Exhibit 99

IPAA OGIS San Francisco October 12-14, 2010 Exhibit 99

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 derivatives, 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 derivatives, 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 Forms 10-Q for the quarters ended December 31, 2009, March 31, 2010 and June 30, 2010. 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 and Forms 10-Q available at www.nationalfuelgas.com. You can also obtain these forms 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 Operating Subsidiaries

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. $217.3 Million 12 Months Ended June 30, 2010 Revenue

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.

Exploration & Production Marcellus Shale Accelerate development; Convert resource potential to reserves Appalachian Region - Upper Devonian Drill 25-50 wells per year Preliminary Proved Reserves at 9/30/10(1) California Continue to operate as a low-cost producer Gulf of Mexico No exploration; Develop and produce existing reserves 700 Bcfe 8 - 15 Tcfe 34 Bcfe 333 Bcfe Probable and Possible Reserves, plus Resource Potential 131 Bcfe 201 Bcfe 280 Bcfe 15 Bcfe Proved reserves at September 30, 2010 are preliminary and subject to final approval from reserve auditor, Netherland Sewell

Exploration & Production Capital Expenditures by Region 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 30%

Exploration & Production Seneca Operating Cash Margins Source: Raymond James estimates and Company Reports

Exploration & Production California

Seneca's California Properties South Lost Hills 1,900 BOEPD Monterey Shale Primary 216 Active Wells Sespe 1,000 BOEPD Sespe Formation Primary 182 Active Wells North Lost Hills 1,200 BOEPD Tulare & Etchegoin Formation Primary & Steamflood 221 Active Wells North Midway Sunset 4,100 BOEPD Potter & Tulare Formation Steamflood 709 Active Wells South Midway Sunset 650 BOEPD Antelope Formation Steamflood 74 Active Wells

California Average Daily Production Modest capital spending to maintain production Pursue additional bolt-on acquisitions 2011 Plans: CapEx - $40 MM 50 Development wells Two 5-acre in-fill wells at Sespe

Gulf of Mexico Exploration & Production

Gulf of Mexico Average Daily Production Minimal capital spending Expect production decline in 2011

East Division Exploration & Production

East Division Average Daily Production Rapid growth in the East Division as Marcellus is ramping up Expect significant production increase in Q1

Marcellus Shale Recent Well Results Validate Seneca's Position McKean County SM Energy IP: 7+ MMCFD SRC Fee Acreage Clearfield County Seneca/EOG IP: 8.9 MMCFD Lycoming County Seneca Resources IP: 15.8 MMCFD Armstrong County EQT IP: 15 MMCFD Elk County Seneca Resources IP: 3.9 MMCFD

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 30 Horizontals Drilled; 8 frac'd Small Fracs: 2-4 MMCFD Big Frac: 8 MMCFD EOG Operated 5 Horizontals Drilled; 4 frac'd Small Fracs: 2-4 MMCFD EOG Operated 2 Horizontals Drilled; 2 frac'd Small Fracs: 1-2 MMCFD EOG

Marcellus Shale Seneca Operated Drilling Program Results 25 Horizontals Drilled 15 frac'd 10 Producing IP: 5-13 MMCFD Net Production: ~45 MMCFD IP: 3.9 MMCFD 2 Horizontals Drilled IP: 1.4 - 2.0 MMCFD IP: 2.2 MMCFD EOG IP: 15.8 MMCFD

Actual Declines flatter than "type" curves 6 BCF "Typecurve" 4 BCF "Typecurve" 3 BCF "Typecurve" 5 BCF "Typecurve" Initial 30-day average for 7 Tioga County wells = 7.0 MMCFD Tioga County Decline Curves

Marcellus Shale Pennsylvania Average Gas Production per Well by Operator (Companies with at least 5 wells producing) Source: All data represents Marcellus Shale gas production from July 1, 2009 through June 30, 2010 for companies with at least five producing wells within the State of Pennsylvania and was provided by the Pennsylvania Department of Environmental Protection

Marcellus Shale Marcellus Net Production Seneca Operated EOG JV Marcellus net production as of September 30, 2010 was: 57 MMcfe per day

Marcellus Shale Wells Drilled per Year

Marcellus Shale Pre-Tax IRR Comparison Description EUR Well Cost ($ MM) Net Working Interest Net Revenue Interest Pre-Tax IRR (NYMEX - $/MMBtu) Pre-Tax IRR (NYMEX - $/MMBtu) Pre-Tax IRR (NYMEX - $/MMBtu) Description EUR Well Cost ($ MM) Net Working Interest Net Revenue Interest $4.00 $5.00 $6.00 Tioga County - 15% Royalty Wells 5 Bcf $4.0 100% 85% 43% 76% 104% EOG JV Wells on Seneca Mineral Fee 3 Bcf $4.0 50% 60% 35% 55% 82% No Royalty Wells on Seneca Mineral Fee 3 Bcf $4.0 100% 100% 22% 39% 55% Typical Well with 15% Royalty Rate 3 Bcf $4.0 100% 85% 14% 26% 40%

Seneca Resources Evaluation of JV Opportunities Seneca has engaged Jefferies & Company to explore joint-venture opportunities across a broad portion of its acreage, with the following goals: Ramp up development faster than current aggressive growth plans Bring forward the earnings stream, where a minority-interest partner pays a significant portion of the early drilling costs, enhancing shareholder value Continue operating across most of its acreage position Seneca's unique Marcellus position provides a competitive advantage for a potential joint-venture partner: 800,000 net acres in PA - 740,000 in heart of the Marcellus Fairway Majority of acreage is held in fee, carrying no royalty and no lease expirations Large, contiguous acreage blocks allow for operating- and cost-efficiency through multi-well pad drilling

Seneca Resources Marcellus Shale Summary Bringing on 12 new wells in Tioga County in September and October Continuing to achieve high IP rates and showing slow decline Fourth horizontal rig is on location Will have 3 rigs in East and 1 in West for 1st half of FY2011 EOG Program is picking up and showing improvement First "big frac" came on at high rate Infrastructure constrained at Punxy Marcellus production will continue to grow rapidly Fiscal Year 2010 exit rate was 57 MMCFD Expect net 100+ MMCFD by fiscal year end 2011 (9/30/2011) Explore joint-venture opportunities

National Fuel Gas Company Dividend Growth $1.38 $0.19 Compound Annual Growth Rate 5.1% National Fuel has had 108 uninterrupted years of dividend payments and has increased its dividend for 40 consecutive years

National Fuel Gas Company 2011 Preliminary EPS Guidance & Sensitivity NFG & Subsidiaries The preliminary earnings guidance and sensitivity table are current as of August 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, and with the settling of hedge contracts at their maturity. For its fiscal 2011 preliminary earnings forecast, the Company is using flat commodity pricing of $5.00 per MMBtu for natural gas and $80.00 per Bbl for crude oil, and adjusting for basis differential. On August 5, 2010, the Company announced its preliminary fiscal 2011 earnings guidance utilizing flat commodity pricing of $5.00 per MMBtu for natural gas and $80.00 per Bbl for crude oil, and adjusting for basis differential Seneca Resources Preliminary Production Guidance: 60 to 70 Bcfe Fiscal 2011 Fiscal 2011 Fiscal 2011 Fiscal 2011 Fiscal 2011 Fiscal 2011 Fiscal 2011 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 $2.60 - $2.90(1) $2.60 - $2.90(1) Earnings per Share Sensitivity to Changes from $5.00/MMBtu for natural gas and $80.00/Bbl for crude oil(1) Earnings per Share Sensitivity to Changes from $5.00/MMBtu for natural gas and $80.00/Bbl for crude oil(1) Earnings per Share Sensitivity to Changes from $5.00/MMBtu for natural gas and $80.00/Bbl for crude oil(1) Earnings per Share Sensitivity to Changes from $5.00/MMBtu for natural gas and $80.00/Bbl for crude oil(1) Earnings per Share Sensitivity to Changes from $5.00/MMBtu for nat ural gas and $80.00/Bbl for crude oil(1) $1 change per MMBtu gas $1 change per MMBtu gas $5 change per Bbl oil $5 change per Bbl oil Increase Decrease Increase Decrease +$0.19 -$0.19 +$0.06 -$0.06

National Fuel Gas Company Debt Maturity Schedule Fiscal Year Total Long-Term Debt Outstanding At June 30, 2010: $1.249 B

National Fuel Gas Company Capital Resources & Credit Ratings Capital Resources $300.0 MM Commercial Paper Program and Uncommitted Credit Facilities - Aggregate of $705.0 MM $300.0 MM Committed Credit Facility through September 2013 - Backs Commercial Paper Program RATING AGENCY RATING FITCH BBB+ MOODY'S Baa1 STANDARD & POOR'S BBB CURRENT CREDIT RATINGS

Utility Segment National Fuel Gas Distribution Corporation

(1) Calculated using Average Total Comprehensive Shareholder Equity. Utility Return on Equity (1)

Utility NFGDC Rate Base New York Ratemaking uses an average net plant and rate base for setting rates and calculating earnings Pennsylvania Ratemaking uses a date certain net plant and rate base for setting rates and calculating earnings (1) (2)

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

WEST TO EAST OVERBECK TO LEIDY APPALACHIAN LATERAL LAMONT COMPRESSOR STATION PHASE I & II COVINGTON GATHERING SYSTEM TIOGA COUNTY EXTENSION LINE "N" EXPANSION PHASE I & II 36 PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES NORTHERN ACCESS IPAA OGIS San Francisco - October 12-14, 2010 TROUT RUN GATHERING SYSTEM

Pipeline & Storage/Midstream Expansion Initiatives Project Name Capacity (Dth/D) Est. CapEx In-Service Date Status Covington Gathering System 145,000 $16 MM 11/17/09 Completed - Flowing into TGP 300 Line Lamont Compressor Station 40,000 $6 MM 6/15/10 Completed - Flowing into TGP 300 Line Lamont Phase II Project 50,000 $7 MM ~ 07/2011 Executed precedent agreements Line "N" Expansion 160,000 $23 MM ~ 09/2011 Filed FERC 7(c) application on 6/11/10. Negotiating final precedent agreement for 10,000 Dth/day Tioga County Extension 350,000 $46 MM ~ 09/2011 Filed FERC 7(c) filing on August 23, 2010 Trout Run Gathering System 250,000 $40 MM Fall 2011 Preliminary work has begun Northern Access Expansion 320,000 $60 MM Late 2012 Executed precedent agreement Line "N" Phase II Expansion ~195,000 $40 MM ~ 11/2012 Executed precedent agreement for 150,000 Dth/day W2E Overbeck to Leidy 425,000 $260 MM 2013 Pursuing post-Open season requests for remaining 300,000 Dth/day

Exploration & Production Seneca Resources Corporation

Exploration & Production Fiscal Year 2010 Preliminary Proved Reserves(1) Proved Reserves @ 9/30 503 Bcfe 528 Bcfe 699 Bcfe West - California Reserves: 333 Bcfe (49%) (55.5 MMBoe) FY '10E Production(2): +- 19.7 Bcfe (40%) Gulf of Mexico Reserves: 34 Bcfe (5%) FY '10E Production(2): +-13.5 Bcfe (27%) East - Appalachia Reserves: 332 Bcfe (46%) FY '10E Production(2): +-16.6 Bcfe (33%) Proved reserves at September 30, 2010 are preliminary and subject to final approval from reserve auditor, Netherland Sewell Fiscal year 2010 production data are preliminary and subject to change (1)

Marcellus Shale Water Use Recovering water discharged from an abandoned coal mine which was polluting a local trout stream Authorized by SRBC to withdraw approximately 500,000 gallon per day of mine discharge Water pipeline system supplies frac water for Seneca in Tioga County (90 wells) Can supply water for 3 fracs per month Cost of system ~ $3.7 million Savings ~ $120,000 per well (pay out: 31 wells) Other Benefits: Improved stream quality Substantial reduction of water truck activity No need to withdraw water elsewhere

Marcellus Shale Western Development Area "Type" Decline Curve - 3.0 BCF Estimated Ultimate Recovery (EUR) 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

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 of Income from Continuing Operations by Segment to Consolidated GAAP Net Income ($ Thousands) 12 Mos. Ended FY 2007 FY 2008 FY 2009 6/30/2010 GAAP Net Income E&P Segment GAAP Net Income 210,669 $ 146,612 $ (10,238) $ 113,173 $ P&S Segment GAAP Net Income 56,386 54,148 47,358 35,812 Utility Segment GAAP Net Income 50,886 61,472 58,664 60,616 Marketing Segment GAAP Net Income 7,663 5,889 7,166 8,129 Corporate & All Other GAAP Net Income 11,851 607 (2,242) (3,220) Total GAAP Net Income 337,455 $ 268,728 $ 100,708 $ 214,510 $ 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) $ 113,173 $ P&S Segment Income from Continuing Operations 56,386 54,148 47,358 35,812 Utility Segment Income from Continuing Operations 50,886 61,472 58,664 60,616 Marketing Segment Income from Continuing Operations 7,663 5,889 7,166 8,129 Corporate & All Other Income from Continuing Operations 11,851 607 (2,242) (3,220) Total Income from Continuing Operations 201,675 $ 268,728 $ 100,708 $ 214,510 $ 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 excluding Items Impacting Comparability E&P Segment Operating Income 74,889 $ 146,612 $ 97,969 $ 113,173 $ P&S Segment Operating Income 49,711 54,148 47,358 35,812 Utility Segment Operating Income 50,886 61,472 58,664 60,616 Marketing Segment Operating Income 5,319 5,889 7,166 8,129 Corporate & All Other Operating Income 11,851 21 (683) (434) Total Income from Continuing Operations excluding Items Impacting Comparability 192,656 $ 268,142 $ 210,474 $ 217,296 $

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 $425,000-500,000 Pipeline & Storage Capital Expenditures 26,023 43,226 165,520 50,118 $35,000-45,000 $100,000-150,000 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 $20,000-30,000 $15,000-25,000 Total Capital Expenditures from Continuing Operations 252,391 247,599 416,909 303,314 $430,000-505,000 $595,000-735,000 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 $ $430,000-505,000 $595,000-735,000