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): January 9, 2012

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

New Jersey	1-3880	13-1086010
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer 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):

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

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

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

¨ 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 the BMO Capital Markets 9th Annual Unconventional Resource Conference in New York, New York on January 10, 2012. 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 materials furnished as part of this Current Report, including statements regarding estimated future earnings and statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will” and “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: 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, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production

activities such as hydraulic fracturing; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in the price of natural gas or oil; changes in the availability, price or accounting treatment of derivative financial instruments; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, 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 major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; changes in price differential between similar quantities of natural gas at different geographic locations, and the effect of such changes on the demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of oil or natural gas having different quality, heating value, geographic location or delivery date; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; significant differences between the Company’s projected and actual capital expenditures and operating expenses; 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; 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 thereof.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit 99 Furnished presentation materials dated January 10, 2012

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

Dated: January 9, 2012

EXHIBIT INDEX

Exhibit Number	Description
99	Furnished presentation materials dated January 10, 2012

EX-99

Exhibit 99

Investor Presentation

BMO Capital Markets Unconventional Resource Conference January 10, 2012

National Fuel Gas Company January 10, 2012

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: 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, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in the price of natural gas or oil; changes in the availability, price or accounting treatment of derivative financial instruments; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, 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 major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; changes in price differential between similar quantities of natural gas at different geographic locations, and the effect of such changes on the demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of oil or natural gas having different quality, heating value, geographic location or delivery date; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; significant differences between the Company’s projected and actual capital expenditures and operating expenses; 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; 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.

Forward looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves 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.

For a discussion of the risks set forth above 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, 2011. The Company disclaims any obligation to update any forward looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events.

(1) Footnote #1 goes here

(2) Footnote #2 goes here 2

Core Businesses January 10, 2012

Integrated Business Structure

Seneca Resources Corporation Empire Pipeline & NFG Supply Corp.

?Significant Appalachian Growth ?Appalachian Pipeline Growth

Leading Marcellus Shale Position Delivery to Growth Markets

Evaluate Utica/Geneseo Shales ?Create Flexible System Exploration Pipeline ?Growing/Predictable EPS

?Stable Oil Production

Significant Cash Flow & & Supports Dividend and Credit Profile

Production Storage

Midstream

NFG Distribution Corp. NFG Midstream Corp.

?Focus on Customer Service Utility ?Appalachian Gathering Growth and Safety Initial Focus on Seneca Acreage

Energy

?Cost Control and Revenue

Protection Marketing Midstream National Fuel Resources, Inc.

?Stable, Predictable Earnings ?Limited Capital, Limited Risk

Supports Dividend and Credit Profile

?Expand into Neighboring Markets

?Maintain Customer Contact

(1) Footnote #1 goes here

(2) Footnote #2 goes here 3

National Fuel Gas Company January 10, 2012

Integrated Business Structure

(1) Footnote #1 goes here

(2) Footnote #2 goes here 4

National Fuel Gas Company January 10, 2012

Consolidated Capital Expenditures

$1,500 Utility Pipeline & Storage Exploration & Production Midstream & Other

s) $1,015 $1,250 $1,185 Million $40 $85 $ $1,000

( $854 s

$750 $785 $875 penditure $501 $500 $417 $649 Ex $192 $307 $398 $250 Capital $166 $188 $129 $135 $165

$53

$0 $57 $56 $58 $58 $55 60

2008 2009 2010 2011 2012 Forecast Fiscal Year

(1) Footnote #1 goes here Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

(2) Footnote #2 goes here 5

Exploration & Production January 10, 2012

(1) Footnote #1 goes here

(2) Footnote #2 goes here 6

Seneca Resources January 10, 2012

Continued Improvement in Finding & Development Costs

Three Year Average U.S Finding & Development Cost

$8.00 $7.38 $7.63 /Mcfe)

$ $6.00

( $5.35 Cost F&D $4.00 Ye ar

3- $2.37

$2.09

$2.00

$0.00

2005 2007 2006 2008 2007 2009 2008 2010 2009 2011

Fiscal Years

(1) Footnote #1 goes here

(2) Footnote #2 goes here 7

Seneca Resources January 10, 2012

Uniquely Positioned in Pennsylvania

??Held over 700,000 Marcellus acres before the play received any attention

??Have since added another 45,000 acres in the core of the play

??80% of acreage is held in fee

?No royalty

?No lease expirations

??In addition to Marcellus, Seneca has a major position in emerging plays:

?Utica Shale

?Geneseo Shale (Upper Devonian)

Proved Reserves Risked Prospective at 9/30/11 Resource Net Acres (BCFE) Potential Marcellus Shale 745,000 491 8 15 TCFE Geneseo Shale 300,000 TBD Utica Shale TBD TBD

(1) Footnote #1 goes here

(2) Footnote #2 goes here 8

Marcellus Shale January 10, 2012

Seneca’s Development Areas

Eastern Development Area (Mostly Leased)

Western Development Area (Mostly Fee and HBP)

SRC Fee Acreage SRC Lease Acreage EOG Acreage

(1) Footnote #1 goes here

(2) Footnote #2 goes here 9

Seneca Resources January 10, 2012

Marcellus Shale Strategic Development Plan

Gross Rig Count ??Aggressively Develop our excellent

16 Tioga and Lycoming County leasehold

Seneca EOG

12 ??Systematically evaluate western

Count 8.5 acreage Rig 8

6 3

ross G 4.5 1.5 ??Begin development of western acres

4

2

1.5 5.5 that are “de risked”

4.5 2.5 0

2009 2010 2011 2012 ??Continue participation with EOG on

Fiscal Year Joint Venture acreage

(1) Footnote #1 goes here

(2) Footnote #2 goes here 10

Marcellus Shale January 10, 2012

3 – Step Development Strategy

1. Area evaluation

??Vertical wells and cores

??3 well horizontal “test” pads

??2D and 3D seismic

2. Optimization

??Landing depth

??Frac design

??Lateral length

??Locations

3. Development Economies of Scale

??Multi well pads

??Crawling rigs

??Batch drill top holes, then horizontal

??Large scale infrastructure

??Water systems fresh water ponds, pipeline system

(1) Footnote #1 goes here

(2) Footnote #2 goes here 11

Marcellus Shale January 10, 2012

Eastern Development Area (EDA) – Results & Plan Forward

Covington – Developed

47 Wells Drilled – 47 Producing

Gross Production: ~100 MMcf/d

DCNR Tract 595 – Full Development

19 Wells Drilled – 4 Producing

Gross Production: ~10 MMcf c /d

FY 2012: 2 Rigs

DCNR Tract 100 – Full Development

5 Wells Drilled

SRC Fee Acreage 1 Well Completed IP: 15.8 MMcf/d

FY 2012: 2 Rigs

SRC Lease Acreage

(1) Footnote #1 goes here

(2) Footnote #2 goes here 12

Marcellus Shale January 10, 2012

EDA Typecurve – 6.7 Bcfe EUR (Greater Than 3,500’ Lateral)

12.0 Original 6.0 Bcf Typecurve

EDA Average Daily Production Rate IP Rate 7,250 MMcf/d 6.7 Bcf Typecurve (40 Year Life) Hyp. Coeff. 1.4 10.0 Decline 72% 6.0 Bcf Typecurve (40 Year Life) Exp. Tail 6% st (MMcf) Current: 1 Segment 8.0 IP Rate 5,400 MMcf/d Current: Compression Segment te Ra Hyp. Coeff. 1.25 IP Rate 3,800 MMcf/d Decline 65.5% Hyp. Coeff. 1.25 6.0 Limit 6 Mo. Decline 48% roduction Exp. Tail 6% P

Daily 4.0 2.0

Lower Production Bound 0.0

0 2 4 6 8 10 12 14 16 18 20 22 24 Month

(1) Footnote #1 goes here

(2) Footnote #2 goes here 13

Marcellus Shale

January 10, 2012

Western Development Area (WDA) – Results & Plan Forward

SRC Fee Acreage

SRC Lease Acreage

SRC Contributed JV Acreage

EOG Contributed JV Acreage

Approx. Outline of JV Acreage

200,000 Gross Acres

Seneca 50% W.I. (Avg. 58% NRI)

Mt. Jewett – Delineating

3 Horizontal Wells

IPs: ~3 MMCFD

Rich Valley - Delineating

Drilling

Owl’s Nest – Full Development

3 Wells Drilled: Optimized Target Zone

Expected IP’s: 4-5 MMcf/d

FY 2012: 1 Rig

Acquiring 3D Seismic

Boone Mountain - Delineating

Testing 3 Horizontal Wells

First well IP: 3.8 MMCFD

Second Well IP: 4.2 MMCFD

Punxy – Full Development

EOG Operated: 63 Wells Drilled; 33 Producing

FY 2012: 2 Rigs

Gross Production (As of 1/1/12): 42 MMCFD

Seneca Operated

EOG Operated

SENECA RESOURCES

(1) Footnote #1 goes here

(2) Footnote #2 goes here

14

Marcellus Shale January 10, 2012

Breaking Down Our Acreage Position

Possible Wells

Area Net Acres Locations Wells Drilled Completed EUR (Bcfe) Status Eastern Development Area (EDA)

Covington 7,000 47 47 47 5.5 Developed 595 6,000 55 19 4 7.0 Full Development 100 10,000 70 5 1 8.0 Full Development 007 15,000 75 1 1 3.0 5 .0 Delineating 001 13,000 58 1 1 3.0 5 .0 Delineating Other EDA 4,000 10 3.0 8 .0 Untested

55,000 315 73 54 Western Development Area (WDA)

Owl’s Nest / Ridgeway 91,000 680 3 3 4.0 Full Development Mt. Jewett 25,000 232 4 4 3.0 Delineating James City 30,000 340 1 1 3.0 5 .0 Delineating Boone Mtn 8,500 59 4 4 4.0 Delineating Rich Valley 30,000 188 4.0 5 .0 Delineating WDA Other 337,000 2,654 4 3 2.0 6 .0 Untested

521,500 4,153 16 15 EOG Operated

Punxy 12,000 87 63 33 4.0 Full Development West Branch 12,500 121 7 5 3.0 5 .0 Delineating Clermont 10,000 96 2 2 3.0 5 .0 Delineating Brady 13,500 113 4.0 5 .0 Untested EOG Other 120,500 502 2 2 2.0 5 .0 Untested

168,500 919 74 42 Seneca Resources Total 745,000 5,387 163 111

(1) Footnote #1 goes here

(2) Footnote #2 goes here 15

Seneca Resources January 10, 2012

Marcellus Acreage Position Provides Superior Economics

Marcellus Economics for a $6.2 Million Well 125%

No Royalty 18% Royalty

100% 90% ??Minimal acreage acquisition cost IRR 75% ??Average NRI: 94%

Tax re- 50%

P 49% ??No lease expiration concerns

34%

25% ??Economies of scale

12% 23% 8% 0%

3.0 5.0 8.0 Gross EUR per Well

(1) Pre Tax IRR determined using the NYMEX forward strip as of November 18, 2011

(1) Footnote #1 goes here

(2) Footnote #2 goes here 16

Marcellus Shale January 10, 2012

Operational Efficiencies Drive Cost Savings

Equipment Ownership

(Frac Tanks, etc…) Pad Cost Reductions Long Term

(Rig Mats, Concrete

Frac Contract

Pads, etc…)

Improved Efficiency

Increased Wells Natural Gas Powered per Pad Leads to Rigs

Improved Costs

Proppant & Chemical External Casing Sourcing Concentrated Packers Regional Development

Total

Drilling Total Completion Completion Total Well Length Cost Drilling Cost Cost Cost D&C Cost

2011 Estimate 4,500’ Lateral $556/Ft $2.5 MM $820/Ft $3.7 MM $6.2 MM

Target $378/Ft $1.7 MM $700/Ft $3.15 MM $4.85 MM

(1) Footnote #1 goes here

(2) Footnote #2 goes here 17

Upper Devonian Geneseo Shale January 10, 2012

Activity Summary East Resources

East Resources 3 Wells Permitted

Drilled & Completed November 2010

Mt. Jewett Vertical (Seneca) April 2010

Depth: 5,095’; Thickness: 110’

DCNR 001 Horizontal (Seneca)

Depth: 5,830’; Thickness: 77’

Peak Rate: 4.5 MMcf/d

East Resources

1 Well Permitted December 2010

PGE

12 Wells Permitted (April 2009 to August 2010)

2 Wells Drilled (February 2010)

(1) Footnote #1 goes here

(2) Footnote #2 goes here 18

Utica Shale January 10, 2012

Activity Summary

Seneca Resources Seneca Resources

Vertical Completed Dry Gas

Vertical Well Permit Prep to Test Vertical Completed: December 2011 Moving in rig for horizontal well

Horizontal Well Permit Drilled Well

Chesapeake

3.1 MMcf/d

1,015 Bbl/d Wet

Seneca Resources Chesapeake

Dry Rex Energy Horizontal to Spud 2Q ‘12

3.8 MMcf/d

9.2 MMcf/d 980 Bbl/d

Chesapeake

9.5 MMcf/d Chesapeake

1,425 Bbl/d 6.4 MMcf/d

(1) Footnote #1 goes here

(2) Footnote #2 goes here 19

Utica Shale January 10, 2012

Mt. Jewett Vertical Well

Seneca Resources recently drilled a vertical Utica/Pt. Pleasant well in McKean County, PA. Preliminary results are encouraging.

?Potential pay spans the Utica, Pt. Pleasant and portions of the Trenton Formations

?Dry Gas

?Moving in rig to spud horizontal well

Wet Dry

(1) Footnote #1 goes here

(2) Footnote #2 goes here 20

California January 10, 2012

Stable Production Fields

North Lost Hills

~1,150 BOEPD

Tulare & Etchegoin Formation South Lost Hills Primary & Steamflood ~1,700 BOEPD 181 Active Wells Monterey Shale Primary 216 Active Wells

North Midway Sunset

~4,350 BOEPD

Potter & Tulare Formation

Steamflood Sespe 703 Active Wells ~1,000 BOEPD

Sespe Formation Primary

South Midway Sunset 193 Active Wells

~800 BOEPD Antelope Formation Steamflood 100 Active Wells

(1) Footnote #1 goes here

(2) Footnote #2 goes here 21

California January 10, 2012

Strong Margins Support Significant Free Cash Flow

Fiscal Year 2011 Net Income and Expenses per BOE

Income tax 21%

DDA 13%

Cash Non Steam Fuel LOE Net Income Expenses 12% $35.50

$31.88

Other 6%

DD&A

DD&A

$10.21 Steam Fuel 4%

G&A 3% Average Price ($/BOE) = $77.59

Net Income 41%

(1) Footnote #1 goes here

(2) Footnote #2 goes here 22

Seneca Resources January 10, 2012

Capital Spending Shifting to the Marcellus

$1,250

California Upper Devonian Marcellus Gulf of Mexico

$1,000

Millions) $785 875 ( $

$750

$649

$500 $398

xpenditures $740 820 E $585 Capital $250 $192 $188 $332

$64

$61 $71 $68

$63 $31(1) $47 $45 55 $0

2008 2009 2010 2011 2012 Forecast Fiscal Year

(1) Footnote #1 goes here (1) Does not include the $34.9 MM acquisition of Ivanhoe’s U.S. based assets in California, as this was accounted for as an investment in subsidiaries on the Statement (2) Footnote #2 goes here of Cash Flows, and was not included in Capital Expenditures 23

Seneca Resources January 10, 2012

Ramping Up Production Growth

125

California Upper Devonian Marcellus Gulf of Mexico

100 Annual production 87 101 growth of ~30% to (Bcfe) ~50% is expected n 75 from 2011 to 2012 67.6 5.2 62 72

49.7

Productio 50 42.5 l 40.8 13.4 35.3 14.1 13.7 Annua 7.2

25 8.7 9.3 7.9 6 8 7.9

18.8 20.1 19.8 19.2 19 21 0 2008 2009 2010 2011 2012 Forecast Fiscal Year

(1) Footnote #1 goes here

(2) Footnote #2 goes here 24

Pipeline & Storage / Midstream January 10, 2012

(1) Footnote #1 goes here

(2) Footnote #2 goes here 25

Pipeline & Storage January 10, 2012

Positioned to Move Growing Marcellus Production

NORTHERN

TIOGA ACCESS

COUNTY EXPANSION

EXTENSION

(In Service)

CENTRAL TIOGA

LAMONT

COUNTY COMPRESSOR

EXTENSION STATION PHASE I & II

(In Service)

COVINGTON GATHERING

SYSTEM TROUT RUN (In Service)

LINE “N” GATHERING 2012 SYSTEM

EXPANSION

WEST TO EAST OVERBECK TO

LEIDY

LINE “N” EXPANSION

(In Service)

(1) Footnote #1 goes here

(2) Footnote #2 goes here 26

Midstream January 10, 2012

Critical To Boosting Returns in the Marcellus

??Midstream’s gathering systems are

TGP 300 critical to unlock remote, but highly productive Marcellus acreage

Tioga County

??Goal is to first work to assist Seneca and then gather 3rd party producer volumes

??History of operational success and efficiency within Pennsylvania

Lycoming County

??Continuously evaluating opportunities to grow along with the rapid Transco development of the Marcellus

(1) Footnote #1 goes here

(2) Footnote #2 goes here 27

National Fuel Gas Company January 10, 2012

Targeted Capital Structure

Debt Equity

Utility 50% 50%

Equity P&S 50% 50% 55% 65% Debt

35% 45%

E&P 30% 70%

All Other 40% 60%

Capital Structure Long Term Consolidated Targets by Segment Capital Structure Target

(1) Footnote #1 goes here

(2) Footnote #2 goes here 28

National Fuel Gas Company January 10, 2012

Appendix

(1) Footnote #1 goes here

(2) Footnote #2 goes here 29

National Fuel Gas Company January 10, 2012

Manageable Debt Maturity Schedule

$600 2012 Debt Maturity Paid on November 21, 2011 $500

$500

illions) $400 M

( $ $300 aturity $300 $250 $250

M $200

Debt $150

$100 7.395%

$49 $50

700% . 250% . 500% . . 750% . 900% 7.375%

$0 6 5 6 8 4

Fiscal Year

(1) Footnote #1 goes here

(2) Footnote #2 goes here 30

National Fuel Gas Company January 10, 2012

Strong Dividend Track Record

$1.60

National Fuel has had 109 uninterrupted $1.40 years of dividend payments and has increased its dividend for 41 consecutive years

Rate $1.20 d $1.00

Dividen $0.80

ual $0.60

Ann Compound Annual $0.40 Growth Rate

$0.20 5.0% $0.00

Annual Rate at Fiscal Year End

(1) Footnote #1 goes here

(2) Footnote #2 goes here 31

National Fuel Gas Company January 10, 2012

Hedge Positions and Strategy

Hedged Forecasted Production

As of January 10, 2012 Volume Average

100% Oil Swaps (MMBbl) Hedge Price

Fiscal 2012 1.6 $77.03 / Bbl Hedged 80% Fiscal 2013 0.9 $86.21 / Bbl n Fiscal 2014 0.2 $94.90 / Bbl

60%

47%

Productio Natural Gas Volume Average Hedge d 40% Swaps (Bcf) Price

Fiscal 2012 35.0 $5.89 / Mcf

21%

Forecaste 20% Fiscal 2013 23.9 $5.67 / Mcf of Fiscal 2014 4.6 $5.89 / Mcf

3% %

0%

2012 2013 2014

Most hedges executed at sales point to

Fiscal Year eliminate basis risk

(1) Footnote #1 goes here

(2) Footnote #2 goes here 32

National Fuel Gas Company January 10, 2012

Capitalization & Liquidity

Short Term Debt 1.3%

Capital Resources Long Term

Debt

?Total Short Term Capacity: $1,135 Million

Shareholders’ 35.2%

?Committed Credit Facility: $750 Million

?Five year syndicated facility entered into Equity January 6, 2012 63.5%

?Uncommitted Lines of Credit: $385 Million

?$300.0 MM Commercial Paper Program backed by Committed Credit Facility

$2.981 Billion

Fiscal Year Ended 2011(1)

(1) Includes Current Portion of Long Term Debt of $150 million at September 30, 2011.

(1) Footnote #1 goes here

(2) Footnote #2 goes here 33

Pipeline & Storage / Midstream January 10, 2012

(1) Footnote #1 goes here

(2) Footnote #2 goes here 34

Pipeline & Storage January 10, 2012

Expansion Initiatives

Capacity Est. In Service

Project Name Market Status (Dth/D) CapEx Date

Lamont Compressor Station 40,000 $6 MM 6/2010 Fully Subscribed Completed

Lamont Phase II Project 50,000 $7.6 MM 7/2011 Fully Subscribed Completed

Line “N” Expansion 160,000 $20 MM 10/2011 Fully Subscribed Completed

Tioga County Extension 350,000 $49 MM 11/2011 Fully Subscribed Completed

Received Certificate from FERC in October Northern Access Expansion 320,000 $62 MM ~11/2012 Fully Subscribed 2011

Line “N” 2012 Expansion 150,000 $36 MM ~11/2012 Fully Subscribed Certificate application filed in July 2011

Marketing continues with producers in West to East ~425,000 $290 MM ~2014 29% Subscribed various stages of exploratory drilling

Central Tioga County Open Season Evaluating market interest and facility 260,000 $135 MM ~2014 Extension Closed design

Total Firm Capacity: ~1,755,000 Dth/D

Capital Investment: ~$606 MM

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Midstream Corporation January 10, 2012

Expansion Initiatives

Capacity Est. In Service

Project Name Market Status (Dth/D) CapEx Date

Completed – Flowing into TGP Covington Gathering System 100,000 $16 MM 11/17/09 Fully Subscribed 300 Line

Covington Gathering System Completed Increased total 40,000 $1.7 MM 3/7/2011 Fully Subscribed Expansion 140 system capacity to 140,000 Dth/d

Covington Gathering System Will increase total system 80,000 $3.5 MM 4/2012 Fully Subscribed Expansion 220 capacity to 220,000 Dth/d

Trout Run Gathering System 466,000 $60 MM Q2 FY2012 70% Subscribed Under construction Owl’s Nest Gathering System 50,000 $17 MM Q3 FY2012 Fully Subscribed Preliminary work underway Mt. Jewett Gathering System 170,000 $22 MM Q3 FY2012 Fully Subscribed Preliminary work underway

Total Firm Capacity: ~906,000 Dth/D Capital Investment: ~$120 MM

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Utility January 10, 2012

National Fuel Gas Distribution Corporation

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Utility January 10, 2012

Continued Cost Control

$350

All Other O&M Expenses $300 O&M Expense Uncollectibles

Millions) $250 $203 $ $203

( $200 $191 $179

$27 $25 $181

$27 $14 $11 Expense $150

$100 $178

O&M $176 $164 $167 $168

$50

$0

2007 2008 2009 2010 2011

Fiscal Year

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Utility January 10, 2012

Financial Stability Return on Equity

30.0% NY PA

Allowed ROE NY Approx. Settled ROE PA

quity 20.0% 18.8% E 14.0% 13.2% 14.7% on

10.9% 10.6% 10.5%

9.8% Return 10.0%

0.0%

2008 2009 2010 2011

Fiscal Year

Rate Mechanisms New York & Pennsylvania

??Low Income Rates

??Choice Program/POR

??Merchant Function Charge New York only

??Revenue Decoupling

??90/10 Sharing

??Weather Normalization

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Exploration & Production January, 10 2012

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Marcellus Shale January, 10 2012

Geotechnical Keys to Success

1. 3D Seismic Data

??Impacts surface location, lateral length and target zone by imaging faults and structure

??Attribute and fracture analyses being conducted to determine if natural fractures and stress regime can be identified

2. Natural Fractures

??Impacts Initial Production (IP) & Estimated Ultimate Recovery (EUR) per well; Varies by area.

3. Target Zone

??Impacts IP & EUR per well; Varies by area.

4. Stress Regime

??Impacts completion efficiency; Varies by area.

5. Optimize Lateral Length

??Cost versus IP/EUR per well; Currently evaluating.

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Marcellus Shale January 10, 2012

Expanding 3D Seismic Coverage

DCNR 001 DCNR 007 Mt. Jewett West Branch Covington

DCNR 595

Owl’s Nest DCNR 100

Punxy Completed – 190,000 ac In Progress – 128,000 ac

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Marcellus Shale January, 10 2012

Importance of 3D Seismic in Identifying Fractures

DCNR 007 5H Well

Drilled prior to 3D Seismic acquisition

Well Test: 2 MMcf/d

TGP 300

DCNR 007 Tioga County

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Marcellus Shale January 10, 2012

3D Seismic Analysis: Fracture Patterns?

DCNR 007 5H Well

In a localized area with minimal fractures

Fault

5H

Major Fractures

DCNR 007

Remainder of DCNR Tract 007

Tioga County

Evidence for significant natural fractures

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Marcellus Shale January 10, 2012

Importance of Closure Stress & Target Zone

Closure Stress & Target Zone

?High Closure Stress

Impacts frac initiation & limits frac width. Avoid high closure stress “pinch points”.

?Currently optimizing

Target Zones in each area.

Higher

Best zone a function of

Closure Stress rock quality, brittleness,

“pinch point” and stress regime.

Owl’s Nest Elk County

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Marcellus Shale January 10, 2012

Owl’s Nest – Improved IP’s by Optimizing The Target Zone

Moving into Full Development

3H Production Results

Treated Lateral: 4,396’

Peak Rate: 4.47 MMcf/d

3 Day Avg.: 4.25 MMcf/d

“Narrowed” Union Springs Target Zone: 15’

Cherry 5,750’ Valley

5,800’

Onondaga Carb

Frac Stages

11 of 20 Stages in Union Springs Target

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Marcellus Shale January, 10 2012

Cost Savings from Multi Well Pad Drilling

1 Well per Pad 6 Wells per Pad

Location & Road Costs ?Location & Road Costs

??$600,000 per well ??$100,000 per well

?Rig Mobilization ?Rig Mobilization

??$600,000 per well ??$100,000 per well

?Ancillary Drilling Costs (Trucking, etc.) ?Ancillary Drilling Costs (Trucking, etc.)

??$150,000 per well ??$25,000 per well

?Frac Mobilization ?Frac Mobilization

??$7,000 per well ??$1,200 per well

?Water Hauling vs. Infrastructure ?Water Hauling vs. Infrastructure

??$200,000 per well ??$50,000 per well

Cost Savings of Pad Drilling: ~$1.2 Million per Well

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Marcellus Shale January 10, 2012

Water Management Program

?Water Sourcing:

Coal mine runoff

Permitted freshwater sources

Recycled water

?Water Management:

Instituted a “Zero Surface Discharge” policy

Recycle Marcellus flowback and produced water

Centralized water handing in development areas ??Tioga County – DCNR 595 and Covington ??Lycoming County – DCNR 100 ??Elk County Owl ‘s Nest

Installing new evaporative technology

Investigating underground injection

Seneca is committed to protecting the surface from any type of pollution

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Marcellus Shale January 10, 2012

“Zero Liquid Discharge Operation”

?Utilizing a state of the art evaporative technology to ensure no liquid is discharged at the surface

Building centrally located units in the Western Development Area (WDA) and the Eastern Development Area (EDA)

Removes all liquids from the production stream

Has the ability to be powered by the waste heat from a compressor station

End products:

Non hazardous solidified salt material

Clean water vapor emissions

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National Fuel Gas Company January 10, 2012

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.

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Reconciliation of Segment Capital Expenditures to

        Consolidated Capital Expenditures

        ($ Thousands)

	FY 2008			FY 2009			FY 2010			FY 2011			FY 2012 Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures	$	192,187		$	188,290		$	398,174		$	648,815		$	785,000-875,000
Pipeline & Storage Capital Expenditures		165,520			52,504			37,894		$	129,206		$	135,000-165,000
Utility Capital Expenditures		57,457			56,178			57,973		$	58,398		$	55,000-60,000
Marketing, Corporate & All Other Capital Expenditures		1,614			9,829			7,311		$	17,767		$	40,000-85,000
Total Capital Expenditures from Continuing Operations	$	416,778		$	306,801		$	501,352		$	854,186		$	1,015,000-1,185,000
Capital Expenditures from Discountinued Operations
All Other Capital Expenditures		131			216		$	150		$	—		$	—
Plus (Minus) Accrued Capital Expenditures
Exploration & Production FY 2011 Accrued Capital Expenditures	$	—		$	—		$	—		$	(63,460	)	$	—
Pipeline & Storage FY 2011 Accrued Capital Expenditures		—			—			—			(7,271	)		—
All Other FY 2011 Accrued Capital Expenditures		—			—			—			(1,389	)		—
Exploration & Production FY 2010 Accrued Capital Expenditures		—			—			(55,546	)		55,546			—
Exploration & Production FY 2009 Accrued Capital Expenditures		—			(9,093	)		9,093			—			—
Pipeline & Storage FY 2008 Accrued Capital Expenditures		(16,768	)		16,768			—			—			—
All Other FY 2009 Accrued Capital Expenditures		—			(715	)		715			—			—
Total Accrued Capital Expenditures	$	(16,768	)	$	6,960		$	(45,738	)	$	(16,574	)	$	—
Eliminations	$	(2,407	)	$	(344	)	$	—		$	—		$	—
Total Capital Expenditures per Statement of Cash Flows	$	397,734		$	313,633		$	455,764		$	837,612		$	1,015,000-1,185,000