EX-99

Investor Presentation

Analyst Day

September 9, 2011

Exhibit 99

September 9, 2011

National Fuel Gas Company

Schedule of Speakers

Time

Presenter

Topic

8:00 -

8:20 am

Dave Smith

Chairman & Chief Executive Officer

Corporate Overview

8:20 -

8:35 am

Matt Cabell

President -

Seneca Resources Corporation

Exploration & Production

Overview

8:35 –

9:00 am

John McGinnis

Senior Vice President -

Seneca Resources Corporation

Exploration & Production

Geology/New Plays

9:00 -

9:20 am

Barry McMahan

Senior Vice President -

Seneca Resources Corporation

Exploration & Production

Operations/Environment

9:20 –

9:40 am

Ron Tanski

President and Chief Operating Officer

Pipeline & Storage

Midstream

9:40 –

9:50 am

Anna Marie Cellino

President -

National Fuel Gas Distribution Corporation

Utility Overview

9:50 -

10:10 am

Dave Bauer

Treasurer and Principal Financial Officer

Financial Update

10:10 -

10:45 am

Question & Answer Session

September 9, 2011

National Fuel Gas Company

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 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 terrorist activities, acts of war, major accidents, fires, severe weather, pest infestation or natural disasters; 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, the need to obtain governmental approvals and permits,

and compliance with environmental laws and regulations; 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; uncertainty of oil and gas reserve estimates; significant differences between the

Company’s projected and actual production levels for natural gas or oil; significant changes in market dynamics or competitive factors affecting the Company’s ability to retain existing customers or

obtain new customers; 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; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the availability and/or cost of derivative financial instruments; changes

in the 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; changes in the projected

profitability of pending or potential projects, investments or transactions; significant differences between the Company’s projected and actual capital expenditures and operating expenses; delays or

changes in costs or plans with respect to the Company’s 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; 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.

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, 2010 and the Company’s Forms 10-Q for the periods ended December 31, 2010, March 31, 2011 and June 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.

September 9, 2011

Core Businesses

Integrated Business Structure

September 9, 2011

Core Businesses

Integrated Business Structure

E&P –

Gulf of Mexico

Sawmills

Landfill Gas

Gas-Fired Generation

Seneca Energy II

Model City

ESNE

Non-Core Assets

September 9, 2011

National Fuel Gas Company

Unique Asset Mix Creates Operational Value

Seneca

Resources

Energy

Marketing

Midstream

Gathering

Utility

Pipeline &

Storage

The

interconnected

nature

the

current

asset

mix

creates

many

operational

efficiencies and synergies

The

Company’s

gathering

and

interstate

pipeline

network,

opportunities

and

capabilities allow for largely unfettered growth in Seneca’s production

National

Fuel

Resources

and

the

NFG

Distribution

Corporation

are

large

customers

the

interstate

pipeline

and

storage

network

Many

internal

resources,

including

facilities

and

employees,

are

shared

and

partially

allocated

subsidiaries,

leading

efficiencies

and

streamlined

operations

September 9, 2011

National Fuel Gas Company

Our Business Mix Leads to Long-Term Value Creation

The strategic and financial benefits created by the integrated mix of businesses has

continued to generate significant long-term value for the Company

The mix of rate-regulated and non-regulated businesses have generated total

shareholder returns that have outperformed over the long-term

The

rate-regulated

returns

–

which

are

not

commodity

price

sensitive

–

provide

downside protection while unregulated returns provide significant upside

opportunity

Coordinated development of infrastructure and Marcellus acreage improves the

present value of all operations

The Company’s strong credit profile lowers the cost of capital for all of our businesses

Seneca

Resources

Utility

Pipeline &

Storage

Energy

Marketing

Midstream

Gathering

September 9, 2011

National Fuel Gas Company

Seneca Resources Joint Venture Discussions

Initial acreage price targets met

by several parties

Several other negotiating points,

each with an associated value or

other significant consequence,

were not mutually agreed upon

Aggressive growth plans were

more compelling than any

current joint venture opportunity

Not capital constrained

September 9, 2011

National Fuel Gas Company

Significant Growth Related to the Marcellus Shale

September 9, 2011

National Fuel Gas Company

2014 –

Where We Are Headed

Significant Ramp Up in Capital Expenditures to Fuel Marcellus Expansion

2011 to 2014: Growing Capital Expenditures at an 18% CAGR

2014 Forecasted Capital Spending: $1.3 to $1.6 Billion

Rapidly Growing Production Through Marcellus Development

2011 to 2014: Growing Production at a 41% CAGR

2014 Forecasted Production: 160 -

200 Bcfe

Transform the Pipeline & Storage Segment

2011 to 2014: Growing Throughput at a 20% CAGR

2014 Forecasted Throughput: ~600 Bcf

Maintain a Strong Balance Sheet

Will be able to maintain targeted Equity-to-Capitalization of 55% to 65%

Cash from Operations is forecasted to double from 2011 to 2014

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Exploration & Production

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Seneca Resources

Our Growth Story

Not the same company we were just a few years ago

Will continue to grow dramatically

Production and reserves expected to triple or quadruple

from 2010 to 2014

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

Have since added another 40,000 acres in the core of the play

In addition to Marcellus, Seneca has acreage in emerging plays:

Utica Shale: significant untested potential

Geneseo Shale (Upper Devonian): ~300,000 prospective acres

Outstanding oil producing assets in California provide steady production

and cash flow

September 9, 2011

Seneca Resources

Major Transformation Over the Past Five Years

Capital Expenditures

2006:

70%

Gulf

Mexico

and

Canada

Production

2006-2009:

Declining

Production

3-Year Average F&D Cost

2006-2008:

$7.63

per

Mcfe

Capital Expenditures

Gulf of Mexico and Canada have been

sold.

2011:

90%

for

Marcellus

Shale

Production

2010-2013:

Production

expected

triple

3-Year Average F&D Cost

2008-2010:

$2.37

per

Mcfe

Then

Now

From Gulf of Mexico Wildcatting to Marcellus Resource Development

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Seneca Resources

Top Tier Acreage and Resource Position

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Seneca Resources

Continued Improvement in Finding & Development Costs

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Seneca Resources

Ramping Up Production Growth

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Seneca Resources

Capital Spending Shifting to the Marcellus

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Seneca Resources

Marcellus Acreage Position Provides Superior Economics

(1)

Pre-Tax IRR determined using the NYMEX forward strip as of August 19, 2011

September 9, 2011

Seneca Resources

Marcellus Shale Strategic Development Plan

Aggressively Develop our excellent

Tioga and Lycoming County leasehold

Systematically evaluate western

acreage

Begin development of western acres

that are “de-risked”

Continue participation with EOG on

Joint Venture acreage

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Seneca’s Development Areas

SRC Lease Acreage

SRC Fee Acreage

Eastern Development Area

(Mostly Leased)

Western Development Area

(Mostly Fee and HBP)

EOG Acreage

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Eastern Development Area (EDA) –

Results & Plan Forward

DCNR Tract 001 –

Delineating

1 Well Drilled –

IP: 4 MMcf/d

Geneseo Well Test –

IP: 2.9 MMcf/d

Acquired 3D Seismic (June, ‘11)

FY 2012: Drill 2 Horizontal Wells

SRC Lease Acreage

SRC Fee Acreage

DCNR Tract 007 -

Delineating

1 Well Drilled –

IP: 2 MMcf/d

Acquired 3D Seismic (July, ‘11)

FY 2012: Drill 4 Horizontal Wells

DCNR Tract 595 –

Full Development

6 Wells Drilled –

3 Producing (1 Shut-In)

Gross Production: 8MMcf/d

FY 2012: 3 Rigs (26 Wells Planned)

Covington –

Developed

47 Wells Drilled –

44 Producing

Gross Production: ~100+ MMcf/d

Estimated Avg. EUR: 5.5 Bcf/Well

DCNR Tract 100 –

Full Development

1 Well Drilled–

IP: 15.8 MMcf/d

FY 2012: 1 Rig (12 Wells Planned)

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

EDA Typecurve –

6.7 Bcfe EUR (Greater Than 3,500’

Lateral)

Current:

Segment

IP Rate

5,400 MMcf/d

Hyp. Coeff.

1.25

Decline

65.5%

Limit

6 Mo.

Current:

Compression

Segment

IP Rate

3,800 MMcf/d

Hyp. Coeff.

1.25

Decline

48%

Exp. Tail

Original 6.0 Bcf Typecurve

IP Rate

7,250 MMcf/d

Hyp. Coeff.

1.4

Decline

72%

Exp. Tail

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Western Development Area (WDA) –

Results & Plan Forward

SRC Lease Acreage

SRC Fee Acreage

EOG Contributed JV Acreage

SRC Contributed JV Acreage

Seneca Operated

EOG Operated

Punxy –

Full Development

EOG Operated: 45 Wells Drilled; 25 Producing

FY 2012: 2 Rigs, Drill 33 wells

Gross Production (As of 8/2/11): 36 MMCFD

Owl’s Nest –

Full Development

3 Wells Drilled: Optimized Target Zone

Expected IP’s: 4 –

5 MMcf/d

FY 2012: 2 Rigs, Drill 15 Wells

Acquiring 3D Seismic

Approx. Outline of JV Acreage

200,000 Gross Acres

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

Mt. Jewett -

Delineating

Just drilled 3 Horizontal wells

Completion: Sept. –

Oct.

Boone Mountain -

Delineating

Just drilled 3 Horizontal Wells

Completion: Oct. –

Nov.

Rich Valley -

Delineating

Drill 2 Wells in Fall 2011

Beechwood

3 Wells Drilled

Poor Results;

Absence of

Fractures

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Geotechnical Keys to Success

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

Natural Fractures

Impacts Initial Production (IP) & Estimated Ultimate Recovery (EUR)

per well; Varies by area.

Target Zone

Impacts IP & EUR per well; Varies by area.

Stress Regime

Impacts completion efficiency; Varies by area.

Optimize Lateral Length

Cost versus IP/EUR per well; Currently evaluating.

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Expanding 3D Seismic Coverage

Completed –

190,000 ac

In Progress –

128,000 ac

Punxy

West Branch

Mt. Jewett

DCNR 001

DCNR 007

Covington

DCNR 595

DCNR 100

Owl’s Nest

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Importance of 3D Seismic in Identifying Fractures

TGP 300

DCNR 007 5H Well

Drilled prior to 3D Seismic acquisition

Well Test: 2 MMcf/d

DCNR 007

Tioga County

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

3D Seismic Analysis: Fracture Patterns?

Remainder of DCNR Tract 007

Evidence for significant natural fractures

DCNR 007

Tioga County

Fault

DCNR 007 5H Well

In a localized area with minimal fractures

Major Fractures

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Importance of Closure Stress & Target Zone

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Owl’s Nest –

Improved IP’s by Optimizing The Target Zone

Moving into Full Development

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Breaking Down Our Acreage Position

Area

Net Acres

Possible

Locations

Wells Drilled

Wells

Completed

EUR (Bcfe)

Status

Eastern Development Area (EDA)

Covington

7,000

5.5

Developed

595

6,000

7.0

Full Development

100

10,000

8.0

Full Development

007

15,000

3.0 -

5.0

Delineating

001

13,000

3.0 -

5.0

Delineating

Other EDA

4,000

3.0 -

8.0

Untested

55,000

315

Western Development Area (WDA)

Owl's Nest / Ridgeway

91,000

680

4.0

Full Development

Mt. Jewett

25,000

232

3.0 -

5.0

Delineating

James City

30,000

340

3.0 -

5.0

Delineating

Boone Mtn

8,500

3.0 -

5.0

Delineating

Rich Valley

30,000

188

4.0 -

5.0

Delineating

WDA Other

337,000

2,654

2.0 -

6.0

Untested

521,500

4,153

EOG Operated

Punxy

12,000

4.0

Full Development

West Branch

12,500

121

3.0 -

5.0

Delineating

Clermont

10,000

3.0 -

5.0

Delineating

Brady

13,500

113

4.0 -

5.0

Untested

EOG Other

120,500

502

2.0 -

5.0

Untested

168,500

919

Seneca Resources Total

745,000

5,387

126

September 9, 2011

Marcellus Shale

Strategic Plan Moving Forward

Fiscal Year 2012

Eastern Development Area

Move forward with full development of DCNR 100 (Lycoming) and

DCNR 595 (Tioga)

Drill several additional delineation wells in DCNR 007 (Tioga) and DCNR 001

(Potter) with recently acquired 3D seismic data

Western Development Area

Acquire 3D seismic in Owl’s Nest (Elk) and begin full development

Continue delineation throughout the WDA, including Mt. Jewett (McKean),

Boone Mountain (Elk) and Rich Valley (Cameron)

EOG-Operated Joint Venture

Continue

fully

participate

all

development

and

delineation

wells

2013 and Beyond

Eastern Development Area

Ongoing full development

Western Development Area

Full development at Owl’s Nest area and other fully delineated areas

Continue delineation of new areas

EOG-Operated Joint Venture

Continue

fully

participate

all

development

and

delineation

wells

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

New Plays

Geneseo Shale –

Area Summary

DCNR 001 Horizontal (Seneca)

Depth: 5,830’; Thickness: 77’

Avg. Reservoir TOC: 3.33

Peak Rate: 2.9 MMcf/d; 7-Day Avg. IP: 2.0 MMcf/d

East Resources

Drilled & Completed

April 2010

East Resources

3 Wells Permitted

November 2010

East Resources

1 Well Permitted

December 2010

PGE

12 Wells Permitted (April 2009 to August 2010)

2 Wells Drilled (February 2010)

Mt. Jewett Vertical (Seneca)

Depth: 5,095’; Thickness: 110’

Avg. Reservoir TOC: 3.34

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

New Plays

Utica Shale –

Activity Summary

Seneca Resources

Mt. Jewett Area

Drilled: June 2011

Seneca Resources

Henderson Area

Spud Date: Sept 2011

Seneca Resources

Tionesta Area

Spud Date: 2012

Vertical Well Permit

Horizontal Well Permit

Source rock maturation (Trenton-Black River Research Consortium, 2006)

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

New Plays

Utica Program Update

Seneca Resources recently drilled a vertical Utica/Pt. Pleasant strat test in

McKean County, PA. Preliminary results are encouraging.

400 feet of gross reservoir at a depth of 10,000’

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

Reservoir quality is similar to that of the shallower Marcellus

Mineralogy is considerably different from the Marcellus

Vertical Well Permit

Horizontal Well Permit

September 9, 2011

Marcellus Shale

Drilling Cost Distribution

Estimated

2011

Development

Well

Drilling

Cost:

$2.5

Million

(4,500’

Lateral)

September 9, 2011

Marcellus Shale

Continuously Improving Drilling Efficiency

Wells

per Pad

Average

Lateral Length

Days per Well

(Incl. Mob)

Drill & Suspend Costs

($MM per Well)

Estimated 2011 Drill Cost

6-8

4,500’

$2.5

Target

6-8

4,500’

$1.7

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Completion Cost Distribution

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Completion Cost Trends

Average

$945/ft

Average

$1,221/ft

Average

$730/ft

Completion costs have been recently improving in the Marcellus

September 9, 2011

Marcellus Shale

Operational Efficiencies Drive Cost Savings

Well Length

Drilling

Cost

Total

Drilling Cost

Completion

Cost

Total

Completion

Cost

Total

D&C Cost

2011 Estimate –

4,500’

Lateral

$556/Ft

$2.5 MM

$800/Ft

$3.6 MM

$6.1 MM

Target

$378/Ft

$1.7 MM

$700/Ft

$3.15 MM

$4.85 MM

Long-Term

Frac Contract

Increased Wells

per Pad

Proppant & Chemical

Sourcing

Equipment

Ownership

(Frac Tanks, etc…)

Concentrated

Regional

Development

Pad Cost Reductions

(Rig Mats, Concrete

Pads, etc…)

Natural Gas Powered

Rigs

External Casing

Packers

Improved Efficiency

Leads to

Improved Costs

Marcellus Shale

Cost Savings from Multi-Well Pad Drilling

Location & Road Costs

$600,000 per well

Rig Mobilization

$600,000 per well

Ancillary Drilling Costs (Trucking, etc..)

$150,000 per well

Frac Mobilization

$7,000 per well

Water Hauling vs. Infrastructure

$200,000 per well

1 Well per Pad

Location & Road Costs

$100,000 per well

Rig Mobilization

$100,000 per well

Ancillary Drilling Costs (Trucking, etc..)

$25,000 per well

Frac Mobilization

$1,200 per well

Water Hauling vs. Infrastructure

$50,000 per well

6 Wells per Pad

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

September 9, 2011

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

Understanding Multi-Well Pad Drilling

Drill Vertical Section

8 Days/Well

132

153

178

194

199

Kickoff Point to TD

14 Days/Well

Prep for Completion

3.5 Days/Well

Completion

4.2 Days/Well

Post-Completion

2.7 Days/Well

First

Production

A typical 6-well pad can

take between six and

seven months from

spud to first production

A typical 6-well pad operation

will take ~50 fewer days than

utilizing individual well pads

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

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

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Marcellus Shale

“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

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

Seneca Resources

Leading Environmental Commitment

www.FracFocus.org

Seneca discloses its hydraulic fracturing

data

Testing “Green Fluids”

Refueling Standards

Evaluate shallow geology and shallow

water systems

Developed Best Practices for design

and cementing of production casing

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

California

Stable Production and Strong Cash Flows

Rank

Company

California

2010

BOEPD

Chevron

174,856

Aera (Shell/Exxon)

158,786

Occidental

151,584

Plains Exploration

36,488

Venoco Inc.

19,121

Berry Petroleum

18,513

Seneca Resources

9,655

Breitburn Energy

7,414

MacPherson

7,185

E&B Natural Resources

5,259

Net Acreage: 11,833 Acres

Net Wells: 1,322

Oil Gravity: 12 –

37°

Api

NRI: 87.64

September 9, 2011

California

Stable Production Fields

South Lost Hills

~1,800 BOEPD

Monterey Shale

Primary

216 Active Wells

Sespe

~950 BOEPD

Sespe Formation

Primary

193 Active Wells

North Lost Hills

~1,150 BOEPD

Tulare & Etchegoin Formation

Primary & Steamflood

181 Active Wells

North Midway Sunset

~4,300 BOEPD

Potter & Tulare Formation

Steamflood

703 Active Wells

South Midway Sunset

~700 BOEPD

Antelope Formation

Steamflood

100 Active Wells

September 9, 2011

(1)

Footnote #1 goes here

(2)

Footnote #2 goes here

September 9, 2011

California

Strong Margins Support Significant Free Cash Flow

Average Price ($/BOE) = $76.86

September 9, 2011

Pipeline & Storage / Midstream

September 9, 2011

Midstream

Critical To Boosting Returns in the Marcellus

Midstream’s gathering systems are

critical to unlock remote, but highly

productive Marcellus acreage

Goal is to first work to assist Seneca

and then gather 3

party producer

volumes

History of operational success and

efficiency within Pennsylvania

Continuously evaluating opportunities

to grow along with the rapid

development of the Marcellus

TGP 300

Transco

Tioga County

Lycoming County

Midstream

Covington Gathering System –

Tioga County

Early completion of gathering system

allowed Seneca to begin flowing gas as

pads were completed

As Seneca’s production matures, open

pipeline to third party production

Non-SRC Well Permits

September 9, 2011

TGP 300

September 9, 2011

Midstream

Trout

Run

Gathering

System

–

Lycoming

County

Will

work

add

party

Marcellus producers to

offset natural decline of

Seneca’s production

Transco

Non-SRC Well Permits

September 9, 2011

Midstream

Future Opportunities for Expansion

The Covington and Trout Run

gathering systems allow Seneca

to achieve significant production

growth over the next three

years. Midstream is continually

looking to build additional

gathering systems.

Will continue to evaluate new gathering infrastructure to alleviate

constraints throughout the Marcellus

Look

fill

existing

gathering

infrastructure

with

party

production

once Seneca’s reaches its peak production and begins the natural

decline

September 9, 2011

Pipeline & Storage

Expansive Network Located Centrally in Appalachia

September 9, 2011

Pipeline & Storage

Intercompany Capacity Utilization

Our integrated business structure allows our affiliated businesses

to efficiently utilize our Pipeline & Storage services

(1)

As of July 1, 2011

September 9, 2011

Pipeline & Storage

Positioned to Move Growing Marcellus Production

September 9, 2011

Pipeline & Storage

Marcellus Producers Increase Utilization of NFGSC

Producers moving Marcellus gas on NFGSC has

more than tripled since January 2009.

September 9, 2011

Pipeline & Storage

Shifting Sources of Throughput

Marcellus

98%

Upper Devonian

47%

Marcellus

53%

Upper Devonian

September 9, 2011

Pipeline & Storage

Stable Revenue Amid Changing Market Dynamics

September 9, 2011

Pipeline & Storage

Marcellus Driving Changing Gas Flow Patterns

September 9, 2011

Pipeline & Storage

Positioned to Move Growing Marcellus Production

Pipeline & Storage

Marcellus Driven Expansion Projects

Lamont Phase II Project (July 2011)

Line “N”

Expansion (October 2011)

Tioga County Extension (November 2011)

Line “N”

2012 Expansion (November 2012)

Northern Access Expansion (November 2012)

West to East (2014)

Central Tioga County Ext (2014)

FY11

FY12

FY14

FY13

Total Firm Capacity: ~1,820,000 Dth/D

Capital Investment: ~$600 Million

50,000 Dth/d

160,000 Dth/d

350,000 Dth/d

150,000 Dth/d

320,000 Dth/d

~425,000 Dth/d

260,000 Dth/d

September 9, 2011

September 9, 2011

Pipeline & Storage

Tioga County Extension Project

FERC Certificate Issued: May 19, 2011

Anticipated In-Service: 11/2011

Firm Transportation: 350,000 Dth/d

15 Miles of 26”

High Pressure Pipe

Replacement of 1.36 miles of Original

Empire

New Interconnect with TGP 200

Tioga County Extension

September 9, 2011

Pipeline & Storage

Line N Expansion Project

Line N Expansion 2011

In-Service Date: 9/2011

Fully Subscribed: 160,000 Dth/D

20+ Miles of 20”

Pipe

New 4,740 HP Compression Station

Delivery to TETCO at Holbrook Station

Line N Expansion 2012

In-Service Date: 11/2012

Fully Subscribed: 150,000 Dth/D

4.85 Miles of 24”

Replacement Pipe

Additional 20,620 HP at Buffalo Station

September 9, 2011

Pipeline & Storage

Marcellus Volumes from System Expansions

Estimated Marcellus Volumes from System

Expansions (80% Load Factor)

Actual Transported Marcellus

Production Volumes

Line N 2012

Expansion &

Northern Access

West to East

Tioga County

Expansion

Line N 2011

Central Tioga

County

Project

September 9, 2011

Pipeline, Storage & Midstream

Significant Throughput Growth

Pipeline & Storage Growth

Deploying Significant Growth Capital

Capital spending is ramping up significantly to fund system expansion and assuming

recently allowed industry average ROE and capital structure targets, this segment

can achieve significant growth with a rapid increase in contracted volumes

September 9, 2011

September 9, 2011

Utility

National Fuel Gas Distribution Corporation

September 9, 2011

Utility

Strong Commitment to Safety

Capital spending from 2011 to 2014 is

expected to be between

$55 and $60 million per year

September 9, 2011

Utility

Operational Reliability

The

development

unconventional

resources

has

shifted

the

need

for

traditional

sources

natural

gas

supply

reliably

serve

our

utility

customers

Changing Natural Gas Supply Dynamics

September 9, 2011

Utility

Continued Cost Control

September 9, 2011

Utility

Stable Earnings/Financial Stability

Photo

courtesy

Carl

Heldmann

Build

Your

Own

House

www.byoh.com

September 9, 2011

Utility

Diluted Earnings per Share (Before Items Impacting Comparability)

(1) Excludes out-of-period adjustment to symmetrical sharing of $0.03; Including this adjustment, GAAP earnings would be $0.58.

September 9, 2011

Utility

Financial Stability

Rate Mechanisms

New York & Pennsylvania

Low Income Rates

Choice Program/POR

Merchant Function Charge

New York only

Revenue Decoupling

90/10 Sharing

Weather Normalization

Fiscal Year

September 9, 2011

Utility

Continuing Goals and Outlook

Strong Commitment to Safety

Continue to control expenses

Financial Stability

Operational Reliability

Maintain a solid regulatory strategy to

achieve strong regulatory outcomes

September 9, 2011

Utility

National Fuel Gas Distribution Corporation

September 9, 2011

National Fuel Gas Company

Corporate & Financial Overview

National Fuel Gas Company

Consolidated Capital Expenditures

Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

September 9, 2011

National Fuel Gas Company

Cash Flow

Forecast

–

Utility

September 9, 2011

$40

$80

$120

$160

2011

Forecast

2012

Forecast

2013

Forecast

2014

Forecast

Cash From Operations

Capital Expenditures

$135-

145

$120-

130

$115-

125

$115-

120

$55-

National Fuel Gas Company

Cash Flow Forecast –

Pipeline & Storage

September 9, 2011

$85-

$100-

150

$95-

105

$100-

135

$105-

115

$100-

150

$110-

125

$300-

350

$350

$300

$200

$100

$150

$250

$50

2011

Forecast

2012

Forecast

2013

Forecast

2014

Forecast

Cash From Operations

Capital Expenditures

National Fuel Gas Company

Cash Flow Forecast –

Exploration & Production

Note:

This assumes NYMEX natural gas pricing of $4.00, $4.50, $5.00 and $5.50 for fiscal years 2011, 2012, 2013 and 2014, respectively. It also assumes NYMEX

crude oil pricing of $80. $95, $100 and $100 for fiscal years 2011, 2012, 2013 and 2014, respectively.

September 9, 2011

$360-

380

$600-

655

$450-

500

$785-

875

$650-

800

$840-

1,050

$900-

1,100

$935-

1,145

$1,200

$1,000

$600

$200

$400

$800

2011

Forecast

2012

Forecast

2013

Forecast

2014

Forecast

Cash From Operations

Capital Expenditures

National Fuel Gas Company

Hedge Positions and Strategy

Natural Gas

Swaps

Volume

(Bcf)

Average

Hedge Price

Fiscal 2012

35.0

$5.89 / Mcf

Fiscal 2013

23.9

$5.67 / Mcf

Fiscal 2014

4.6

$5.89 / Mcf

Oil Swaps

Volume

(MMBbl)

Average

Hedge Price

Fiscal 2012

1.6

$77.03 / Bbl

Fiscal 2013

0.9

$86.21 / Bbl

Fiscal 2014

0.2

$94.90 / Bbl

Most hedges executed at sales point to

eliminate basis risk

September 9, 2011

20%

40%

60%

80%

100%

Hedged Forecasted Production

As of September 9, 2011

47%

21%

2012

2013

2014

Fiscal Year

National Fuel Gas Company

Cash Flow Forecast –

Midstream, Marketing & Other

September 9, 2011

$23-27

$100

$75

$50

2011

Forecast

2012

Forecast

2013

Forecast

2014

Forecast

Cash From Operations

Capital Expenditures

$25

$15-20

$20-30

$40-60

$40-50

$20-30

$55-70

$5-15

National Fuel Gas Company

Financing Needs –

A Consolidated View of Cash Flows

2013E

2014E

2012E

2011E

Note:

This assumes NYMEX natural gas pricing of $4.00, $4.50, $5.00 and $5.50 for fiscal years 2011, 2012, 2013 and 2014, respectively. It also assumes

NYMEX crude oil pricing of $80, $95, $100 and $100 for fiscal years 2011, 2012, 2013 and 2014, respectively.

September 9, 2011

$828

$1,055

$1,153

$1,433

$625

$725

$1,000

$1,300

$124

$2,000

$1,500

$1,000

$500

Cash from Ops

Asset Sales & Other

CapEx

National Fuel Gas Company

Strong Dividend Track Record

Compound Annual

Growth Rate

5.0%

National Fuel has had 109 uninterrupted

years of dividend payments and has increased

its dividend for 41

consecutive years

September 9, 2011

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

Annual Rate at Fiscal Year End

National Fuel Gas Company

Manageable Debt Maturity Schedule

September 9, 2011

$150

$250

$300

$250

$49

$50

$100

$150

$200

$250

$300

$350

Fiscal Year

National Fuel Gas Company

Financing Needs

–

Consolidated

View

Cash

Flows

2013E

2014E

2012E

2011E

September 9, 2011

$625

$725

$1,000

$1,300

$124

$828

$1,055

$1,153

$1,433

$115

$119

$123

$128

$200

$150

$250

$385

$550

575

$500

525

$225

250

$500

$1,000

$1,500

$2,000

Cash from Ops

Asset Sales & Other

CapEx

Dividend

Debt Repayment

Cash on Hand

New Financing

Note:

This assumes NYMEX natural gas pricing of $4.00, $4.50, $5.00 and $5.50 for fiscal years 2011, 2012, 2013 and 2014, respectively.

also

assumes

NYMEX

crude

oil

pricing

$80.00,

$95,

$100

and

$100

for

fiscal

years

2011,

2012,

2013

and

2014,

respectively.

National Fuel Gas Company

Targeted Capital Structure

Long-Term Consolidated

Capital Structure Target

Capital Structure

Targets by Segment

September 9, 2011

Debt

35% -

45%

Equity

55% -

65%

All Other

E&P

P&S

Utility

40%

30%

50%

60%

70%

50%

Debt

Equity

National Fuel Gas Company

Investment Grade Credit Rating

Rating Agency

Rating

Fitch

BBB+

Moody’s

Baa1

Standard & Poors

BBB

Current Credit Ratings

September 9, 2011

Capital Resources

Total Short-Term Capacity: $685 Million

Commercial Paper Program: $300 Million

Uncommitted Lines of Credit: $385 Million

$300.0 MM Committed Credit Facility through

September 2013 –

backs Commercial Paper Program

National Fuel Gas Company

Appendix

September 9, 2011

National Fuel Gas Company

Fiscal Year 2012 Earnings Guidance Drivers

2012 Forecast

GAAP Earnings per Share

$2.85 -

$3.15

Operating Earnings per Share

$2.85 -

$3.15

12% EPS Growth

Exploration & Production Drivers

Total Production (Bcfe)

87 -

101

35% Production Growth

DD&A Expense

$2.20 -

$2.30

LOE Expense

$0.85 -

$1.00

G&A Expense

$54 -

$58 MM

Pipeline & Storage Drivers

O&M Expense

Increase in Revenue (Expansion Projects)

$27 MM

Decrease in Revenue (De-Contracting)

$4 MM

Utility Drivers

O&M Expense

PA Normal Weather Assumption

$0.03 / Share

September 9, 2011

Pipeline & Storage

Expansion Initiatives

Project Name

Capacity

(Dth/D)

Est.

CapEx

In-Service

Date

Market

Status

Lamont Compressor Station

40,000

$6 MM

6/15/10

Fully Subscribed

Completed

–

Flowing

into

TGP

300 Line

Lamont Phase II Project

50,000

$7.6 MM

07/1/11

Fully Subscribed

First 10,000 Dth/d in-service. Remaining

40,000 Dth/d in-service 10/2011.

Line “N”

Expansion

160,000

$20 MM

~ 09/2011

Fully Subscribed

Construction began February 2011

Tioga County Extension

350,000

$49 MM

~ 11/2011

Fully Subscribed

Construction began July 2011

Northern Access Expansion

320,000

$62 MM

~11/2012

Fully Subscribed

Certificate filed in March 2011

Line “N”

2012 Expansion

150,000

$36 MM

~ 11/2012

Fully Subscribed

Certificate filed in July 2011

West to East

~425,000

$290 MM

2014

29% Subscribed

Marketing continues with producers in

various stages of exploratory drilling

Central Tioga County

Extension

260,000

$135 MM

2014

Open Season

Closed

Evaluating market interest and facility

design

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

Capital Investment ~ $606 MM

September 9, 2011

Midstream Corporation

Expansion Initiatives

Project Name

Capacity

(Dth/D)

Est.

CapEx

In-Service

Date

Market

Status

Covington Gathering System

140,000

$16 MM

11/17/09

Fully Subscribed

Completed

–

Flowing into TGP 300 Line

Covington Gathering System

Expansion

80,000

$3.5 MM

~12/2011

Fully Subscribed

Will increase total system capacity to

220,000 Dth/d

Trout Run Gathering System

466,000

$52 MM

Q2 FY2012

70% Subscribed

Preliminary work has begun

Total Firm Capacity ~ 686,000 Dth/D

Capital Investment ~ $ 71.5 MM

September 9, 2011

Seneca Resources

Industry Leading Production Growth

September 9, 2011

U.S. Independent E&P Companies

Quarter Year-Over-Year Production Growth

(1)

Source: Raymond James & Associates, Inc. – August 22, 2011

Marcellus Shale

Eastern Development Area (EDA) –

Current Results

Location

Possible

Locations

Wells

Drilled

Gross

Production

(MMcf/d)

Seismic

2012

Wells

Planned

Comments

Developed

Covington

100+

Acquired

N/A

Estimated Gross EUR: 5.5 Bcfe

Full Development

DCNR 595

1 Well Currently Shut-In

DCNR 100

N/A

Mid-2012

1 Well IP: 15.8 MMcf/d

Delineating

DCNR001

N/A

June 2011

1 Well IP: 4 MMcf/d

DCNR 007

N/A

July 2011

1 Well IP: 2 MMcf/d

September 9, 2011

Permitting

DCNR 007

Covington

DCNR 595

DCNR 100

SRC Lease Acreage

SRC Fee Acreage

DCNR 001

Marcellus Shale

Western Development Area (EDA) –

Results & Plan Forward

Boone Mtn.

Mt. Jewett

Owl’s

Nest

Punxy

Approx. Outline of JV Acreage

200,000 Gross Acres

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

Rich Valley

Location

Possible

Locations

Wells

Drilled

Gross

Production

(MMcf/d)

Seismic

2012

Wells

Planned

Comments

Full Development

Owl’s Nest/ Ridgeway

680

Expected IPs: 4-5 MMcf/d

Punxy

Acquired

Delineating

Mt. Jewett

232

N/A

Acquired

TBD

Completions Scheduled for Sept. to Oct.

Boone Mtn.

N/A

TBD

Completions Scheduled for Oct. to Nov.

Rich Valley

188

N/A

September 9, 2011

Permitting

SRC Lease Acreage

SRC Fee Acreage

Marcellus Shale

Ensuring Gas Reaches the Market

September 9, 2011

100

120

140

Tioga County Production and Future Firm Sales

Firm Sales

Tioga County Production

Firm sales agreements

continue to be layered on

as the future production

profile becomes more

predictable

Marcellus Shale

Water Sourcing Program

Utilizing least quality freshwater sources,

including abandoned coal mine drainage

Centralized storage impoundments

create a flexible and efficient water

system

Seven mile pipeline supplies multiple

locations:

Covington Area: 47 Wells

DCNR 595: 55 Wells

Water Withdrawal: 500,000 gallons per

day

Reduced Trucking: 800-1,000

Trucks per

well

Cost Savings: ~$120,000 per well

Pay Out: 31 Wells

Unaffected by regional droughts

September 9, 2011

Seneca Resources

Committed to Health, Safety and the Environment

Seneca

Resources

Corporation

–

Value

Statement

“We ask that each employee share in our philosophy and unwavering

commitment to each other’s health and safety and the environment.”

“…creating a

systematically

integrated model of

EHS stewardship

beyond mere

compliance.”

Dedicated 24-Hour

EHS Hotline and

E-mail Address

Culture Above and

Beyond Best Practices

and Required

Compliance

Simultaneous

Operations (SIMOPS)

Program

Extensive Operations

Audit Program

Dedicated Safety

Office in Every

Location

September 9, 2011

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.

September 9, 2011

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures

($ Thousands)


	FY 2010			FY 2011 Forecast		FY 2012 Forecast		FY 2013 Forecast		FY 2014 Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures	$	398,174		$	600,000-655,000	$	785,000-875,000	$	840,000-1,050,000	$	935,000-1,145,000
Pipeline & Storage Capital Expenditures		37,894		$	100,000-150,000	$	100,000-135,000	$	100,000-150,000	$	300,000-350,000
Utility Capital Expenditures		57,973		$	55,000-60,000	$	55,000-60,000	$	55,000-60,000	$	55,000-60,000
Marketing, Corporate & All Other Capital Expenditures		7,311		$	15,000-20,000	$	40,000-60,000	$	20,000-30,000	$	5,000-15,000

Total Capital Expenditures from Continuing Operations	$	501,352		$	770,000-885,000	$	980,000-1,130,000	$	1,015,000-1,290,000	$	1,295,000-1,570,000

Capital Expenditures from Discontinued Operations
Exploration & Production Capital Expenditures	$	—		$	—	$	—	$	—	$	—
All Other Capital Expenditures		150

Total Capital Expenditures from Discontinued Operations	$	150		$	—	$	—	$	—	$	—

Plus (Minus) Accrued Capital Expenditures
Exploration & Production FY 2010 Accrued Capital Expenditures	$	(55,546	)	$	—	$	—	$	—	$	—
Exploration & Production FY 2009 Accrued Capital Expenditures		9,093			—		—		—		—
Pipeline & Storage FY 2008 Accrued Capital Expenditures		—			—		—		—		—
All Other FY 2009 Accrued Capital Expenditures		715			—		—		—		—

Total Accrued Capital Expenditures	$	(45,738	)	$	—	$	—	$	—	$	—

Eliminations	$	—		$	—	$	—	$	—	$	—

Total Capital Expenditures per Statement of Cash Flows	$	455,764		$	770,000-885,000	$	980,000-1,130,000	$	1,015,000-1,290,000	$	1,295,000-1,570,000