National Fuel Gas Company

Investor Presentation

August 2013

Exhibit 99

August 2013

National Fuel Gas Company

2

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,

aswell

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

projectionswill

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

towhich

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;

changes

in

the

price

of

natural

gas

or

oil;

impairments

under

the

SEC’s

full

cost

ceiling

test

for

natural

gas

and

oil

reserves;

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

demographic

patterns

andweather

conditions;

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;

significant

differences

between

the

Company’s

projected

and

actual

capital

expenditures

and

operating

expenses;

changes

in

laws,

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;

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

gaswhich,

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,

2012

and

Forms

10-Q

for

the

periods

ended

December

31,

2012,

March

31,

2013

and

June

30,

2013.

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.

August 2013

National Fuel Gas Company

3

Our Business Mix Leads to Long-Term Value Creation

Upstream

Crude Oil

Midstream

Downstream

National Fuel Gas

Supply Corporation

Empire Pipeline, Inc.

National Fuel Gas

Midstream Corporation

National Fuel Gas

Distribution

Corporation

National Fuel

Resources, Inc.

The strategic, operational and financial benefits, along with capital

flexibility and consistent growth opportunities generated by this

integrated mix of businesses continues to create significant

long-term value for the Company’s shareholders in nearly all

economic and commodity price scenarios

Upstream

Natural Gas

Seneca Resources

Corporation

(West Division)

Seneca Resources

Corporation

(East Division)

August 2013

National Fuel Gas Company

4

Integrated Businesses with Significant Marcellus Exposure…

August 2013

National Fuel Gas Company

5

…And Exposure to Growth from the Utica Shale

August 2013

National Fuel Gas Company

6

EBITDA Growth Driven by Stability and Ongoing Success

Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this presentation. 

August 2013

National Fuel Gas Company

7

Capital Spending Flexibility to Maintain Financial Strength

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

(1)

Does not include the $34.9 MM Seneca Resources Corporation’s acquisition of Ivanhoe’s U.S.-based assets in California, as this was accounted for as an

investment in subsidiaries on the Statement of Cash Flows, and was not included in the Exploration & Production segment’s Capital Expenditures

August 2013

Total Debt

(1)

44%

National Fuel Gas Company

8

Strong Balance Sheet and Liquidity Position

$3.786 Billion

As of June 30, 2013

Note:  A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation

(1)

Long-Term Debt of $1.649 billion

Debt / Adjusted EBITDA

Capitalization

The Company has a total short-term debt capacity of

$1.085 billion of which all remains available

August 2013

National Fuel Gas Company

9

Dividend Track Record

Current

Dividend Yield

(1)

2.2%

(1) As of August 5, 2013

Dividend Consistency

Consecutive Dividend Payments

111 Years

Consecutive Dividend Increases

43 Years

Current

Annualized Dividend Rate

$1.50

per Share

August 2013

Exploration & Production

10

August 2013

Seneca Resources

11

Disciplined Capital Spending

(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 of Cash Flows, and was not included in Capital Expenditures

August 2013

Seneca Resources

12

Production Continues to Grow

August 2013

Seneca Resources

13

Driving Down Costs

(1)

Represents the midpoint of current General & Administrative Expense guidance of $0.50 to $0.55 per Mcfe for fiscal 2013 and $0.45 to $0.50 per Mcfe for fiscal

2014

(2)

The total of the two Lease Operating Expense components represents the midpoint of current Lease Operating Expense Guidance of $0.95 to $1.05 per Mcfe  for

fiscal 2013 and $0.90 to $1.10 per Mcfe for fiscal 2014

August 2013

Seneca Resources

14

California: Seventh Largest Producer in the State

Net Acreage:  18,418 Acres

Net Wells:  1,485

Oil Gravity:  12 –

37°

Api

NRI:  87.64

Rank

Company

California

2012

BOEPD

(1)

1

Occidental

187,376

2

Chevron

160,611

3

Aera (Shell/Exxon)

143,983

4

Plains Exploration

36,365

5

Berry Petroleum

19,589

6

Macpherson Oil

10,416

7

Seneca Resources

10,154

8

Venoco Inc

6,113

9

E&B Natural Resources

6,042

10

ExxonMobil

3,664

(1)

Gross operated production (Source: California Division of Oil, Gas, & Geothermal Resources)

August 2013

Seneca Resources

15

California: Stable Production Fields

East Coalinga

~120 BOEPD

Temblor Formation

Primary

South Lost Hills

~1,500 BOEPD

Monterey Shale

Primary

222 Active Wells

Sespe

~1,100 BOEPD

Sespe Formation

Primary

172 Active Wells

South Midway Sunset

~1,200 BOEPD

Antelope Formation

Steamflood

120 Active Wells

North Midway Sunset

~4,000 BOEPD

Potter & Tulare Formation

Steamflood

728 Active Wells

North Lost Hills

~1,100 BOEPD

Tulare & Etchegoin Formation

Primary & Steamflood

175 Active Wells

August 2013

Seneca Resources

16

California: Strong Margins Provide Significant Free Cash Flow

Average Revenue

(12 Months Ended 6/30/13)

$87.51 per BOE

(1)  Total production from the Exploration & Production segment’s properties in California  was 3,308 Mboe for the 12 months ended June 30, 2013.

Note:

A

reconciliation

of

Exploration&

Production

WestDivision

Adjusted

EBITDA

to

Exploration&

Production

Segment

Net

Income

is

includedat

theend

of

this

presentation. 

August 2013

Seneca Resources

17

California: Midway-Sunset South Activity Update

August 2013

18

WS 48-33

IP: 80 BOEPD

1st

Oil 09/12

“X”

SANDS ISOCHORE (Thickness)

Seneca Resources

California: Sespe Field –

Drilling Programs and Results

1 Mile

Oak Flat 1-31

IP: 110 BOEPD

1st

Oil 08/12

FA 502-33

IP: 75 BOEPD

1st

Oil 1/13

FA 501-33

IP: 100 BOEPD

1st

Oil 1/13

Oak Flat 2-31

IP: 100 BOEPD

1st

Oil 08/12

TG 562-29

IP: 190 BOEPD

1st

Oil 2/13

TG 53-29

IP: 90 BOEPD

1st

Oil 3/13

2011 Sespe Wells (5)

2012 Sespe Wells (6)

2013 Sespe Wells (6)

2014 Sespe Wells (4)

August 2013

Seneca Resources

19

California: East Coalinga Overview

Seneca became operator on January 30, 2013

Previous Operator: Chevron

7,764 net acres

90 active wells

~380 BOPD (Up from 230 BOPD on 1/30/13)

$30 million capital commitment over first

three years

$100 million of potential opportunities over

the next five to seven years

2013 Plans

Drill ~12 evaluation wells across acreage

block (9 of 12 drilled to date)

Place ~50% of currently idled wells back on

production

Have put 40 on since 1/30/13

Upgrade surface facilities

August 2013

Seneca Resources

20

California: Delivering Steady Results

Key Areas of Focus in 2014

1.East Coalinga Evaluation

2.South Midway Sunset Extensions

3.Sespe Coldwater Evaluation

August 2013

Seneca Resources

21

Expansive Pennsylvania Acreage Position

SRC Lease Acreage

SRC Fee Acreage

Eastern Development Area

Net Acreage: 55,000 acres

Mostly leased (16-18% royalty)

No near-term lease expiration

First large expiration: 2018

Ongoing development drilling in

Tioga and Lycoming Counties

Western Development Area

Net acreage:

~720,000 acres

Own most mineral rights

Minimal

royalty obligation

Minimal

lease expiration

Evaluating rich-gas potential and

initiating dry gas development

NFG Storage Acreage

August 2013

Seneca Resources

Firm Sales in Place for Appalachian Production

22

Prices shown represent the sales (netback

price) at the first non-affiliated interstate

pipeline , including the cost of all related

downstream transportation.

(1)

Long-term firm sales represent gross volumes

August 2013

Seneca Resources

23

Eastern Development Area (EDA)

SRC Lease Acreage

SRC Fee Acreage

DCNR Tract 595

Gross Production: ~75 MMcf per Day

34 Wells Drilled

26 Wells Producing

Covington –

Fully Developed

Gross Production: ~60 MMcf per Day

47 Wells Drilled and Producing

DCNR Tract 100

Gross Production:  ~165 MMcf per Day

40 Wells Drilled

25 Wells Producing

August 2013

Seneca Resources

24

Strong Results in Lycoming and Tioga Counties

Development Area

Producing

Well

Count

Average

IP Rate

(MMcf/d)

Average

7-Day

(MMcf/d)

Average

30-Day

(MMcf/d)

Average

EUR

per Well

(Bcf)

Average

Lateral

Length

EUR per

1,000’

of

Lateral

(Bcfe)

Covington

Tioga

County

47

5.2

4.7

4.1

5.7

4,023’

1.42

Tract 595

Tioga

County

26

7.1

6.0

5.1

8.2

4,629’

1.77

Tract 100

Lycoming

County

25

15.4

13.5

11.1

11.0

5,008’

2.20

August 2013

Seneca Resources

25

Successful Delineation Across a Large Acreage Position

Owl’s Nest

2 Wells Drilled

Testing: August 2013

Church Run (1 Well)

IP : 4.8 MMcfd

SRC Lease Acreage

SRC Fee Acreage

Horizontal Well

Ridgway (1 Well)

IP: 7.1 MMcfd

Rich Valley (1 Well)

Peak 7-Day IP: 7.8 MMcfd

30-Day Rate: 6.7MMcfd

Estimated EUR: 7.4 Bcf

BTU

Contours

Clermont (2 Wells)

9H (RCS) IP: 8.9 MMcfd

10H (Non-RCS) IP: 6.6 MMcfd

Tionesta

1 Well Drilled

August 2013

Seneca Resources

26

Delineation Well Test Data Provides Positive Data Points

Completion Design

Initial Test Data

Sales Data

Well Name

RCS

(1)

/

Non-RCS

Treatable

Lateral

Length

Stages

Peak

IP Rate

(MMcfd)

7-Day

Rate

(MMcfd)

Normalized

7-Day Rate

(MMcfd per

1,000’)

7-Day

Rate

(MMcfd)

30-Day

Rate

(MMcfd)

EUR

(Bcf)

Rich Valley

27H

RCS

6,372’

42

6.4

5.4

0.8

7.8

6.7

7.4

Clermont 9H

RCS

5,500’

37

8.9

8.6

1.6

Clermont 10H

Non-RCS

5,565’

23

6.6

6.3

1.1

Ridgway 19H

RCS

5,537’

37

7.1

6.4

1.2

Church Run 2H

RCS

4,435’

29

4.8

4.5

1.0

Wells tested during

the 3

rd

quarter of

fiscal 2013

Initial well test data in the Western Development Area furthers our

confidence in a long-term Marcellus development program

(1)

RCS –

Reduced Cluster Spacing

August 2013

Seneca Resources

27

Rich Valley/Clermont: Moving Forward with Full Development

Clermont

Rich Valley

Rich Valley

7-day IP: 7.8 MMcf/d

EUR: 7.4 BCF

Rich Valley 2nd

Well

Currently Drilling

Marcellus Faults

Marcellus & Basement Faults

Drilled Well

Planned Well

Rich

Valley/Clermont

Program

150-200 horizontal locations

SRC Lease Acreage

SRC Fee Acreage

Pad N (9 Wells)

Spud Q4 FY2013

Clermont

9H 7-day Flow back:  8.6 MMcf/d

10H 7-day Flow back:  6.3 MMcf/d

August 2013

Seneca Resources

28

Ongoing Production Growth in the East Division

August 2013

Seneca Resources

29

Utica Shale –

Activity Summary

Permitted

Drilled/Drilling

Completed

Producing

Mt. Jewett

Tested 3 Frac Stages at 1.6 MMcfd

(Typical Well: 17 Frac Stages)

2nd

Horizontal: Completed (Soaking)

Henderson

Vertical Well: Tested

Tionesta

Horizontal: Completed Fall 2012

Peak 24-Hour Rate: 3.9 MMcfd

Rex

9.2 MMcfd

Chesapeake

6.4 MMcfd

Range Resources

4.4 MMcfd

Range Resources

1.4 MMcfd

“Not Effectively Stimulated”

August 2013

Seneca Resources

30

Initial Entry into the Mississippian Lime Play in Kansas

Total Net Acres: 13,615

Negotiated an increase in Seneca’s

working interest and have taken over

as operator

Will drill up to 5 evaluation wells in

2014

The initial entry into the Mississippian Lime play furthers the Company’s goal

of maintaining a significant contribution from oil-producing properties

Unit

30-day IP:

352 BOED

(92% Oil/NGLs)

100% working interest in 4,400 gross

acres

55% net working interest in 17,365

gross acres

Spud first horizontal well in the first

quarter of fiscal 2014

August 2013

Midstream Businesses

31

Pipeline & Storage/NFG Midstream

August 2013

Midstream Businesses

32

Pipeline Expansions to Transport Appalachian Production

Gathering

Marcellus

Production

Shipping Gas

to Canada &

Northeast

Line N

Corridor

Expansions

August 2013

Midstream Businesses

33

A Closer Look at the Expansion Progress

COVINGTON

GATHERING SYSTEM

(In-Service)

TROUT RUN

GATHERING SYSTEM

(In-Service)

TIOGA

COUNTY

EXTENSION

(In-Service)

LINE “N”

EXPANSION

(In-Service)

NORTHERN ACCESS

EXPANSION

(In-Service)

CENTRAL TIOGA

COUNTY EXTENSION

(2016)

LINE “N”

2012

EXPANSION

(In-Service)

MERCER

EXPANSION

PROJECT

(Nov. 2014)

LINE “N”

2013

EXPANSION

(Nov. 2013)

WEST SIDE

EXPANSION

(Nov. 2015)

TIONESTA

GATHERING SYSTEM

(In-Service)

MT. JEWETT

GATHERING SYSTEM

(Under Construction)

CLERMONT

GATHERING SYSTEM

(IQ4 FY2014)

August 2013

Midstream Businesses

34

NFG Midstream is Focused on Serving Appalachian Producers

Midstream’s gathering systems are

critical to unlock remote, but highly

productive Marcellus acreage

History of operational success and

efficiency within Pennsylvania

Current focus is on developing and

expanding gathering infrastructure

for both Seneca and other producers

in the Appalachian Basin

August 2013

Utility

35

August 2013

Total Customers: 520,000

Rate Mechanisms:

Revenue Decoupling

Weather Normalization

Low Income Rates

Choice Program/Purchase of

Receivables (POR)

Merchant Function Charge

(Uncollectibles Adjustment)

90/10 Sharing (Large Customers)

Natural Gas Vehicle Pilot Program

Allowed ROE: 9.1%

Utility

36

New York Service Territory

August 2013

Utility

37

New York -

Earnings Sharing Proposal and Show Cause Order

March 27, 2013

Filed a plan with the NY PSC

to adopt an earnings

sharing and stabilization

mechanism on earnings

above a 9.96% ROE

April 19, 2013

NY PSC issued an Order

to Show Cause (OTSC)

commencing a

proceeding to establish

“temporary rates”

June 1, 2013

OTSC suggests

“temporary rates”

could

become effective

Further proceedings would follow to establish

permanent rates

Most recent NY PSC multi-year plan include:

ROE: 9.4%

Equity Ratio: 48%

National Fuel continues to maintain a dialogue

with regulators

May 8, 2013

Company responds to

OTSC

June 14, 2013

“Temporary rates”

become effective

July 26, 2013

Settlement discussions

commence for

permanent rates

August 2013

Utility

38

Pennsylvania Service Territory

Total Customers: 213,000

Rate Mechanisms:

Low Income Rates

Choice Program/Purchase of

Receivables (POR)

Merchant Function Charge

Allowed ROE: N/A

(1)

(1)

Black Box Settlement

August 2013

Utility

39

Continued Cost Control Helps Provide Earnings Stability

Low natural gas prices,

combined with a focus

on cost control, continue

to help reduce expenses

August 2013

Utility

40

Strong Commitment to Safety

The anticipated increase in 2013

capital expenditures is largely due

to the implementation of a new

Customer Information System

The Utility remains

focused on consistent

spending to maintain

the ongoing safety and

reliability of its system

August 2013

National Fuel Gas Company

41

Appendix

August 2013

National Fuel Gas Company

42

No Debt Maturities Until Fiscal 2018

In February, the Company

Issued $500 million in

10-year notes at 3.75%

August 2013

Midstream Businesses

43

Appendix

August 2013

Midstream Businesses

44

Regulated Interstate Expansion Initiatives (Pipeline & Storage)

Project Name

Capacity

(Dth/D)

Est.

CapEx

In-Service

Market

Status

Lamont Compressor Station

90,000

$14 MM

2010/2011

Fully Subscribed

Completed –

Two Phases

Line “N”

Expansion

160,000

$61 MM

(1)

10/2011

Fully Subscribed

Completed

Tioga County Extension

350,000

$58 MM

11/2011

Fully Subscribed

Completed

Northern Access Expansion

320,000

$77 MM

11/2012

Fully Subscribed

Completed

Line “N”

2012 Expansion

163,000

$39 MM

(2)

11/2012

Fully Subscribed

Completed

Line “N”

2013 Expansion

30,000

$4 MM

11/2013

Fully Subscribed

Under Construction

Mercer Expansion Project

105,000

$30 MM

(3)

11/2014

Fully Subscribed

Executed Precedent Agreement

West Side Expansion and

Modernization Project

95,000+

$66 MM

(4)

2015

OS Concluded

Executed one of two Precedent

Agreements

Central Tioga County

Extension

260,000

~$150 MM

2016

OS Concluded

Discussions with anchor shipper

West to East

~425,000

~$290 MM

~2016

29% Subscribed

Marketing continues with producers in

various stages of exploratory drilling

Total Firm Capacity:  ~1,998,000+ Dth/D

Capital Investment: ~$789 MM

(1)

The Line  “N”

Expansion Project consists of $22 million in expansion capital expenditures and $39 million in replacement capital expenditures

(2)

The Line  “N”

2012 Expansion Project consists of $32 million in expansion capital expenditures and $7 million in replacement capital expenditures

(3)

The Mercer

Expansion Project consists of $27 million in expansion capital expenditures and $3 million in replacement capital expenditures

(4)

The

Westside

Expansion

and

Modernization

Project

consists

of

$31

million

in

expansion

capital

expenditures

and

$35

million

in

replacement

capital

expenditures

August 2013

Midstream Businesses

45

Gathering Expansion Initiatives (NFG Midstream)

Project Name

Capacity

(Mcf/D)

Est.

CapEx

In-Service

Date

Market

Comments

Covington Gathering System

220,000

$40 MM

Multiple

Phases -

Most

In-Service

Capacity

Available

[Marketing to

Third Parties]

Completed

–

Flowing into TGP 300

Line.  This includes ~$10 million of

current and future spending to

build pipeline to connect additional

wells

Trout Run Gathering System

466,000

$185 MM

May 2012

Capacity

Available

[Marketing to

Third Parties]

Completed

–

Flowing into Transco

Leidy Line.  This includes ~$90

million of current and future

spending to build compression and

pipeline to connect additional wells

Tionesta Gathering System

10,000

$2.1 MM

April 2012

Fully Subscribed

Completed

–

Flowing into TGP 300

Line

Mt. Jewett Gathering System

10,000

$3.9 MM

FY2013

Q4

Fully Subscribed

Under Construction

Clermont Gathering System

500,000+

~$25 MM

(FY2014)

FY2014

Q4

Evaluating

Fiscal 2014 capital spending on the

Clermont Gathering System is

primarily for the trunkline

Total Firm Capacity:  ~1,206,000 Mcf/D

Capital Investment: ~$256 MM

August 2013

Exploration & Production

46

Appendix

August 2013

Seneca Resources

47

Another Strong Year of Reserve Growth

Fiscal

Years

3-Year

F&D Cost

(1)

($/Mcfe)

2006-2008

$7.63

2007-2009

$5.35

2008-2010

$2.37

2009-2011

$2.09

2010-2012

$1.87

Seneca has more than doubled

its proved reserves since 2009,

while maintaining a relatively

high percentage of proved

developed reserves (67%),

given its large resource base

(1)

Represents a three-year average U.S. finding and development cost

August 2013

Seneca Resources

48

Hedge Positions and Strategy

Natural Gas

Swaps

Volume

(Bcf)

Average

Hedge Price

Fiscal 2013

19.4

$4.49 / Mcf

Fiscal 2014

63.8

$4.28 / Mcf

Fiscal 2015

42.5

$4.29 / Mcf

Fiscal 2016

38.2

$4.35 / Mcf

Fiscal 2017

38.8

$4.45 / Mcf

Fiscal 2018

5.3

$4.81 / Mcf

Oil Swaps

Volume

(MMBbl)

Average

Hedge Price

Fiscal 2013

0.4

$94.92 / Bbl

Fiscal 2014

2.0

$100.22 / Bbl

Fiscal 2015

1.1

$94.95 / Bbl

Fiscal 2016

0.8

$91.60 / Bbl

Fiscal 2017

0.2

$91.50 / Bbl

Fiscal 2018

0.05

$91.00 / Bbl

Most hedges executed at sales point to eliminate basis risk

Seneca has hedged approximately 54% of its

forecasted production for Fiscal 2014 

Note: Fiscal 2013 hedge positions are for the remaining three months of the fiscal year

August 2013

Seneca Resources

49

Operational Efficiencies Continue to Drive Production Growth

Ongoing efficiency allows for more activity with a flat rig count

(1)

RCS

–

Reduced

Cluster

Spacing

(2)

Drilling pace represents the average feet drilled per day from the time the well is spud until it reaches total depth (TD)

August 2013

Marcellus Shale

50

Targeting Continued Cost Reductions

(1) Completion Cost per Stage is for horizontal wells completed utilizing a standard completion design, not a Reduced Cluster Spacing (RCS) completion design. 

August 2013

National Fuel Gas Company

51

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,

or

on

earnings

absent

the

effect

of

certain

credits

and

charges,

including

interest,

taxes,

and

depreciation,

depletion

and

amortization.

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.

August 2013

52

Reconciliation of Exploration & Production West Division Adjusted EBITDA

to Exploration & Production Segment Net Income

($ Thousands)

12 Months Ended

June 30, 2013

Exploration & Production - West Division Adjusted EBITDA

215,766

$                           

Exploration & Production - All Other Divisions Adjusted EBITDA

251,623

Total Exploration & Production Adjusted EBITDA

467,389

$                           

Minus: Exploration & Production Net Interest Expense

(35,947)

Minus: Exploration & Production Income Tax Expense

(93,596)

Minus: Exploration & Production Depreciation, Depletion & Amortization

(229,645)

Exploration & Production Net Income

108,201

$                           

Exploration & Production Net Income

108,201

$                           

Pipeline & Storage Net Income

72,903

Utility Net Income

70,890

Energy Marketing Net Income

5,248

Corporate & All Other Net Income

3,719

Consolidated Net Income

260,961

$                    

August 2013

53

Reconciliation of Adjusted EBITDA to Consolidated Net Income

($ Thousands)

FY 2009

FY 2010

FY 2011

FY 2012

Exploration & Production - West Division Adjusted EBITDA

171,572

$           

187,838

$           

187,603

$           

226,897

$           

215,766

$              

Exploration & Production - All Other Divisions Adjusted EBITDA

108,139

139,624

189,854

170,232

251,623

Total Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

467,389

$              

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

467,389

$              

Utility Adjusted EBITDA

164,443

167,328

168,540

159,986

172,898

Pipeline & Storage Adjusted EBITDA

130,857

120,858

111,474

136,914

156,803

Energy Marketing Adjusted EBITDA

11,589

13,573

13,178

5,945

7,694

Corporate & All Other Adjusted EBITDA

(5,575)

2,429

(2,960)

4,140

14,120

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

818,904

$              

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

818,904

$              

Minus: Net Interest Expense

(81,013)

(90,217)

(75,205)

(82,551)

(89,078)

Plus:  Other Income

9,762

6,126

5,947

5,133

4,723

Minus: Income Tax Expense

(52,859)

(137,227)

(164,381)

(150,554)

(183,151)

Minus: Depreciation, Depletion & Amortization

(170,620)

(191,199)

(226,527)

(271,530)

(312,109)

Minus: Impairment of Oil and Gas Properties (E&P)

(182,811)

-

-

-

-

Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax (Corp. & All Other)

(2,776)

6,780

-

-

-

Plus: Gain on Sale of Unconsolidated Subsidiaries (Corp. & All Other)

-

-

50,879

-

-

Plus: Elimination of Other Post-Retirement Regulatory Liability (P&S)

-

-

-

21,672

21,672

Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P)

-

-

-

(6,206)

-

Rounding

-

-

-

(1)

-

Consolidated Net Income

100,708

$           

225,913

$           

258,402

$           

220,077

$           

260,961

$              

Consolidated Debt to Total Adjusted EBITDA

Long-Term Debt, Net of Current Portion (End of Period)

1,249,000

$        

1,049,000

$        

899,000

$           

1,149,000

$        

1,649,000

$          

Current Portion of Long-Term Debt (End of Period)

-

200,000

150,000

250,000

-

Notes Payable to Banks and Commercial Paper (End of Period)

-

-

40,000

171,000

-

Total Debt (End of Period)

1,249,000

$     

1,249,000

$     

1,089,000

$     

1,570,000

$     

1,649,000

$       

Long-Term Debt, Net of Current Portion (Start of Period)

999,000

1,249,000

1,049,000

899,000

1,149,000

Current Portion of Long-Term Debt (Start of Period)

100,000

-

200,000

150,000

250,000

Notes Payable to Banks and Commercial Paper (Start of Period)

-

-

-

40,000

70,200

Total Debt (Start of Period)

1,099,000

$     

1,249,000

$     

1,249,000

$     

1,089,000

$     

1,469,200

$       

Average Total Debt

1,174,000

$     

1,249,000

$     

1,169,000

$     

1,329,500

$     

1,559,100

$       

Average Total Debt to Total Adjusted EBITDA

2.02

1.98

1.75

1.89

1.90

12-Months Ended

6/30/13

August 2013

54

Reconciliation of Segment Capital Expenditures to

Consolidated Capital Expenditures

($ Thousands)

FY 2013

FY 2014

FY 2009

FY 2010

FY 2011

FY 2012

Forecast

Forecast

Capital Expenditures from Continuing Operations

Exploration & Production Capital Expenditures

188,290

$  

398,174

$        

648,815

$        

693,810

$        

$525,000-585,000

$550,000-650,000

Pipeline & Storage Capital Expenditures - Expansion

52,504

37,894

129,206

144,167

$70,000-90,000

$80,000-100,000

Utility Capital Expenditures

56,178

57,973

58,398

58,284

$65,000-70,000

$80,000-90,000

Marketing, Corporate & All Other Capital Expenditures

9,829

7,311

17,767

81,133

$50,000-75,000

$80,000-100,000

Total Capital Expenditures from Continuing Operations

306,801

$  

501,352

$        

854,186

$        

977,394

$        

$710,000-820,000

$790,000-940,000

Capital Expenditures from Discountinued Operations

All Other Capital Expenditures

216

150

$                

-

$                  

-

$                  

-

$                                 

-

$                                 

Plus (Minus) Accrued Capital Expenditures

Exploration & Production FY 2012 Accrued Capital Expenditures

-

$           

-

$                  

-

$                  

(38,861)

$         

-

$                                 

-

$                                 

Exploration & Production FY 2011 Accrued Capital Expenditures

-

-

(103,287)

103,287

-

-

Exploration & Production FY 2010 Accrued Capital Expenditures

-

(78,633)

78,633

-

-

-

Exploration & Production FY 2009 Accrued Capital Expenditures

(9,093)

19,517

-

-

-

-

Pipeline & Storage FY 2012 Accrued Capital Expenditures

-

-

-

(2,696)

-

-

Pipeline & Storage FY 2011 Accrued Capital Expenditures

-

-

(7,271)

7,271

-

-

Pipeline & Storage FY 2008 Accrued Capital Expenditures

16,768

-

-

-

-

-

All Other FY 2012 Accrued Capital Expenditures

-

-

-

(11,000)

-

-

All Other FY 2011 Accrued Capital Expenditures

-

-

(1,389)

1,389

-

-

All Other FY 2009 Accrued Capital Expenditures

(715)

715

-

-

-

-

Total Accrued Capital Expenditures

6,960

$       

(58,401)

$         

(33,314)

$         

59,390

$          

-

$                                 

-

$                                 

Eliminations

(344)

$         

-

$                  

-

$                  

-

$                  

-

$                                 

-

$                                 

Total Capital Expenditures per Statement of Cash Flows

313,633

$  

443,101

$        

820,872

$        

1,036,784

$    

$710,000-820,000

$790,000-940,000