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): March 22, 2010

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))

TABLE OF CONTENTS

EX-99

Item 7.01 Regulation FD Disclosure.

National Fuel Gas Company (the “Company”) will participate in the Howard Weil 38th Annual Energy Conference on March 23, 2010. The Company also plans to hold meetings with certain industry analysts, money managers and other members of the financial community. A copy of materials to be presented by the Company during the conference and provided to participants in the Company’s meetings 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 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, 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: financial and economic conditions, including the availability of credit, and their effect on the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments; occurrences affecting the Company’s ability to obtain financing under credit lines or other credit facilities or through the issuance of commercial paper, other short-term notes or debt or equity securities, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; changes in economic conditions, including global, national or regional recessions, and their

effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from terrorist activities, acts of war, major accidents, fires, hurricanes, other severe weather, pest infestation or other natural disasters; changes in demographic patterns and weather conditions; 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; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; uncertainty of oil and gas reserve estimates; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, and the need to obtain governmental approvals and permits and comply with environmental laws and regulations; significant differences between the Company’s projected and 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 oil having different quality and/or different geographic locations, or changes in the price differentials between natural gas having different heating values and/or different geographic locations; changes in laws and regulations to which the Company is subject, including those involving taxes, safety, employment, climate change, other environmental matters, and exploration and production activities such as hydraulic fracturing; the nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; significant differences between the Company’s projected and actual capital expenditures and operating expenses, and unanticipated project delays or changes in project costs or plans; 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 natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; unanticipated impacts of restructuring initiatives in the natural gas and electric industries; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; changes in actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; 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; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other 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 or to reflect the occurrence of unanticipated events.

Item 9.01 Financial Statements and Exhibits.

     (d) Exhibits

Exhibit 99 Presentation materials furnished for the Howard Weil 38th Annual Energy 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/ Paula M. Ciprich
	Paula M. Ciprich
	Secretary

Dated: March 22, 2010

EXHIBIT INDEX

Exhibit Number	Description
99	Presentation materials furnished for the Howard Weil 38th Annual Energy Conference

EX-99

Exhibit 99

Howard Weil Energy Conference March 23, 2010

Safe Harbor For Forward Looking Statements 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: financial and economic conditions, including the availability of credit, and their effect on the Company's ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments; occurrences affecting the Company's ability to obtain financing under credit lines or other credit facilities or through the issuance of commercial paper, other short-term notes or debt or equity securities, including any downgrades in the Company's credit ratings and changes in interest rates and other capital market conditions; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers' ability to pay for, the Company's products and services; the creditworthiness or performance of the Company's key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from terrorist activities, acts of war, major accidents, fires, hurricanes, other severe weather, pest infestation or other natural disasters; changes in demographic patterns and weather conditions; 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; impairments under the SEC's full cost ceiling test for natural gas and oil reserves; uncertainty of oil and gas reserve estimates; factors affecting the Company's ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, and the need to obtain governmental approvals and permits and comply with environmental laws and regulations; significant differences between the Company's projected and 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 oil having different quality and/or different geographic locations, or changes in the price differentials between natural gas having different heating values and/or different geographic locations; changes in laws and regulations to which the Company is subject, including those involving taxes, safety, employment, climate change, other environmental matters, and exploration and production activities such as hydraulic fracturing; the nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; significant differences between the Company's projected and actual capital expenditures and operating expenses, and unanticipated project delays or changes in project costs or plans; 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 natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; unanticipated impacts of restructuring initiatives in the natural gas and electric industries; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; changes in actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company's pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; 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; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other 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, 2009 and the Company's Form 10-Q for the quarter ended December 31, 2009. 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. The Securities and Exchange Commission (the "SEC") currently permits the Company, in its filings with the SEC, to disclose only proved reserves that the Company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The Company uses the terms "probable," "possible," "resource potential" and other descriptions of volumes of reserves or resources potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines would prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and, accordingly, are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.nationalfuelgas.com. You can also obtain this form on the SEC's website at www.sec.gov.

National Fuel Gas Company Business Segment Reporting Publicly Traded Holding Company NYSE symbol - NFG Reporting Segments Corporate Subsidiaries

National Fuel Gas Company Capital Expenditures(1) from Continuing Operations (CHART) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

National Fuel Gas Company Capital Expenditures - An Appalachian Focus (CHART) (1) (2) Defined as spending related to efforts to drill for, gather, or transport Appalachian sources of natural gas Any other maintenance spending in the Appalachian region, plus spending in areas outside of the Appalachian region

(CHART) Sources and Uses of Cash National Fuel Gas Company 2010 Forecast $ Millions 2011 Forecast $597 NFG Consolidated sources of cash includes cash from operations for all of the Company's segments. $597 $1,096 $1,096 (1) (1)

National Fuel Gas Company Capital Structure (CHART) $2.884 Billion(1) at December 31, 2009 (CHART) Longer- Term Target Capital Structure At December 31, 2009, Comprehensive Shareholders' Equity, Long-Term Debt and the Current Portion of Long-Term Debt totaled $2.884 Billion as presented on the Company's Balance Sheet, of which $1.049 Billion was Long-Term Debt, $0.2 Billion was the Current Portion of Long-Term Debt and $1.635 Billion was Comprehensive Shareholders' Equity

WEST TO EAST PHASE 1 & PHASE 2 APPALACHIAN LATERAL LAMONT COMPRESSOR STATION COVINGTON GATHERING SYSTEM TIOGA COUNTY EXTENSION LINE "N" EXPANSION GALBRAITH STORAGE EAST BRANCH STORAGE 8 WEST TO EAST EXPANSION HORIZONTAL DRILLING ACTIVITY VERTICAL DRILLING ACTIVITY PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES Howard Weil Energy Conference - March 23, 2010

Exploration & Production Seneca Resources Corporation

Exploration & Production Marcellus Shale Accelerate development; convert resource potential to reserves Appalachian Region - Upper Devonian Drill 50-150 wells per year Proved Reserves California Continue to operate as a low-cost producer Gulf of Mexico No exploration; Develop and produce existing reserves 721 Bcfe 4 - 8 Tcfe 35 Bcfe 342 Bcfe Probable Reserves, Possible Reserves, and Resource Potential 130 Bcfe 21 Bcfe 272 Bcfe 21 Bcfe

Exploration & Production Capital Expenditures by Region (CHART) Does not include the $34.9MM acquisition of Ivanhoe's US-based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not included in Capital Expenditures.

Exploration & Production Annual Production by Region Marcellus Gulf of Mexico Upper Devonian West Production (Bcfe) 75 55?70 60 44 - 51 20?29 45 40.8 42.5 5.0?7.0 39.3 14.1 13.7 11.0?13.5 30 14.7 8?10 7.9 8.7 8.5?9.5 8?10 6.3 15 18.3 18.8 20.1 19.5?21.0 19?21 0 Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Forecast Forecast 12 Howard Weil Energy Conference - March 23, 2010

Exploration & Production California

Seneca's California Properties South Lost Hills 2,100 BOEPD Monterey Shale Primary 221 Active Wells Sespe 900 BOEPD Sespe Formation Primary 192 Active Wells North Lost Hills 1,200 BOEPD Tulare & Etchegoin Formation Primary & Steamflood 202 Active Wells North Midway Sunset 4,300 BOEPD Potter & Tulare Formation Steamflood 694 Active Wells South Midway Sunset 600 BOEPD Antelope Formation Steamflood 59 Active Wells

California Average Daily Production 2009 Average Daily Production Up ~ 550 BOEPD vs. 2008: Marvic drilling @ MWSS Sespe property exchange Improved steaming efficiency Ivanhoe Acquisition Strategy: Modest Capital spending to maintain production Pursue additional bolt-on acquisitions (CHART) Ivanhoe Acquisition

West Division Ivanhoe Acquisition Acquisition(July 2009) Current(Jan. 2010) Oil Price $58 $72 PV10 (Proved) $42.1MM $70.3MM LOE $17.56/BOE $10.97/BOE Completed 14 well development program First well went into production on February 10, 2010 South Midway Sunset Production: 600 BOE/d 900 BOE/d by Mid-2010 1,000 BOE/d by Mid-2011

? ? ? ? ? ? 50' 100' 50' 100' Sand shaled- out ? ? Antelope "A" Sand Antelope Sands - Net Pay Isochores Seneca Western Minerals 252F-20 Midway Sunset South Ivanhoe Acquisition Seneca Western Minerals 282J Drilled Jan 2010 - 1st Well in SE Pool Seneca Western Minerals 252F Drilled Jan 2010 - Oil Discovery Antelope "B" Sand Antelope "C" Sand Section 19 Section 20 2010 Drilling Locations Updip Sand Pinch-Out Approx. Oil/Water Contact Oil / Water Contact Top Antelope "A" 125 ft Net Pay Base

Gulf of Mexico Exploration & Production

Gulf of Mexico Average Daily Production Minimal Capital spending in 2010 Production Holding steady (CHART)

Marcellus Shale Exploration & Production

Marcellus Shale Seneca Acreage Position Seneca Seneca Cabot Chesapeake Seneca/EOG Range Resources SRC Fee/Lease 21 Howard Weil Energy Conference -- March 23, 2010

Marcellus Shale EOG Joint Venture Overview & Results Approx. Outline of JV Acreage 200,000 Gross Acres Seneca 50% W.I. (Avg. 58% NRI) EOG 50% W.I. (40% NRI) EOG Acreage Contributed ~120,000 Gross Acres Seneca 50% W.I. (40% NRI) EOG Operated 16 Horizontals Drilled; 6 frac'd IP: 1-4 MMCFD EURs: 2-3 BCF Not Yet Producing EOG Operated 4 Horizontals Drilled; 4 frac'd IP: 2-4 MMCFD EURs: 2-3 BCF Net Production: 3.0 MMCFD EOG Operated 2 Horizontals Drilled; 2 frac'd IP: 1-2 MMCFD EURs: 1-2 BCF Net Production: 0.8 MMCFD EOG

Marcellus Shale Seneca Drilling Program Results Seneca Operated 9 Horizontals Drilled 6 frac'd IP: 5-10+ MMCFD EURs: 4-6 BCF Net Production: ~20 MMCFD Seneca Operated 2 Horizontals Drilled 1 frac'd IP: 3.9 MMCFD EUR: 3 BCF EOG

Marcellus Shale Horizontal Drilling Results EOG Total 32 Horizontals Drilled 18 Frac'd and Completed 10 Gross Wells Producing Net Production: 25-30 MMCFD

IP: 5.7, 4.8 MMCFPD IP: 9.5 MMCFPD Last 30 Days: 11.0 MMCFD IP: 9.3, 7.5 MMCFPD IP: 7.8 MMCFD off map to south Marcellus Shale Covington Area Structure Map Currently drilling

Marcellus Shale Marcellus Net Production MMBtu/d 30,000 25,000 20,000 15,000 10,000 5,000 EOG Operated JV Wells Seneca Op. #1 Seneca Op. #2 Seneca Op. #3 Seneca Op. #4 Seneca Op. #5 26 Howard Weil Energy Conference -- March 23, 2010

Fiscal 2010 Marcellus Shale Drilling Plan Marcellus Shale Develop JV focus area (EOG Operated) 20-30 wells September 2010 net production 10-20 MMcfd Develop Tioga focus area (Seneca Operated) 20-25 wells Current net production ~20 MMcfd September 2010 net production 30-50 MMcfd De-risk and prioritize additional areas: 10-15 wells (includes some verticals) Minimal production in Fiscal Year 2010 2-3 new focus areas by September 2010

(CHART) Marcellus Shale Wells Drilled per Year

Marcellus Shale Western Development Area Pre-Tax IRR: 3.0 BCF EUR; $4.0 MM Well Cost (CHART) JV Wells on Seneca Mineral Fee 100% Wells on Seneca Mineral Fee Typical 15% Royalty Rate

Seneca Full-Cycle Economics Superior to Most Competitors Marcellus Shale Minimal Acreage Cost Mostly Fee (Seneca owns minerals) Average cost < $100/acre Low Royalty Mostly Fee (0% royalty) Acres contributed to EOG JV have 50% WI/ 58% NRI Rode the Learning Curve at minimal cost Early EOG JV wells at no cost to Seneca Experienced PA Operator - Top-Notch Team Long history of PA operations First Horizontal drilled in 17 days Average 1-Week IP: 7.0 MMCFD

Seneca Resources Summary Use excess cash flow from California to develop Marcellus Maintain production Low-cost producer Produce-out Gulf of Mexico Minimal Capex Expect fairly robust production in fiscal 2010 Focus on the Marcellus 7-day IPs averaging 7.0 MMCFD on first three Seneca operated wells Plan 50-70 horizontal wells in Fiscal 2010 $260-280 Million (80% of Fiscal 2010 E&P Capex) Expect net 20-30 40-70 MMCFD by September 2010 Expect net 30-50 80-120 MMCFD by September 2011

APPENDIX

National Fuel Gas Company Corporate & Financial Highlights

Net Plant by Segment (CHART) National Fuel Gas Company

Net Income from Continuing Operations Excluding Items Impacting Comparability (1) National Fuel Gas Company A reconciliation to GAAP Net Income is included at the end of this presentation. (CHART) (CHART) $210.7 Million 12 Months Ended At December 31, 2009 E&P $103.1 MM 48.9%

National Fuel Gas Company 2010 EPS Guidance & Sensitivity NFG & Subsidiaries The earnings guidance and sensitivity table are current as of February 5, 2010. 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, As of February 5, 2010, for its fiscal 2010 earnings guidance, the Company is utilizing flat commodity pricing of $5.00 per MMBtu for natural gas and $75.00 per Bbl for crude oil, and adjusting for basis differential Seneca Resources Production Guidance: 44 to 51 Bcfe Fiscal 2010 Fiscal 2010 Fiscal 2010 Fiscal 2010 Fiscal 2010 Fiscal 2010 Fiscal 2010 Preliminary Earnings per Share (Diluted) Guidance(1) Preliminary Earnings per Share (Diluted) Guidance(1) Preliminary Earnings per Share (Diluted) Guidance(1) Preliminary Earnings per Share (Diluted) Guidance(1) Preliminary Earnings per Share (Diluted) Guidance(1) Preliminary Earnings per Share (Diluted) Guidance(1) Preliminary Earnings per Share (Diluted) Guidance(1) Range Range Consolidated Earnings Consolidated Earnings Consolidated Earnings $2.40 - $2.70(2) $2.40 - $2.70(2) Earnings per Share Sensitivity to Changes from $5.00/MMBtu for natural gas and $75.00/Bbl for crude oil(1) Earnings per Share Sensitivity to Changes from $5.00/MMBtu for natural gas and $75.00/Bbl for crude oil(1) Earnings per Share Sensitivity to Changes from $5.00/MMBtu for natural gas and $75.00/Bbl for crude oil(1) Earnings per Share Sensitivity to Changes from $5.00/MMBtu for natural gas and $75.00/Bbl for crude oil(1) Earnings per Share Sensitivity to Changes from $5.00/MMBtu for natural gas and $75.00/Bbl for crude oil(1) $1 change per MMBtu gas $1 change per MMBtu gas $1 change per Bbl oil $1 change per Bbl oil Increase Decrease Increase Decrease +$0.06 -$0.06 +$0.04 -$0.04 and with the settling of NYMEX hedge contracts at their maturity. For its fiscal 2010 earnings forecast, the Company is using flat commodity pricing of $5.00 per MMBtu for natural gas and $75.00 per Bbl for crude oil, and adjusting for basis differential.

National Fuel Gas Company Dividend Growth (CHART) $1.34 $0.19 Compound Annual Growth Rate 5.2% National Fuel has had 107 uninterrupted years of dividend payments and has increased its dividend for 39 consecutive years

Ranked the 4th best energy company in 2009 Report Based on the 4-year averages of: Profit Margin Dividend Yield FCF, ROE, ROA Sustainable Growth Consistently in the Top 10 best energy companies (2006-2009 Reports) "National Fuel Gas ... strongly positioned in gas markets from the well to the burner tip." Public Utilities Fortnightly National Fuel Gas Company

National Fuel Gas Company Peer Group Comparisons Peer Group Total Return E&P Peers 119% National Fuel 70% Diversified Peers 60% Utility Peers 28% 1-Year Total Return Peer Group Total Return National Fuel 30% E&P Peers 4% Utility Peers 3% Diversified Peers -7% 3-Year Total Return Peer Group Total Return National Fuel 107% E&P Peers 79% Diversified Peers 37% Utility Peers 29% 5-Year Total Return National Fuel's Diversified business model continues to generate long-term outperformance versus its peer groups by limiting downside risk through economically challenging times and capturing upside growth in an expanding market All returns for the period ending February 2010, share prices adjusted for all dividend payments Diversified Peers: D, EGN, EP, EQT, MDU, STR, WMB; Utility Peers: AGL, ATO, CPK, NI, NJR, NWN, SWX, UGI, WGL; E&P Peers: BRY, CHK, CNX, COG, CRZO, EOG, KWK, PVA, PETD, PQ, RRC, SM, SWN, SFY

National Fuel Gas Company Debt Maturity Schedule (CHART) Fiscal Year Total Long-Term Debt Outstanding At December 31, 2009: $1.249 B

National Fuel Gas Company Capital Resources & Credit Ratings Capital Resources(1) $300.0 MM Commercial Paper Program and Uncommitted Credit Facilities - Aggregate of $720.0 MM $300.0 MM Committed Credit Facility through September 2010 - backs Commercial Paper Program RATING AGENCY RATING FITCH A- MOODY'S Baa1 STANDARD & POOR'S BBB CURRENT CREDIT RATINGS 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.

Exploration & Production Seneca Resources Corporation

Exploration & Production Proved Reserves (CHART) Proved Reserves @ 9/30 491 Bcfe 503 Bcfe 528 Bcfe West - California Reserves: 342 Bcfe (64%) (57 Mmboe) FY '09 Production: 20.1 Bcfe (47%) Gulf of Mexico Reserves: 35 Bcfe (7%) FY '09 Production: 13.7 Bcfe (32%) East - Appalachia Reserves: 151 Bcfe (29%) FY '09 Production: 8.7 Bcfe (21%)

Marcellus Shale Company Net Acres Shares Outstanding (MM) Acres/1K Shares Seneca Resources 738,000 80.5 9.17 Range Resources 1,400,000 157.4 8.89 Atlas Energy Resources LLC 519,000 78.1 6.65 Carrizo Oil & Gas 108,000 31.1 3.47 EQT Corp. 445,000 130.9 3.40 Chesapeake Energy 1,520,000 644.5 2.36 Cabot Oil & Gas 179,500 103.7 1.73 EXCO Resources 348,000 211.5 1.65 CNX Gas 250,000 151.0 1.66 Ultra Petroleum 170,000 151.4 1.12 EOG Resources 240,000 252.3 0.95 Seneca is One of the Largest Marcellus Acreage Holders Taken from UBS research report, dated February 16, 2010; top 11 acreage holders sorted by acres/1,000 shares outstanding. The most Marcellus acreage per share outstanding (1)

Marcellus Shale Western Development Area Decline Curve - 3.0 BCF Estimated Ultimate Recovery (EUR) (CHART) Category Type Curve Parameters Initial Rate 3,550 MCF/D Average first year decline 68% Final decline 6% Hyperbolic Coefficient 1.6 Abandonment rate 10 MCF/D Average first month rate 3,090 MCF/D Average first year rate 1,580 MCF/D EUR 3.0 BCF

Upper Devonian Development Drilling (CHART)

National Fuel Gas Supply Corporation Empire Pipeline, Inc. Pipeline & Storage

PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES 48 WEST TO EAST EXPANSION HORIZONTAL DRILLING ACTIVITY VERTICAL DRILLING ACTIVITY WEST TO EAST PHASE 1 & PHASE 2 APPALACHIAN LATERAL LAMONT COMPRESSOR STATION COVINGTON GATHERING SYSTEM TIOGA COUNTY EXTENSION LINE "N" EXPANSION GALBRAITH STORAGE EAST BRANCH STORAGE Covington Gathering System - Phase I Covington Gathering System - Phase I Planned Capacity 100,000 Dth/d In-Service Date 11/17/2009 Estimated CAPEX Investment ~$16 MM Project flowing into the Tennessee 300 Line Project flowing into the Tennessee 300 Line Howard Weil Energy Conference - March 23, 2010

49 WEST TO EAST EXPANSION HORIZONTAL DRILLING ACTIVITY VERTICAL DRILLING ACTIVITY WEST TO EAST PHASE 1 & PHASE 2 APPALACHIAN LATERAL LAMONT COMPRESSOR STATION COVINGTON GATHERING SYSTEM TIOGA COUNTY EXTENSION LINE "N" EXPANSION GALBRAITH STORAGE EAST BRANCH STORAGE PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES Lamont Compressor Station Lamont Compressor Station Planned Capacity 40,000 Dth/d Planned Compression 1,150 HP Anticipated In-Service Date June 2010 Estimated CAPEX Investment ~$6 MM Construction under FERC Blanket Certificate Construction under FERC Blanket Certificate Howard Weil Energy Conference - March 23, 2010

50 WEST TO EAST EXPANSION HORIZONTAL DRILLING ACTIVITY VERTICAL DRILLING ACTIVITY WEST TO EAST PHASE 1 & PHASE 2 APPALACHIAN LATERAL LAMONT COMPRESSOR STATION COVINGTON GATHERING SYSTEM TIOGA COUNTY EXTENSION LINE "N" EXPANSION GALBRAITH STORAGE EAST BRANCH STORAGE PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES Line "N" Expansion Line "N" Expansion Planned Capacity 150,000 Dth/d Planned Compression 4,700 HP Anticipated In-Service Date November 2011 Estimated CAPEX Investment $23 MM Preparing FERC Application for April Filing Preparing FERC Application for April Filing Howard Weil Energy Conference - March 23, 2010

51 WEST TO EAST EXPANSION HORIZONTAL DRILLING ACTIVITY VERTICAL DRILLING ACTIVITY WEST TO EAST PHASE 1 & PHASE 2 APPALACHIAN LATERAL LAMONT COMPRESSOR STATION COVINGTON GATHERING SYSTEM TIOGA COUNTY EXTENSION LINE "N" EXPANSION GALBRAITH STORAGE EAST BRANCH STORAGE PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES Tioga County Extension Tioga County Extension Planned Capacity >300,000 Dth/d Anticipated In-Service Date September 2011 Estimated CAPEX Investment $45 MM Negotiating Precedent Agreements Negotiating Precedent Agreements Howard Weil Energy Conference - March 23, 2010

52 WEST TO EAST EXPANSION HORIZONTAL DRILLING ACTIVITY VERTICAL DRILLING ACTIVITY WEST TO EAST PHASE 1 & PHASE 2 APPALACHIAN LATERAL LAMONT COMPRESSOR STATION COVINGTON GATHERING SYSTEM TIOGA COUNTY EXTENSION LINE "N" EXPANSION GALBRAITH STORAGE EAST BRANCH STORAGE PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES West to East - Phases I & II West to East - Phases I & II Planned Combined Capacity 425,000 Dth/d Anticipated In-Service (Phase I) November 2011 Anticipated In-Service (Phase II) November 2012 Estimated CAPEX Investment $260 MM Ongoing post-open season negotiations Ongoing post-open season negotiations Howard Weil Energy Conference - March 23, 2010

53 WEST TO EAST EXPANSION HORIZONTAL DRILLING ACTIVITY VERTICAL DRILLING ACTIVITY WEST TO EAST PHASE 1 & PHASE 2 APPALACHIAN LATERAL LAMONT COMPRESSOR STATION COVINGTON GATHERING SYSTEM TIOGA COUNTY EXTENSION LINE "N" EXPANSION GALBRAITH STORAGE EAST BRANCH STORAGE PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES East Branch & Galbraith Storage Expansion East Branch & Galbraith Storage Expansion Planned Capacity 7.9 Bcf Planned Compression 11,245 HP Anticipated In-Service Date April 2013 Estimated CAPEX Investment $64 MM 35 New Wells & 12.4 Miles of Pipe 35 New Wells & 12.4 Miles of Pipe Howard Weil Energy Conference - March 23, 2010

54 Utility Segment National Fuel Gas Distribution Corporation Howard Weil Energy Conference - March 23, 2010

55 National Fuel Gas Distribution Corporation Service Territory Howard Weil Energy Conference - March 23, 2010

56 New York Revenue Decoupling Conservation Incentive Program Merchant Function Charge Low Income Rates 90/10 Sharing (Revenue Decoupling for Industrial Load) Weather Normalization Pennsylvania Low Income Rates Pending: Revenue Decoupling Choice Program Rate Mechanisms Utility Howard Weil Energy Conference - March 23, 2010

57 Utility Average Use per Residential Customer Fiscal Year TME Howard Weil Energy Conference - March 23, 2010

58 Howard Weil Energy Conference - March 23, 2010 Accounts Receivable - Customer (1) (1) All values include Purchase of Receivables ("POR") Program Utility

59 Howard Weil Energy Conference - March 23, 2010 As of February 19, 2010 Program year opens in November HEAP/LIHEAP (1) (2) Utility

60 Howard Weil Energy Conference - March 23, 2010 National Fuel Gas Company Comparable GAAP Financial Measure Slides and Reconciliations 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.

Reconciliation to Income from Continuing Operations by Segment to Consolidated GAAP Net Income
     ($ Thousands)

	FY 2007			FY 2008			FY 2009			12 Mos. Ended 12/31/2009
GAAP Net Income
E&P Segment GAAP Net Income	$	210,669		$	146,612		$	(10,238	)	$	103,097
P&S Segment GAAP Net Income		56,386			54,148			47,358			40,537
Utility Segment GAAP Net Income		50,886			61,472			58,664			59,589
Marketing Segment GAAP Net Income		7,663			5,889			7,166			7,659
Corporate & All Other GAAP Net Income		11,851			607			(2,242	)		(2,997	)
Total GAAP Net Income	$	337,455		$	268,728		$	100,708		$	207,885
Discontinued Operations
Income (Loss) from Operations, Net of Tax	$	15,479		$	—		$	—		$	—
Gain on Disposal, Net of Tax		120,301			—			—			—
Income (Loss) from Discontinued Operations, Net of Tax	$	135,780		$	—		$	—		$	—
Income from Continuing Operations
E&P Segment Income from Continuing Operations	$	74,889		$	146,612		$	(10,238	)	$	103,097
P&S Segment Income from Continuing Operations		56,386			54,148			47,358			40,537
Utility Segment Income from Continuing Operations		50,886			61,472			58,664			59,589
Marketing Segment Income from Continuing Operations		7,663			5,889			7,166			7,659
Corporate & All Other Income from Continuing Operations		11,851			607			(2,242	)		(2,997	)
Total Income from Continuing Operations	$	201,675		$	268,728		$	100,708		$	207,885
Items Impacting Comparability
Reversal of reserve for preliminary project costs (P&S)	$	(4,787	)	$	—		$	—		$	—
Resolution of purchased gas contingency (Marketing)		(2,344	)		—			—			—
Discontinuance of hedge accounting (P&S)		(1,888	)		—			—			—
Gain on sale of turbine (Corporate & All Other)		—			(586	)		—			—
Gain on life insurance policies (Corporate & All Other)		—			—			(2,312	)		—
Impairment of investment partnership (Corporate & All Other)		—			—			1,085			—
Impairment of landfill gas assets (Corporate & All Other)		—			—			2,786			2,786
Impairment of oil and gas properties (E&P)		—			—			108,207			—
Total Items Impacting Comparability	$	(9,019	)	$	(586	)	$	109,766		$	2,786
Income from Continuing Operations after Items Impacting Comparability
E&P Segment Operating Income	$	74,889		$	146,612		$	97,969		$	103,097
P&S Segment Operating Income		49,711			54,148			47,358			40,537
Utility Segment Operating Income		50,886			61,472			58,664			59,589
Marketing Segment Operating Income		5,319			5,889			7,166			7,659
Corporate & All Other Operating Income		11,851			21			(683	)		(211	)
Total Income from Continuing Operations after Items Impacting Comparability	$	192,656		$	268,142		$	210,474		$	210,671

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures
     ($ Thousands)

											FY 2010		FY 2011
	FY 2006		FY 2007		FY 2008			FY 2009			Forecast		Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures	$	166,535	$	146,687	$	192,187		$	188,290		$	320,000-370,000	$	425,000-525,000
Pipeline & Storage Capital Expenditures		26,023		43,226		165,520			50,118		$	35,000-45,000	$	200,000-250,000
Utility Capital Expenditures		54,414		54,185		57,457			56,178		$	55,000-60,000	$	55,000-60,000
Marketing, Corporate & All Other Capital Expenditures		5,419		3,501		1,745			8,728		$	45,000-50,000	$	15,000-25,000
Total Capital Expenditures from Continuing Operations		252,391		247,599		416,909			303,314		$	455,000-525,000	$	695,000-860,000
Capital Expenditures from Discountinued Operations
Exploration & Production Capital Expenditures		41,768		29,129		—			—			—		—
Total Capital Expenditures from Discontinued Operations	$	41,768	$	29,129	$	—		$	—		$	—	$	—
Less Accrued Capital Expenditures
Exploration & Production Accrued Capital Expenditures	$	—	$	—	$	—		$	(9,093	)	$	—	$	—
Pipeline & Storage Accrued Capital Expenditures		—		—		(16,768	)		16,768			—		—
All Other Accrued Capital Expenditures		—		—		—			(715	)		—		—
Less Total Accrued Capital Expenditures	$	—	$	—	$	(16,768	)	$	6,960		$	—	$	—
Eliminations		—		—		(2,407	)		(344	)		—		—
Total Capital Expenditures per Statement of Cash Flows	$	294,159	$	276,728	$	397,734		$	309,930		$	455,000-525,000	$	695,000-860,000

Reconciliation of Appalachian Growth Capital Expenditures to
Consolidated Capital Expenditures
($ Millions)

											FY 2010		FY 2011
	FY 2006		FY 2007		FY 2008			FY 2009			Forecast		Forecast
Appalachian Growth Capital Expenditures from Continuing Operations1
Exploration & Production Capital Expenditures — East Division	$	27.0	$	39.1	$	65.8		$	138.6		$	280-315	$	405-475
Less Exploration & Production Accrued Capital Expenditures		—		—		—			(9.1	)		—		—
Pipeline & Storage Appalachian Expansion Capital Expenditures		—		—		—			—		$	5-10	$	155-185
Midstream Capital Expenditures		—		—		—			8.1		$	45-47.5	$	15-22.5
Total Appalachian Capital Expenditures from Continuing Operations	$	27.0	$	39.1	$	65.8		$	137.6		$	330-372.5	$	575-682.5
Other Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures	$	139.5	$	107.6	$	126.4		$	49.7		$	40-55	$	20-50
Pipeline & Storage Capital Expenditures		26.0		43.2		165.5			50.1		$	30-35	$	45-65
Utility Capital Expenditures		54.4		54.2		57.5			56.2		$	55-60	$	55-60
Marketing, Corporate & All Other Capital Expenditures		5.4		3.5		1.7			0.6		$	0-2.5	$	0-2.5
Total Other Capital Expenditures from Continuing Operations	$	225.4	$	208.5	$	351.1		$	156.6		$	125-152.5	$	120-177.5
Capital Expenditures from Discountinued Operations
Exploration & Production Capital Expenditures		41.8		29.1		—			—			—		—
Total Capital Expenditures from Discontinued Operations	$	41.8	$	29.1	$	—		$	—		$	—	$	—
Less Accrued Capital Expenditures
Pipeline & Storage Accrued Capital Expenditures	$	—	$	—	$	(16.8	)	$	16.8		$	—	$	—
All Other Accrued Capital Expenditures		—		—		—			(0.7	)		—		—
Less Total Accrued Capital Expenditures	$	—	$	—	$	(16.8	)	$	16.1		$	—	$	—
Eliminations		—		—		(2.4	)		(0.3	)		—		—
Total Capital Expenditures per Statement of Cash Flows	$	294.1	$	276.7	$	397.7		$	309.9		$	455-525	$	695-860

(1) Defined as spending related to efforts to drill for, gather, or transport Appalachian sources of natural gas.