8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

November 16, 2005

Date of Report (Date of earliest event reported):

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

New Jersey	1-3880	13-1086010
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer or Identification No.)

6363 Main Street,
Williamsville,
New York 14221

(Address of principal executive offices)(Zip Code)

(716) 857-7000

Registrant’s telephone number, including area code:

     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

TABLE OF CONTENTS

EX-99 Slide Presentation Given By The Company

Item 7.01 Regulation FD Disclosure

     National Fuel Gas Company (the “Company”) will be making presentations to financial analysts and/or Company shareholders on Wednesday, November 16, 2005 and Thursday, November 17, 2005. A copy of the slide presentation is hereby incorporated by reference into this Item 7.01 and furnished as part of this Current Report as Exhibit 99.

     Neither the furnishing of the slide presentation as an exhibit to this Current Report nor the inclusion in such presentation of any reference to the Company’s internet address shall, under any circumstances, be deemed to incorporate the information available at such internet address into this Current Report. The information available at the Company’s internet address is not part of this Current Report or any other report filed or furnished by the Company with the Securities and Exchange Commission.

     In addition to financial measures calculated in accordance with generally accepted accounting principles (“GAAP”), the slide presentation furnished as part of this Current Report as Exhibit 99 contains certain non-GAAP financial measures. The Company believes that such non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s operating results in a manner that is focused on the performance of the Company’s ongoing operations. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be considered a substitute for financial measures prepared in accordance with GAAP.

     Certain statements contained herein or incorporated by reference from the slide presentation, including statements regarding earnings projections, statements designated with an asterisk (“*”) and statements identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions, are “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. There is no assurance that the Company’s projections will in fact be achieved nor do these projections reflect any acquisitions or divestitures that may occur during fiscal 2006. While the Company’s expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis, actual results may differ materially from those in the forward-looking statement. Furthermore, each forward-looking statement speaks only as of the date on which it is made. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: changes in economic conditions, including economic disruptions caused by terrorist activities or acts of war; changes in demographic patterns or weather conditions, including the occurrence of severe weather; changes from expectations with respect to the extent of damage caused by recent hurricanes or the amount of time necessary for repairs to be made to the Company’s exploration and production facilities or those of third parties; disputes with insurance providers; increasing costs of insurance, changes in coverage and the ability to obtain insurance; changes in the availability and/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; impairments under the Securities and Exchange Commission’s full cost ceiling test for natural gas and oil reserves; changes in the availability and/or price of derivative financial

instruments; changes in the price differentials between various types of oil; failure of the price differential between heavy sour crude oil and light sweet crude oil to return to its historical norm; inability to obtain new customers or retain existing ones; significant changes in competitive factors affecting the Company; governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; unanticipated impacts of restructuring initiatives in the natural gas and electric industries; significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs; the nature and projected profitability of pending and potential projects and other investments; occurrences affecting the Company’s ability to obtain funds from operations, debt or equity to finance needed capital expenditures and other investments, including any downgrades in the Company’s credit ratings; uncertainty of oil and gas reserve estimates; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; ability to successfully identify, drill for and produce economically viable natural gas and oil reserves; significant changes from expectations in the Company’s actual production levels for natural gas or oil; 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; significant changes in tax rates or policies or in rates of inflation or interest; 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; changes in accounting principles or the application of such principles to the Company; changes in laws and regulations to which the Company is subject, including tax, environmental, safety and employment laws and regulations; the cost and effects of legal and administrative claims against the Company; changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefits; or increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide post-retirement benefits. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

Item 9.01 Financial Statements and Exhibits

     (c) Exhibits

Exhibit 99	Slide presentation to be given by the Company on
	November 16, 2005 and November 17, 2005

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	NATIONAL FUEL GAS COMPANY
Date: November 16, 2005	By:	/s/ J. R. Peterson
		J. R. Peterson
		Assistant Secretary

EXHIBIT INDEX

Exhibit Number	Description
99	Slide presentation to be given by the Company
	on November 16, 2005 and November 17, 2005

EX-99

National Fuel Gas Company Philip C. Ackerman Chairman, President & CEO

National Fuel Gas Company Philip C. Ackerman Chairman, President & CEO

Safe Harbor NOTE: This presentation contains certain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements include, but are not limited to, statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements that are not statements of historical fact, and statements identified by words such as "anticipates," "estimates," "expects," "intends," "plans, " "predicts, " " projects, " and similar expressions. While National Fuel's expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. You may refer to National Fuel's most recent Form 10-Q for a listing of important risk factors you should consider. In addition, this presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided at the end of this presentation.

70 0.19 71 0.2 72 0.205 73 0.215 74 0.225 75 0.235 76 0.245 77 0.255 78 0.27 79 0.2875 80 0.3075 81 0.33 82 0.36 83 0.39 84 0.47 85 0.52 86 0.57 87 0.6 88 0.63 89 0.67 90 0.71 91 0.73 92 0.75 93 0.77 94 0.79 95 0.81 96 0.84 97 0.87 98 0.9 99 0.93 '00 0.96 '01 1.01 '02 1.04 '03 1.08 '04 1.12 '05 1.16 National Fuel Gas Company Dividend Growth $0.19 $1.16 Annual Rate At Fiscal Year End

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006E $2.89 B At Fiscal Year End Net Plant by Segment (in Millions)

1999 2000 2001 2002 2003 2004 2005 2006E Utility 47 55.8 42.4 51.5 49.9 55.5 50.1 56 P & S 34.9 35.8 26 30.3 199.4 23.2 21.1 35 E & P 97.6 280.1 296.4 114.6 75.8 77.7 121.2 115 Energy Mkt. 0.302 0.089 0.116 0.1 0.2 0.0102 0 0 Timber 52.3 13.5 3.7 25.6 3.5 2.8 18.9 1 Corp & Others 0.066 3.7 0.937 6.6 50.1 5.7 1.1 1 International 33.4 9.8 15.6 4.2 2.5 7.5 5.9 0 $398.8 $385.1 $ Millions $232.9 $381.4 $172.3 $218.3 Fiscal Year National Fuel Gas Company Expenditures for Long-Lived Assets Approx. $208

2001 2002 2003 2004 2005 2006E 2.05 1.58 1.89 1.98 2.15 2.4 Fiscal Year National Fuel Gas Company Diluted Earnings per Share* * Excludes special items

2001 2002 2003 2004 2005 CFPS -1.15 1.24 2.67 1.84 2.4 Fiscal Year National Fuel Gas Company Free Cash Flow per Diluted Share

National Fuel Gas Company Net Plant by Segment $2,840 Million At September 30, 2005 Utility P&S E&P All Other Net plant 1064.6 680.6 974.8 119.3

National Fuel Gas Company FY 2006 Est. Diluted EPS by Segment $2.30 - $2.50 Fiscal 2006 Estimated Range Utility P&S E&P All Other Net plant 0.555 0.615 1.15 0.08

Fiscal Year 1999 2000 2001 2002 2003 2004 2005 2006E Earnings 0.51 0.4 0.76 0.62 0.7 0.59 0.46 0.555 a Excludes SFAS 88 settlement loss of -$0.03 a Fiscal Year Utility Diluted Earnings per Share

1997 1998 1999 2000 2001 2002 2003 2004 2005 Utility 182 173 172 169 179 191 211 Utility O & M Expense * Excludes SFAS 88 settlement loss of -$3.4 million Fiscal Year $ Millions *

At 09/30/02 At 09/30/03 At 09/30/04 At 09/30/05 30-59 days 5.4 7.87 8.27 8.97 60-89 days 3.66 5.59 5.95 6.47 90-119 days 3.4 5.84 5.38 6.3 120 days & over 28.97 43.81 48.41 54.45 Reserve for Bad Debt 13.3 12.67 12.9 25.1 Utility Aged Accounts Receivable $ Millions

New York Merchant Function Charge Varies with Cost of Gas Rates Include Allowance Attributable to Uncollectible Expense Residential Non-Residential 2.742% .304% Multiplied by Gas Supply Cost Rate Utility Bad Debt Tracking

'72 '73 '74 '75 '76 '77 '78 '79 '80 '81 '82 '83 '84 '85 '86 '87 '88 '89 '90 '91 '92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 182.96 180.205 173.305 173.431 170.237 164.955 156.044 156.898 152.605 153.207 145.597 132.388 134.153 131.672 132.194 131.12 135.531 132.77 130.829 133.551 128.393 127.036 128.857 123.223 124.975 124.137 119.631 116.131 118.369 116.198 114.23 115.627 113.961 107.989 (New York) Fiscal Year Utility Average Use Per Residential Customers (1972 - 2005) Mcf

1/1/1995 2/1/1995 3/1/1995 4/1/1995 5/1/1995 6/1/1995 7/1/1995 8/1/1995 9/1/1995 10/1/1995 11/1/1995 12/1/1995 1/1/1996 2/1/1996 3/1/1996 4/1/1996 5/1/1996 6/1/1996 7/1/1996 8/1/1996 9/1/1996 10/1/1996 11/1/1996 12/1/1996 1/1/1997 2/1/1997 3/1/1997 4/1/1997 5/1/1997 6/1/1997 7/1/1997 8/1/1997 9/1/1997 10/1/1997 11/1/1997 12/1/1997 1/1/1998 2/1/1998 3/1/1998 4/1/1998 5/1/1998 6/1/1998 7/1/1998 8/1/1998 9/1/1998 10/1/1998 11/1/1998 12/1/1998 1/1/1999 2/1/1999 3/1/1999 4/1/1999 5/1/1999 6/1/1999 7/1/1999 8/1/1999 9/1/1999 10/1/1999 11/1/1999 12/1/1999 1/1/2000 2/1/2000 3/1/2000 4/1/2000 5/1/2000 6/1/2000 7/1/2000 8/1/2000 9/1/2000 10/1/2000 11/1/2000 12/1/2000 1/1/2001 2/1/2001 3/1/2001 4/1/2001 5/1/2001 6/1/2001 7/1/2001 8/1/2001 9/1/2001 10/1/2001 11/1/2001 12/1/2001 1/1/2002 2/1/2002 3/1/2002 4/1/2002 5/1/2002 6/1/2002 7/1/2002 8/1/2002 9/1/2002 10/1/2002 11/1/2002 12/1/2002 1/1/2003 2/1/2003 3/1/2003 6.44 6.07 6.21 6.38 6.68 6.51 6.34 6.14 6.33 6.55 6.75 7.41 8.14 7.22 7.66 7.7 7.27 7.47 7.67 7.33 6.67 6.76 7.77 9.25 9.47 8.04 6.65 6.74 7.27 7.55 7.52 7.48 7.77 8.82 8.99 7.8 7.51 7.22 7.33 7.32 7.54 7.3 7.73 7.19 7.15 7.27 7.41 7.47 7.32 7.19 7.06 6.99 7.32 7.37 7.34 7.47 8.01 7.93 8.03 7.61 7.63 7.89 7.72 8.27 8.43 9.43 10.21 9.05 9.97 11.04 10.75 11.84 15.85 12.12 10.38 11.47 10.81 10.14 9.52 9.72 8.97 8.97 8.09 8.28 7.87 7.7 7.4 7.92 7.88 8.1 8.14 7.8 8.14 8.61 9.05 9 9.66 10.35 13.7 Utility Residential Cost per Mcf New York Cost per Mcf $19.37 (October 2005)

2,972 Miles of System Pipeline 15 Compressor Stations Totaling 39,606 Horsepower Transportation Volume for Fiscal 2005: 372.4 Bcf $121.6 MM in Revenues for Fiscal 2005 Pipeline & Storage Pipeline Operating Statistics

32 Underground Natural Gas Storage Fields (4 Co-owned with Nonaffiliated Companies) 15 Compressor Stations Totaling 35,475 Horsepower 73.4 Bcf of Working Storage Capacity $65.6 MM in Revenues for Fiscal 2005 Pipeline & Storage Storage Operating Statistics

Fiscal Year 1999 2000 2001 2002 2003 2004 2005 2006E Earnings 0.51 0.4 0.5 0.49 0.56 0.599 0.63 0.615 a Excludes impairment of Independence Pipeline of -$0.12 b Excludes SFAS 88 settlement loss of -$0.02 c Excludes base gas sale of $0.03 and gain associated with insurance proceeds of $0.05 a b Fiscal Year Pipeline & Storage Diluted Earnings per Share c

1997 1998 1999 2000 2001 2002 2003 2004 2005 65.835 66.29 60.634 68.223 58.5 61.3 60.7 65.1 65.4 * Excludes SFAS 88 settlement loss of -$3.0 million * Pipeline & Storage O & M Expense $ Millions Fiscal Year

78 MILES of 24" 20,700 HP COMPRESSION APPROX. $144 MILLION COST TARGET IN-SERVICE DATE 11/07 EMPIRE PIPELINE PROPOSED EMPIRE CONNECTOR

Empire Connector Filed application with FERC on 10/12/05 Initial Capacity 250,000 Dth/day - KeySpan 150,000 Dth/day Target In-Service Date Fall 2007 78 Miles of 24" Pipe - 1,440 psig 20,620 HP of Compression Receipts from TransCanada Pipeline @ Chippawa, Ontario Deliveries to Millennium @ Corning, New York Capital Cost Approximately $144 Million

Our Prime Location Niagara CANADA Lake Ontario Lake Erie Leidy Ellisburg NY PA PA OH TRANSCANADA UNION GAS Chippawa Corning A-5 Line Independence MILLENNIUM Empire Connector Project 250 MDth/Day Cost: Approx. $144 Million NFGSC Tuscarora Extension Project Will Interconnect with both Millennium and Empire Pipelines 130 MDth/Day Cost: Approx. $39 Million Tuscarora Storage GAS SUPPLY SOURCES DAWN HUB: Canadian, Gulf, &Mid-Continent FUTURE: Alaska, Rocky Mountain & Gulf LNG TCPL INTERCONNECTS At Niagara & Chippawa GAS SUPPLY SOURCES Gulf & Appalachian Prod'n FUTURE: Cove Point & Gulf LNG ELLISBERG LEIDY HUB INTERCONNECTS Transco, TETCO, TGP, TCO & DTI GAS SUPPLY Millennium Pipeline 500 MDth/Day National Fuel Gas Company NFGSC System Storages NFGSC System Pipelines Empire State Pipeline Interconnects Empire Pipeline

Tuscarora Extension Initial Pipeline Capacity 130,000 Dth/day Estimated In-Service Date Late Calendar 2007/Early Calendar 2008 23 Miles of 24" Pipe 800 HP of Compression Receipts from NFGSC and Other Storages and Upstream Pipelines Deliveries to Millennium and Empire Capital Cost Approximately $39 Million Development Activities Contingent on Market

Canada - 9% 56.3 BCFE NY PA Gulf Coast - 8% 46.2 BCFE East - 14% 84.2 BCFE CA - 69% 413 BCFE Total: 599.7 BCFE/ 99.95 MMBOE Oil: 60% Gas: 40% E&P's Reserves by Region (at 09/30/05)

Fiscal Year 1999 2000 2001 2002 2003 2004 2005 2006E Earnings 0.09 0.44 0.89 0.33 0.46 0.61 0.6 1.15 a b c a Excludes oil & gas impairment of -$1.29 b Excludes oil & gas impairment, loss on sale and cum. effect of change in acctg of - $0.85 c Excludes SFAS 88 settlement loss of -$0.01 and Adjustment of loss on sale of oil and gas assets of +$0.06 d Based on forecast using 9/13/05 NYMEX price. Fiscal Year Exploration & Production Diluted Earnings per Share d

Seneca's Year End Results September 30, 2005 Production: 52.4 BCFE Operating Revenue $293.4 MM Net Income $50.7 MM Drilled 241 New Wells - 98% Success Rate Expenses/Mcfe 4th Quarter Fiscal Year DD&A $1.84 $1.74 LOE $1.09 $0.98 G&A $0.36 $0.41 ($21.5 MM)

2002 2003 2004 2005 2006 LOE 0.752 0.817 0.714 0.98 1.15 Prod/Ad Val Tax 0.111 0.157 0.081 0.097 0.13 General & Admin. 0.403 0.292 0.383 0.411 0.48 Interest 0.622 0.703 0.811 0.844 0.841 Cash Tax -0.105 0.19 0.053 0.084 0.341 Cash Margin 1.774 1.955 2.838 3.287 4.855 Improving Margins

Granted Federal Royalty Relief from all Offshore Production after October 1, 2006 $44 MM Total Recovery $19MM Net to Seneca Spud 2 New Sukunka Wells 93-D (Well #5) and 77-D (Well #6) Recent Developments

0 15 miles (2nd Well) (3rd Well) (5th Well) (4th Well) (6th Well) AREA OF MUTUAL INTEREST Gas Wells Proposed Wells Working interest lands Lands to be earned by drilling 77-D 75-E 79-J 50-C 93-D (1st Well) 60-E Sukunka Area Land Map Monkman

Exploration & Production Sukunka Wells Seneca has 20% Working Interest in This Area Sukunka b-60-E Production Commenced on December 13, 2004 Current Sales Rate up to 60 MMcf/d Fourth Sukunka Well b-75-E Currently Completing Sukunka b-93-D (Well #5), Currently Drilling, is Offset to b-60-E Well

Gulf East West Canada Anticipated Well Drilling Well High Med Low Risk Reserve Potential High Med. Low **Well plans as of 8/1/05 Successful Well P & A Well Peppers #1 Sukunka #77-D (#6) Sukunka #93-D (#5) Central N.Y. (3) Drumheller (15) S W Sask (10) Westline (60) Muzette (20) Bronson #2 West Cameron 96 #2 Viosca Knoll 256 #1 Sukunka #7 Galveston 253 #1 Caribou (3) Vigilant (2) Shale (6) East Cameron 34 #1 Vermilion 342 Alberta CBM (10) High Island 37 #B-2 High Island 37 #A-5 2006 Exploration and Exploitation Opportunities**

High Island 37 #A-5 Drilling 78% Production & Reserves Galveston 227 On Production 30% Production Sukunka #77-D (#6) Drilling 20% Production & Reserves Sukunka #93-D (#5) Drilling 20% Production & Reserves Eugene Island 320 #1 Waiting on Platform 100% Production* East Cameron 213 #1 Platform Set 100% Production* Viosca Knoll 77 Waiting on Platform 47% Production Viosca Knoll 432 Waiting on Platform 47% Production High Island 37 #B-2 Waiting on Rig 25% Production & Reserves Working Fiscal 2006 Status Interest Impact * Already included in Forecast Impact Wells for Seneca's Production & Reserves

Working Fiscal 2007 Status Interest Impact Sukunka (Well #7) Planning Stage 20% Production & Reserves Vermilion 342 #1 Waiting on Rig 37.5% Production & Reserves West Cameron 96 #2 Partner Approval 11.5% Production & Reserves East Cameron 34 #1 Waiting on Rig 15% Production & Reserves Viosca Knoll 256 #1 Permitting 47% Production & Reserves Galveston 253 Waiting for Rig 40% Production & Reserves High Island 83 #1 High Bid (Waiting on Award) 62.5% Production & Reserves High Island A-306/315 High Bid (Waiting on Award) 40% Production & Reserves Impact Wells for Seneca's Production & Reserves

Swaps Volume Average Hedge Price Oil 1.9 MMBBL $34.14 / BBL Gas 9.2 BCF $6.17 /MCF No-cost Collars Volume Lowest Floor Price Highest Ceiling Price Gas 6.7 BCF $4.50 / MCF $17.95 / MCF Fiscal 2006 Exploration & Production Hedging Summary at 10/28/05 Fiscal 2007 Swaps Volume Average Hedge Price Oil 0.9 MMBBL $37.03 / BBL Gas 0.7 BCF $5.84 /MCF No-cost Collars Volume Lowest Floor Price Highest Ceiling Price Gas 2.4 BCF $7.42 / MCF $10.81 / MCF Fiscal 2008 Swaps Volume Average Hedge Price Oil 0.05 MMBBL $39.00 / BBL

* As of September 30, 2005 2002 2003 2004 2005 2006* 2007* Oil 23.84 22.55 26.55 30.44 34.14 37.03 Gas 15.5 18 20.2 24.3 36.7 42 $8.00 $3.00 $0 $9.00 Avg. Hedged Oil Price Avg. Hedged Gas Price Fiscal Year $10.00 $7.00 $6.00 $5.00 $4.00 $2.00 $1.00 Improving Hedging - Improving Results

E&P's Forecast Data for Fiscal 2006 Production*: 46 - 51 BCFE Number of Wells to be Drilled: 216 - 248 Expenses/Mcfe Estimated Range DD&A $1.85 - $1.95 LOE* (includes Other Taxes of $0.15) $1.25 - $1.35 Other Operating Expenses $6.0 MM - $8.0 MM General and Administrative $ 22 MM - $24 MM Earnings Per Share** $ 1.10 - $1.20 * Tentative depending on offshore pipeline repairs ** Based on September 13, 2005 NYMEX price forecast

Oct-05 Oct-05 $10.763 $63.11 Nov-05 Nov-05 $11.371 $63.78 Dec-05 Dec-05 $11.866 $64.38 Jan-06 Jan-06 $12.156 $64.83 Feb-06 Feb-06 $12.046 $65.19 Mar-06 $11.751 $11.751 $65.41 Apr-06 Apr-06 $9.551 $65.48 May-06 May-06 $9.191 $65.44 Jun-06 Jun-06 $9.216 $65.35 Jul-06 Jul-06 $9.257 $65.23 Aug-06 Aug-06 $9.300 $65.10 Sep-06 Sep-06 $9.276 $64.96 Average Average $10.479 $64.86 NYMEX Settlement Prices Natural Gas ($/MMBtu) Oil ($/Bbl) Oct-05 Oct-05 $13.907 $62.27 Nov-05 Nov-05 $13.832 $59.92 Dec-05 Dec-05 $11.380 $59.80 Jan-06 Jan-06 $11.954 $59.70 Feb-06 Feb-06 $12.004 $59.61 Mar-06 $11.799 $11.799 $59.51 Apr-06 Apr-06 $9.819 $59.39 May-06 May-06 $9.639 $59.27 Jun-06 Jun-06 $9.672 $59.12 Jul-06 Jul-06 $9.722 $58.96 Aug-06 Aug-06 $9.762 $58.79 Sep-06 Sep-06 $9.752 $58.62 Average Average $11.104 $59.58 Natural Gas ($/MMBtu) Oil ($/Bbl) (1) Actual NYMEX last day contract settled price (2) Actual monthly NYMEX average excluding weekends. At 09/13/05 At 11/10/05 (1) (1) (2)

Increase Decrease Increase Increase Utility -$0.01 +$0.01 - - Pipeline & Storage +$0.02 -$0.02 - - Exploration & Production +$0.11 -$0.11 +$0.01 -$0.01 Energy Marketing - - - - Timber - - - - Corporate & Other - - - - Consolidated +$0.12 -$0.12 +$0.01 -$0.01 $1 change per MMBtu gas $1 change per Bbl Oil Earnings Per Share Sensitivity to Changes from 09/13/05 NYMEX Prices* * Please refer to forward looking statement footnote on page 9 of National Fuel Gas's 10/27/05 press release. This sensitivity table is current as of October 28, 2005, but will become obsolete with the passage of time, changes in Seneca's production forecast, changes in customer use per account, as additional hedging contracts are entered into, and the settling of NYMEX hedge contracts at their maturity.

Path of Hurricanes Katrina & Rita

64% of Production Online as of 11/10/2005 No Definite Timetable for Remaining Production Waiting on Pipelines Total Estimated Insured Repair Costs - $4 MM Seneca's Deductible for Property Damage - $500,000 Separate Deductible for Restoring & Redrilling Wells - $750,000 Revisit Producing Forecast When All Repair Dates are Known Hurricanes Katrina & Rita Update

Fiscal Year 1999 2000 2001 2002 2003 2004 2005 2006E Earnings 0.51 0.08 0.1 0.12 0.12 0.07 0.06 0.05 a Excludes gain from timber sale of +$1.26 b Excludes adj. of gain on timber sale of -$0.01 a b Fiscal Year Timber Diluted Earnings per Share

Cherry 26 Oak 12 Maple 35 Other 27 Total Estimated Inventory 370,000,000 B.F. Timber Trees by Type* * as of 09/30/05

Veneer Average Price per Board Foot Cherry $6.28 Oak $1.29 Maple $2.83 All Other $0.60 Timber Price by Log Veneer* * at 09/30/05

Energy Marketing Diluted Earnings per Share Fiscal Year 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006E Earnings 0.02 0.03 0.02 0.01 0.03 -0.1 -0.04 0.11 0.07 0.07 0.06 0.02 Fiscal Year

APPENDIX

National Fuel Gas Company Energy Mktg. Timber E&P P&S Utility National Fuel Gas Distribution Corporation National Fuel Gas Supply Corporation and Empire State Pipeline Seneca Resources Corporation Highland Forest Resources, Inc. and NE Div. Of Seneca Resources Corporation National Fuel Resources, Inc. National Fuel Gas Company Major Business Segments

National Fuel Gas Company New York Stock Exchange NFG Shares Outstanding (Approx.) (As of 09/30/05) 84.4 Million Average Daily Trading Volume (12 Months Ended 09/30/05) 322,887 Market Capitalization (Approx.) (As of 10/31/05) $2.5 Billion $1.16 Annual Dividend Rate September Fiscal Year End

1/1/1960 2/1/1960 3/1/1960 4/1/1960 5/1/1960 6/1/1960 7/1/1960 8/1/1960 9/1/1960 10/1/1960 11/1/1960 12/1/1960 1/1/1961 2/1/1961 3/1/1961 4/1/1961 5/1/1961 6/1/1961 7/1/1961 8/1/1961 9/1/1961 10/1/1961 11/1/1961 12/1/1961 1/1/1962 2/1/1962 3/1/1962 4/1/1962 5/1/1962 6/1/1962 7/1/1962 8/1/1962 9/1/1962 10/1/1962 11/1/1962 12/1/1962 1/1/1963 2/1/1963 3/1/1963 4/1/1963 5/1/1963 6/1/1963 7/1/1963 8/1/1963 9/1/1963 10/1/1963 11/1/1963 12/1/1963 1/1/1964 2/1/1964 3/1/1964 4/1/1964 5/1/1964 6/1/1964 7/1/1964 8/1/1964 9/1/1964 10/1/1964 11/1/1964 12/1/1964 1/1/1965 2/1/1965 3/1/1965 4/1/1965 5/1/1965 6/1/1965 7/1/1965 8/1/1965 9/1/1965 10/1/1965 11/1/1965 12/1/1965 1/1/1966 2/1/1966 3/1/1966 4/1/1966 5/1/1966 6/1/1966 7/1/1966 8/1/1966 9/1/1966 10/1/1966 11/1/1966 12/ 1/1966 1/1/1967 2/1/1967 3/1/1967 4/1/1967 5/1/1967 6/1/1967 7/1/1967 8/1/1967 9/1/1967 10/1/1967 11/1/1967 12/1/1967 1/1/1968 2/1/1968 3/1/1968 4/1/1968 2.713056818 2.698881818 2.585243182 2.599418182 2.500002273 2.556797727 2.613640909 2.698881818 2.672727273 2.542622727 2.656261364 2.713056818 2.883538636 3.210231818 3.409111364 3.352268182 3.03975 3.167611364 3.238629545 3.167611364 3.238629545 3.423286364 3.693184091 3.451684091 3.267027273 3.338045455 3.394888636 3.394888636 3.082370455 2.883538636 3.124990909 3.124990909 3.124990909 3.139213636 3.338045455 3.380665909 3.494304545 3.678961364 3.565322727 3.778425 3.963081818 3.821045455 3.749979545 4.119340909 4.048275 3.863618182 3.849443182 3.920461364 3.749979545 3.735804545 3.650563636 3.764202273 3.778425 3.636340909 3.622165909 3.735804545 3.707406818 3.636340909 3.650563636 3.678961364 4.005702273 4.076720455 3.977256818 3.906238636 3.863618182 3.749979545 4.133515909 4.076720455 3.877840909 3.707406818 3.693184091 3.778425 3.664786364 3.622165909 3.536925 3.380665909 3.338045455 3.409111364 3.323870455 3.124990909 3.167611364 3.338045455 3.224454545 3.210231818 3.394888636 3.352268182 3.267027273 3.352268182 3.338045455 3.28125 3.465906818 3.480129545 3.494304545 3.309647727 3.053972727 3.153388636 3.28125 3.224454545 3.167611364 3.139213636 $30.14 (10/31/05) $34.79 (10/03/05) National Fuel Gas Stock Price (January 1992 - October 31, 2005)

Standard & Poor's Moody's Fitch, Inc. Long-Term Debt BBB+ Baa1 A- Outlook Stable Stable Stable Commercial Paper A-2 P-2 F-2 NFG Debt Ratings at September 30, 2005

Commercial Paper Program And Bilateral Credit Facilities - Aggregate Of $580 MM $0 MM borrowed at September 30, 2005 $300.0 MM Committed Credit Facility Through September 2010 $0 borrowed Universal Shelf Registration on File - Additional $550 MM Can Be Issued As Debt Or Equity Securities Any offer and sale of such securities will be made only by means of a prospectus meeting requirements of securities laws National Fuel Gas Company Capital Resources

Success Exploratory Development Dry Ratio East 2 78 1 99% West - 115 - 100% Gulf 7 3 1 91% Canada 24 7 3 91% Total 33 203 5 98% Seneca's Gross Well Drilling Activity for Fiscal 2005

Seneca's Fourth Quarter Results September 30, 2005 Production: 12.7 BCFE Number of Gross Wells Drilled: 79 Operating Revenue $73.9 MM Net Income $11.7 MM Diluted Earnings per Share $0.13 Expenses Actual Amount $/Mcfe LOE $13,870,000 $1.09 DD&A $23,368,000 $1.84 General and Administrative $ 4,623,000 $0.36

Utility Rate Case Settlements New York Pennsylvania Approximate Rate Base $640-$650 MM $270 MM Approximate Rate Base Revenue Increase $21 MM $12 MM Effective Date 08/01/2005 04/12/2005 * Black-box settlement in both states. Approximate Utility Capital Structure* : Long-term Debt 45% Cost Component 6.65% Short-term Debt 5% Cost Component 3.5% - 4.5% Equity Component 50% Return on Equity 10% - 11%

Comparable GAAP Financial Measure Slides And Reconciliations

2001 2002 2003 2004 2005 0.82 1.46 2.2 2.01 2.23 Fiscal Year National Fuel Gas Company Reported Diluted Earnings per Share

2000 2001 2002 2003 2004 2005 384.3 387.9 205.8 104.8 163.2 102.7 Fiscal Year National Fuel Gas Company Consolidated Net Cash Used in Investing Activities $ Millions

2001 2002 2003 2004 2005 5.15 4.29 4.02 5.36 4.54 Fiscal Year National Fuel Gas Company Net Cash Provided by Operating Activities per Diluted Share

1999 2000 2001 2002 2003 2004 2005 Utility 0.51 0.4 0.76 0.62 0.7 0.56 0.46 All Other Segments 0.96 1.21 0.06 0.84 1.5 1.45 1.77 $0.82 $1.46 $2.20 $2.01 $2.23 Fiscal Year Utility vs. Consolidated NFG Diluted Earnings per Share

1999 2000 2001 2002 2003 2004 2005 Utility 182 173 172 169 179 194 211 All Other Segments 147 177 192 225 207 220 193 Fiscal Year $ Millions Utility vs. Consolidated NFG O & M Expense $329 $350 $364 $394 $386 $414 $404

1999 2000 2001 2002 2003 2004 2005 Pipeline & Storage 0.51 0.4 0.5 0.37 0.56 0.58 0.71 All Other Segments 0.96 1.21 0.32 1.09 1.64 1.43 1.52 $0.82 $1.46 $2.20 $2.01 $2.23 Fiscal Year Pipeline & Storage vs. Consolidated NFG Diluted Earnings per Share

1999 2000 2001 2002 2003 2004 2005 Pipeline & Storage 61 68 59 61 61 68 65 All Other Segments 268 282 305 333 325 346 339 Fiscal Year $ Millions Pipeline & Storage vs. Consolidated NFG O & M Expense $329 $350 $364 $394 $386 $414 $404

1999 2000 2001 2002 2003 2004 2005 Exploration & Production 0.09 0.44 -0.4 0.33 -0.39 0.66 0.6 All Other Segments 1.38 1.17 1.22 1.13 2.59 1.35 1.63 $0.82 $1.46 $2.20 $2.01 $2.23 Fiscal Year Exploration & Production vs. Consolidated NFG Diluted Earnings per Share

1999 2000 2001 2002 2003 2004 2005 Timber 0.06 0.08 0.1 0.12 1.38 0.06 0.06 All Other Segments 1.41 1.53 0.72 1.34 0.82 1.95 2.17 $0.82 $1.46 $2.20 $2.01 $2.23 Fiscal Year Timber vs. Consolidated NFG Diluted Earnings per Share

NATIONAL FUEL GAS COMPANY
AND SUBSIDIARIES
RECONCILIATION TO REPORTED EARNINGS

	Fiscal Year			Fiscal Year			Fiscal Year			Fiscal Year			Fiscal Year
	Ended			Ended			Ended			Ended			Ended
(Diluted Earnings Per Share)	September 30, 2001			September 30, 2002			September 30, 2003			September 30, 2004			September 30, 2005
Utility
Reported earnings	$	0.76		$	0.62		$	0.70		$	0.56		$	0.46
Pension settlement loss		—			—			—			0.03			—
Earnings before non-recurring items		0.76			0.62			0.70			0.59			0.46
Pipeline and Storage
Reported earnings		0.50			0.37			0.56			0.58			0.71
Impairment of Independence Pipeline		—			0.12			—			—			—
Pension settlement loss		—			—			—			0.02			—
Gain associated with insurance proceeds		—			—			—			—			(0.05	)
Base gas sale														(0.03	)
Earnings before non-recurring items		0.50			0.49			0.56			0.60			0.63
Exploration and Production
Reported earnings		(0.40	)		0.33			(0.39	)		0.66			0.60
Loss on sale of oil and gas assets		—			—			0.48			—			—
Impairment of oil and gas producing properties		1.29			—			0.36			—			—
Cumulative Effect of Change in Accounting		—			—			0.01			—			—
Adjustment of loss on sale of oil and gas assets		—			—			—			(0.06	)		—
Pension settlement loss		—			—			—			0.01			—
Earnings before non-recurring items		0.89			0.33			0.46			0.61			0.60
International
Reported earnings		(0.04	)		(0.06	)		(0.12	)		0.07
Cumulative Effect of Change in Accounting		—			—			0.10			—		see
Pension settlement loss		—			—			—			—		"Discontinued
Tax rate change		—			—			—			(0.06	)	Operations"
Repatriation tax													below
Earnings before non-recurring items		(0.04	)		(0.06	)		(0.02	)		0.01
Energy Marketing
Reported earnings		(0.04	)		0.11			0.07			0.07			0.06
Pension settlement loss		—			—			—			—			—
Earnings before non-recurring items		(0.04	)		0.11			0.07			0.07			0.06
Timber
Reported earnings		0.10			0.12			1.38			0.06			0.06
Gain on sale of timber assets		—			—			(1.26	)		—			—
Pension settlement loss		—			—			—			—			—
Adjustment of gain on sale of timber properties		—			—			—			0.01			—
Earnings before non-recurring items		0.10			0.12			0.12			0.07			0.06
Corporate and All Other
Reported earnings		(0.06	)		(0.03	)		—			0.01			(0.08	)
Pension settlement loss		—			—			—			0.02			—
Earnings before non-recurring items		(0.06	)		(0.03	)		—			0.03			(0.08	)
Consolidated
Reported earnings		0.82			1.46			2.20			2.01
Total non-recurring items from above		1.29			0.12			(0.31	)		(0.03	)
Earnings before non-recurring items	$	2.11		$	1.58		$	1.89		$	1.98
Consolidated Earnings from Continuing Operations
Reported earnings from continuing operations														1.81
Total non-recurring items from above														(0.08	)
Earnings from continuing operations before non-recurring items													$	1.73
Discontinued Operations
Reported earnings from discontinued operations														0.42
Consolidated
Reported earnings													$	2.23

Reconciliation of National Fuel Gas Expenditures for Long-lived Assets to Consolidated Net Cash Used in Investing Activities (‘000)

	2000 *			2001			2002			2003			2004			2005
Capital Expenditures	$	(270,571	)	$	(292,706	)	$	(232,368	)	$	(152,251	)	$	(172,341	)	$	(218,271	)
Investment in Subsidiaries, Net of Cash		(123,809	)		(90,567	)	$	—			(228,814	)	$	—		$	—
Investment in Partnerships	$	(4,442	)	$	(1,830	)	$	(536	)	$	(375	)	$	—		$	—
Expenditures for Long Lived Assets	$	(398,822	)	$	(385,103	)	$	(232,904	)	$	(381,440	)	$	(172,341	)	$	(218,271	)
Expenditures for Long Lived Assets	$	(397,622	)	$	(385,103	)	$	(232,904	)	$	(381,440	)	$	(172,341	)	$	(218,271	)
Net Proceeds from Sale of Foreign Subsidiary	$	—		$	—		$	—		$	—		$	—		$	111,619
Net Proceeds from Sale of Timber Properties	$	—		$	—		$	—		$	186,014		$	—		$	—
Net Proceeds from Sale of Oil and Gas Producing Properties	$	4,159		$	2,069		$	22,068		$	78,531		$	7,162		$	90
Other	$	9,124		$	(4,892	)	$	5,012		$	12,065		$	1,974		$	3,890
Net Cash Used in Investing Activities	$	(384,339	)	$	(387,926	)	$	(205,824	)	$	(104,830	)	$	(163,205	)	$	(102,672	)

* 2000 includes $1.2 million in a stock-for-asset swap in Pipeline & Storage segment

Free Cash Flow Per Diluted Share Calculation
and Reconciliation to Net Cash Provided by Operating Activities

	Fiscal Year Ended			Fiscal Year Ended			Fiscal Year Ended			Fiscal Year Ended			Fiscal Year Ended
	9/30/01			9/30/02			9/30/03			9/30/04			9/30/05
Net Income Available for Common Stock	$	65,499,000		$	117,682,000		$	178,944,000		$	166,586,000		$	189,488,000
Addback:
Gain on Sale of Discontinued Operations	$	—		$	—		$	—		$	—		$	(27,274,000	)
Loss on Sale of Timber Properties	$	—		$	—		$	—		$	1,252,000		$	—
Gain on Sale of Timber Properties	$	—		$	—		$	(168,787,000	)	$	—		$	—
Loss on Sale of Oil and Gas													$	—
Producing Properties	$	—		$	—		$	58,472,000		$	(4,645,000	)	$	—
Impairment of Oil & Gas Properties	$	180,781,000		$	—		$	42,774,000		$	—		$	—
Depreciation & Depletion and Amortization	$	174,914,000		$	180,668,000		$	195,226,000		$	189,538,000		$	193,144,000
Deferred Taxes	$	(55,849,000	)	$	62,013,000		$	78,369,000		$	40,329,000		$	32,338,000
Impairment of Investment in Partnership	$	—		$	15,167,000		$	—		$	—		$	4,158,000
Cumulative Effect of Change													$	—
in Accounting	$	—		$	—		$	8,892,000		$	—		$	—
Income/loss from Unconsolidated Subs.										$	—		$	—
Net of Cash Distributions	$	(1,199,000	)	$	361,000		$	703,000		$	(19,000	)	$	(1,372,000	)
Minority Interests in Foreign Subsidiary	$	1,342,000		$	730,000		$	785,000		$	1,933,000		$	2,645,000
Other	$	6,553,000		$	9,842,000		$	11,289,000		$	9,839,000		$	7,390,000
Net Cash Used in Investing Activities	$	(387,926,000	)	$	(205,824,000	)	$	(104,830,000	)	$	(163,205,000	)	$	(102,672,000	)
Dividends	$	(76,671,000	)	$	(80,974,000	)	$	(84,530,000	)	$	(89,092,000	)	$	(94,159,000	)
Total Free Cash Flow	$	(92,556,000	)	$	99,665,000		$	217,307,000		$	152,516,000		$	203,686,000
Weighted Avg. Shares Outstanding (Diluted)		80,361,258			80,534,453			81,357,896			82,900,438			85,029,131
Free Cash Flow Per Diluted Share	$	(1.15	)	$	1.24		$	2.67		$	1.84			2.40
Total Free Cash Flow	$	(92,556,000	)	$	99,665,000		$	217,307,000		$	152,516,000		$	203,686,000
Add back:
Net Cash Used in Investing Activities	$	387,926,000		$	205,824,000		$	104,830,000		$	163,205,000		$	102,672,000
Dividends	$	76,671,000		$	80,974,000		$	84,530,000		$	89,092,000		$	94,159,000
Change in:
Receivables and Unbilled Utility Revenue	$	(2,277,000	)	$	40,786,000		$	(28,382,000	)	$	4,840,000		$	(31,246,000	)
Gas Stored Underground and Materials							$	—		$	—
and Supplies	$	(37,054,000	)	$	8,717,000		$	(12,421,000	)	$	9,860,000		$	(1,171,000	)
Unrecovered Purchased Gas Costs	$	25,568,000		$	(8,318,000	)	$	(16,261,000	)	$	21,160,000		$	(7,285,000	)
Prepayments	$	(399,000	)	$	(1,737,000	)	$	(2,773,000	)	$	8,146,000		$	(16,455,000	)
Accounts Payable	$	20,419,000		$	(24,025,000	)	$	13,699,000		$	(5,134,000	)	$	48,089,000
Amounts Payable to Customers	$	41,640,000		$	(51,223,000	)	$	692,000		$	2,462,000		$	(1,996,000	)
Other Accruals and Current Liabilities	$	13,969,000		$	(27,332,000	)	$	8,595,000		$	25,857,000		$	3,637,000
Other Assets and Liabilities	$	—		$	—		$	—		$	—		$	—
Other Assets	$	(33,169,000	)	$	11,869,000		$	(32,681,000	)	$	(10,693,000	)	$	(12,918,000	)
Other Liabilities	$	13,289,000		$	10,350,000		$	(10,298,000	)	$	(17,011,000	)	$	4,694,000
Net Cash Provided by Operating Activities	$	414,027,000		$	345,550,000		$	326,837,000		$	444,300,000		$	385,866,000
Weighted Avg. Shares Outstanding (Diluted)		80,361,258			80,534,453			81,357,896			82,900,438			85,029,131
Net Cash Provided by Operating Activities per Diluted Share	$	5.15		$	4.29		$	4.02		$	5.36			4.54

Reconciliation of Utility Segment Diluted Earnings Per Share to
  Consolidated Diluted Earnings Per Share

	Forecast
	Fiscal 2006E
Utility Segment	$	0.52-$0.59
All Other Segments	$	1.78-$1.91
Total Corporation	$	2.30-$2.50

Reconciliation of Utility Segment O&M Expense to
  Consolidated O&M Expense (From Continuing Operations)
($000s)

	1999		2000		2001		2002		2003		2004		2005
Utility Segment	$	181,636	$	173,213	$	171,481	$	168,633	$	179,052	$	190,669	$	211,019
SFAS 88 Pension Settlement	$	—	$	—	$	—	$	—	$	—	$	3,374	$	—
All Other Segments		147,164		177,170		192,837		225,524		207,218	$	219,550	$	193,498
Total Corporation	$	328,800	$	350,383	$	364,318	$	394,157	$	386,270	$	413,593	$	404,517

Reconciliation of Utility Segment Aged Accounts Receivable to
  Consolidated Accounts Receivable — Net
($Millions)

	at 9/30/02			at 9/30/03			at 9/30/04			at 9/30/05
Utility Aged Accounts Receivable	$	41.5		$	63.1		$	68.1		$	76.3
Utility Current/Other Accounts Receivable	$	16.2		$	28.0		$	18.2		$	16.4
Utility Gross Accounts Receivable	$	57.7		$	91.1		$	86.3		$	92.7
Utility Reserve for Bad Debt	$	(13.3	)	$	(12.7	)	$	(12.9	)	$	(25.1	)
Utility Net Accounts Receivable	$	44.4		$	78.4		$	73.4		$	67.6
All Other Segments Gross Accounts Receivable	$	55.1		$	63.4		$	61.0		$	89.3
All Other Segments Reserve for Bad Debts	$	(4.0	)	$	(5.3	)	$	(4.6	)	$	(1.8	)
All Other Segments Net Accounts Receivable	$	51.1		$	58.2		$	56.4		$	87.5
Total Corporation Accounts Receivable — Net	$	95.5		$	136.6		$	129.8		$	155.1

Reconciliation of Pipeline & Storage Operating Revenues to
  Consolidated Operating Revenues Fiscal 2005
($Millions)

Pipeline Revenues	$	121.6
Storage Revenues	$	65.6
Other Revenues	$	28.7
Total Pipeline & Storage Revenues	$	215.9
All Other Segments	$	1,707.7
Total Corporation	$	1,923.6

Reconciliation of Pipeline & Storage Segment Diluted Earnings Per Share to
  Consolidated Diluted Earnings Per Share

	Forecast
	Fiscal 2006E
Pipeline & Storage Segment	$	0.60-$0.63
All Other Segments	$	1.70-$1.87
Total Corporation	$	2.30-$2.50

Reconciliation of Pipeline & Storage O&M Expense to
  Consolidated O&M Expense (From Continuing Operations)
($000s)

	1999		2000		2001		2002		2003		2004		2005
Pipeline & Storage	$	60,600	$	68,200	$	58,500	$	61,300	$	60,705	$	65,071	$	65,397
SFAS 88 Pension Settlement	$	—	$	—	$	—	$	—	$	—	$	3,026	$	—
All Other Segments		268,200		282,183		305,818		332,857		325,565	$	345,496	$	339,120
Total Corporation	$	328,800	$	350,383	$	364,318	$	394,157	$	386,270	$	413,593	$	404,517

Reconciliation of Exploration & Production Operating Revenue to
  Consolidated Operating Revenue
($Millions)

	4Q FY 2005		2005
Exploration & Production	$	73.9	$	293.4
All Other Segments	$	213.2	$	1,630.1
Total Corporation	$	287.1	$	1,923.5

Reconciliation of Exploration & Production Net Income to
  Consolidated Net Income
($Millions)

	4Q FY 2005		2005
Exploration & Production	$	11.7	$	50.7
All Other Segments	$	37.5	$	138.8
Total Corporation	$	49.2	$	189.5

Reconciliation of Exploration & Production Diluted Earnings Per Share to
  Consolidated Diluted Earnings Per Share

					Forecast
	4Q FY 2005		2005		Fiscal 2006E
Exploration & Production	$	0.13	$	0.60	$	1.10-$1.20
All Other Segments	$	0.44	$	1.63	$	1.20-$1.30
Total Corporation	$	0.57	$	2.23	$	2.30-$2.50

Reconciliation of Timber Segment Diluted Earnings Per Share to
  Consolidated Diluted Earnings Per Share

	Forecast
	Fiscal 2006E
Timber Segment	$	0.05
All Other Segments	$	2.25-$2.45
Total Corporation	$	2.30-$2.50

Reconciliation of Energy Marketing Segment Diluted Earnings Per Share to
  Consolidated Diluted Earnings Per Share

	Forecast
	Fiscal 2006E
Energy Marketing Segment	$	0.02
All Other Segments	$	2.28-$2.48
Total Corporation	$	2.30-$2.50