Exhibit 99

The BMO Capital Markets 2009 North American Unconventional Gas Conference January 13, 2009

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 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; 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; 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 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 natural 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; 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 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; 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, 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.

National Fuel Gas Company Business Segment Reporting

National Fuel Gas Company Capital Expenditures(1) by Segment Utility Pipeline & Storage Exploration & Production (1) Capital Expenditures exclude all expenditures associated with Discontinued Operations

National Fuel Gas Company Net Income from Continuing Operations(1) Timber $0.1 MM Energy Mkt. $5.9 MM 2.2% $268.7 Million 12 Months Ended 9/30/08 Excludes income from Discontinued Operations and any gain/loss on disposal of Discontinued Operations Corp. & All Other $0.5 MM

11 Empire Connector In-service as of December 2008 Storage Expansion Increase Storage Capacity by 8.5 Bcf West to East / Appalachian Lateral Proposed pipeline project Millennium Pipeline

Exploration & Production Seneca Resources Corporation

Exploration & Production Proved Reserves @9/30 491 Bcfe 503 Bcfe West - California Reserves: 339 Bcfe (67%) Prod: 52 Mmcfed (8,600 Boepd) Gulf of Mexico Reserves: 33 Bcfe (7%) Production: 38 Mmcfed East - Appalachia Reserves: 131 Bcfe (26%) Production: 22 Mmcfed

Exploration & Production Capital Expenditures Major shift in capital allocation from higher-risk exploration to lower-risk development will lead to improved Finding & Development costs $208. 3 $175. 8 $192.2 $285 East 2006 2007 2008 2009E 13% 22% 34% 69% West 2006 2007 2008 2009E 17% 24% 33% 19% Gulf of Mexico 2006 2007 2008 2009E 50% 38% 33% 12% Increased Focus Stable Spending Reduced Focus

Marcellus Shale Recent Daily Production Rates Cabot 6.4 MMCFD All production figures from individual company disclosures Marcellus Outcrop Seneca Fee Acreage Seneca Lease Acreage EOG/Seneca Resources 1.4 MMCFD (25 days) Atlas Energy Multiple Verticals: 1-3 MMCFD Chesapeake 2 Well Avg.: 4.5 MMCFD Range Resources Multiple Wells: 1-5 MMCFD Marcellus Fairway

Marcellus Shale 3rd Largest Acreage Holder Company Acres Chesapeake 1,200,000 Range 900,000 Seneca 725,000 Atlas 580,000 ("under control") Equitable 400,000 Chief 350,000 XTO 280,000 Exco 276,000 EOG 220,000 All acreage positions taken from most recent individual company disclosures, available from company websites as of January 6, 2009

Marcellus Shale EOG JV Drilling Update Horizontal Well Summary Drilling Summary 2009: Anticipated 10 Horizontal Wells (1) Horizontal Well #2 was "junked"

Marcellus Shale Seneca Resources-EOG Joint Venture Joint Venture Terms JV Agreement Originated November, 2006, 10 Year Term tied to a Continuous Drilling commitment. Total Acreage EOG can earn 50% WI in 200,000 Seneca acres. Seneca can earn 50% WI in ~120,000 EOG acres. Prospect Selection EOG prospect selection to be completed by March 2009 (Originally - December 2011). Drilling Requirements EOG must ramp up to 60 development wells per year by 2014. Beginning in March 2009, Seneca will have complete control of ~525,000 acres

Marcellus Shale Log and Core Evaluation Depth TVD: 5,000' - 8,000' Thickness 50' - 200' Total Organic Content (TOC) 2% - ^ 10% Thermal Maturity 1% - 3% Effective Porosity 3% - 12% Pressure (psi/foot) 0.43 - 0.65 Water Saturation 12% - 35% Gas-in-Place (Bcfe/Section) 30 - 150 Anticipated EUR/Horizontal Well (Bcfe) 1.0 - 3.0

Marcellus Shale PA State (DCNR) Lease Sale - 9/3/08 Seneca was the high bidder on 4 of 6 tracts Total of the 4 high bids - $74 million 10-year lease terms Lycoming & Tioga Counties Marcellus Shale impact 150-200 potential horizontal well locations Acreage is relatively contiguous in the core area of the play where the shale is thick

Marcellus shale Seneca Operations New DCNR Leases Adjusted EOG JV Terms Seneca as a major Marcellu s Operato r ~525,000 net acres to evaluate as operator Plan to drill 6-8 vertical "test" wells this fiscal year, beginning March '09 Begin horizontal program in July '09 Marcellus acreage prioritized by: Geology Lease Terms Permitting Issues Pipeline infrastructure May partner in some areas, remain 100% in others

Summary Seneca is the third largest acreage holder in the Marcellus Shale play EOG Joint Venture Initial exploration at minimal cost Gained experience of an industry leader 2009 is a big year Development drilling on Joint Venture acreage March '09 - Seneca drilling operations commence

Reconciliation of Exploration & Production Segment Capital Expenditures from Continuing Operations to
      Consolidated Capital Expenditures
($ millions)

	2004		2005		2006		2007			2008			2009 Forecast		2010 Forecast
Exploration & Production Capital Expenditures from Continuing Operations	$	46.3	$	83.9	$	166.5	$	146.7		$	192.2		$	285.0	$	227.0
Pipeline & Storage Capital Expenditures (1)		23.2		21.1		26.0		43.2			165.5			73.0		76.0
Utility Capital Expenditures		55.4		50.1		54.4		54.2			57.5			58.0		60.0
Timber Capital Expenditures		2.8		18.9		2.3		3.7			1.4			1.0		1.0
Corporate & All Other Capital Expenditures		5.7		1.1		3.2		(0.2	)		(2.1	)
Total Corporation — Continuing Operations	$	133.4	$	175.1	$	252.4	$	247.6		$	414.5		$	417.0	$	364.0
Capital Expenditures from Discontinued Operations		38.9		38.5		41.8		29.1			—			—		—
Total Capital Expenditures	$	172.3	$	213.6	$	294.2	$	276.7		$	414.5		$	417.0	$	364.0

(1) Amount for year ended September 30, 2008 includes $16.8 million of accrued capital expenditures related to the Empire Connector project. This amount has been excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represents a non-cash investing activity at that date.

Reconciliation of Segment Net Income from Continuing Operations to
   Consolidated Net Income
(‘000)

	2005		2006			2007		2008
Income from Continuing Operations	$	138,437	$	184,614		$	201,675	$	268,728
Discontinued Operations:
Income (Loss) From Operations, Net of Tax		25,277		(46,523	)		15,479		—
Gain on Disposal, Net of Tax		25,774		—			120,301		—
Income (Loss) From Discontinued Operations, Net of Tax	$	51,051	$	(46,523	)	$	135,780	$	—
GAAP Net Income	$	189,488	$	138,091		$	337,455	$	268,728