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~~

~~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 ~~fails~~fail 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, ~~2004~~2006 and ~~6.5% at~~ September 30, ~~2003.~~2005. Refer to “Interest Rate Risk” in this Item for a more detailed ~~break-down~~breakdown 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.

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.

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
2005 2006 2007 2008 2009 Thereafter Total
(Millions)
Long-Term Debt $ 14.3 $ 14.3 $ 9.3 $ 209.3 $ 104.1 $ 796.3 $ 1,147.6
Short-Term Bank Notes $ 26.5 $ — $ — $ — $ — $ — $ 26.5
Commercial Paper $ 130.3 $ — $ — $ — $ — $ — $ 130.3
Operating Lease Obligations $ 8.7 $ 7.1 $ 6.1 $ 5.2 $ 4.8 $ 2.4 $ 34.3
Capital Lease Obligations $ 0.8 $ 1.1 $ 0.9 $ 0.8 $ 0.4 $ 1.0 $ 5.0
Purchase Obligations:
Gas Purchase Contracts(1) $ 589.5 $ 87.0 $ 11.1 $ 5.8 $ 5.7 $ 68.4 $ 767.5
Transportation and Storage Contracts $ 134.4 $ 135.4 $ 133.0 $ 125.9 $ 69.5 $ 12.4 $ 610.6
Other $ 2.4 $ 0.8 $ 0.4 $ 0.4 $ 0.4 $ — $ 4.4


	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 ~~Policies~~Estimates — 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 in~~These other matters may include, for example, negligence claims and tax, regulatory ~~and~~or other governmental audits, inspections, investigations ~~and~~or other ~~proceedings that~~proceedings. 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 regulatory~~these normal-course matters

could have a material effect on earnings and cash flows in the period ~~of resolution, none of this litigation, and none of these regulatory matters,~~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 employees~~approximately 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 ~~2005~~2007 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

the Post-Retirement Plan. The Company anticipates that the annual contribution to the Post-Retirement Plan in ~~2005~~2007 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, ~~2004~~2006 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

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

Natural Gas Price Swap Agreements


	*~~Crude Oil Price Swap Agreements~~*

Expected Maturity Dates
2005 2006 2007 Total
Notional Quantities (Equivalent bbls) 2,743,000 1,755,000 540,000 5,038,000
Weighted Average Fixed Rate (per bbl) $30.51 $33.27 $35.55 $32.01
Weighted Average Variable Rate (per bbl) $46.74 $41.31 $38.41 $43.95

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.~~

2006.

At September 30, ~~2003,~~2005, the Company had natural gas price swap agreements covering ~~13.1~~18.8 Bcf at a weighted average fixed rate of ~~$4.24~~$5.73 per Mcf. The Company also had crude oil price swap agreements covering ~~2,184,000~~2,835,000 bbls at a weighted average fixed rate of ~~$25.44~~$35.09 per bbl. The ~~increase~~decrease in natural gas price swap agreements from September ~~2003~~2005 to September ~~2004~~2006 is largely ~~a result of~~attributable to management’s decision to ~~hedge farther into the future~~utilize 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 use~~segment. The decrease in crude oil price swap agreements ~~instead of~~is primarily due to the fact that the Company has not been entering into new swap agreements for its West Coast crude oil ~~no cost collars~~production. 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
2005 2006 Total
Natural Gas
Notional Quantities (Equivalent Bcf) 5.1 0.4 5.5
Weighted Average Ceiling Price (per Mcf) $8.31 $ 7.88 $8.28
Weighted Average Floor Price (per Mcf) $4.94 $ 4.77 $4.93
Crude Oil
Notional Quantities (Equivalent bbls) 105,000 — 105,000
Weighted Average Ceiling Price (per bbl) $28.56 — $28.56
Weighted Average Floor Price (per bbl) $25.00 — $25.00


	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


	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 pay~~received 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 $2.1~~received $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 ~~3.7~~8.5 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.


	*~~Options~~*

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

Expected Maturity Dates
2005 2006 Total
Natural Gas Put Options Purchased
Notional Quantities (Equivalent Bcf) 0.8 0.3 1.1
Weighted Average Strike Price (per Mcf) $ 6.05 $ 5.83 $ 5.99
Natural Gas Call Options Sold
Notional Quantities (Equivalent Bcf) 0.8 0.3 1.1
Weighted Average Strike Price (per Mcf) $ 7.84 $ 8.69 $ 8.06

At September 30, 2004, the Company would have received from the respective counterparties an aggregate of approximately $0.2 million to terminate the put options outstanding at that date. The Company would have had to pay an aggregate of approximately $1.0 million to terminate the call options outstanding at that date. The Company did not have any ~~options~~ outstanding 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
2005 2006 2007 Total
Net Contract Volumes Purchased (Sold) (Equivalent Bcf) (3.5 ) (0.4 ) 0.1 (3.8 )
Weighted Average Contract Price (per Mcf) $ 6.16 $ 6.29 $ 5.88 $ 6.17
Weighted Average Settlement Price (per Mcf) $ 7.74 $ 6.96 $ 6.33 $ 7.69


	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 ~~3.6~~2.2 Bcf (net ~~long~~short position) at a weighted average contract price of ~~$5.60~~$8.63 per Mcf.

The ~~change from a~~increase in net long ~~position at September 30, 2003~~positions in 2006 was due to ~~a net short position at September 30, 2004 can largely be explained by~~ the ~~high commodity price environment experienced by~~decrease in natural gas prices in the ~~Energy Marketing segment~~summer 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 sales~~These 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 ~~seven~~six 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

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.

Exchange Rate Risk

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

The Exploration and Production segment’s investment in Canada is valued in Canadian dollars, and, as such, this investment is subject to currency exchange risk when the Canadian dollars are translated into U.S. dollars. This exchange rate risk to the Company’s ~~investments~~investment 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
2005 2006 2007 2008 2009 Thereafter Total
(Dollars in Millions)
National Fuel Gas Company

Long-Term Fixed Rate Debt $ — $ — $ — $ 200 $ 100 $ 796.3 $ 1,096.3
Weighted Average Interest Rate Paid 0 % 0 % 0 % 6.3 % 6.0 % 6.5 % 6.4 %
Fair Value = $1,147.9 million
Other Notes

Long-Term Debt(1) $ 14.3 $ 14.3 $ 9.3 $ 9.3 $ 4.1 $ — $ 51.3
Weighted Average Interest Rate Paid(2) 4.1 % 4.1 % 2.8 % 2.8 % 2.8 % — 3.5 %
Fair Value = $51.3 million

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

~~The Company uses an interest rate collar to limit interest rate fluctuations on $41.4~~$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

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 Order~~RATE MATTERS~~667-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 ~~filed~~commenced a rate case by filing proposed tariff amendments and supporting testimony ~~designed~~requesting approval to increase its annual revenues ~~by $41.3 million~~ beginning October 1, 2004. ~~The rate request was filed to address throughput reductions~~Various 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 filing~~approved the April 15, 2005 settlement agreement, substantially as ~~provided by law in order to allow time~~filed, 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 outcome~~The settlement agreement provides for a rate increase of $21 million by means of the ~~rate proceeding at this time. The existing~~elimination 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 expired~~agreement and thereafter, the return on ~~September 30, 2004 will continue to~~equity level above which earnings must be ~~in effect until the Commission issues an order concerning Distribution Corporation’s~~shared 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

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 request~~proposed 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 date~~rate request was filed to ~~January 15, 2004. Distribution Corporation filed this request for several reasons including increases in the~~address increased costs associated with Distribution Corporation’s ongoing construction program as well as increases in operating costs, particularly uncollectible ~~accounts~~accounts. 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 adoption~~including 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 for~~Settlement 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 million~~case until January 28, 2008 at the earliest and ~~authorizes deferral accounting for pension and other post-retirement benefit expenses.~~an early implementation date. The ~~settlement~~Settlement was approved by the PaPUC at its meeting on ~~December 18, 2003,~~November 30, 2006, and new rates ~~became~~will become effective January ~~15, 2004.~~

1, 2007.

On ~~September 15, 2004, Distribution Corporation filed revised tariffs with~~June 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 FERC~~NTSB 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), but~~damaged 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 clarification~~differ in their assessment of the ~~new rules, or by complying with~~probable cause of the ~~requirements applicable if~~explosion. 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 ~~were~~to have an ~~energy affiliate. Treating~~adequate 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 changes~~had 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 and~~vicinity of Distribution Corporation’s pipeline. Distribution Corporation ~~operate~~also 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 condition~~seek review of the ~~Company.* Until there is further clarification from~~NTSB’s findings and conclusions to ensure that the ~~FERC on the scope of these~~NTSB considered all

~~exemptions~~

relevant evidence, including the report of Distribution Corporation’s third-party plastic pipe expert and ~~rulings on~~other 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 ~~Company~~PaPUC 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 2004~~outcome 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 ~~have~~depend 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-system~~has 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 Company~~of gas retained from shippers, and (ii) if FERC concludes that Supply Corporation does not ~~expect~~have such authority, to direct Supply Corporation to show

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 ~~change~~the rate at which Supply Corporation is permitted to ~~have~~retain gas from shippers for fuel and loss is unjust and unreasonable, (ii) to require Supply Corporation to make a ~~material effect on~~compliance 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 results~~complainants’ 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 sales~~of December 1, 2006. The principal elements of the settlement are ~~minimal~~ as ~~a result of profit sharing with retail~~follows:


(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-


		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

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 ~~SEC~~FASB issued ~~Staff Accounting Bulletin No. 106 (SAB 106). SAB 106 addresses the application~~FIN 47, an interpretation of SFAS ~~No.~~143. FIN 47 provides additional guidance on the term “conditional asset retirement obligation” as used in SFAS 143, ~~“Accounting~~and 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 follow~~Obligations for further disclosure regarding the ~~full-cost method~~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 ~~oil~~ and ~~gas property acquisition, exploration~~reporting 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 106~~SFAS 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

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

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;


	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 ~~affecting~~involving 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;

~~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 7A	*Quantitative and Qualitative Disclosures About Market Risk*

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


Item 8	*Financial Statements and Supplementary Data*


	*~~Index to Financial Statements~~*

Index to Financial Statements


			~~Page~~

~~Financial Statements:~~
		Page
Financial Statements:
Report of Independent Registered Public Accounting Firm			5261
	Consolidated Statements of Income and Earnings Reinvested in the Business, three years ended September 30, ~~2004~~2006			5363
	Consolidated Balance Sheets at September 30, ~~2004~~2006 and ~~2003~~2005			5464
	Consolidated ~~Statement~~Statements of Cash Flows, three years ended September 30, ~~2004~~2006			5565
	Consolidated ~~Statement~~Statements of Comprehensive Income, three years ended September 30, ~~2004~~2006			5666
	Notes to Consolidated Financial Statements			5767
Financial Statement Schedules:
	For the three years ended September 30, ~~2004~~2006
	~~II-Valuation~~Schedule II — Valuation and Qualifying Accounts			~~100~~113

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.

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, ~~2004~~2006 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, ~~2004~~2006 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 ~~consolidated~~maintenance 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 Statement~~in 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.~~

~~PRICEWATERHOUSECOOPERS LLP~~

~~Buffalo, New York~~

~~December 9, 2004~~

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

NATIONAL FUEL GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS

REINVESTED IN THE BUSINESS

Year Ended September 30
2004 2003 2002
(Thousands of dollars, except per
common share amounts)
INCOME

Operating Revenues
$ 2,031,393 $ 2,035,471 $ 1,464,496

Operating Expenses:

Purchased Gas 949,452 963,567 462,857
Fuel Used in Heat and Electric Generation 65,722 61,029 50,635
Operation and Maintenance 413,593 386,270 394,157
Property, Franchise and Other Taxes 72,111 82,504 72,155
Depreciation, Depletion and Amortization 189,538 195,226 180,668
Impairment of Oil and Gas Producing Properties — 42,774 —

1,690,416 1,731,370 1,160,472
Gain (Loss) on Sale of Timber Properties (1,252 ) 168,787 —
Gain (Loss) on Sale of Oil and Gas Producing Properties 4,645 (58,472 ) —

Operating Income
344,370 414,416 304,024
Other Income (Expense):

Income from Unconsolidated Subsidiaries 805 535 224
Impairment of Investment in Partnership — — (15,167 )
Other Income 6,671 6,887 7,017
Interest Expense on Long-Term Debt (83,827 ) (92,766 ) (90,543 )
Other Interest Expense (6,763 ) (12,290 ) (15,109 )

Income Before Income Taxes and Minority

Interest in Foreign Subsidiaries
261,256 316,782 190,446
Income Tax Expense 92,737 128,161 72,034
Minority Interest in Foreign Subsidiaries (1,933 ) (785 ) (730 )

Income Before Cumulative Effect of Changes In Accounting
166,586 187,836 117,682
Cumulative Effect of Changes in Accounting — (8,892 ) —

Net Income Available for Common Stock
166,586 178,944 117,682

EARNINGS REINVESTED IN THE BUSINESS

Balance at Beginning of Year 642,690 549,397 513,488

809,276 728,341 631,170
Dividends on Common Stock 90,350 85,651 81,773

Balance at End of Year
$ 718,926 $ 642,690 $ 549,397

Earnings Per Common Share:

Basic:
Income Before Cumulative Effect of Changes in Accounting $ 2.03 $ 2.32 $ 1.47
Cumulative Effect of Changes in Accounting — (0.11 ) —

Net Income Available for Common Stock
$ 2.03 $ 2.21 $ 1.47

Diluted:
Income Before Cumulative Effect of Changes in Accounting $ 2.01 $ 2.31 $ 1.46
Cumulative Effect of Changes in Accounting — (0.11 ) —

Net Income Available for Common Stock
$ 2.01 $ 2.20 $ 1.46

Weighted Average Common Shares Outstanding:

Used in Basic Calculation 82,045,535 80,808,794 79,821,430
Used in Diluted Calculation 82,900,438 81,357,896 80,534,453


	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

NATIONAL FUEL GAS COMPANY

CONSOLIDATED BALANCE SHEETS
At September 30,
2004 2003
(Thousands of dollars)
ASSETS
Property, Plant and Equipment
$ 4,602,779 $ 4,657,343
Less — Accumulated Depreciation, Depletion and Amortization 1,596,015 1,666,295

3,006,764 2,991,048

Current Assets

Cash and Temporary Cash Investments 66,153 51,421
Receivables — Net of Allowance for Uncollectible Accounts of $17,440 and $17,943, Respectively 129,825 136,604
Unbilled Utility Revenue 18,574 20,155
Gas Stored Underground 68,511 89,640
Materials and Supplies — at average cost 43,922 32,311
Unrecovered Purchased Gas Costs 7,532 28,692
Prepayments 38,760 46,860
Fair Value of Derivative Financial Instruments 23 1,698

373,300 407,381

Other Assets

Recoverable Future Taxes 83,847 84,818
Unamortized Debt Expense 19,573 22,119
Other Regulatory Assets 66,862 52,381
Deferred Charges 3,411 7,528
Other Investments 72,556 64,025
Investments in Unconsolidated Subsidiaries 16,444 16,425
Goodwill 5,476 5,476
Intangible Assets 45,994 49,664
Other 17,571 18,195

331,734 320,631

Total Assets
$ 3,711,798 $ 3,719,060

CAPITALIZATION AND LIABILITIES
Capitalization:

Comprehensive Shareholders’ Equity

Common Stock, $1 Par Value Authorized — 200,000,000 Shares; Issued and Outstanding — 82,990,340 Shares and 81,438,290 Shares, Respectively $ 82,990 $ 81,438
Paid In Capital 506,560 478,799
Earnings Reinvested in the Business 718,926 642,690

Total Common Shareholder Equity Before Items
Of Other Comprehensive Loss 1,308,476 1,202,927
Accumulated Other Comprehensive Loss (54,775 ) (65,537 )

Total Comprehensive Shareholders’ Equity
1,253,701 1,137,390
Long-Term Debt, Net of Current Portion
1,133,317 1,147,779

Total Capitalization
2,387,018 2,285,169

Minority Interest in Foreign Subsidiaries
37,048 33,281

Current and Accrued Liabilities

Notes Payable to Banks and Commercial Paper 156,800 118,200
Current Portion of Long-Term Debt 14,260 241,731
Accounts Payable 115,979 118,563
Amounts Payable to Customers 3,154 692
Other Accruals and Current Liabilities 91,164 52,851
Fair Value of Derivative Financial Instruments 95,099 17,928

476,456 549,965

Deferred Credits

Accumulated Deferred Income Taxes 458,095 423,282
Taxes Refundable to Customers 11,065 13,519
Unamortized Investment Tax Credit 7,498 8,199
Cost of Removal Regulatory Liability 82,020 76,782
Other Regulatory Liabilities 67,669 72,632
Pension Liability 91,587 153,240
Asset Retirement Obligation 32,292 27,493
Other Deferred Credits 61,050 75,498

811,276 850,645

Commitments and Contingencies
— —

Total Capitalization and Liabilities
$ 3,711,798 $ 3,719,060


	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

NATIONAL FUEL GAS COMPANY

CONSOLIDATED ~~STATEMENT~~STATEMENTS OF CASH FLOWS
Year Ended September 30
2004 2003 2002
(Thousands of dollars)
Operating Activities

Net Income Available for Common Stock $ 166,586 $ 178,944 $ 117,682
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
(Gain) Loss on Sale of Timber Properties 1,252 (168,787 ) —
(Gain) Loss on Sale of Oil and Gas Producing Properties (4,645 ) 58,472 —
Impairment of Oil and Gas Producing Properties — 42,774 —
Depreciation, Depletion and Amortization 189,538 195,226 180,668
Deferred Income Taxes 40,329 78,369 62,013
Impairment of Investment in Partnership — — 15,167
Cumulative Effect of Changes in Accounting — 8,892 —
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions (19 ) 703 361
Minority Interest in Foreign Subsidiaries 1,933 785 730
Other 9,839 11,289 9,842
Change in:
Receivables and Unbilled Utility Revenue 4,840 (28,382 ) 40,786
Gas Stored Underground and Materials and Supplies 9,860 (12,421 ) 8,717
Unrecovered Purchased Gas Costs 21,160 (16,261 ) (8,318 )
Prepayments 8,146 (2,773 ) (1,737 )
Accounts Payable (5,134 ) 13,699 (24,025 )
Amounts Payable to Customers 2,462 692 (51,223 )
Other Accruals and Current Liabilities 38,718 8,595 (27,332 )
Other Assets (10,693 ) (32,681 ) 11,869
Other Liabilities (29,872 ) (10,298 ) 10,350

Net Cash Provided by Operating Activities
444,300 326,837 345,550

Investing Activities

Capital Expenditures (172,341 ) (152,251 ) (232,368 )
Investment in Subsidiaries, Net of Cash Acquired — (228,814 ) —
Investment in Partnerships — (375 ) (536 )
Net Proceeds from Sale of Timber Properties — 186,014 —
Net Proceeds from Sale of Oil and Gas Producing Properties 7,162 78,531 22,068
Other 1,974 12,065 5,012

Net Cash Used in Investing Activities
(163,205 ) (104,830 ) (205,824 )

Financing Activities

Change in Notes Payable to Banks and Commercial Paper 38,600 (147,622 ) (224,845 )
Net Proceeds from Issuance of Long-Term Debt — 248,513 243,844
Reduction of Long-Term Debt (243,085 ) (227,826 ) (104,212 )
Proceeds from Issuance of Common Stock 23,763 17,019 10,915
Dividends Paid on Common Stock (89,092 ) (84,530 ) (80,974 )

Net Cash Used in Financing Activities
(269,814 ) (194,446 ) (155,272 )

Effect of Exchange Rates on Cash
3,451 1,644 1,535

Net Increase (Decrease) in Cash and Temporary Cash Investments
14,732 29,205 (14,011 )
Cash and Temporary Cash Investments At Beginning of Year
51,421 22,216 36,227

Cash and Temporary Cash Investments At End of Year
$ 66,153 $ 51,421 $ 22,216

Supplemental Disclosure of Cash Flow Information

Cash Paid For:

Interest
$ 90,705 $ 104,452 $ 100,397

Income Taxes
$ 30,214 $ 56,146 $ 29,985


	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

NATIONAL FUEL GAS COMPANY

CONSOLIDATED ~~STATEMENT~~STATEMENTS OF COMPREHENSIVE INCOME
Year Ended September 30
2004 2003 2002
(Thousands of dollars)
Net Income Available for Common Stock $ 166,586 $ 178,944 $ 117,682

Other Comprehensive Income (Loss), Before Tax:
Minimum Pension Liability Adjustment 56,612 (86,170 ) (52,977 )
Foreign Currency Translation Adjustment 21,466 54,472 24,278
Reclassification Adjustment for Realized Foreign Currency Translation Gain in Net Income — (9,607 ) —
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period 3,629 2,419 (2,086 )
Unrealized Loss on Derivative Financial Instruments Arising During the Period (129,934 ) (47,777 ) (42,584 )
Reclassification Adjustment for Realized (Gain) Loss on Derivative Financial Instruments in Net Income 49,142 69,809 (20,063 )

Other Comprehensive Income (Loss), Before Tax 915 (16,854 ) (93,432 )

Income Tax Expense (Benefit) Related to Minimum Pension Liability Adjustment 19,814 (30,159 ) (18,542 )
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period 1,270 847 (730 )
Income Tax Benefit Related to Unrealized Loss on Derivative Financial Instruments Arising During the Period (49,113 ) (18,594 ) (17,341 )
Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gain) Loss on Derivative Financial Instruments in Net Income 18,182 26,953 (8,040 )

Income Taxes — Net (9,847 ) (20,953 ) (44,653 )

Other Comprehensive Income (Loss) 10,762 4,099 (48,779 )

Comprehensive Income $ 177,348 $ 183,043 $ 68,903


	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

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 America~~GAAP 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.


	*~~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.

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, ~~2003~~2006 and September 30, ~~2003. The~~2006. As such, the Company recognized pre-tax impairments of ~~$31.8 million and $11.0~~$62.4 million at June 30, ~~2003~~2006 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
68

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
2004 2003
(Thousands)
Utility $ 1,426,540 $ 1,380,278
Pipeline and Storage 946,866 854,923
Exploration and Production 1,517,856 1,673,827
International 379,356 349,132
Energy Marketing 1,169 1,159
Timber 97,290 96,315
All Other and Corporate 28,442 20,541

$ 4,397,519 $ 4,376,175


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


	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, 2003~~2006, 2005 and ~~2002,~~2004, respectively.

~~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 ~~record~~test 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
2004 2003
(Thousands)
Balance at Beginning of Year $ 27,493 $ 36,090
Liabilities Incurred and Revisions of Estimates 3,510 242
Liabilities Settled (831 ) (13,227 )
Accretion Expense 1,933 2,602
Exchange Rate Impact 187 1,786

Balance at End of Year $ 32,292 $ 27,493

In the Company’s Utility and Pipeline and Storage segment, costs of removal are collected from customers through depreciation expense. These removal costs are not a legal retirement obligation in accordance with SFAS 143. Rather, they represent a regulatory liability. However, SFAS 143 requires 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 could~~was 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, 2003~~2006 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, 2003~~2006, 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
2004 2003
(Thousands)
Minimum Pension Liability Adjustment $ (53,648 ) $ (90,446 )
Cumulative Foreign Currency Translation Adjustment 51,516 30,050
Net Unrealized Loss on Derivative Financial Instruments (56,733 ) (6,872 )
Net Unrealized Gain on Securities Available for Sale 4,090 1,731

Accumulated Other Comprehensive Loss $ (54,775 ) $ (65,537 )


	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.

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-current~~underground — 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.

~~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 ~~Statement~~Statements of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.

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 serve~~serves as collateral for open positions on exchange-traded futures contracts, exchange-traded options andover-the-counter swaps and ~~exchange-traded options. The~~collars.

Other Current Assets

Other Current Assets consist of prepayments in the amounts ~~held in margin accounts amounted to $8.6~~of $25.7 million and ~~$1.5~~$23.9 million at September 30, ~~2004~~2006 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 ~~Statement~~Statements of Income ~~reflects~~reflect the potential dilution as a result of these stock options as determined using the Treasury Stock Method. Stock options that are antidilutive are excluded from the calculation of diluted earnings per common share. For ~~2004, 2003 and 2002, 2,296,828, 7,789,688 and 5,260,633~~2006, 119,241 stock options ~~respectively,~~ were excluded as being antidilutive.

~~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 ~~accounts~~considers 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 ~~using~~under 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 ~~plans~~Company’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.

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 ~~2003~~was 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 based~~is included in operation and maintenance expense on ~~fair value~~the 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, which~~date 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.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table illustrates the ~~Company’s~~effect on net income and earnings per share ~~would have been reduced~~of 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
2004 2003 2002
(Thousands, except per share amounts)
Net Income Available for Common Stock As Reported $ 166,586 $ 178,944 $ 117,682
Deduct: Total Compensation Expense Determined Based on Fair Value at the Grant Dates 1,318 3,105 4,641

Pro Forma Net Income Available for Common Stock $ 165,268 $ 175,839 $ 113,041

Earnings Per Common Share:
Basic — As Reported $ 2.03 $ 2.21 $ 1.47
Basic — Pro Forma $ 2.01 $ 2.18 $ 1.42
Diluted — As Reported $ 2.01 $ 2.20 $ 1.46
Diluted — Pro Forma $ 1.99 $ 2.16 $ 1.40

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 ~~2003~~is $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, $4.17~~approximately $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 date~~period of ~~grant using~~one year. For a ~~binomial~~summary of transactions during 2006 involving option ~~pricing model with the following weighted average assumptions:~~

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

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

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.

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.

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.

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
2004 2003
(Thousands)
Regulatory Assets(1):

Recoverable Future Taxes (Note C) $ 83,847 $ 84,818
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A) 7,532 28,692
Unamortized Debt Expense (Note A) 9,882 11,364
Pension and Post-Retirement Benefit Costs (2)(Note F) 62,664 47,750
Other(2) 4,198 4,631

Total Regulatory Assets 168,123 177,255

Regulatory Liabilities:

Cost of Removal Regulatory Liability (See Cumulative Effect Discussion in Note A) 82,020 76,782
Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 3,154 692
New York Rate Settlements(3) 26,048 30,900
Taxes Refundable to Customers (Note C) 11,065 13,519
Pension and Post-Retirement Benefit Costs(3) (Note F) 13,232 23,719
Other(3) 28,389 18,013

Total Regulatory Liabilities 163,908 163,625

Net Regulatory Position $ 4,215 $ 13,630


	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.

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 for~~have 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 shareholders~~New York State gross receipts tax surcharge and ~~customers. As~~its 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 million~~regulatory liability at September 30, ~~2004~~2006 and ~~2003,~~2005 of $19.8 million and $34.3 million, respectively. ~~Other aspects~~Under 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 against~~CMR is principally the ~~Company’s incremental costs resulting from the~~

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~NYPSC’s gas restructuring effort and a “cost mitigation reserve” of $5.6 million and $8.2 million at September 30, 2004 and 2003, respectively. The cost mitigation reserve is an~~ accumulation of certain refunds from upstream pipeline ~~companies~~companies. 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 used~~the 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, ~~2004~~2006 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.

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 ~~Statement~~Statements of Income are as follows:
Year Ended September 30
2004 2003 2002
(Thousands)
Operating Expenses:
Current Income Taxes —
Federal $ 42,502 $ 37,335 $ 7,743
State 7,871 11,990 1,384
Foreign 2,035 467 894
Deferred Income Taxes —
Federal 29,559 53,311 50,205
State 9,620 12,983 9,968
Foreign 1,150 12,075 1,840

92,737 128,161 72,034
Other Income:
Deferred Investment Tax Credit (697 ) (693 ) (697 )
Minority Interest in Foreign Subsidiaries 374 (566 ) (277 )
Cumulative Effect of Change in Accounting — (354 ) —

Total Income Taxes $ 92,414 $ 126,548 $ 71,060


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

$ 259,000 $ 305,493 $ 188,743

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

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
2004 2003 2002
(Thousands)
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% $ 90,650 $ 106,923 $ 66,060
Increase (Reduction) in Taxes Resulting from:
State Income Taxes 11,369 16,232 7,379
Foreign Tax Differential (1,166 ) 3,318 (481 )
Foreign Tax Rate Reduction (5,174 ) — —
Miscellaneous (3,265 ) 75 (1,898 )

Total Income Taxes $ 92,414 $ 126,548 $ 71,060


	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 reduces~~amount for 2005 includes tax effects relating to the ~~corporate statutory income tax rate from 31% to 24% over~~disposition of a ~~three-year period.~~foreign subsidiary. The foreign tax rate reduction amount shown above ~~reflects a~~for 2004 relates to the reduction ~~in deferred~~of 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
2004 2003
(Thousands)
Deferred Tax Liabilities:
Property, Plant and Equipment $ 568,114 $ 519,578
Other 37,051 21,532

Total Deferred Tax Liabilities 605,165 541,110

Deferred Tax Assets:
Minimum Pension Liability Adjustment (28,887 ) (48,701 )
Capital Loss Carryover (12,546 ) (18,607 )
Unrealized Hedging Losses (33,890 ) (4,509 )
Other (74,624 ) (52,368 )

(149,947 ) (124,185 )
Valuation Allowance 2,877 6,357

Total Deferred Tax Assets (147,070 ) (117,828 )

Total Net Deferred Income Taxes $ 458,095 $ 423,282


	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, ~~2004~~2006 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, ~~2004~~2006 and ~~2003,~~2005, respectively.

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

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

The American Jobs Creation Act of 2004, ~~was~~ signed into law on October 22, ~~2004. The Company is reviewing the aspects of this legislation~~2004, included a provision which ~~affect, or will affect, the Company’s various segments, including the provision providing~~provided a substantially reduced tax rate of 5.25% on certain dividends received from foreign affiliates. ~~This provision is effective, at the election of~~During 2005, the Company ~~for~~received 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 ~~estimates~~determined that ~~a portion of~~it 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 to~~period. 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)

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~~*

Earnings Accumulated
Common Stock Reinvested Other
Paid In in the Comprehensive
Shares Amount Capital Business Income (Loss)
(Thousands, except per share amounts)
Balance at September 30, 2001 79,406 $ 79,406 $ 430,618 $ 513,488 $ (20,857 )
Net Income Available for Common Stock 117,682
Dividends Declared on Common Stock ($1.03 Per Share) (81,773 )
Other Comprehensive Loss, Net of Tax (48,779 )
Common Stock Issued Under Stock and Benefit Plans 859 859 16,214

Balance at September 30, 2002 80,265 80,265 446,832 549,397 (69,636 )
Net Income Available for Common Stock 178,944
Dividends Declared on Common Stock ($1.06 Per Share) (85,651 )
Other Comprehensive Income, Net of Tax 4,099
Cancellation of Shares (3 ) (3 ) (63 )
Common Stock Issued Under Stock and Benefit Plans 1,176 1,176 32,030

Balance at September 30, 2003 81,438 81,438 478,799 642,690 (65,537 )
Net Income Available for Common Stock 166,586
Dividends Declared on Common Stock ($1.10 Per Share) (90,350 )
Other Comprehensive Income, Net of Tax 10,762
Common Stock Issued Under Stock and Benefit Plans 1,552 1,552 27,761

Balance at September 30, 2004 82,990 $ 82,990 $ 506,560 $ 718,926 ⁽¹⁾ $ (54,775 )

(1) 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, $644.5~~2006, $692.7 million of accumulated earnings was free of such limitations.

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.

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 prices~~NATIONAL FUEL GAS COMPANY~~and/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

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.

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~


	*~~Stock Option and Stock Award Plans~~*

Stock Option and Stock Award Plans

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Transactions involving option shares for all plans are summarized as follows:
Number of
Shares Subject Weighted Average
to Option Exercise Price
Outstanding at September 30, 2001 9,372,686 $ 21.92
Granted in 2002(2) 5,673,172 $ 22.26
Exercised in 2002(1) (247,910 ) $ 15.76
Forfeited in 2002 (168,444 ) $ 25.56

Outstanding at September 30, 2002 14,629,504 $ 22.12
Granted in 2003 233,500 $ 24.61
Exercised in 2003(1) (673,866 ) $ 16.56
Forfeited in 2003 (123,800 ) $ 23.55

Outstanding at September 30, 2003 14,065,338 $ 22.41
Granted in 2004 87,000 $ 24.95
Exercised in 2004(1) (1,571,794 ) $ 18.29
Forfeited in 2004 (84,105 ) $ 25.40

Outstanding at September 30, 2004 12,496,439 $ 22.93

Option shares exercisable at September 30, 2004 11,594,368 $ 22.83
Option shares available for future grant at September 30, 2004(3) 919,537


						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 Outstanding Options Exercisable
Weighted
Number Average Weighted Number Weighted
Outstanding Remaining Average Exercisable Average
Range of Exercise Price at 9/30/04 Contractual Life Exercise Price at 9/30/04 Exercise Price
$13.90-$16.68 441,060 1.0 $ 14.23 441,060 $ 14.23
$16.69-$19.46 1,139,558 2.0 $ 18.38 1,139,558 $ 18.38
$19.47-$22.24 2,545,696 5.0 $ 21.26 2,432,296 $ 21.25
$22.25-$25.02 6,073,297 5.3 $ 23.34 5,354,957 $ 23.19
$25.03-$27.80 2,296,828 6.3 $ 27.63 2,226,497 $ 27.68

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 COMPANY~~Restricted 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
2004 2003 2002
Shares of Restricted Stock Awarded — — 100,000
Weighted Average Market Price of Stock on Award Date — — $ 24.50

~~As of September 30, 2004, 98,528~~outstanding shares of non-vested restricted stock ~~were outstanding. Vesting restrictions~~at September 30, 2006 will lapse as follows: ~~2005 — 33,600 shares; 2006 — 34,600 shares;~~ 2007 — ~~29,000~~25,000 shares; 2008 — 2,500 shares; 2009 — 4,500 shares; 2010 — 5,828 shares; and ~~2010~~2011 — ~~1,328~~4,500 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
2004 2003
(Thousands)
Debentures(1):
7 3/4% due February 2004 $ — $ 125,000
Medium-Term Notes(1):
6.0% to 7.50% due August 2004 to June 2025 749,000 849,000
Notes(1):
5.25% to 6.50% due March 2013 to September 2022(2) 347,272 347,400

1,096,272 1,321,400

Other Notes:
Secured(3) 41,433 50,767
Unsecured 9,872 17,343

Total Long-Term Debt 1,147,577 1,389,510
Less Current Portion 14,260 241,731

$ 1,133,317 $ 1,147,779


	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, ~~2004~~2006 and ~~2003, $97,272,000~~2005, $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

~~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.

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 these~~These 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 million~~which 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 ~~and~~or 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, 2003~~September 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.

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

~~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

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
2004 2004 2003 2003
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands)
Long-Term Debt $ 1,147,577 $ 1,199,189 $ 1,389,510 $ 1,520,606


	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, ~~2004~~2006 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, ~~2004~~2006 and ~~2003,~~September 30, 2005, respectively. The gross unrealized gain on ~~the~~this 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 at~~2006 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, ~~2004~~2006 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, ~~2004~~2006 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.

~~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

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 ~~23.0~~7.4 Bcf extending through 2009 at a weighted average fixed rate of ~~$5.47~~$7.24 per Mcf. Of this amount, ~~3.3~~1.1 Bcf is accounted for as fair value hedges at a weighted average fixed rate of ~~$5.51~~$6.98 per Mcf. The remaining ~~19.7~~6.3 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 ~~5,038,000~~900,000 bbls extending through ~~2007~~2008 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 ~~5.5~~7.1 Bcf extending through ~~2006~~2008 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. ~~The~~At September 30, 2006, the Company ~~also~~would 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 ~~105,000~~180,000 bbls extending through ~~2005~~2007 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 ~~3.5~~14.5 Bcf of gas extending through ~~2007~~2012 at a weighted average contract price of ~~$6.13~~$9.20 per Mcf. ~~Of this amount, 3.1 Bcf is~~

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

They are accounted for as fair value ~~hedges. They~~hedges 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 $5.1~~had 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 ~~7.3~~7.5 Bcf of gas extending through ~~2006~~2009 at a weighted average contract price of ~~$6.19~~$10.57 per Mcf. Of this amount, ~~5.9~~4.7 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 ~~1.4~~2.8 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 $11.3~~received $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 ~~seven~~six 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

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, ~~2004~~2006 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 all~~approximately 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.

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

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

The expected returns on plan assets of the Retirement Plan and Post-Retirement Plan are applied to the market-related value of plan assets of the respective plans. ~~For~~The 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 set~~are equal to market ~~value.~~

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 Plan Other Post-Retirement Benefits
Year Ended September 30 Year Ended September 30
2004 2003 2002 2004 2003 2002
(Thousands)
Change in Benefit Obligation

Benefit Obligation at Beginning of Period $ 694,960 $ 625,470 $ 580,046 $ 467,418 $ 393,851 $ 304,548
Service Cost 14,598 13,043 11,639 6,027 5,844 4,658
Interest Cost 40,565 40,967 40,720 26,393 26,124 21,617
Plan Participants’ Contributions — — — 627 682 610
Amendments — — 420 — — —
Actuarial (Gain) Loss (19,593 ) 51,302 28,880 (62,146 ) 57,983 76,972
Benefits Paid (36,998 ) (35,822 ) (36,235 ) (16,316 ) (17,066 ) (14,554 )

Benefit Obligation at End of Period
$ 693,532 $ 694,960 $ 625,470 $ 422,003 $ 467,418 $ 393,851

Change in Plan Assets

Fair Value of Assets at Beginning of Period $ 491,333 $ 485,927 $ 536,625 $ 166,494 $ 150,293 $ 161,959
Actual Return on Plan Assets 81,946 6,145 (29,898 ) 38,960 390 (18,181 )
Employer Contribution 37,085 35,083 15,435 39,720 32,195 20,459
Plan Participants’ Contributions — — — 627 682 610
Benefits Paid (36,998 ) (35,822 ) (36,235 ) (16,316 ) (17,066 ) (14,554 )

Fair Value of Assets at End of Period
$ 573,366 $ 491,333 $ 485,927 $ 229,485 $ 166,494 $ 150,293

Reconciliation of Funded Status

Funded Status $ (120,166 ) $ (203,627 ) $ (139,543 ) $ (192,518 ) $ (300,924 ) $ (243,558 )
Unrecognized Net Actuarial Loss 159,554 222,250 132,064 108,943 212,242 157,247
Unrecognized Transition (Asset) Obligation — — (3,716 ) 64,144 71,272 78,399
Unrecognized Prior Service Cost 9,171 10,274 11,451 20 26 30

Net Amount Recognized at End of Period $ 48,559 $ 28,897 $ 256 $ (19,411 ) $ (17,384 ) $ (7,882 )

Amounts Recognized in the Balance Sheets Consist of:

Accrued Benefit Liability $ (91,587 ) $ (153,240 ) $ (75,116 ) $ (27,263 )* $ (23,163 )* $ (20,375 )*
Prepaid Benefit Cost 14,536 10,782 10,944 7,852 5,779 12,493
Regulatory Assets 33,904 21,934 — — — —
Intangible Assets 9,171 10,274 11,451 — — —
Accumulated Other Comprehensive Loss (Pre-Tax) 82,535 139,147 52,977 — — —

Net Amount Recognized at End of Period $ 48,559 $ 28,897 $ 256 $ (19,411 ) $ (17,384 ) $ (7,882 )

Weighted Average Assumptions Used to Determine Benefit Obligation at September 30

Discount Rate 6.25 % 6.00 % 6.75 % 6.25 %** 6.00 % 6.75 %
Expected Return on Plan Assets 8.25 % 8.25 % 8.50 % 8.25 % 8.25 % 8.50 %
Rate of Compensation Increase 6.11 % 6.11 % 6.11 % 6.11 % 6.11 % 6.11 %
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

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 ) $ — $ — $ —

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%.

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

Retirement Plan Other Post-Retirement Benefits
Year Ended September 30 Year Ended September 30
2004 2003 2002 2004 2003 2002
(Thousands)
Components of Net Periodic Benefit Cost

Service Cost $ 14,598 $ 13,043 $ 11,639 $ 6,027 $ 5,844 $ 4,658
Interest Cost 40,565 40,967 40,720 26,393 26,124 21,617
Expected Return on Plan Assets (48,281 ) (47,260 ) (48,454 ) (14,898 ) (12,268 ) (13,551 )
Amortization of Prior Service Cost 1,103 1,176 1,205 4 4 4
Amortization of Transition Amount — (3,716 ) (3,716 ) 7,127 7,127 7,127
Recognition of Actuarial (Gain) or Loss 9,438 2,231 (1,061 ) 17,092 14,866 4,289
Net Amortization and Deferral for Regulatory Purposes 722 3,781 7,379 (9,731 ) (15,423 ) (729 )

Net Periodic Benefit Cost $ 18,145 $ 10,222 $ 7,712 $ 32,014 $ 26,274 $ 23,415

Other Comprehensive (Income) Loss (Pre-Tax) Attributable to Change in Additional Minimum Liability Recognition $ (56,612 ) $ 86,170 $ 52,977 $ — $ — $ —

Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30

Discount Rate 6.00 % 6.75 % 7.25 % 6.25 %* 6.75 % 7.25 %
Expected Return on Plan Assets 8.25 % 8.50 % 8.50 % 8.25 % 8.50 % 8.50 %
Rate of Compensation Increase 6.11 % 6.11 % 6.11 % 6.11 % 6.11 % 6.11 %

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

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, 2003~~2005 and ~~2002~~2004 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 of~~At 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:
2004 2003 2002
Projected Benefit Obligation $ 693,532 $ 694,960 $ 625,470
Accumulated Benefit Obligation $ 616,513 $ 611,858 $ 550,099
Fair Value of Plan Assets $ 573,366 $ 491,333 $ 485,927


	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 ~~2005~~2007 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; $42.3~~fiscal 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; $46.2~~and $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 ~~nonqualified~~Non 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 million~~in 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, ~~2004~~2006 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, ~~2004~~2006 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, 2003~~2006, 2005 and ~~2002~~2004, 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, ~~2004~~2006, 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 ~~losses~~loses resulting from experience different from that assumed and from changes in ~~assumptions~~assumption 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 ~~accumulated~~other post-retirement benefit obligation decreased by $42.9 million and the Net Periodic Post-Retirement Benefit Cost

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 )

~~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 Obligation~~other post-retirement benefit obligation by $3.5 million for 2004.

The ~~effects~~estimated 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 million~~subsidy 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% by~~2004. In 2005, the ~~year 2010 and remain level thereafter. The~~Company began making separate estimates of the annual rate of increase ~~for~~in the per capita cost of covered medical care benefits ~~provided by healthcare maintenance organizations~~for 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 2004~~10% 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 ~~2010~~2014. 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 ~~2010~~2014 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 decline~~5.25% 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, ~~2004~~2006 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 ~~2004~~2006 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, ~~2004~~2006 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 ~~2004~~2006 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 ~~2005~~2006 will be in the range of ~~$30.0~~$35.0 million to ~~$40.0~~$45.0 million.

The Company’s ~~retirement plan~~Retirement Plan weighted average asset allocations at September 30, ~~2004, 2003~~2006, 2005 and ~~2002~~2004 by asset category are as follows:
Percentage of Plan
Assets at
September 30
Target Allocation
Asset Category 2005 2004 2003 2002
Equity Securities 60-65% 61 % 53 % 55 %
Fixed Income Securities 25-30% 28 % 32 % 29 %
Other 10-15% 11 % 15 % 16 %

Total 100 % 100 % 100 %


				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 plan~~Post-Retirement Plan weighted average asset allocations at September 30, ~~2004, 2003~~2006, 2005 and ~~2002~~2004 by asset category are as follows:
Percentage of Plan
Assets at
September 30
Target Allocation
Asset Category 2005 2004 2003 2002
Equity Securities 93% 91 % 85 % 90 %
Fixed Income Securities 3% 1 % 1 % 0 %
Other 4% 8 % 14 % 10 %

Total 100 % 100 % 100 %


				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 ~~pension~~Retirement 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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

site. At a second site ~~remediation~~in 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 Company~~remediation 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 ~~has~~and post-remedial construction care and maintenance have been completed at a fifth ~~site; however, post-remedial construction care~~site, and ~~maintenance is ongoing.~~

~~NATIONAL FUEL GAS COMPANY~~the 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 ~~DEC~~Department 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 pipelines~~gas, 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 under~~The 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 ~~contracts~~costs 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 regulatory~~these 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~~

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 ~~six~~five 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~~

~~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

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 subsidiaries~~proceeds, 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
Pipeline Exploration Total Corporate and
and and Energy Reportable Intersegment Total
Utility Storage Production International Marketing Timber Segments All Other Eliminations Consolidated
(Thousands)
Revenue from External Customers $ 1,137,288 $ 122,970 $ 293,698 $ 123,425 $ 284,349 $ 55,968 $ 2,017,698 $ 13,695 $ — $ 2,031,393
Intersegment Revenues $ 15,353 $ 86,737 $ — $ — $ — $ 2 $ 102,092 $ — $ (102,092 ) $ —
Interest Expense $ 21,945 $ 10,933 $ 50,642 $ 7,080 $ 33 $ 2,218 $ 92,851 $ 919 $ (3,180 ) $ 90,590
Depreciation, Depletion and Amortization $ 39,101 $ 37,345 $ 89,943 $ 15,257 $ 102 $ 6,277 $ 188,025 $ 1,071 $ 442 $ 189,538
Income Tax Expense $ 31,393 $ 30,968 $ 28,899 $ (6,137) $ 3,964 $ 3,320 $ 92,407 $ 829 $ (499 ) $ 92,737
Significant Item:
Loss on Sale of Timber Properties $ — $ — $ — $ — $ — $ 1,252 $ 1,252 $ — $ — $ 1,252
Significant Item:
Gain on Sale of Oil and Gas Producing Properties $ — $ — $ 4,645 $ — $ — $ — $ 4,645 $ — $ — $ 4,645
Segment Profit (Loss):
Net Income $ 46,718 $ 47,726 $ 54,344 $ 5,982 $ 5,535 $ 5,637 $ 165,942 $ 1,530 $ (886 ) $ 166,586
Expenditures for Additions to Long-Lived Assets $ 55,449 $ 23,196 $ 77,654 $ 7,498 $ 10 $ 2,823 $ 166,630 $ 200 $ 5,511 $ 172,341
At September 30, 2004

(Thousands)
Segment Assets $ 1,390,361 $ 777,800 $ 1,039,524 $ 268,119 $ 65,971 $ 143,101 $ 3,684,876 $ 73,583 $ (46,661 ) $ 3,711,798

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

At September 30, 2003
(Thousands)
Segment Assets $ 1,411,808 $ 812,846 $ 969,512 $ 247,721 $ 54,134 $ 125,915 $ 3,621,936 $ 77,195 $ 19,929 $ 3,719,060


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

At September 30, 2002
(Thousands)
Segment Assets $ 1,248,426 $ 532,543 $ 1,161,310 $ 241,466 $ 52,850 $ 131,721 $ 3,368,316 $ 33,563 $ (570 ) $ 3,401,309

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

For the Year Ended September 30
Geographic Information 2004 2003 2002
(Thousands)
Revenues from External Customers(1):

United States $ 1,867,335 $ 1,818,980 $ 1,293,239
Czech Republic 123,425 114,070 95,315
Canada 40,633 102,421 75,942

$ 2,031,393 $ 2,035,471 $ 1,464,496

At September 30
(Thousands)
Long-Lived Assets:

United States $ 2,967,277 $ 2,975,329 $ 2,621,001
Czech Republic 228,179 219,695 216,044
Canada 143,042 116,655 258,196

$ 3,338,498 $ 3,311,679 $ 3,095,241

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, ~~2004~~2006 and ~~2003~~2005 is as follows:
At September 30
2004 2003
(Thousands)
ESNE $ 10,045 $ 11,113
Seneca Energy 5,169 4,445
Model City 1,230 867

$ 16,444 $ 16,425


	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 — Acquisitions~~101

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

Cash Paid, Net of Cash Acquired $ 181,152


	~~Condensed Balance Sheet:~~

Property, Plant and Equipment $ 220,792
Current Assets 14,984
Goodwill 5,476
Intangible Assets (see Note K) 8,580
Other Assets 7,565

Total Assets $ 257,397

Equity $ 189,205
Long-Term Debt, Net of Current Portion 48,433

Total Capitalization 237,638
Current Liabilities 15,265
Other Liabilities 4,494

Total Capitalization and Liabilities $ 257,397

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

Assets Acquired $ 48,319
Liabilities Assumed (497 )
Cash Acquired at Acquisition (160 )

Cash Paid, Net of Cash Acquired $ 47,662

Note 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

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

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

At September 30, 2004 At September 30, 2003
Gross Carrying Accumulated Net Carrying
Amount Amortization Amount Net Carrying Amount
Intangible Assets Subject to Amortization
Long-Term Transportation Contracts $ 8,580 $ (1,782 ) $ 6,798 $ 7,867
Long-Term Gas Purchase Contracts 31,864 (1,839 ) 30,025 31,522
Intangible Assets Not Subject to Amortization
Retirement Plan Intangible Asset (see Note F) 9,171 — 9,171 10,275

$ 49,615 $ (3,621 ) $ 45,994 $ 49,664

Aggregate Amortization Expense
For the Year Ended September 30, 2004 $ 2,567
For the Year Ended September 30, 2003 $ 1,054

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 ~~Statement~~Statements of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

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

Net
Income
Available Earnings Per
for Common Share
Operating Operating Common
Quarter Ended Revenues Income Stock Basic Diluted
2004
(Thousands, except per common share amounts)
9/30/2004 $ 278,197 $ 27,675 $ 7,754 $ 0.09 $ 0.09
6/30/2004 $ 419,006 $ 72,324 $ 32,563 ⁽¹⁾ $ 0.40 $ 0.39
3/31/2004 $ 801,677 $ 148,554 $ 77,055 ⁽²⁾ $ 0.94 $ 0.93
12/31/2003 $ 532,513 $ 95,817 $ 49,214 ⁽³⁾ $ 0.60 $ 0.60

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

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 effect~~impairment of ~~change~~oil 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 ~~$0.6~~a 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 effect~~reversal 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 holders~~17,767 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

~~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, ~~2004~~2006 and ~~2003,~~2005, are shown below:

Price Range
Dividends
Quarter Ended High Low Declared
2004

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

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


	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
2004 2003
(Thousands)
Proved Properties(1) $ 1,489,284 $ 1,647,075
Unproved Properties 27,277 30,955

1,516,561 1,678,030
Less — Accumulated Depreciation, Depletion and Amortization 609,469 763,258

$ 907,092 $ 914,772

(1) Includes asset retirement costs of ~~$22.2~~$42.2 million and ~~$18.1~~$30.8 million at September 30, ~~2004~~2006 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, 2004 2004 2003 2002 Prior
(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
2004 2003 2002
(Thousands)
United States

Property Acquisition Costs:
Proved $ (8 ) $ (13 ) $ 9,316
Unproved 3,529 1,920 698
Exploration Costs 10,503 17,947 25,583
Development Costs 31,881 23,649 51,792
Asset Retirement Costs 2,292 242 —

48,197 43,745 87,389
Canada

Property Acquisition Costs:
Proved 29 181 (536 )
Unproved 3,167 6,217 2,804
Exploration Costs 22,624 6,641 8,779
Development Costs 5,500 17,745 15,332
Asset Retirement Costs 1,218 — —

32,538 30,784 26,379
Total

Property Acquisition Costs:(1)
Proved 21 168 8,780
Unproved 6,696 8,137 3,502
Exploration Costs 33,127 24,588 34,362
Development Costs 37,381 41,394 67,124
Asset Retirement Costs 3,510 242 —

$ 80,735 $ 74,529 $ 113,768


	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,
2004 2003 2002
(Thousands, except per Mcfe amounts)
United States

Operating Revenues:
Natural Gas (includes revenues from sales to affiliates of $72, $69 and $43, respectively) $ 151,570 $ 148,104 $ 104,954
Oil, Condensate and Other Liquids 139,301 118,277 101,549

Total Operating Revenues(1) 290,871 266,381 206,503
Production/ Lifting Costs 39,677 39,162 42,956
Accretion Expense 1,756 1,800 —
Depreciation, Depletion and Amortization ($1.41, $1.29 and $1.25 per Mcfe of production) 73,396 70,127 80,142
Income Tax Expense 65,337 62,672 30,253

Results of Operations for Producing Activities (excluding corporate overheads and interest charges) 110,705 92,620 53,152

Canada

Operating Revenues:
Natural Gas 30,359 26,992 14,621
Oil, Condensate and Other Liquids 10,018 62,908 56,511

Total Operating Revenues(1) 40,377 89,900 71,132
Production/ Lifting Costs 8,176 33,038 30,109
Accretion Expense 177 802 —
Depreciation, Depletion and Amortization ($1.83, $1.30 and $0.93 per Mcfe of production) 14,922 26,165 21,707
Impairment of Oil and Gas Producing Properties(2) — 42,774 —
Income Tax Expense (Benefit) 5,235 (3,273 ) 4,672

Results of Operations for Producing Activities (excluding corporate overheads and interest charges) 11,867 (9,606 ) 14,644

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

Year Ended September 30,
2004 2003 2002
(Thousands, except per Mcfe amounts)
Total

Operating Revenues:
Natural Gas (includes revenues from sales to affiliates of $72, $69 and $43, respectively) 181,929 175,096 119,575
Oil, Condensate and Other Liquids 149,319 181,185 158,060

Total Operating Revenues(1) 331,248 356,281 277,635
Production/ Lifting Costs 47,853 72,200 73,065
Accretion Expense 1,933 2,602 —
Depreciation, Depletion and Amortization ($1.47, $1.30 and $1.16 per Mcfe of production) 88,318 96,292 101,849
Impairment of Oil and Gas Producing Properties(2) — 42,774 —
Income Tax Expense 70,572 59,399 34,925

Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 122,572 $ 83,014 $ 67,796

(1) Exclusive of hedging gains and losses. See further discussion in Note EF — Financial ~~Instruments~~Instruments.

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


	*~~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 Coast West Coast Appalachian Total Total
Region Region Region U.S. Canada Company
Proved Developed and Undeveloped Reserves:
September 30, 2001 89,858 98,498 78,457 266,813 55,567 322,380
Extensions and Discoveries 6,530 5,770 4,242 16,542 20,263 36,805
Revisions of Previous Estimates 1,613 (26,063 ) 342 (24,108 ) (20,676 ) (44,784 )
Production (25,776 ) (4,889 ) (4,402 ) (35,067 ) (6,387 ) (41,454 )
Sales of Minerals in Place (14,361 ) — (365 ) (14,726 ) — (14,726 )

September 30, 2002 57,864 73,316 78,274 209,454 48,767 258,221
Extensions and Discoveries 10,538 — 5,844 16,382 11,641 28,023
Revisions of Previous Estimates (2,278 ) 1,213 2,224 1,159 (2,211 ) (1,052 )
Production (18,441 ) (4,467 ) (5,123 ) (28,031 ) (5,774 ) (33,805 )
Sales of Minerals in Place — — — — (270 ) (270 )


	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 Coast West Coast Appalachian Total Total
Region Region Region U.S. Canada Company
September 30, 2003 47,683 70,062 81,219 198,964 52,153 251,117
Extensions and Discoveries �� 2,632 — 3,784 6,416 15,925 22,341
Revisions of Previous Estimates (4,984 ) 1,831 (1,111 ) (4,264 ) (11,004 ) (15,268 )
Production (17,596 ) (4,057 ) (5,132 ) (26,785 ) (6,228 ) (33,013 )
Sales of Minerals in Place (1 ) (392 ) — (393 ) — (393 )

September 30, 2004 27,734 67,444 78,760 173,938 50,846 224,784

Proved Developed Reserves:
September 30, 2001 87,893 47,442 78,457 213,792 53,463 267,255
September 30, 2002 57,274 57,286 78,273 192,833 39,253 232,086
September 30, 2003 45,402 54,180 81,218 180,800 42,745 223,545
September 30, 2004 25,827 53,035 78,760 157,622 46,223 203,845

Oil Mbbl
U.S.
Gulf Coast West Coast Appalachian Total Total
Region Region Region U.S. Canada Company
Proved Developed and Undeveloped Reserves:
September 30, 2001 6,294 68,424 77 74,795 40,533 115,328
Extensions and Discoveries 57 1,360 20 1,437 586 2,023
Revisions of Previous Estimates 781 129 6 916 (10,278 ) (9,362 )
Production (1,815 ) (3,004 ) (9 ) (4,828 ) (2,834 ) (7,662 )
Sales of Minerals in Place (200 ) — — (200 ) (410 ) (610 )

September 30, 2002 5,117 66,909 94 72,120 27,597 99,717
Extensions and Discoveries 104 — 46 150 729 879
Revisions of Previous Estimates (365 ) (185 ) 8 (542 ) (4,119 ) (4,661 )
Production (1,473 ) (2,872 ) (10 ) (4,355 ) (2,382 ) (6,737 )
Sales of Minerals in Place — — — — (19,434 ) (19,434 )

September 30, 2003 3,383 63,852 138 67,373 2,391 69,764
Extensions and Discoveries 19 — 18 37 181 218
Revisions of Previous Estimates 213 (17 ) 11 207 (144 ) 63
Production (1,534 ) (2,650 ) (20 ) (4,204 ) (324 ) (4,528 )
Sales of Minerals in Place (1 ) (303 ) — (304 ) — (304 )

September 30, 2004 2,080 60,882 147 63,109 2,104 65,213

Proved Developed Reserves:
September 30, 2001 6,259 44,304 77 50,640 33,676 84,316
September 30, 2002 5,111 41,735 94 46,940 24,100 71,040
September 30, 2003 2,533 40,079 139 42,751 2,391 45,142
September 30, 2004 2,061 38,631 148 40,840 2,104 42,944

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,
2004 2003 2002
(Thousands)
United States

Future Cash Inflows $ 3,728,168 $ 2,684,286 $ 2,764,556
Less:
Future Production Costs 676,361 579,321 546,182
Future Development Costs 124,298 116,639 117,999
Future Income Tax Expense at Applicable Statutory Rate 995,327 613,893 653,347

Future Net Cash Flows 1,932,182 1,374,433 1,447,028
Less:
10% Annual Discount for Estimated Timing of Cash Flows 996,813 641,185 665,941

Standardized Measure of Discounted Future Net Cash Flows 935,369 733,248 781,087


	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,
2004 2003 2002
(Thousands)
Canada

Future Cash Inflows 343,026 279,772 888,515
Less:
Future Production Costs 111,519 85,817 413,006
Future Development Costs 13,222 9,787 25,398
Future Income Tax Expense at Applicable Statutory Rate 60,610 58,436 101,919

Future Net Cash Flows 157,675 125,732 348,192
Less:
10% Annual Discount for Estimated Timing of Cash Flows 46,945 40,575 103,097

Standardized Measure of Discounted Future Net Cash Flows 110,730 85,157 245,095

Total

Future Cash Inflows 4,071,194 2,964,058 3,653,071
Less:
Future Production Costs 787,880 665,138 959,188
Future Development Costs 137,520 126,426 143,397
Future Income Tax Expense at Applicable Statutory Rate 1,055,937 672,329 755,266

Future Net Cash Flows 2,089,857 1,500,165 1,795,220
Less:
10% Annual Discount for Estimated Timing of Cash Flows 1,043,758 681,760 769,038

Standardized Measure of Discounted Future Net Cash Flows $ 1,046,099 $ 818,405 $ 1,026,182

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,
2004 2003 2002
(Thousands)
United States

Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 733,248 $ 781,087 $ 605,350
Sales, Net of Production Costs (251,194 ) (227,219 ) (163,548 )
Net Changes in Prices, Net of Production Costs 592,326 11,130 441,085
Purchases of Minerals in Place — — —
Sales of Minerals in Place (5,554 ) — (27,197 )
Extensions and Discoveries 16,638 29,266 42,970
Changes in Estimated Future Development Costs (40,042 ) (35,062 ) (42,069 )
Previously Estimated Development Costs Incurred 32,653 36,423 45,310
Net Change in Income Taxes at Applicable Statutory Rate (166,055 ) 24,796 (126,263 )
Revisions of Previous Quantity Estimates (5,107 ) (3,572 ) (32,646 )
Accretion of Discount and Other 28,456 116,399 38,095

Standardized Measure of Discounted Future Net Cash Flows at End of Year 935,369 733,248 781,087

Canada

Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year 85,157 245,095 181,439
Sales, Net of Production Costs (32,201 ) (56,862 ) (41,023 )
Net Changes in Prices, Net of Production Costs 29,230 8,167 111,148
Purchases of Minerals in Place — — —
Sales of Minerals in Place — (120,960 ) (3,084 )
Extensions and Discoveries 36,986 28,241 29,813
Changes in Estimated Future Development Costs (8,491 ) (14,045 ) 18,151
Previously Estimated Development Costs Incurred 5,055 29,657 12,361
Net Change in Income Taxes at Applicable Statutory Rate (2,640 ) (6,280 ) (6,910 )
Revisions of Previous Quantity Estimates (19,369 ) (41,205 ) (88,571 )
Accretion of Discount and Other 17,003 13,349 31,771

Standardized Measure of Discounted Future Net Cash Flows at End of Year 110,730 85,157 245,095


	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,
2004 2003 2002
(Thousands)
Total

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

Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,046,099 $ 818,405 $ 1,026,182

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
Additions Additions
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts(1) Deductions(2) Period
(Thousands)
Year Ended September 30, 2004

Reserve for Doubtful Accounts $ 17,943 $ 20,328 $ — $ 20,831 $ 17,440
Deferred Tax Valuation Allowance $ 6,357 $ (3,480 ) $ — $ — $ 2,877

Year Ended September 30, 2003

Reserve for Doubtful Accounts $ 17,299 $ 17,275 $ — $ 16,631 $ 17,943
Deferred Tax Valuation Allowance $ — $ 6,357 $ — $ — $ 6,357

Year Ended September 30, 2002

Reserve for Doubtful Accounts $ 18,521 $ 16,082 $ 2,834 $ 20,138 $ 17,299


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

None


Item 9A	*Controls and Procedures*

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

Evaluation of Disclosure Controls and Procedures

The term “disclosure controls and procedures” is defined 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 ~~Treasurer~~Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of ~~the end~~September 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 of~~is responsible for establishing and maintaining adequate internal control over financial reporting ~~that~~as 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 ~~that~~regarding 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 preparation~~effectiveness 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 report~~quarter 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 9B	*Other Information*

None

PART III


Item 10	*Directors and Executive Officers of the Registrant*

The information required by this item concerning the directors of the Company is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its February ~~17, 2005~~15, 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 ~~captions~~headings 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 11	*Executive 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, 2005~~15, 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 ~~captions~~headings “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and, excepting the “Report of the Compensation Committee” and the “Corporate Performance Graph,” is incorporated herein by reference.


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

Equity Compensation Plan Information

The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its February ~~17, 2005~~15, 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 ~~caption~~heading “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, 2005~~15, 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 ~~caption~~heading “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, 2005~~15, 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 ~~caption~~heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.

115


*(c)*	*Changes in Control*

None


Item 13	*Certain 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, 2005~~15, 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 ~~caption~~heading “Compensation Committee Interlocks and Insider Participation” and is incorporated herein by reference.


Item 14	*Principal Accountant Fees and Services*

The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its February ~~17, 2005~~15, 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 ~~caption~~heading “Audit Fees” and is incorporated herein by reference.

PART IV


Item 15	*Exhibits and Financial Statement Schedules*

(a)1. Financial Statements

Financial statements filed as part of this report are listed in the index included in Item 8 of 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
~~Number~~		Description 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~~
~~Number~~		~~Description of Exhibits~~

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

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:
	•	~~Credit~~Form of Indemnification Agreement, dated ~~as of~~ September ~~30, 2002, among~~2006, between the Company ~~the Lenders~~ and ~~JPMorgan Chase Bank~~each Director (Exhibit 10.1,Form ~~10-K for fiscal year ended~~8-K dated September ~~30, 2002~~18, 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, 2003~~N.A., as Administrative Agent (Exhibit 10.1,Form 10-K for fiscal year ended September 30, ~~2003~~2005 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~~
~~Number~~		~~Description of Exhibits~~

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

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, 2001~~September 8, 2005 (Exhibit ~~10.2,~~ 10.3,Form 10-K for fiscal year ended September 30, ~~2001~~2005 in File No. 1-3880)
	•	~~Amendment to~~Form of Award Notice under National Fuel Gas Company ~~Deferred Compensation~~1997 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, 2001~~March 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-K~~Form10-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-K~~Form10-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 Agreement~~Internal Revenue Code Section 409A, dated ~~January 9, 1998~~July 12, 2005 (Exhibit ~~10.1,~~ 10.7,Form ~~10-Q~~10-K for ~~the quarterly period~~fiscal year ended ~~June~~September 30, ~~2000~~2005 in File No. 1-3880)
	•	~~Contingent Benefit Agreement effective June 15, 2000, between the~~National Fuel Gas Company Tophat Plan, Amended and ~~Bernard J. Kennedy~~Restated December 7, 2005 (Exhibit ~~10.2,~~ 10.1,Form 10-Q for the quarterly period ended ~~June 30, 2000~~December 31, 2005 in File No. ~~1-3880~~

~~104~~

Exhibit
Number Description of Exhibits
• Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 17, 1997 between the Company and Philip C. Ackerman (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
• Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Philip C. Ackerman, dated March 23, 1999 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and Joseph P. Pawlowski (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
• Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Joseph P. Pawlowski, dated March 23, 1999 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and Dennis J. Seeley (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Dennis J. Seeley, dated March 29, 1999 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997, between the Company and Bruce H. Hale (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and Bruce H. Hale, dated March 29, 1999 (Exhibit 10.12, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and David F. Smith (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
10 .1 National Fuel Gas Company Parameters for Executive Life Insurance Plan
• National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880)
10 .2 National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement (I), dated September 1, 2003
• National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
• Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated September 18, 1997 (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
• Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated December 10, 1998 (Exhibit 10.2, Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880)
• Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16, 1999 (Exhibit 10.15, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)

~~105~~

Exhibit
Number Description of Exhibits
• Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 5, 2001 (Exhibit 10.4, Form 10-K/A for fiscal year ended September 30, 2001, in File No. 1-3880)
• Retirement Supplement Agreement, dated January 11, 2002, between the Company and Joseph P. Pawlowski (Exhibit 10.6, Form 10-K/A for fiscal year ended September 30, 2001 in File No. 1-3880)
• Amendment No. 1 to Retirement Supplement Agreement, dated March 11, 2004, between the Company and Joseph P. Pawlowski (Exhibit 10(iii), Form 10-Q for the quarterly period ended March 31, 2004 in File No. 1-3880)
• Administrative Rules with Respect to At Risk Awards under the 1993 Award and Option Plan (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
• Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan (Exhibit A, Definitive Proxy Statement, Schedule 14(A) filed January 10, 2002 in File No. 1-3880)
10 .3 Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated, effective September 9, 2004
• Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
10 .4 Retirement and Consulting Agreement, dated September 5, 2001, between the Company and Bernard J. Kennedy
(12 ) Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 1998 through 2003
(21 ) Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report on Form 10-K
(23 ) Consents of Experts:
23 .1 Consent of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation
23 .2 Consent of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc.
23 .3 Consent of Independent Accountants
(31 ) Rule 13a-15(e)/15d-15(e) Certifications
31 .1 Written statements of Chief Executive Officer pursuant to Rule 13a-15(e)/15d-15(e) of the Exchange Act.
31 .2 Written statements of Principal Financial Officer pursuant to Rule 13a-15(e)/15d-15(e) of the Exchange Act.
(32 ) Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(99 ) Additional Exhibits:
99 .1 Report of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation
99 .2 Report of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc.
99 .3 Company Maps
• The Company agrees to furnish to the SEC upon request the following instruments with respect to long-term debt that the Company has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(ii)(A):
Secured Credit Agreement, dated as of June 5, 1997, among the Empire State Pipeline, as borrower, Empire State Pipeline, Inc., the Lenders party thereto, JPMorgan Chase Bank (f/k/a The Chase Manhattan Bank), as administrative agent, and Chase Securities, as arranger.
First Amendment to Secured Credit Agreement, dated as of May 28, 2002, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, and JPMorgan Chase Bank, as administrative agent.
Second Amendment to Secured Credit Agreement, dated as of February 6, 2003, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, as amended, and JPMorgan Chase Bank, as administrative agent.

~~106~~


~~Exhibit~~1-3880)
~~Number~~		~~Description 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 or~~•	Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the ~~required information is shown elsewhere~~Company 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

~~SIGNATURES~~Signatures

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

~~NATIONAL FUEL GAS COMPANY~~
~~(REGISTRANT)~~

National Fuel Gas Company
(Registrant)


	By	/s/ P. C. ~~ACKERMAN~~Ackerman



	~~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
~~Signature~~Title		~~Title~~	~~Date~~


/s/ P. C. ~~ACKERMAN~~ Ackerman P. C. Ackerman	Chairman of the Board, ~~President,~~ Chief Executive Officer and Director	Date: December ~~9, 2004~~7, 2006

/s/ R. T. ~~BRADY~~ Brady R. T. Brady	Director	Date: December ~~9, 2004~~7, 2006

/s/ R. D. ~~CASH~~ Cash R. D. Cash	Director	Date: December ~~9, 2004~~7, 2006

/s/ R. E. ~~KIDDER~~ Kidder R. E. Kidder	Director	Date: December ~~9, 2004~~7, 2006

/s/ ~~B. S. LEE~~ ~~B. S. Lee~~C. G. Matthews C. G. Matthews	Director	Date: December ~~9, 2004~~7 2006

/s/ G. L. ~~MAZANEC~~ Mazanec G. L. Mazanec	Director	Date: December ~~9, 2004~~7, 2006

/s/ R. G. Reiten R. G. Reiten	Director	Date: December 7, 2006

/s/ J. F. ~~RIORDAN~~ Riordan J. F. Riordan	Director	Date: December ~~9, 2004~~7, 2006

/s/ R. J. ~~TANSKI~~ Tanski R. J. Tanski	Treasurer and Principal Financial Officer	Date: December ~~9, 2004~~7, 2006

/s/ K. M. ~~CAMIOLO~~ Camiolo K. M. Camiolo	Controller and Principal Accounting Officer	Date: December ~~9, 2004~~7, 2006

122

~~108~~


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)


		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


						Page



~~PART~~Part I
	ITEM 1			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 OPERATIONS~~	All Other Category and Corporate Operations		7
		~~SOURCES AND AVAILABILITY OF RAW MATERIALS~~		Discontinued Operations		7
		~~COMPETITION~~			8
Sources and Availability of Raw Materials		~~SEASONALITY~~7
				Competition		7
				Seasonality		9
		~~CAPITAL EXPENDITURES~~		Capital Expenditures		10
		~~ENVIRONMENTAL MATTERS~~		Environmental Matters		10
		~~MISCELLANEOUS~~		Miscellaneous		10
		~~EXECUTIVE OFFICERS OF THE COMPANY~~			11
~~ITEM 2~~Executive Officers of the Company		~~PROPERTIES~~10
	ITEM 1A			RISK FACTORS		12
	ITEM 1B			~~GENERAL INFORMATION ON FACILITIES~~UNRESOLVED STAFF COMMENTS			12	17
	ITEM 2			~~EXPLORATION AND PRODUCTION ACTIVITIES~~PROPERTIES		17
12				General Information on Facilities		17
				Exploration and Production Activities		18
	ITEM 3			LEGAL PROCEEDINGS			16	21
	ITEM 4			SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			17	22

Part II
	ITEM 5
~~PART II~~
~~ITEM 5~~		MARKET FOR THE REGISTRANT’S COMMON EQUITY, ~~AND~~ RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES			17	22
	ITEM 6			SELECTED FINANCIAL DATA			18	23
	ITEM 7			MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			19	25
	ITEM 7A			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			50	59
	ITEM 8			FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			51	60
	ITEM 9			CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			~~100~~	114
	ITEM 9A			CONTROLS AND PROCEDURES			~~100~~	114
	ITEM 9B			OTHER INFORMATION			~~101~~	114



		For the Year Ended
		September 30

		2004		2003		2002

United States
Gulf Coast Region
	Average Sales Price per Mcf of Gas	$	5.61	$	5.41	$	2.89
	Average Sales Price per Barrel of Oil	$	35.31	$	29.17	$	22.83
	Average Sales Price per Mcf of Gas (after hedging)	$	4.78	$	4.22	$	3.69
	Average Sales Price per Barrel of Oil (after hedging)	$	31.51	$	27.88	$	22.51
	Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	$	0.60	$	0.56	$	0.60
	Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)		73		75		100
West Coast Region
	Average Sales Price per Mcf of Gas	$	5.54	$	5.01	$	2.86
	Average Sales Price per Barrel of Oil	$	31.89	$	26.12	$	19.94
	Average Sales Price per Mcf of Gas (after hedging)	$	5.72	$	5.12	$	2.86
	Average Sales Price per Barrel of Oil (after hedging)	$	22.86	$	23.67	$	20.09
	Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	$	1.05	$	1.00	$	0.81
	Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)		55		59		63
Appalachian Region
	Average Sales Price per Mcf of Gas	$	5.91	$	5.07	$	3.74
	Average Sales Price per Barrel of Oil	$	31.30	$	28.77	$	23.76
	Average Sales Price per Mcf of Gas (after hedging)	$	5.72	$	5.10	$	3.74
	Average Sales Price per Barrel of Oil (after hedging)	$	31.30	$	28.77	$	23.76
	Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	$	0.54	$	0.43	$	0.53
	Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)		14		14		12



	Canada				Total Company

At September 30, 2004	Gas		Oil		Gas		Oil

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



			Productive						Dry

For the Year Ended September 30			2004		2003		2002		2004		2003		2002

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


					Total Number of
					Shares Purchased		Maximum Number of
					as Part of Publicly		Shares that May Yet
	Total Number of				Announced Share		Be Purchased Under
	Shares		Average Price		Repurchase Plans		Share Repurchase
Period	Purchased(a)		Paid per Share		or Programs		Plans or Programs

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

Total		311,325	$	27.43		—		—


	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 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.~~



						Percent (Warmer)
						Colder Than

Year Ended September 30		Normal		Actual		Normal			Prior Year

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


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


	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,

	2005		2006		2007


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

	$	191.0	$	192.0	$	192.0


	þ	ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d)


	o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)


	~~OF THE SECURITIES EXCHANGE ACT OF 1934~~


	*Regulatory Agencies*



		Payments by Expected Maturity Dates

		2005		2006		2007		2008		2009		Thereafter		Total


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



	Expected Maturity Dates

	2005		2006		2007		2008		2009		Total

Notional Quantities (Equivalent Bcf)		11.3		8.4		1.8		1.2		0.3		23.0
Weighted Average Fixed Rate (per Mcf)	$	5.47	$	5.68	$	5.02	$	4.80	$	4.81	$	5.47
Weighted Average Variable Rate (per Mcf)	$	7.12	$	6.74	$	6.13	$	5.58	$	5.50	$	6.81


~~(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.~~


	~~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;


	~~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.



			At September 30,

			2004			2003


			(Thousands of dollars)
ASSETS
Property, Plant and Equipment			$	4,602,779		$	4,657,343
	Less — Accumulated Depreciation, Depletion and Amortization			1,596,015			1,666,295

				3,006,764			2,991,048

Current Assets
	Cash and Temporary Cash Investments			66,153			51,421
	Receivables — Net of Allowance for Uncollectible Accounts of $17,440 and $17,943, Respectively			129,825			136,604
	Unbilled Utility Revenue			18,574			20,155
	Gas Stored Underground			68,511			89,640
	Materials and Supplies — at average cost			43,922			32,311
	Unrecovered Purchased Gas Costs			7,532			28,692
	Prepayments			38,760			46,860
	Fair Value of Derivative Financial Instruments			23			1,698

				373,300			407,381

Other Assets
	Recoverable Future Taxes			83,847			84,818
	Unamortized Debt Expense			19,573			22,119
	Other Regulatory Assets			66,862			52,381
	Deferred Charges			3,411			7,528
	Other Investments			72,556			64,025
	Investments in Unconsolidated Subsidiaries			16,444			16,425
	Goodwill			5,476			5,476
	Intangible Assets			45,994			49,664
	Other			17,571			18,195

				331,734			320,631

Total Assets			$	3,711,798		$	3,719,060

CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
	Common Stock, $1 Par Value Authorized — 200,000,000 Shares; Issued and Outstanding — 82,990,340 Shares and 81,438,290 Shares, Respectively		$	82,990		$	81,438
	Paid In Capital			506,560			478,799
	Earnings Reinvested in the Business			718,926			642,690

Total Common Shareholder Equity Before Items
		Of Other Comprehensive Loss		1,308,476			1,202,927
	Accumulated Other Comprehensive Loss			(54,775	)		(65,537	)

Total Comprehensive Shareholders’ Equity				1,253,701			1,137,390
Long-Term Debt, Net of Current Portion				1,133,317			1,147,779

Total Capitalization				2,387,018			2,285,169

Minority Interest in Foreign Subsidiaries				37,048			33,281

Current and Accrued Liabilities
	Notes Payable to Banks and Commercial Paper			156,800			118,200
	Current Portion of Long-Term Debt			14,260			241,731
	Accounts Payable			115,979			118,563
	Amounts Payable to Customers			3,154			692
	Other Accruals and Current Liabilities			91,164			52,851
	Fair Value of Derivative Financial Instruments			95,099			17,928

				476,456			549,965

Deferred Credits
	Accumulated Deferred Income Taxes			458,095			423,282
	Taxes Refundable to Customers			11,065			13,519
	Unamortized Investment Tax Credit			7,498			8,199
	Cost of Removal Regulatory Liability			82,020			76,782
	Other Regulatory Liabilities			67,669			72,632
	Pension Liability			91,587			153,240
	Asset Retirement Obligation			32,292			27,493
	Other Deferred Credits			61,050			75,498

				811,276			850,645

Commitments and Contingencies				—			—

Total Capitalization and Liabilities			$	3,711,798		$	3,719,060



	As of September 30

	2004		2003


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

	$	4,397,519	$	4,376,175



		At September 30

		2004		2003


		(Thousands)
Regulatory Assets(1):
Recoverable Future Taxes (Note C)		$	83,847	$	84,818
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A)			7,532		28,692
Unamortized Debt Expense (Note A)			9,882		11,364
Pension and Post-Retirement Benefit Costs (2)(Note F)			62,664		47,750
Other(2)			4,198		4,631

	Total Regulatory Assets		168,123		177,255

Regulatory Liabilities:
Cost of Removal Regulatory Liability (See Cumulative Effect Discussion in Note A)			82,020		76,782
Amounts Payable to Customers (See Regulatory Mechanisms in Note A)			3,154		692
New York Rate Settlements(3)			26,048		30,900
Taxes Refundable to Customers (Note C)			11,065		13,519
Pension and Post-Retirement Benefit Costs(3) (Note F)			13,232		23,719
Other(3)			28,389		18,013

	Total Regulatory Liabilities		163,908		163,625

Net Regulatory Position		$	4,215	$	13,630


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


	(Thousands, except per share amounts)
Balance at September 30, 2001		79,406		$	79,406		$	430,618		$	513,488		$	(20,857	)
Net Income Available for Common Stock											117,682
Dividends Declared on Common Stock ($1.03 Per Share)											(81,773	)
Other Comprehensive Loss, Net of Tax														(48,779	)
Common Stock Issued Under Stock and Benefit Plans		859			859			16,214

Balance at September 30, 2002		80,265			80,265			446,832			549,397			(69,636	)
Net Income Available for Common Stock											178,944
Dividends Declared on Common Stock ($1.06 Per Share)											(85,651	)
Other Comprehensive Income, Net of Tax														4,099
Cancellation of Shares		(3	)		(3	)		(63	)
Common Stock Issued Under Stock and Benefit Plans		1,176			1,176			32,030

Balance at September 30, 2003		81,438			81,438			478,799			642,690			(65,537	)
Net Income Available for Common Stock											166,586
Dividends Declared on Common Stock ($1.10 Per Share)											(90,350	)
Other Comprehensive Income, Net of Tax														10,762
Common Stock Issued Under Stock and Benefit Plans		1,552			1,552			27,761

Balance at September 30, 2004		82,990		$	82,990		$	506,560		$	718,926	⁽¹⁾	$	(54,775	)


(1)		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, $644.5~~2006, $692.7 million of accumulated earnings was free of such limitations.



	Options Outstanding						Options Exercisable

			Weighted
	Number		Average		Weighted		Number		Weighted
	Outstanding		Remaining		Average		Exercisable		Average
Range of Exercise Price	at 9/30/04		Contractual Life		Exercise Price		at 9/30/04		Exercise Price

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


	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.



		Retirement Plan									Other Post-Retirement Benefits


		Year Ended September 30									Year Ended September 30

		2004			2003			2002			2004			2003			2002


		(Thousands)
Change in Benefit Obligation
Benefit Obligation at Beginning of Period		$	694,960		$	625,470		$	580,046		$	467,418		$	393,851		$	304,548
Service Cost			14,598			13,043			11,639			6,027			5,844			4,658
Interest Cost			40,565			40,967			40,720			26,393			26,124			21,617
Plan Participants’ Contributions			—			—			—			627			682			610
Amendments			—			—			420			—			—			—
Actuarial (Gain) Loss			(19,593	)		51,302			28,880			(62,146	)		57,983			76,972
Benefits Paid			(36,998	)		(35,822	)		(36,235	)		(16,316	)		(17,066	)		(14,554	)

Benefit Obligation at End of Period		$	693,532		$	694,960		$	625,470		$	422,003		$	467,418		$	393,851

Change in Plan Assets
Fair Value of Assets at Beginning of Period		$	491,333		$	485,927		$	536,625		$	166,494		$	150,293		$	161,959
Actual Return on Plan Assets			81,946			6,145			(29,898	)		38,960			390			(18,181	)
Employer Contribution			37,085			35,083			15,435			39,720			32,195			20,459
Plan Participants’ Contributions			—			—			—			627			682			610
Benefits Paid			(36,998	)		(35,822	)		(36,235	)		(16,316	)		(17,066	)		(14,554	)

Fair Value of Assets at End of Period		$	573,366		$	491,333		$	485,927		$	229,485		$	166,494		$	150,293

Reconciliation of Funded Status
Funded Status		$	(120,166	)	$	(203,627	)	$	(139,543	)	$	(192,518	)	$	(300,924	)	$	(243,558	)
Unrecognized Net Actuarial Loss			159,554			222,250			132,064			108,943			212,242			157,247
Unrecognized Transition (Asset) Obligation			—			—			(3,716	)		64,144			71,272			78,399
Unrecognized Prior Service Cost			9,171			10,274			11,451			20			26			30

Net Amount Recognized at End of Period		$	48,559		$	28,897		$	256		$	(19,411	)	$	(17,384	)	$	(7,882	)

Amounts Recognized in the Balance Sheets Consist of:
	Accrued Benefit Liability	$	(91,587	)	$	(153,240	)	$	(75,116	)	$	(27,263	)*	$	(23,163	)*	$	(20,375	)*
	Prepaid Benefit Cost		14,536			10,782			10,944			7,852			5,779			12,493
	Regulatory Assets		33,904			21,934			—			—			—			—
	Intangible Assets		9,171			10,274			11,451			—			—			—
	Accumulated Other Comprehensive Loss (Pre-Tax)		82,535			139,147			52,977			—			—			—

Net Amount Recognized at End of Period		$	48,559		$	28,897		$	256		$	(19,411	)	$	(17,384	)	$	(7,882	)

Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
Discount Rate			6.25	%		6.00	%		6.75	%		6.25	%**		6.00	%		6.75	%
Expected Return on Plan Assets			8.25	%		8.25	%		8.50	%		8.25	%		8.25	%		8.50	%
Rate of Compensation Increase			6.11	%		6.11	%		6.11	%		6.11	%		6.11	%		6.11	%


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


	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	)


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	)



			Percentage of Plan
			Assets at
			September 30
	Target Allocation
Asset Category	2005		2004			2003			2002

Equity Securities		60-65%		61	%		53	%		55	%
Fixed Income Securities		25-30%		28	%		32	%		29	%
Other		10-15%		11	%		15	%		16	%

Total				100	%		100	%		100	%


		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



	Year Ended September 30, 2003

			Pipeline		Exploration										Total					Corporate and
			and		and						Energy				Reportable					Intersegment			Total
	Utility		Storage		Production			International			Marketing		Timber		Segments		All Other			Eliminations			Consolidated


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

	At September 30, 2003

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