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

Date of Report (Date of earliest event reported): August 14, 2008

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

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

6363 Main Street, Williamsville, New York	14221
(Address of principal executive offices)	(Zip Code)

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

Former name or former address, if changed since last report: Not Applicable

     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))

Item 7.01 Regulation FD Disclosure

National Fuel Gas Company (the “Company”) will participate in an industry conference on Thursday, August 14, 2008. A copy of materials to be presented by the Company and provided to conference participants is furnished as part of this Current Report as Exhibit 99.

Neither the furnishing of the 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 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 a substitute for financial measures prepared in accordance with GAAP.

Certain statements contained herein or in the presentation furnished as part of this Current Report, including statements regarding expected future natural gas and oil production, estimated future earnings, future prospects, plans and capital structure, anticipated capital expenditures, and completion of construction projects, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking” statements” as defined by the Private Securities Litigation Reform Act of 1995. There can be no assurance that the Company’s projections will in fact be achieved nor do these projections reflect any acquisitions or divestitures that may occur in the future. 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 projected in forward-looking statements. 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, acts of war or major accidents, and downturns in economic activity including national or regional recessions; changes in demographic patterns and weather conditions, including the occurrence of severe weather such as hurricanes; changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments or the valuation of the Company’s natural gas and oil reserves; uncertainty of oil and gas reserve estimates; ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including shortages, delays or unavailability of equipment and services required in drilling operations; significant changes from expectations in the Company’s actual production levels for

natural gas or oil; changes in the availability and/or price of derivative financial instruments; changes in the price differentials between various types of oil; inability to obtain new customers or retain existing ones; significant changes in competitive factors affecting the Company; changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations; 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 or plans; the nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; occurrences affecting the Company’s ability to obtain funds from operations, from borrowings under our credit lines or other credit facilities or from issuances of other short-term notes or debt or equity securities to finance needed capital expenditures and other investments, including any downgrades in the Company’s credit ratings; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the market price of timber and the impact such changes might have on the types and quantity of timber harvested by the Company; 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; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefit plans; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide post-retirement benefits; or 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 9.01 Financial Statements and Exhibits

(c) Exhibits

Exhibit 99  Presentation materials August 14, 2008 conference

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
By:	/s/ James R. Peterson
	James R. Peterson
	Assistant Secretary

August 14, 2008

EXHIBIT INDEX

Exhibit Number	Description
99	Presentation materials for August 14, 2008 conference

EX-99

Exhibit 99

National Fuel Gas Company August 2008

This presentation may contain "forward-looking statements" as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, performance and capital structure, anticipated capital expenditures and completion of construction projects, as well as statements that are identified by the use of the words "anticipates," "estimates," "expects," "forecasts," "intends," "plans," "predicts," "projects," "believes," "seeks," "will," "may," and similar expressions. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company's expectations, beliefs and projections contained herein are expressed in good faith and are believed to have a reasonable basis, but there can be no assurance that such expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from results referred to in the forward-looking statements: changes in economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents, and downturns in economic activity including national or regional recessions; changes in demographic patterns and weather conditions, including the occurrence of severe weather such as hurricanes; changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments or the valuation of the Company's natural gas and oil reserves; uncertainty of oil and gas reserve estimates; ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including shortages, delays or unavailability of equipment and services required in drilling operations; significant changes from expectations in the Company's actual production levels for natural gas or oil; changes in the availability and/or price of derivative financial instruments; changes in the price differentials between various types of oil; inability to obtain new customers or retain existing ones; significant changes in competitive factors affecting the Company; changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations; 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 or plans; the nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; occurrences affecting the Company's ability to obtain funds from operations, from borrowings under our credit lines or other credit facilities or from issuances of other short-term notes or debt or equity securities to finance needed capital expenditures and other investments, including any downgrades in the Company's credit ratings; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; impairments under the SEC's full cost ceiling test for natural gas and oil reserves; changes in the market price of timber and the impact such changes might have on the types and quantity of timber harvested by the Company; 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; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; changes in actuarial assumptions and the return on assets with respect to the Company's retirement plan and post-retirement benefit plans; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide post-retirement benefits; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. For a discussion of these risks and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see "Risk Factors" in the Company's Form 10-K for the fiscal year ended September 30, 2007 and Forms 10-Q for the quarters ended March 31, 2008 and June 30, 2008. 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. Safe Harbor For Forward Looking Statements

National Fuel Gas Company Major Business Segments

National Fuel Gas Company Net Plant by Segment $3.0 Billion At June 30, 2008 P&S Utility All Other E&P Net plant 0.77 1.1 0.1 1.047

$259.2 Million 12 Months Ended June 30, 2008 P&S Utility Timber Energy Mkt. * Corp. & Other E&P NI 54.2 58.8 2.9 6.3 6.2 125.1 National Fuel Gas Company Net Income

2003 2004 2005 2006 2007 9 Mos. End 6/30/08 2008E 2009E Utility 49.9 55.5 50.1 54.4 54.2 38.8 59 62 P & S 199.4 23.2 21.1 26 43.2 106.2 146 70 E & P 75.8 77.7 122.45 208.3 146.7 140.5 177 231 Energy Mkt. 0.2 0.0102 0.06 $- 0.08 0 0 Timber 3.5 2.8 18.9 2.3 3.657 1.2 0 Corp & Others 50.1 5.7 1.1 3.2 0 0.2 1 1 International 2.5 7.5 5.9 0 0 0 0 E&P Discont'd Ops 0 0 0 0 29.1 0 $ Millions $172.3 $219.5 Fiscal Year National Fuel Gas Company Expenditures for Long-Lived Assets $294.2 Approx. $379 - $387 $276.7 $284.6* $381.4 *Total includes an Elimination of $(2.4) Million of capital expenditures included in the East division of the E&P segment for the purchase of storage facilities, buildings, and base gas from the P&S segment during the quarter ended June 30, 2008. Approx. $328 - $403

DAWN Hub: Canadian, Gulf & Mid-Continent FUTURE: Alaska Rockies Express Pipeline - REX East Gulf & Appalachian Production FUTURE: Cove Point Expansion & Gulf LNG 11

ROCKIES EXPRESS (REX) MILLENNIUM (NOV 2008) 525 MDth/day EMPIRE CONNECTOR (NOV 2008) 250 MDth/day CANADA Lake Ontario Lake Erie Leidy Ellisburg NY PA Chippawa Corning Independence TransCanada Pendleton Niagara PA OH National Fuel Supply Corp. Empire Pipeline Bristoria Clarington Lamont TGP, DTI = Existing NFG Right of Way (New Pipeline) = New Right of Way (New Pipeline) = Existing Pipeline = Proposed Expansion of Existing Storage = Existing NFGSC Storage Field Gulf & Appalachian Production, Cove Point LNG, & Future Gulf LNG DAWN Hub: Canadian, Gulf & Mid-Continent; Future Alaska Our Prime Location Tuscarora Storage West to East Project 13

EMPIRE CONNECTOR = Appalachian Lateral = Original W2E - Overbeck to Corning = Original W2E - Clarington to Overbeck (including Bristoria to Waynesburg extension) = Proposed Storage Expansion REX MILLENNIUM CANADA Lake Ontario Lake Erie Leidy Ellisburg NY PA Corning Independence Tuscarora Storage PA OH National Fuel Supply Corp. Empire Pipeline Clarington Overbeck Pittsburgh Lamont Leidy to Ellisburg: Existing pipeline; no new construction required Waynesburg Bristoria 8 Appalachian Lateral Appalachian Lateral

Exploration & Production Segment National Fuel Gas Company

Large undeveloped shallow gas potential in Appalachia Major Appalachian upside from the Marcellus Shale Steady predictable oil production in California Recent exploration success in the Gulf of Mexico Exploration & Production Positioned for Growth

East - Appalachia (Growth) 110 BCFE Proved Reserves 220 BCFE 3P (Prvd+Prob+Poss) 670 BCFE Upper Devonian Prospective Resources 700,000 Acres Prospective in the Marcellus Shale (Over 900,000 net acres total) West - California (Cash Flow) Producing over 50 MMCFED 347 BCFE Proved Reserves Gulf of Mexico (Short Cycle Upside) Producing over 40 MMCFED 5 Recent Discoveries Exploration & Production Balanced Portfolio Gulf Coast - 7% 34 BCFE West - 71% 58 MMBOE (347 BCFE) East - 22% 110 BCFE Reserves 9/30/07: 491 BCFE Oil: 58% Gas: 42%

Goals: Changing Strategic Direction Steady sustainable growth Replace production through drilling Improve Finding & Development Cost Strategies: Emphasize low-risk development drilling Focus our exploration program - leverage past success and internal expertise Exploit Appalachian land position

2006 2007 2008 Forecast 2009 Budget East 27 39.1 71 129 West 36 41.4 49 54 Gulf 103 66.2 57 48 Canada 42 29.1 0 Major shift in capital allocation More low-risk development Less high-risk exploration In 2006, 13% Appalachia In 2008, 40% Appalachia 2009 Budget, 56% Appalachia Finding & development costs will continue to improve with more emphasis on low-risk Appalachian drilling Changing Strategic Direction Capital Expenditures (excluding acquisitions) $208 $175 $177 $195 - $270

U.S. Production up in fiscal 2007 and 2008 Expect 2009 similar to 2008 ~20% increase in East Down 10-15% in Gulf Flat in West 2006 2007 2008 Forecast 2009 Budget East 5.5 6.3 7.9 9.6 West 19.4 18.3 18.4 18.3 Gulf 13.2 14.7 14.9 13.2 Canada 9.3 7.7 Exploration & Production Annual Production by Division 47.4 ~41.2 47.0 38 - 44 (Bcfe)

Exploration & Production Appalachian Basin

30% production growth in 2008 Over 300% reserve replacement in 2008 Over half of preliminary 2009 E&P Capital Over 60% of our projected '09 reserve additions At planned drilling pace, should overtake California as largest producing Division by 2012 Back to our Roots Growing Importance of Appalachia

1998 1999 2000 2001 2002 2003 2004 '05 '06 '07 '08 Fcst '09 Fcst '10 Fcst Wells Drilled 5 2 7 41 40 52 42 82 152 233 270 325 370 Wells Comp 5 2 7 41 40 48 40 78 145 220 243 293 333 Gas Price 2.36 2.13 3.21 4.98 2.84 5.2 5.51 7.15 8.83 7.49 Fiscal Year Wells Drilled / Completed Average Gas Price E&P Appalachian Basin Upper Devonian: Development Drilling

Significantly improving reserves/well Fiscal Year 2004 2005 2006 2007 2008 Fcst MCFE/Well 80 57 71 97 110 Wells Completed 42 83 145 220 270 Reserves per well Wells Completed per Year PDP Reserves Added 2004: 3.7 BCFE 2005: 5.6 BCFE 2006: 11.2 BCFE 2007: 20.8 BCFE E&P Appalachian Basin Upper Devonian: Reserves per Well

E&P Appalachian Basin Marcellus Black Shale

Marcellus Shale: Basin edge Range Resources Marcellus Activity Seneca Resources Marcellus Activity Atlas Energy Marcellus Activity * Marcellus Isopach from "The Atlas of Major Appalachian Gas Plays", West Virginia Geological & Economic Survey, Mont Chateau Research Center, Morgantown, WV 26507-0879. E&P Appalachian Basin Marcellus Shale Activity Marcellus Shale: > 100' thick

Marcellus shale Fairway Seneca Resources Major Activity E&P Appalachian Basin Seneca's Marcellus Shale Activity SRC minerals in yellow EOG minerals in blue Seneca Marcellus position ~700,000 prospective acres

Boxes indicated are for illustration, not actual locations Marcellus Shale Fairway 10,000 Acre Prospect Box 1st Phase EOG to Drill 10 "R&D" Wells 10 Prospects selected by end '08 Vertical wells earn 160 acres Horizontal 320 EOG earns option to continue development on each Prospect @ 50% W.I. 2nd Phase EOG to Drill 10+ additional "R&D" Wells 10 additional Prospects selected by end 2011 2nd Phase Prospect Exploration Phase I & II

Wells Drilled 50/50 EOG and Seneca Minimum Drilling Pace for Development of Phase I Prospects: 2009: 10 Wells 2010: 20 Wells '11-'16: 30 Wells/year Total Phase I: 220 Wells (includes 10 R&D Wells completed by end of 2008) Phase II Prospects 10 R&D Wells complete by end of 2011 and development drilling begins in 2012 at same pace as described above Development Drilling 2007 - 2016

Activity to Date: Drilled 3 Horizontal wells and 3 vertical wells: 1st well averaged 350 mcfd over 1st 30 days 2nd well P&A'd due to mechanical problems 3rd well - 400 mcfd on 30-day flow test (1,500' lateral) New Rig drilling 4th horizontal - 4,000' lateral planned Fiscal 2009 Plans: Participate in at least 10 EOG operated development wells Drill at least 10 Seneca operated vertical "test" wells Test of productivity for vertical wells High grade areas for future horizontal program Develop long-term plan and estimate of ultimate Marcellus potential E&P Appalachian Basin Marcellus Shale Activity

Exploration & Production Gulf of Mexico

Why the Gulf of Mexico? $1.5 billion operating income on $.9 billion investment IRR on overall GOM program 19% Very large seismic data base Strategic Plan: Focus on core areas Build off of Seneca's recent success in trends where we have a competitive advantage Divest properties and eliminate capital exposure on projects not in our core areas Results to date: Five consecutive exploration discoveries E&P Gulf of Mexico Strategic Overview

High rate wells in Gulf have superior IRRs at same F&D Seneca FY 2008 Budget: 0.6 0.5 0.4 0.3 0.2 0.1 Appalachia 0.85 1.75 2.55 3.25 3.75 4.1 Gulf of Mexico 2.6 3.5 4.3 5 5.5 5.85 F&D IRR Appalachia $2.54 40% Gulf of Mexico $4.45 37% Economics @ $8/Mcf and $80/Bbl Exploration & Production Appalachia v. Gulf of Mexico Economics

*Average Daily Production: 1st Q, FY08 Recent Discoveries: Prospect Inventory: WC 96 Disc (Q4, 07): Producing: 9 MMCFD WI: 11% Disc (Q2, 08): 106' Pay; WI: 29% First Production: Q2 '09 HI 24L North Disc. (Q3 '07): Producing: 35 MMCFD WI: 35% HI 23L Prospect (Q2, 08): 60' Pay WI: 55%; Paid 35% Tested: 20 MMCFD; 3,000 BCPD E&P Gulf of Mexico Core Areas Fiscal Year 2008 EI383 (Q3, 08): 70' Pay; WI: 30% First Production: Q2 '09

Exploration & Production California

1,100 BOEPD 1,060 BOEPD 4,300 BOEPD 2,100 BOEPD Seneca's California Properties

Reserves R/P Ratio Production Revenue Lifting Cost Operating Income 2007 58 MMBOE (347 BCFE) 18.9 3.06 MMBOE (47% of Seneca) $148.9 M (30% of Seneca) $7.97 / BOE $88.3 M (52% of Seneca) 2008 Goal 2.83 - 3.17 MMBOE (~45% of Seneca) $180.4 M * (45% of Seneca) $8.19 / BOE $113.9 M * (52% of Seneca) Crude Pricing After Hedging $ / BBL Increase = $51.29 Increase = $4.69 E&P California Increasing Margins * FY2008 Production of 3.02 MMBOE

Property Trade Exchanged Seneca's Upper Ojai assets plus $14.1mm for additional Sespe assets SRC gained 6.6 BCFE, 210 BOEPD, reserve replacement cost of $2.14/MCFE Significant upside potential at Sespe Marvic Sand Develop at MWSS Drill 11 wells in 2008 3.3 BCFE @ $1.58 F&D cost Additional wells in planned 2009 E&P California Reserve Replacement Projects

Fiscal Year 2002 2003 2004 2005 2006 2007 9 Mo. End 6/30/08 Earnings 0.33 0.46 0.61 0.6 0.71 0.88 1.28 6 Mo. End 3/31/08 0.61 a b a Excludes oil & gas impairment, loss on sale and cum. effect of change in acctg of - $0.85 b Excludes SFAS 88 settlement loss of -$0.01 and Adjustment of loss on sale of oil and gas assets of +$0.06 c Excludes loss from discontinued operations of -$0.54 and income tax adjustments of +$0.07 d Excludes gain on disposal of discontinued operations of +$1.41 and Earnings from discontinued operations of +$0.18. e Excludes earnings from discontinued operations of $0.15. Fiscal Year c d E&P Diluted Earnings per Share e

Exploration & Production Summary Fiscal '08 Results to-date Production up substantially Exploration success in Gulf California production holding steady Appalachia growing fast Earnings more than double prior year Long term plan Increasing emphasis on Appalachia Establish significant Marcellus production Continue in Gulf as long as good opportunities are available Manage production decline in California

APPENDIX

National Fuel Gas Company New York Stock Exchange NFG Shares Outstanding (Approx.) (As of 06/30/08) 81.5 Million Average Daily Trading Volume (12 Months Ended 06/30/08) 616,238 Market Capitalization (Approx.) (As of 06/30/08) $4.8 Billion $1.30 Annual Dividend Rate (At 6/30/08) September Fiscal Year End

1/1/1992 2/1/1992 3/1/1992 4/1/1992 5/1/1992 6/1/1992 7/1/1992 8/1/1992 9/1/1992 10/1/1992 11/1/1992 12/1/1992 1/1/1993 2/1/1993 3/1/1993 4/1/1993 5/1/1993 6/1/1993 7/1/1993 8/1/1993 9/1/1993 10/1/1993 11/1/1993 12/1/1993 1/1/1994 2/1/1994 3/1/1994 4/1/1994 5/1/1994 6/1/1994 7/1/1994 8/1/1994 9/1/1994 10/1/1994 11/1/1994 12/1/1994 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 12.1875 12.75 12.1875 12.5 12.6875 12.75 13.1875 14.125 13.0625 13.125 14.0625 14.75 14.8125 15.75 16 15.875 14.9375 16.6875 17.375 17.9375 18.1875 17.75 16.6875 17 17.4375 15.375 15 15 15.1875 14.6875 15 15.5625 14.9375 14.875 13 12.75 13.25 13.625 14 14.4375 14.4375 14.3125 14 14.0625 14.375 14.875 16.0625 16.8125 16.75 16.0625 17.3125 17.5625 17.1875 18 16.875 18.5 18.375 18.625 21.3125 20.625 21.125 21.5 21.375 20.8125 20.6875 20.96875 21.25 22.21875 22 22.0625 23.34375 24.34375 23 23.3125 23.5 23 21.1875 21.78125 20.65625 20.5625 23.5 23.625 22.96875 22.59375 21.15625 20.21875 19.625 21.875 23.75 24.25 23.46875 23.53125 23.59375 24.4375 25.03125 23.25 22.28125 20.46875 22.28125 National Fuel Gas Company Stock Price 06/30/08 $59.48 NFG LISTED NYSE

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 '06 1.2 '07 1.24 '08 1.3 $0.19 2008 $1.30 Annual Rate At Fiscal Year End National Fuel Gas Company Dividend Growth

National Fuel Gas Company Earnings Guidance (at August 7, 2008) FY 2008 Earnings Guidance $3.10-$3.20 per share. Includes: Exploration & Production Production between 38 and 44 Bcfe No new 2008 production from announced venture with EOG Resources Utility New York rate determination in effect as of January 1, 2008 ROE 9.1% Weather Normalization and Revenue Decoupling

EPS Guidance & Sensitivity * The earnings guidance and sensitivity table are current as of August 7, 2008. The sensitivity table only considers revenue from the Exploration and Production segment's crude oil and natural gas sales. The sensitivities will become obsolete with the passage of time, changes in Seneca's production forecast, changes in basis differentials, as additional hedging contracts are entered into, and with the settling of NYMEX hedge contracts at their maturity. Earnings per Share Sensitivity to Changes from $9.50 per MMBtu for natural gas and $115 per Bbl for crude oil* Increase - -$0.07 +$0.07 - -$0.08 +$0.08 Decrease Decrease Increase $5 change per Bbl Oil $1 change per MMBtu Gas Fiscal 2009 NFG & Subsidiaries For its fiscal 2009 earnings forecast, the Company is utilizing flat commodity pricing, exclusive of basis differential, of $9.50 per MMBtu for natural gas and $115 per Bbl for crude oil.

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008E $3.1 B At Fiscal Year End Net Plant by Segment (in Billions)

Commercial Paper Program And Bilateral Credit Facilities - Aggregate Of $430.0 MM $0 borrowed at June 30, 2008 $300.0 MM Committed Credit Facility Through September 2010 $0 borrowed at June 30, 2008 The Company may issue debt or equity securities in a public offering or a private placement from time to time, depending on market conditions, indenture requirements, regulatory authorizations and the Company's capital requirements. National Fuel Gas Company Capital Resources

National Fuel Gas Company Share Buyback Date Authorized: December 8, 2005 Authorized Amount: Up to 8 Million Shares As of 06/30/08: 6,667,275 Shares Repurchased

* Long-term Debt includes Current Portion of Long-term Debt. ** Includes Discontinued Operations. National Fuel Gas Company Capitalization $2.55 Billion at June 30, 2007 ** Long-Term Debt Short-Term Debt Shareholder Equity Capitalization 1000 0 1552 Short-Term Debt N/A Shareholder Equity 61% Long-Term* Debt 39% $2.68 Billion at June 30, 2008 Long-Term Debt Short-Term Debt Shareholder Equity Capitalization 1099 0 1584 Short-Term Debt N/A Shareholder Equity 59% Long-Term* Debt 41%

## national fuel 89 Q3 FY 2008 Maintenance Expansion Cap Ex 53 6

S ## national fuel 91 Q3 FY 2008 Maintenance Expansion Cap Ex 23 122.9 Expansion $122.9 MM 80.9% Maintenance $29.1 MM 19.1%

13 East West Gulf Cap Ex 71 49 57 East $71 MM 40.1% Gulf $57 MM 32.2% West $49 MM 27.7% national fuel 93 AGA Financial Forum May 2008 * Excludes Acquisitions of $18 MM national fuel 93 Q3 FY 2008

Marcellus Shale Fairway national fuel 95 Management Conference 2008 national fuel 95 Q3 FY 2008

national fuel 97 Management Conference 2008 national fuel 97 Q3 FY 2008

National Fuel Gas Supply Corporation Empire State Pipeline Pipeline & Storage Segment

2,495 Miles of System Pipeline 15 Compressor Stations Totaling 39,929 Horsepower Transportation Volume for Fiscal 2007: 356.1 Bcf $122.9 MM in Revenues for Fiscal 2007 Pipeline & Storage Pipeline Operating Statistics

31 Underground Natural Gas Storage Fields (4 Co-owned with Nonaffiliated Companies) 15 Compressor Stations Totaling 35,475 Horsepower 78.3 Bcf of Working Storage Capacity $67.1 MM in Revenues for Fiscal 2007 Pipeline & Storage Storage Operating Statistics

Fiscal Year 2002 2003 2004 2005 2006 2007 9 Mos End 6/30/08 Earnings 0.49 0.56 0.599 0.63 0.65 0.583 0.48 9 Mos End 6/30/07 0.43 a Excludes SFAS 88 settlement loss of -$0.02 b Excludes base gas sale of $0.03 and gain associated with insurance proceeds of $0.05 c Excludes reversal of reserve for preliminary project costs of $0.06, and Discontinuance of Hedge Accounting of $0.02. a Fiscal Year Pipeline & Storage Diluted Earnings per Share b c c

XX national fuel 107 Q3 FY 2008

Construction Started September 2007 >18 miles Completed in Calendar 2007; Activities to Resume for the 2008 Construction Season Initial Capacity 250,000 Dth/day - KeySpan 150,750 Dth/day Target In-Service Date November 1, 2008 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 $180 Million $87 Million spent as of June 30, 2008 Pipeline & Storage Empire Connector

ROCKIES EXPRESS (REX) MILLENNIUM (NOV 2008) 525 MDth/day EMPIRE CONNECTOR (NOV 2008) 250 MDth/day CANADA Lake Ontario Lake Erie Leidy Ellisburg NY PA Chippawa Corning Independence TransCanada Pendleton Niagara PA OH National Fuel Supply Corp. Empire Pipeline Bristoria Clarington Lamont TGP, DTI = Existing NFGSC Storage Field Gulf & Appalachian Production, Cove Point LNG, & Future Gulf LNG DAWN Hub: Canadian, Gulf & Mid-Continent; Future Alaska Our Prime Location 111

Open Season Conducted May 2007 Initial Interest Strong 324-mile pipeline from Rockies Express (REX) terminus at Clarington, OH to Millennium Pipeline in Corning, NY Receipts from REX (~555,000 to 750,000 dth/d), Local Production, Cove Point Gas at Leidy and Corning Deliveries to Millennium and Empire at Corning Pipeline & Storage West to East Project

ROCKIES EXPRESS (REX) MILLENNIUM (NOV 2008) 525 MDth/day EMPIRE CONNECTOR (NOV 2008) 250 MDth/day CANADA Lake Ontario Lake Erie Leidy Ellisburg NY PA Chippawa Corning Independence Tuscarora Storage TransCanada Pendleton Niagara PA OH National Fuel Supply Corp. Empire Pipeline Bristoria Clarington Lamont TGP, DTI = New Right of Way (New Pipeline) = Proposed Expansion of Existing Storage = Existing NFGSC Storage Field Gulf & Appalachian Production, Cove Point LNG, & Future Gulf LNG DAWN Hub: Canadian, Gulf & Mid-Continent; Future Alaska Our Prime Location Tuscarora Extension 115

Phase I Pipeline Capacity 130,000 Dth/day 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 $49 Million Development Activities Contingent on Market Pipeline & Storage Tuscarora Extension

ROCKIES EXPRESS (REX) MILLENNIUM (NOV 2008) 525 MDth/day EMPIRE CONNECTOR (NOV 2008) 250 MDth/day CANADA Lake Ontario Lake Erie Leidy Ellisburg NY PA Chippawa Corning Independence Tuscarora Storage TransCanada Pendleton Niagara PA OH National Fuel Supply Corp. Empire Pipeline Bristoria Clarington Lamont TGP, DTI Gulf & Appalachian Production, Cove Point LNG, & Future Gulf LNG DAWN Hub: Canadian, Gulf & Mid-Continent; Future Alaska Our Prime Location Galbraith Storage East Branch Storage = Existing NFG Right of Way (New Pipeline) = New Right of Way (New Pipeline) = Existing Pipeline = Proposed Expansion of Existing Storage = Existing NFGSC Storage Field Storage Expansion 119

Incremental storage capacity of ~ 8.5 Bcf No additional base gas required East Branch and Galbraith Storage Fields in western Pennsylvania, Tuscarora Storage Field in central New York Assessment ongoing Pipeline & Storage Storage Expansion Project

National Fuel Gas Distribution Corporation Utility Segment

125

Utility Diluted Earnings per Share a Excludes SFAS 88 settlement loss of -$0.03 b Excludes out-of-period adjustment to symmetrical sharing of $0.03 * Due to the seasonal nature of the heating business, earnings for the nine months ended June 30 should not be taken as a prediction of earnings for the entire fiscal year. Fiscal Year

At 6/30/05 At 6/30/06 At 6/30/07 At 6/30/08 30-59 days 17.23 16.44 15.32 17.06 60-89 days 15.53 16.93 14.81 16.48 90-119 days 12.8 15.08 12.54 14.39 120 days & over 43.03 54.8 49.15 55.63 Reserve for Bad Debt 18.1 32.2 32.6 33.04 Utility Accounts Receivable - Customer

New York Merchant Function Charge Varies with Cost of Gas Rates from the 2007 Adjudicated Case Continues Allowance Attributable to Uncollectible Expense Residential Non-Residential 2.832% .402% Multiplied by Gas Supply Cost Rate Utility Bad Debt Tracking

Fiscal Year Utility Average Annual Use Per Residential Customer Normalized Mcf Per Account '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 '06 '07 180.205 173.305 173.431 170.237 164.955 156.044 156.898 152.605 153.207 145.597 132.388 134.153 131.672 132.194 131.12 135.531 132.77 130.829 133.551 128.393 127.036 128.857 123.223 124.975 124.137 119.631 116.131 118.369 116.198 114.23 115.603 113.854 107.928 105.861 108.195 108.195 Mcf (New York)

Utility Rate Cases * Represents the approximate range of rate base filed for in this case. ** Black-box settlement in Pennsylvania. Pennsylvania New York Settled Adjudicated Approximate Rate Base $280-$290 MM* $699 MM Approximate Base Rate Revenue Increase $14.3 MM $1.8 MM Conservation Incentive Program n/a $10.8 MM Effective Date 1/1/2007 12/28/2007 Approximate Utility Capital Structure**: Approximate Utility Capital Structure**: Long-term Debt Cost Component Short-term Debt Cost Component Equity Component Return on Equity 45.0% 6.65% 5.0% 5.0 - 6.0% 50.0% 10.0 - 11.0% 45.54% 6.57% 9.32% 5.98% 44.35% 9.10%

Utility Rate Case Activity 11/30/06: The Pennsylvania PUC Approved the Settlement Agreement Reached in the Delivery Service Charge Rate Case Effective Date: 1/1/07 Revenue Increase: $14.3 MM Revenue Decoupling: Initially Proposed by The Utility in This Case. Will Instead be Pursued Via Active Participation in The Statewide Generic Proceeding Announced by The Pennsylvania PUC on September 28, 2006 Pennsylvania Effective Date: 12/28/07 Awarded $1.8 MM base rate increase & $10.8 MM rate component (for expenses associated with Conservation Incentive Program) Granted 9.1% ROE Approved Revenue Decoupling: Recovery of operating costs & margin is decoupled from customer usage Early Decision on Conservation Incentive Program; Became Effective 11/1/07 NY Revenue Stabilization Features: WNC, RDM, MFC, Symmetrical Sharing New York Case Concluded Case Concluded

Energy Marketing Customers & Marketing Area Customers @ FYE 2004 2005 2006 2007 Residential 15,983 14,902 14,963 15,357 Commercial/Industrial 4,345 4,265 4,605 5,219

* Excludes resolution of a purchased gas contingency of +$0.03 Fiscal Year Energy Marketing Diluted Earnings per Share

Fiscal Year Timber Diluted Earnings per Share a Excludes gain from timber sale of +$1.26 b Excludes adj. of gain on timber sale of -$0.01

2002 2003 2004 2005 2006 2007 9 Mo. End 6/30/08 CFPS 1.18 2.52 1.82 2.29 0.36 2.49 1.23 9 Mo. End 6/30/08 0.67 Fiscal Year National Fuel Gas Company Free Cash Flow per Diluted Share

Standard & Poor's Moody's Fitch, Inc. Long-Term Debt BBB+ Baa1 A- Outlook Negative Stable Stable Commercial Paper A-2 P-2 F2 NFG Debt Ratings at June 30, 2008

Fiscal Year National Fuel Gas Company Net Cash Provided by Operating Activities per Diluted Share

2002 2003 2004 2005 2006 2007 9 Mos End 6/30/08 61.3 60.7 65.1 65.4 66.3 61.2 50.9 * Excludes SFAS 88 settlement loss of -$3.0 million * Pipeline & Storage O & M Expense $ Millions Fiscal Year

2002 2003 2004 2005 2006 2007 9 Mos End. 6/30/08 Utility 169 179 191 211 204 203 157.9 * Excludes SFAS 88 settlement loss of -$3.4 million Fiscal Year $ Millions * Utility O & M Expense

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 in the slides that follow. The Company believes that its 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 a substitute for financial measures prepared in accordance with GAAP. Comparable GAAP Financial Measure Slides and Reconciliations

$383.2 Million 12 Months Ended June 30, 2008 P&S Utility Timber Energy Mkt. * Corp. & Other E&P NI 54.2 58.8 2.9 6.3 6.8 254.1 National Fuel Gas Company Net Income GAAP Reconciliation Slide

2002 2003 2004 2005 2006 2007 9 Mos End 6/30/08 Pipeline & Storage 0.37 0.56 0.58 0.71 0.65 0.66 0.48 All Other Segments 1.09 1.64 1.43 1.52 0.96 3.3 2.17 $2.20 $2.01 $2.23 Fiscal Year Pipeline & Storage vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96 $2.65

2002 2003 2004 2005 2006 2007 9 Mos End 6/30/08 Pipeline & Storage 61 61 68 65 66 61 51 All Other Segments 333 269 306 323 329 335 275 Fiscal Year $ Millions Pipeline & Storage vs. Consolidated NFG O & M Expense from Continuing Operations $330 $374 $388 $395 $396 $326

2002 2003 2004 2005 2006 2007 9 Mos. End 6/30/08 Utility 0.62 0.7 0.56 0.46 0.58 0.6 0.73 All Other Segments 0.84 1.5 1.45 1.77 1.03 3.36 1.92 $2.20 $2.01 $2.23 Fiscal Year Utility vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96 $2.65

2002 2003 2004 2005 2006 2007 9 Mos End 6/30/08 Utility 169 179 194 211 204 203 158 All Other Segments 225 151 180 177 191 193 168 Fiscal Year $ Millions Utility vs. Consolidated NFG O & M Expense from Continuing Operations $330 $374 $388 $395 $396 $326

2002 2003 2004 2005 2006 2007 9 Mos End 6/30/08 Exploration & Production 0.33 -0.39 0.66 0.6 0.24 2.47 1.28 All Other Segments 1.13 2.59 1.35 1.63 1.37 1.49 1.37 $2.20 $2.01 $2.23 Fiscal Year Exploration & Production vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96 $2.65

2002 2003 2004 2005 2006 2007 9 Mos. Ended 6/30/08 Energy Marketing 0.11 0.07 0.07 0.06 0.07 0.09 0.077 All Other Segments 1.35 2.13 1.94 2.17 1.54 3.87 2.57 Fiscal Year Energy Marketing vs. Consolidated NFG Diluted Earnings per Share $2.20 $2.01 $2.23 $1.61 $3.96 $2.65

2002 2003 2004 2005 2006 2007 9 Mos. Ended 6/30/08 Timber 0.12 1.38 0.06 0.06 0.07 0.04 0.03 All Other Segments 1.34 0.82 1.95 2.17 1.54 3.92 2.62 $2.20 $2.01 $2.23 Fiscal Year Timber vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96 $2.65

Reconciliation of Segment Net Income to
    Consolidated Net Income
(‘000)

	12 Mos Ended 06/30/08
Utility			$	58,792
Pipeline & Storage			$	54,242
Exploration & Production	$	130,701
Plus: Gain on disposal of discontinued operations.		120,301
Earnings from discontinued operations		3,094		254,096
Energy Marketing				6,311
Timber				2,889
Corporate & Other	$	6,236
Plus: Gain on sale of turbine		586	$	6,822
Consolidated Net Income			$	383,152

NATIONAL FUEL GAS COMPANY
AND SUBSIDIARIES
RECONCILIATION TO REPORTED EARNINGS

	Fiscal Year			Fiscal Year			Fiscal Year			Fiscal Year			Fiscal Year			9 Months
	Ended			Ended			Ended			Ended			Ended			Ended
(Diluted Earnings Per Share)	September 30, 2003			September 30, 2004			September 30, 2005			September 30, 2006			September 30, 2007			June 30, 2008
Utility
Reported earnings	$	0.70		$	0.56		$	0.46		$	0.58		$	0.60		$	0.73
Out-of-period adjustment to symmetical sharing		—			—			—			(0.03	)		—			—
Pension settlement loss		—			0.03			—			—			—			—
Earnings before non-recurring items		0.70			0.59			0.46			0.55			0.60			0.73
Pipeline and Storage
Reported earnings		0.56			0.58			0.71			0.65			0.66			0.48
Reversal of reserve for preliminary project costs		—			—			—			—			(0.06	)
Discontinuance of hedge accounting		—			—			—			—			(0.02	)
Pension settlement loss		—			0.02			—			—			—			—
Gain associated with insurance proceeds		—			—			(0.05	)		—			—			—
Base gas sale								(0.03	)		—			—			—
Earnings before non-recurring items		0.56			0.60			0.63			0.65			0.58			0.48
Exploration and Production
Reported earnings		(0.39	)		0.66			0.60			0.24			2.47			1.28
Gain on disposal of discontinued operations		—			—			—			—			(1.41	)		—
(Earnings)/Loss from discontinued operations		—			—			—			0.54			(0.18	)		—
Income tax adjustments		—			—			—			(0.07	)		—			—
Loss on sale of oil and gas assets		0.48			—			—			—			—			—
Impairment of oil and gas producing properties		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		0.46			0.61			0.60			0.71			0.88			1.28
International
Reported earnings		(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		(0.02	)		0.01
Energy Marketing
Reported earnings		0.07			0.07			0.06			0.07			0.09			0.08
Resolution of a purchased gas contingency		—			—			—			—			(0.03	)		—
Pension settlement loss		—			—			—			—			—			—
Earnings before non-recurring items		0.07			0.07			0.06			0.07			0.06			0.08
Timber
Reported earnings		1.38			0.06			0.06			0.07			0.04			0.03
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		0.12			0.07			0.06			0.07			0.04			0.03
Corporate and All Other
Reported earnings		—			0.01			(0.08	)		—			0.10			0.05
Pension settlement loss		—			0.02			—			—			—			—
Gain on sale of turbine		—			—			—			—			—			(0.01	)
Earnings before non-recurring items		—			0.03			(0.08	)		—			0.10			0.04
Consolidated
Reported earnings		2.20			2.01
Total non-recurring items from above		(0.31	)		(0.03	)
Earnings before non-recurring items	$	1.89		$	1.98
Consolidated Earnings from Continuing Operations
Reported earnings from continuing operations								1.81			1.61			3.96			2.65
Total non-recurring items from above								(0.08	)		(0.10	)		(1.70	)		(0.01	)
Earnings from continuing operations before non-recurring items							$	1.73		$	1.51		$	2.26		$	2.64
Discontinued Operations
Reported earnings from discontinued operations								0.42
Consolidated
Reported earnings							$	2.23		$	1.61		$	3.96		$	2.65

Reconciliation of Pipeline & Storage Operating Revenues to
    Consolidated Operating Revenues Fiscal 2007
($Millions)

Pipeline Revenues	$	122.9
Storage Revenues	$	67.1
Other Revenues	$	21.9
Total Pipeline & Storage Revenues	$	211.9
All Other Segments	$	1,827.7
Total Corporation	$	2,039.6

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

											9 Mos. End
	2003		2004		2005		2006		2007		6/30/08
Pipeline & Storage	$	61,286	$	65,071	$	65,397	$	66,340	$	61,230	$	50,877
SFAS 88 Pension Settlement		—		3,026		—		—		—		—
All Other Segments		269,030		305,913		322,697		328,949		335,178		274,765
Total Corporation	$	330,316	$	374,010	$	388,094	$	395,289	$	396,408	$	325,642

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

											9 Mos. End
	2003		2004		2005		2,006.00		2007		6/30/08
Utility Segment	$	179,052	$	190,669	$	211,019		204,330.00	$	202,965	$	157,980
SFAS 88 Pension Settlement		—		3,374		—		—		—		—
All Other Segments		151,264		179,967		177,075		190,959.00		193,443		167,662
Total Corporation	$	330,316	$	374,010	$	388,094		395,289.00	$	396,408	$	325,642

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

	at 6/30/05			at 6/30/06			at 6/30/07			at 6/30/08
Utility Aged Accounts Receivable	$	88.59		$	103.27		$	91.81			103.56
Utility Current/Other Accounts Receivable	$	86.16		$	87.93		$	94.29			118.90
Utility Gross Accounts Receivable	$	174.75		$	191.20		$	186.10			222.46
Utility Reserve for Bad Debt	$	(18.13	)	$	(32.20	)	$	(32.60	)		(33.04	)
Utility Net Accounts Receivable	$	156.62		$	159.00		$	153.50			189.42
All Other Segments Gross Accounts Receivable		66.84			76.05			70.20			115.65
All Other Segments Reserve for Bad Debts	$	(2.05	)	$	(1.90	)	$	(1.50	)		(2.55	)
All Other Segments Net Accounts Receivable	$	64.79		$	74.15		$	68.70			113.10
Total Corporation Accounts Receivable — Net	$	221.41		$	233.15		$	222.20			302.52

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

																9 Mos. End
	2003			2004			2005			2006			2007			6/30/08
Capital Expenditures as presented on Statement of Cash Flows	$	(152,251	)	$	(172,341	)	$	(219,530	)	$	(294,159	)	$	(276,728	)	$	(264,728	)
Investment in Subsidiaries, Net of Cash		(228,814	)	$	—		$	—		$	—		$	—		$	—
Non Cash Accrual of Expenditures at 6/30/08																$	(19,855.00	)
Investment in Partnerships	$	(375	)	$	—		$	—		$	—		$	(3,300	)	$	—
Expenditures for Long Lived Assets	$	(381,440	)	$	(172,341	)	$	(219,530	)	$	(294,159	)	$	(280,028	)	$	(284,583	)
Expenditures for Long Lived Assets	$	(381,440	)	$	(172,341	)	$	(219,530	)	$	(294,159	)	$	(280,028	)	$	(284,583	)
Non Cash Accrual of Expenditures at 6/30/08																$	19,855.00
Net Proceeds from Sale of Foreign Subsidiary	$	—		$	—		$	111,619		$	—		$	232,092		$	—
Cash Held in Escrow													$	(58,248	)	$	58,397
Net Proceeds from Sale of Timber Properties	$	186,014		$	—		$	—		$	—		$	—		$	—
Net Proceeds from Sale of Oil and Gas Producing Properties	$	78,531		$	7,162		$	1,349		$	13		$	5,137		$	5,675
Other	$	12,065		$	1,974		$	3,238		$	(3,230	)	$	(725	)	$	(3,414	)
Net Cash Used in Investing Activities	$	(104,830	)	$	(163,205	)	$	(103,324	)	$	(297,376	)	$	(101,772	)	$	(204,070	)

Reconciliation of Exploration & Production Segment Capital Expenditures to
     Consolidated Capital Expenditures
($000s)

	2006		2007		2008E		2009E
Exploration & Production Capital Expenditures	$	166,535	$	146,687	$	177,000	$	195,000–$270,000
Acquisition Expenditures	$	—	$	0	$	18,000
Expenditures from Discontinued Operations	$	41,768		29,129		—		—
Total Exploration & Production Capital Expenditures	$	208,303	$	175,816		$195,000	$	195,000–$270,000
All Other		85,856	$	100,912	$	184,000–$192,000		$133,000
Total Corporation	$	294,159	$	276,728	$	379,000–$387,000	$	328,000–$403,000

Reconciliation of Exploration & Production Operating Revenue to
     Consolidated Operating Revenue (from Continuing Operations)
($000s)

	2007
Exploration & Production	$	324,037
All Other Segments		1,715,529
Consolidated Operating Revenue	$	2,039,566

Reconciliation of Exploration & Production Net Income to
     Consolidated Net Income
($000s)

	2007
Exploration & Production (Income from Continuing Operations)	$	74,889
Income from Discontinued Operations, Net of Tax		15,479
Gain on Disposal of Discontinued Operations, Net of Tax		120,301
Total Exploration & Production	$	210,669
All Other Segments		126,786
Consolidated Net Income	$	337,455

Reconciliation of Exploration & Production Lease Operating Expense (LOE) to
     Consolidated O&M (from Continuing Operations)
($000s)

	2007
Exploration & Production LOE	$	43,916
Exploration & Production Property, Franchise and Other Taxes		4,493
Exploration & Production Total LOE *	$	48,409
Exploration & Production LOE	$	43,916
Exploration & Production Other O&M		28,324
Exploration & Production Total O&M	$	72,240
All Other Segments O&M		324,168
Total Consolidated O&M	$	396,408
Exploration & Production Property, Franchise and Other Taxes (from Continuing Operations)	$	4,493
All Other Segments Property, Franchise and Other Taxes		66,167
Total Consolidated Property Franchise and Other Taxes	$	70,660

Reconciliation of Exploration & Production Depreciation, Depletion and Amortization to
     Consolidated Depreciation, Depletion and Amortization (DD&A)
($000s)

	2007
Exploration & Production DD&A *	$	78,174
All Other Segments DD&A		79,745
Consolidated DD&A	$	157,919

* DD&A and Total LOE cost per Mcf equivalent equals Exploration & Production DD&A and Total LOE costs, respectively, for the referenced fiscal period, divided by the Total Gas & Oil Production (Mmcfe) in that same fiscal period.

Reconciliation of Exploration & Production General & Administrative Costs to
     Consolidated O&M (from Continuing Operations)
($000s)

	2007
Exploration & Production General & Administrative *	$	19,946
Exploration & Production All Other O&M		52,294
Exporation & Production Total O&M	$	72,240
All Other Segments O&M		324,168
Total Consolidated O&M	$	396,408

* General and Administrative cost per Mcf equivalent equals Exploration & Production General and Administrative cost, for the referenced fiscal period, divided by the Total Gas & Oil Production (Mmcfe) in that same fiscal period.

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

($000s)

	Fiscal Year Ended			Fiscal Year Ended			Fiscal Year Ended			Fiscal Year Ended			9 Months Ending			Fiscal Year Ended			9 Months Ending
	September 30, 2003			September 30, 2004			September 30, 2005			September 30, 2006			June 30, 2007			September 30, 2007			June 30, 2008
Net Income	$	178,944		$	166,586		$	189,488		$	138,091		$	179,765		$	337,455		$	225,463
DD&A		195,226			189,538			193,144			179,615			125,986			170,803			129,337
Impairment of Oil and Gas Producing Properties		42,774			—			—			104,739			—			—			—
Impairment of Investment in Partnership		—			—			4,158			—			—			—			—
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions		703			(19	)		(1,372	)		1,067			(1,486	)		(3,366	)		1,340
Gain on Sale of Discontinued Operations		—			—			(27,386	)		—			—			(159,873	)		—
Loss (Gain) on Sale of Oil and Gas Properties		58,472			(4,645	)		—			—			—			—			—
(Gain) Loss on Sale of Timber Properties		(168,787	)		1,252			—			—			—			—			—
Deferred Income Taxes		78,369			40,329			40,388			(5,230	)		27,107			52,847			27,603
Minority Interest in Foreign Subsidiaries		785			1,933			2,645			—			—			—			—
Cumulative Effect of Changes in Accounting		8,892			—			—			—			—			—			—
Other		11,289			9,839			7,390			4,829			4,722			16,399			(1,120	)
		406,667			404,813			408,455			423,111			336,094			414,265			382,623
Less: Dividends Paid on Common Stock (Including Dividends to Minority Interests)		(84,530	)		(89,092	)		(106,835	)		(98,266	)		(74,748	)		(100,632	)		(77,204	)
Plus: Net Proceeds from Sale of Oil and Gas Producing Properties		78,531			7,162			1,349			13			5,137			5,137			5,675
Plus: Net Proceeds from Sale of Timber Properties		186,014			—			—			—			—			—			—
Plus: Net Proceeds from Sale of Turbine		—			—			—			—			—			—			—
Plus: Net Proceeds from Sale of Foreign Subsidiary		—			—			111,619			—			—			232,092			—
Plus: Cash Held in Escrow		—			—			—			—			—			(58,248	)		58,397
Less: Expenditures for Long-Lived Assets		(381,440	)		(172,341	)		(219,530	)		(294,159	)		(209,809	)		(280,028	)		(264,728	)
Free Cash Flow	$	205,242		$	150,542		$	195,058		$	30,699		$	56,674		$	212,586		$	104,763
Weighted Average Diluted Shares		81,358			82,900			85,029			86,028			85,193			85,301			85,000
Free Cash Flow Per Share	$	2.52		$	1.82		$	2.29		$	0.36		$	0.67		$	2.49		$	1.23
Reconciliation to Net Cash Provided by Operating Activities:
Free Cash Flow	$	205,242		$	150,542		$	195,058		$	30,699		$	56,674		$	212,586		$	104,763
Add Back:
Expenditures for Long-Lived Assets		381,440			172,341			219,530			294,159			209,809			280,028			264,728
Dividends Paid on Common Stock (Inc. Dividends to Minority Interests)		84,530			89,092			106,835			98,266			74,748			100,632			77,204
Cash Held in Escrow		—			—			—			—			—			58,248			(58,397	)
Deduct:
Excess Tax Benefits Associated with Stock-Based Compensation Awards		0			0			0			(6,515	)		(13,689	)		(13,689	)		(16,275	)
Net Proceeds from Sale of Oil and Gas Producing Properties		(78,531	)		(7,162	)		(1,349	)		(13	)		(5,137	)		(5,137	)		(5,675	)
Net Proceeds from Sale of Timber Properties		(186,014	)		—			—			—			—			—			—
Net Proceeds from Sale of Turbine		—			—			—			—			—			—			—
Net Proceeds from Sale of Foreign Subsidiary		—			—			(111,619	)		—			—			(232,092	)		—
Change in:
Hedging Collateral Deposits		(1,109	)		(7,151	)		(69,172	)		58,108			16,276			15,610			(26,712	)
Receivables and Unbilled Utility Revenue		(25,788	)		3,917			(25,828	)		(12,343	)		(43,733	)		5,669			(129,102	)
Gas Stored Underground & Materials and Supplies		(13,826	)		13,662			1,934			1,679			34,725			(5,714	)		14,819
Unrecovered Purchased Gas Costs		(16,261	)		21,160			(7,285	)		1,847			12,970			(1,799	)		9,089
Prepayments and Other Current Assets		(12,628	)		35,647			(42,409	)		(39,572	)		30,685			18,800			17,370
Accounts Payable		13,699			(5,134	)		48,089			(23,144	)		(12,560	)		(26,002	)		53,081
Amounts Payable to Customers		692			2,462			(1,996	)		22,777			(4,738	)		(13,526	)		2,455
Customer Advances		(2,594	)		4,970			3,971			4,946			(29,417	)		(6,554	)		(22,863	)
Other Accruals and Current Liabilities		9,343			2,082			18,715			(17,754	)		77,842			8,950			94,031
Other Assets		(9,343	)		(4,829	)		(13,461	)		(22,700	)		918			4,109			19,178
Other Liabilities		(23,124	)		(34,450	)		(3,667	)		80,960			(821	)		(5,922	)		17,373
Net Cash Provided by Operating Activities	$	325,728		$	437,149		$	317,346		$	471,400		$	404,552		$	394,197		$	415,067