National Fuel Gas Company

Analyst Day Presentation

November 19, 2013

Exhibit 99

National Fuel Gas Company

Safe Harbor For Forward Looking Statements

2

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;

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

and

weather

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

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,

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.

National Fuel Gas Company

Analyst Day –

Schedule of Speakers

3

Presenter

Topic

Ron Tanski

President and Chief Executive Officer

Corporate

Overview

Matt Cabell

President of Seneca Resources Corporation

Exploration

&

Production

Overview

John McGinnis

Senior VP of Seneca Resources Corporation

Appraisal

&

Development

Barry McMahan

Senior VP of Seneca Resources Corporation

California

Marcellus

Operational

&

Environmental

Ron Kraemer

President of Empire Pipeline, Inc.

VP of National Fuel Gas Supply Corporation

Midstream Businesses

Dave Bauer

Treasurer and Principal Financial Officer

Utility

Overview

Hedging

Strategy

Financial

Wrap-Up

Corporate Overview

National Fuel Gas Company

Exceptional Assets, Focused on Execution

5

1.549 Tcfe of Proved Reserves

800,000 Net Acres in Pennsylvania

2.8 MMBbl of Crude Oil Production

$191 Million of Midstream EBITDA

National Fuel Gas Company

A History of Success & A Future of Opportunity

6

Recent Success

35% Production CAGR

Since 2010

Nearly $600 Million Invested

in New Pipeline Infrastructure

De-risked 2,000 Well

Locations in the Marcellus

Corporate Overview

Integrated Businesses Provide Complimentary Benefits

7

Corporate Overview

Consistent Growth in Low Natural Gas Price Environment

8

Fiscal

Year

Natural Gas

(1)

($/MMBtu)

2009

$4.68

2010

$4.49

2011

$4.10

2012

$2.83

2013

$3.60

Natural gas prices dropped

23% from 2009 to 2013

Corporate Overview

Still in the Early Stages of Our Marcellus Growth Story

9

2008-2009

2010-2011

2012-2013

2014-2015

2016+

Initial Delineation

Full Development

(200-220 Locations)

Initial Delineation

Full Development

(1,700-2,000 Locations)

Optimization & Enhancement

Optimization &

Enhancement

Delineation (New Areas/Depths)

Delineation

(New Areas/Depths)

Production

Decline

Corporate Overview

Formula to Grow Our Marcellus Development Program

10

High-Quality

Reservoir

Realized

Natural Gas

Price

?

Increased

Capital

Deployment

Operating

Efficiencies

Corporate Overview

Opportunities to Move Gas Out of the Northeast

11

The oversupply of natural gas in the Northeast is creating opportunities for

the midstream businesses to develop projects to deliver to higher-priced

markets such as Eastern Canada and the Southeast

Corporate Overview

Marcellus Infrastructure Growth Still Has Room to Run

12

Capacity Added

1,819 MDth per day

Capital Deployed

$422 million

2010 to 2013 Expansions

Capacity Planned

1,724 to 2,224 MDth per day

Capital Expenditures Planned

~$1.5 billion

2014+ Expansions

Plans are in place to deploy

significant capital to double

the expansion capacity

added since 2010

National Fuel Gas Company

A History of Success & A Future of Opportunity

13

10-15%

Adjusted EBITDA Growth

15-25%

Production Growth

$1.5 Billion of Midstream

Investment Over 5 Years

Future Goals

Strong Balance Sheet

Ability to modestly increase

leverage

1.89x Debt/Adjusted EBITDA

Balanced Business Mix

58% E&P

(1)

42% Midstream/Utility

(1)

Operational synergies

Investment Grade Credit

Diversification of businesses

provide credit support

Leverage is the cheapest cost of

capital today

Corporate Overview

Maintaining Our View on Corporate Structure

14

Today

Future (2015+)

More Aggressive Growth

Requires Capital

Goal is to accelerate value

creation

Need stronger natural gas prices

Additional leverage is limited

Result may lead to a shift in

business mix

Options to Consider

Midstream MLP

Upstream/Midstream JV

In today’s commodity price environment, our current structure

can handle near-term growth.  Look to accelerate development

when the economics of doing so are favorable.

Exploration & Production

Overview

Seneca Resources

Seneca’s Evolution

16

Total production increased 45% to 120.7 Bcfe

Seneca Resources

Fiscal 2013 Highlights

17

Replaced 351% of proved reserves

Finding & Development Cost: $1.31/Mcfe

Marcellus Finding & Development Cost: $0.99/Mcfe

351%

Achieved major breakthrough in the Marcellus

Shale Western Development Area (WDA)

De-risked 1,700 to 2,000 future drilling locations

WDA

Success

Seneca Resources

Disciplined Capital Spending

18

Seneca Resources

Proven Record of Growth

19

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

2011-2013

$1.67

2013 F&D Cost = $1.31

Marcellus F&D: $0.99

Doubled Proved Reserves

Since 2010

71% Proved Developed

Seneca Resources

Best-In-Class Marcellus Shale Reserve Growth

20

Seneca Resources

Delivering Tremendous Production Growth

21

Seneca Resources

Delivering More than Just Absolute Growth

22

Marcellus Shale

Significant Position & Integral Part of Seneca’s Future

23

Company

Net Marcellus

Acreage

(1)

Enterprise

Value

(2)

($ Billions)

Acres per

$ Million of EV

NFG

780,000

$7.4

105.4

RRC

835,000

$15.5

53.9

EQT

560,000

$15.5

36.1

SWN

337,000

$14.6

23.0

AR

334,000

$17.2

19.4

COG

200,000

$15.2

13.1

Marcellus Shale

Factors for Success

Acreage Position –

Quantity & Quality

Operating Expertise

Control costs

Maximize production

Gathering, Transportation and Marketing

Financial Stability

Ability to withstand price swings and market dislocations

24

Marcellus Shale

Prolific Pennsylvania Acreage

25

Seneca Acreage

Huge Position –

Varies in Understanding

26

Understanding Seneca’s

780,000 Net Acres

Northeast Core

~30,000 acres in NE Core

Tier I Acres

~200,000 acres

Economic less than $4/Mcf

Awaiting Evaluation

~250,000 acres

Requires Gas Price Above $4/Mcf

~300,000 acres

Seneca Acreage

Fee Ownership & Contiguity are Beneficial

27

No Royalty

No Lease

Expiration

Contiguous

Acreage

Blocks

Seneca’s Tier I acreage is approaching

Northeast Core economics

28

Seneca Acreage

Seneca’s Marcellus Acreage Provides a Unique Advantage

Seneca Advantage #1

Fee Ownership

Position

28% IRR

Competitor

Advantage #1

Advantage #2

Seneca Advantage

Capital Expenditures

$9,000

$9,000

$7,000

$7,000

Multiple Pads

No

No

Yes

Yes

Working Interest

100%

100%

100%

100%

Revenue Interest

84%

100%

84%

100%

IRR

18%

28%

29%

43%

Seneca Advantage #2

Contiguous Acreage

for Multiple Pads

29% IRR

Seneca Advantage

Fee Ownership +

Contiguous Acreage

43% IRR

Competitor

Single Pad

Working Interest: 100%

Revenue Interest: 84%

18% IRR

Seneca’s Operations

Best-In-Class Operator in Lycoming County (EDA)

29

Seneca’s Operations

Top-Notch Lycoming Economics

30

Seneca’s Operations

Seneca’s Lycoming Economics are in the Top 3

31

Seneca’s Operations

Driving Down Well Costs

32

In 2014, total well costs are expected to be ~35-40% lower than 2012

Seneca’s Gathering & Marketing

Seneca’s Overall Marketing Strategy

33

Develop gathering

infrastructure with

NFG Midstream

Firm sales at

interstate pipeline

interconnects

Firm transport  (FT)

to major markets

Firm sales tied to

FT contracts

Financial hedges to

lock in benchmark

and basis risk

Financial hedges to

lock in benchmark

and basis risk

Historical Strategy

Current/Long-Term Strategy

National Fuel’s Financial Stability

Ability to Withstand Pricing Challenges

34

Marcellus Shale

Factors for Success

Acreage Position –

Quantity & Quality

Operating Expertise

Control costs

Maximize production

Gathering, Transportation and Marketing

Financial Stability

Ability to withstand price swings and market dislocations

35

California

Outstanding Cash Flow

(1)

36

California

Looking Back at the Successful Ivanhoe Acquisition

37

California

Looking Forward

38

1.

Manage decline of base

production

2.

Pursue and develop opportunities

for growth from current assets

Sespe

East Coalinga

South Midway Sunset

3.

Continue to pursue additional

acquisition and farm-in

opportunities

Seneca Resources

Key Metrics

39

Operational

Strategy

Metric

Fiscal 2009

Strategic

Improvements

Fiscal 2013

Focus on growth-

oriented Marcellus

Shale assets with

significant fee

acreage

Maintain and grow

strong cash flow

assets in California

East Division

Production

East Division

Proved Reserves

East Division

EBITDA

Operating Costs

(1)

West Division

EBITDA

Cash Margin

(2)

9 Bcfe

(21% of Total Production)

152 Bcfe

(29% of Proved Reserves)

$57 million

(20% of Total EBITDA)

$2.15 per Mcfe

$172 million

$52 per Bbl

101 Bcfe

(83% of Total Production)

1,240 Bcfe

(80% of Proved Reserves)

$284 million

(57% of Total EBITDA)

$1.09 per Mcfe

One of the lowest cost

producers in the region

$215 million

$66 per Bbl

12x Production

Growth

7x Reserve

Growth

5x EBITDA

Growth

49% Decrease

per Mcfe

25% EBITDA

Growth

28% Margin

Improvement

Seneca Resources

What Will Seneca Look Like Moving Forward?

40

Consistent Production Growth: 15-25% CAGR

Driven by a very large, high-quality Appalachian acreage position

Maintain Oil Production    

Expand When Possible

Excellent operator and significant cash flow generation

Disciplined Spending Driven by Rates of Return

Pace of development adapts to changing market dynamics

A Leader in Technology, Safety & Environmental Responsibility

Maintain a leadership role in using technology and developing best practices

41

Appraisal & Development

Overview

Marcellus Shale

WDA Is the Key to Seneca’s Long-Term Growth Outlook

42

Full Development Since 2010

~225 locations remaining

70-90 wells in Lycoming County

Near-term driver of growth

Full Development Started in 2013

1,700 to 2,000 locations de-risked

Long-term driver of growth

Seneca Lease

Seneca Fee

720,000 Acres

60,000 Acres

Marcellus Shale

Significantly Improved Understanding of the WDA

43

James City

Church Run

Owl’s Nest

Mt. Jewett

W. Branch

Clermont

St. Mary’s

Kyler’s Corner

Boone Mtn

Sulger Farm

Tionesta

Beechwood

Red Hill/

Leasgang

Punxy

Rich Valley

Ridgway

SRC Lease Acreage

SRC Fee Acreage

Key Statistics

Vertical

Wells:

30

Full

Core:

8

Sidewall

Core:

2

3D

Seismic:

432

sq

m

3D Seismic Outlines

EOG Earned Acreage

Marcellus Shale

Northwest PA Generalized Cross-Section

44

Transitional

Outer Shelf

CaCO

3

Sed. Rate

TOC

Platform

Basin

Rich Valley

Clermont

Beechwood

Owl’s Nest

James City

Leasgang

Punxy

Ridgway

High variability, very poor

rock quality in areas

High organics, great rock quality, less variability

Medium rock quality, high pressures

Marcellus Shale

WDA Log Summary Cross-Section

45

TOC/PHI/BWV

0        Wt%       50

0.2   v/v    0

0.2   v/v    0

Mineralogy

Volume %

Gas Resource

0   Mcf/ac-ft  1500

0  Bcf/mi  100

= 6.8 -

8.1%

Total GIP = ~70/sect

= 5.6 -

6.7%

Total GIP = ~75/sect

TOC/PHI/BWV

0        Wt%       50

0.2   v/v    0

0.2   v/v    0

Mineralogy

Volume %

Gas Resource

0   Mcf/ac-ft  1500

0  Bcf/mi  100

TOC/PHI/BWV

0        Wt%       50

0.2   v/v    0

0.2   v/v    0

Mineralogy

Volume %

Gas Resource

0   Mcf/ac-ft  1500

0  Bcf/mi  100

TOC/PHI/BWV

0        Wt%       50

0.2   v/v    0

0.2   v/v    0

Mineralogy

Volume %

Gas Resource

0   Mcf/ac-ft  1500

0  Bcf/mi  100

= 5.5 -

6.6%

Total GIP = ~60/sect

= 2.8 –

4.3%

Total GIP =  < 40/sect

Very poor rock quality.

Low gas in place.

Transitional Outer Shelf

Platform

Basin

SRC Lease Acreage

SRC Fee Acreage

EOG Earned JV Acreage

Marcellus Shale

2013 & 2014 WDA Delineation Program

46

Owl’s Nest –

Delineating

2 High Btu Wells Completed

Rich Valley –

Full Development

2 Wells Completed

7-Day IP of 7.8 MMcf/d & EUR of 7.4 Bcf

2

Well 7-Day IP: 4.5 MMcf/d

Tionesta –

Delineating

1 Well Completed

Ridgway –

Delineating

1 Well Completed

2013 Drill Program

Seneca Operated

Heath –

Delineating

1 Well Planned

Sulger Farms –

Delineating

1 Well Planned

Hemlock –

Delineating

1 Well Planned

2014 Drill Program

Church Run –

Delineating

1 Well Completed

Clermont –

Full Development

2 Wells Completed

9H: 7-Day IP of 10 MMcf/d & EUR of 8.6 Bcf

10H: 7-Day IP of 7.4 MMcf/d & EUR of 6.6 Bcf

nd

Marcellus Shale

Rich Valley/Clermont is in Full Development Mode

47

Clermont

Rich Valley

Rich Valley 2

Well

7-day IP: 4.5 MMcf/d

Lateral Length: 4,492’

Marcellus Faults

Marcellus & Basement Faults

200-250 Horizontal Locations

Pad N: Spacing Test

JV Wells

Pad H

Pad D

Pad E

Pad O

SRC Lease Acreage

SRC Fee Acreage

Clermont

RCS: 9H 7-day IP:  10.0 MMcf/d (EUR: 8.6 Bcf)

Non-RCS: 10H 7-day IP:  7.4 MMcf/d

Rich Valley

7-day IP: 7.8 MMcf/d

EUR: 7.4 BCF

Lateral Length: 6,372’

nd

Marcellus Shale

Clermont Wells Improved from Early Non-Op JV Wells

48

Clermont 5H & 6H (Non-op wells)

Avg. lateral length: 3,344’

Small casing: 4.5”

Restricted pump rates

Wide stage spacing: 350’

No soaking, low Sw’s

Clermont 9H & 10H

(Seneca wells)

Avg. lateral length: >5,500’

Large casing: 5.5”

Increased pump rates

9H (RCS): 150’

spacing

10H (Standard): 240’

spacing

Soaked both wells: 30 Days

Marcellus Shale

Moving All Completions to Reduced Cluster Spacing (RCS)

49

RCS Design

Conventional Design

Twice the number of stages/perforations

Increases stimulated reservoir volume

Increased proppant near the wellbore improves fracture conductivity

Marcellus Shale

Consistently Improved Results in the Owl’s Nest Area

50

2013 Appraisal Program

Lateral length

>4,400’

to 6,200’

RCS completions

150’

spacing

Soaked wells

30 –

60 days

Target interval

Union Springs: 100% in

target

Marcellus Shale

Strong Wells Across WDA Acreage

51

Well Name

Completion

Design

Treatable

Lateral

Length

Stages

Peak

24-Hour

Rate

(MMcfd)

Peak

7-Day

Rate

(MMcfd)

EUR

(Bcf)

Status

Rich Valley 27H

RCS

1

6,372’

42

8.1

7.8

7.4

Producing

Clermont 9H

RCS

5,500’

37

11.4

10.0

8.6

Producing

Clermont 10H

Non-RCS

5,565’

23

8.1

7.3

6.6

Producing

Ridgway 19H

RCS

5,537’

37

7.1

6.4

5-8

Flowback

Test

Church Run 2H

RCS

4,435’

29

4.8

4.5

4-6

Flowback

Test

Owl’s Nest 54H

RCS

6,139’

41

6.1

5.8

4-7

Flowback

Test

Owl’s Nest 59H

RCS; Gel

2

5,371’

36

3.4

3.1

2-4

Flowback

Test

Marcellus Shale

Key Areas of Improvement in Recent Delineation Program

52

Areas of Improvement

2012-2013 Delineation Program

Target Selection (Landing Depth)

Identification of specific target interval is key

Target Execution

Percent of wellbore in target interval increased

from prior years

Completion Design

Reduced Cluster Spacing (RCS)

Shorter stages: From 240-350’

down to 150’

Increased volume of sand per foot

Lateral Length

Drilled laterals 15-45% longer than in prior years

Marcellus Shale

Selection of Target Interval is Critical

53

Previous programs spent a significant portion ( > 60% ) of the wellbore outside of

the current target interval, identified to have improved productivity

Marcellus Shale

Optimized Landing Depth

54

EDA Lycoming Type Log

160

140

120

100

80

40

20

60

ROP (ft/hr)

ROP vs Height Above Onondaga

Improved Target Zone Drivers

Best rock quality in terms of organic content,

brittleness, and porosity

Highest rate of penetration (ROP)

Marcellus Shale

Continued Improvement Staying within Targeted Interval

55

Reasons for Improvement

3D seismic acquisition

Improved communication between Geology, Drilling and Completion

teams

Geosteering technology (azimuthal GR)

Marcellus Shale

RCS

&

Increased

Sand

Volume

Generating

Better

Results

56

Improved near wellbore

fracture conductivity

Increases near wellbore fracturing

& stimulated  reservoir volume

Reducing stage length, increasing the number of stages, and increasing proppant

volume have been integral in improving well productivity

Marcellus Shale

Longer Laterals Drive Improved Economics

57

Lateral lengths have increased even as target

selection and execution have improved

Marcellus Shale

2013 Appraisal Program was a Success

58

50-hr Flowback Rate (Mcf/d/1000')

P10

P50

P90

Mean

StDev

FY13 Program

1,427

1,128

893

1,147

211

Previous Programs

1,002

519

270

589

329

Avg Rate. Peak 50 ht/1000’

Marcellus Shale

200,000 Acres With 6-8 Bcfe EUR Wells

59

Marcellus Shale

1,700 To 2,000 Economic WDA Locations Below $4/Mcfe

60

Prospect

County

Product

Approx.

Remaining

Locations

EUR

(Bcfe)

BTU

IRR

(1)

@

$4/MMBtu

15% IRR

(1)

Breakeven Price

($/Mcf)

Tract 100

Lycoming

Dry Gas

40

11.5

1,030

90%

$2.20

Gamble

Lycoming

Dry Gas

29

10-11

1,030

77%

$2.33

Tract 595

Tioga

Dry Gas

20

8.4

1,030

45%

$2.63

Clermont/Rich Valley

Elk/Cameron

Dry Gas

228

6-8

1,050

38%

$2.80

Ridgway

Elk

Dry Gas

450-570

6-8

1,111

26%

$3.30

Hemlock

Elk

Dry Gas

130-170

6-8

1,070

23%

$3.40

Church Run

Elk

Dry Gas

60-70

6-8

1,125

22%

$3.45

(W) West Branch

McKean

Dry Gas

47

6-8

1,050

22%

$3.48

Covington

Tioga

Dry Gas

Developed

5.7

1,030

22%

$3.49

Heath

Jefferson

Dry Gas

260-330

5-8

1,060

19%

$3.65

Sulger Farms

Jefferson

Dry Gas

170-210

5-8

1,020

19%

$3.66

Owl’s Nest/James City

Elk/Forest

Dry Gas

120-160

5-8

1,125

18%

$3.69

Boone Mt.

Elk

Dry Gas

230-290

4-6

1,020

18%

$3.76

Church Run

Elk

Wet Gas

40-50

2-4

1,140

13%

$4.32

Tionesta

Forest/Venango

Wet Gas/

Liquids

300-340

4-6

1,325

12%

$4.50

Owl’s Nest/James City

Elk/Forest

Wet Gas

150-180

4-6

1,140

11%

$4.51

Mt. Jewett

McKean

Wet Gas

90-110

2-4

1,140

6%

$5.50

Beechwood

Cameron

Dry Gas

210-280

2-4

1,030

2%

$7.14

Red Hill

Cameron

Dry Gas

150-200

2-4

1,030

2%

$7.14

2013 Appraisal prospects

2014 Appraisal prospects

Marcellus Shale Marketing

Intercompany Gathering Ensures Timely Gas Sales

61

Develop gathering

infrastructure with

NFG Midstream

Firm transport  (FT)

to major markets

Firm sales tied to

FT contracts

Financial hedges to

lock in benchmark

and basis risk

Financial hedges to

lock in benchmark

and basis risk

Historical Strategy

Current/Long-Term Strategy

Firm sales at

interstate pipeline

interconnects

Marcellus Shale Marketing

Securing Firm Transportation to Major Markets

62

Current Seneca

Development Areas

Firm transport to

Canada, Northeast

and Southeast

U.S. markets

Marcellus Shale Marketing

TGP 300 Production & Firm Sales Aligned Thru 2014

63

Marcellus Shale Marketing

Targeting Future Firm Sales on Transco

64

Point Pleasant & Utica Shale

Continuing to Delineate

65

Permitted

Drilled/Drilling

Completed

Producing

Mt. Jewett

Horizontal: completed September 2013

Peak 24-Hour Rate: 8.5 MMcf/d

Tionesta

Horizontal: Completed Fall 2012

Peak 24-Hour Rate: 3.9 MMcf/d

Rex

9.2 MMcf/d

Chesapeake

6.4 MMcf/d

Range Resources

4.4 MMcf/d

Range Resources

1.4 MMcf/d

“Not Effectively Stimulated”

Halcon

6.6 MMcf/d,

750 Bbls/d

Halcon

2.5 MMcf/d,

360 Bbls/d

Halcon

4.5 MMcf/d,

860 Bbls/d

Eastern Ohio

Point Pleasant Core

Point Pleasant

Northern Boundary

Mississippian Lime

Commencing Evaluation Program in Fiscal 2014

66

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)

Total Net Acres: 13,615

100% working interest in 4,400

gross acres

55% net working interest in 17,365

gross acres

Negotiated an increase in Seneca’s

working interest and have taken over

as operator

Currently

drilling first well

Will drill up to 5 evaluation wells in

2014

California

Update

California

Stable Production Fields; Modest Growth Potential

68

East Coalinga

Temblor Formation

Primary

North Lost Hills

Tulare & Etchegoin Formation

Primary/Steamflood

South Lost Hills

Monterey Shale

Primary

North Midway Sunset

Tulare & Potter Formation

Steamflood

South Midway Sunset

Antelope Formation

Steamflood

Sespe

Sespe Formation

Primary

Key Areas of Focus in 2014

1.

East Coalinga Evaluation

2.

South Midway Sunset Extensions

3.

Sespe Coldwater Evaluation

California

South Midway Sunset Has Delivered Significant Growth

69

Highlights Since Acquisition

Increased daily production by 130%

Drilled 80 new producers

Added 3.3 MMBO of proven reserves

Increased steam capacity by 280%

Identified opportunities for additional

pool development

Extended Pool Boundary

Original Pool Boundary

Existing Wells

California

South MWSS Growth Opportunities Continue into 2014

70

California

Early Success in Farm-In with Chevron at East Coalinga

71

1-Acre

Test

48 BOPD

5-Acre Test

54 BOPD

2-Acre Test

18 BOPD

2000’

Returned to Production

1-acre (~30 locations)

2-acre (~40 locations)

5-acre (~120 locations)

Downspacing Potential

2013 Evaluation Wells

Seneca Lease

Existing Wells

Highlights Since Acquisition

Achieved highest field production in 10

years

Production increased 130% since 1/2013

Drilled 12 evaluation wells that

confirmed downspacing potential

Returned 40 idle wells back to

production

California

Ramping Up the Coalinga Drill Program in Fiscal 2014

72

2014 Development Program

(Tentative)

Location Selection Criteria

2014 Locations (30)

2013 Locations (12)

•

2013 new well production

•

Reservoir pressure mapping

•

Historical production

•

Past EOR attempts

California

Ongoing Evaluation of Long-Term Sespe Potential

73

TC 524-28

IP: 100 BOEPD

1

Oil 10/13

“X”

SANDS ISOCHORE (Thickness)

1

Mile

2011 Wells (5)

2012 Wells (6)

2013 Wells (6)

2014 Wells (4)

TC 525-28

IP: 160 BOEPD

1

Oil 10/13

WS 525-33

1

Oil in 11/13

WS 535-33

1

Oil in 11/13

Year

Target

# of

Wells

Average IP

(BOEPD)

2011

Sespe (5-Acre Infill)

2

75

2011

Sespe (10-Acre)

3

90

2012

Sespe (5-Acre Infill)

2

70

2012

Coldwater

2

125

2012

Sespe (10 Acre)

2

110

2013

Sespe (5-Acre Infill)

2

NA

2013

Coldwater

2

130

2013

Sespe (10 Acre)

2

85

st

st

st

st

California

Evaluating the Monterey Shale at South Lost Hills

74

California

Limited Growth Opportunities, But Strong Economics

75

Field

Average

Well Cost

Average

EUR

(MBO)

Estimated

IRR

@$100/Bbl

Fiscal 2014

Locations

South Midway Sunset

$250,000

30

75%

23

East Coalinga

$400,000

40

50%

30

Sespe –

5 Acre Infill

$2,800,000

150

25%

0

Sespe -

Coldwater

$2,800,000

180

35%

4

California

Modest Growth Anticipated in 2014 and 2015

76

77

Marcellus Operational

& Environmental Overview

Marcellus Shale

Our Development Approach Drives Major Efficiencies

78

Multi-Well

Pads

Focused

Development

Areas

Faster Spud-to-Sales Timing

Economies of Scale Reduces Costs

Minimal Infrastructure Constraints & Well Backlog

Technical &

Operational

Expertise

Marcellus Shale

EDA Delivering Significant Growth

79

Covington –

Fully Developed

Gross Production: ~60 MMcf per Day

47 Wells Drilled and Producing

DCNR Tract 595

Gross Production: ~100 MMcf per Day

34 Wells Drilled (52 Total Locations)

26 Wells Producing

DCNR Tract 100

Gross Production:  ~220 MMcf per Day

40 Wells Drilled (70 Total Locations)

30 Wells Producing

Gamble

Recently, 30 to 50 future

locations were added in

Lycoming County

Marcellus Shale

EDA –

Historical Well Results Are Exceptional

80

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

8.4

4,639’

1.81

Tract 100

Lycoming

County

30

16.1

14.2

11.9

11.5

5,210’

2.21

Seneca’s acreage in Lycoming County has consistently delivered some of

the most prolific wells in the Marcellus Shale

Marcellus Shale

Faster Spud-to-Sales: Drilling Efficiencies

81

How has this been accomplished?

Directional Plan Optimization

Minimize drilling path corrections

Bit Selection

Increases drilling rate and durability

Drill Top-hole Sections Deeper

with Water

More efficient and cost effective

Optimize Landing Depth

Improves production and rate of

penetration

Marcellus Shale

Faster Spud-to-Sales: Multi-Well Pads Are Key

82

Limiting the movement of rigs between pads allows for more drilling

Using LEAN practices has eliminated four days from each rig move

Staying in smaller regional areas further limits move time

Marcellus Shale

Drilling Efficiencies Allow for More Wells per Year

83

In spite of increasing the average lateral length, each

rig is drilling more wells per year

Marcellus Shale

Faster Spud-to-Sales: Completing More Stages per Day

84

Marcellus Shale

Faster Spud-to-Sales: The Overall Picture

85

(1)

Marcellus Shale

Faster Spud-to-Sales: More Lateral Feet Completed Yearly

86

Marcellus Shale

Drilling Cost Reductions: Several Contributing Factors

87

Improvements From 2012 to 2013 ($525,000 per well)

Shorter drilling days to TD: $300,000

Faster rig moves (2012: 8.5 Days

2013: 4.5 Days): $20,000 (6-well pad)

Procurement and supply chain initiatives: $120,000

Directional plan optimization: $60,000

Natural gas-powered rigs: $25,000

Marcellus Shale

Completion Cost Reductions: Ongoing Optimization

88

Marcellus Shale

Completion Cost Reductions: New Efficient Technologies

89

Toe Sub

$60,000 savings per well

Time Savings

Time Savings

Time Savings

Sleeve

$200,000 savings per well

Dissolvable Balls

$300,000 savings per well

$3.4 million saved on a 6-well pad from the utilization of new technologies

Marcellus Shale

Completion Cost Reductions: Water Infrastructure

90

System Cost: $8.5 million

8 miles of pipeline

43 million gallons of storage

Will serve at least 70 wells

Provides 75% of water needs, with

the remainder being recycled

production fluid

Environmental & Cost Benefits

Eliminated the need for 47,000

water trucks since February 2012

Saved more than $4 million on Tract

100 development to date

Improved Efficiencies

Trucking in water across this

challenging terrain would have

delayed completions and production

This model has been successful in Lycoming & Tioga counties and

will be utilized in the WDA as development progresses

Marcellus Shale

Minimizing Backlogs: Coordinated Development

91

Coordination with NFG Midstream to construct gathering systems

Development well backlog typically consists of wells on pads in either

the drill or complete phase

Regional development programs

Focus on multi-well pads in smaller geographic areas allows for efficient

gathering connectivity

Managing completion schedule

Ongoing monitoring of operations and maintaining the flexibility

to alter

completion schedules

Sales Lag (Months)

0

6

12

18

IRR

(1)

@ $4/Mcf Realized Pricing

90%

58%

46%

38%

Seneca Resources

Committed to Health, Safety, and the Environment

92

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

Best Practices

Incorporating Lean

Process Strategies

Management team

dedicated to building

a culture of

continual EHS

improvement

Operating Excellence

Program

Compliance

Department

Midstream Businesses

Overview

Midstream Businesses

National Fuel’s Midstream Businesses

94

Reporting

Segments

Subsidiaries

Midstream Businesses

Positioned Well to Serve Appalachian Producers

95

National Fuel  Gas Supply

Corporation

System Length

~ 2,550 Miles

Storage Capacity

73.4 Bcf

Contracted Transport

2.58 MMDth/d

2013 Revenue

$191.2 Million

2010 –

2013

Capital Expenditures

$304.6 Million

Midstream Businesses

Positioned Well to Serve Appalachian Producers

96

Midstream Businesses

Positioned Well to Serve Appalachian Producers

97

Midstream Businesses

Long-Term Strategy Driven by Both Seneca & 3

rd

Parties

98

Develop strong partnerships with customers to help them

reach diverse, high-value markets

Midstream Businesses

Positioned to Serve Seneca’s Rapidly Growing Production

99

Gathering

Gathering is the Crucial First Step to Reaching a Market

100

Gathering

Existing Systems Supporting Seneca’s Near-Term Growth

101

Covington Gathering System

In-service date: November 2009

Capacity: 220,000 Dth per day

Interconnect: TGP 300

Capital expenditures (to date): $28.3 million

Capital expenditures (future): $7.5 million

Trout Run Gathering System

In-service date: May 2012

Capacity: 466,000 to 585,000 Dth per day

Interconnect:

Transco

–

Leidy

Lateral

Capital expenditures (to date): $128.0 million

Capital expenditures (future): $60 to $90 million

Gathering

Developing a 1+ Bcf/d Gathering System in the WDA

102

In-Service: August 2014

Initial Trunkline Capacity:

700 MMcf per day

Interconnect

TGP 300

Total Cost: $60-$92 Million

Major Facilities

24”

Pipeline –

6 Miles

8”-20”

Pipeline –

25+ Miles

Seneca Pads Producing

2 in Fiscal 2014 (15 Wells)

Gathering

Clermont Gathering System has Large Expandability

103

In-Service: Ongoing build-out

Ultimate Trunkline Capacity:

700 to 1,000 MMcf per day

Interconnects

TGP 300 and National Fuel

Gas Supply Corporation

(anticipated)

Total Cost:

$75 -

$125 million

Major Facilities

Additional Gathering

Clermont West, Clermont

East and Rich Valley

Compressor Stations

Seneca Pads Connected

Up to 25 pads connected

following the 2015

expansion

Gathering

A Number of Options to Serve 3

rd

Party Producers

104

Gathering

2014 Spending Driven by Seneca Development

105

$100 to $150 Million

Gathering

More than 1.5 Bcf per day of Gathering Capacity by 2015

106

Gathering

Capital Deployment Will Deliver Long-Term Growth

107

Revenue Growth (2013 to 2015): ~60%

CAGR

Capital Investment (2013 to 2015): ~60%

CAGR

Pipeline & Storage

Project Opportunities to Support WDA Growth

108

Develop multiple outlets

to high-value markets

Midstream Businesses

Providing Transportation to Higher-Priced Markets

109

Currently

Short Supply

Short Supply

Midstream Businesses

NE Supply Approaching NE Peak Demand

110

Forecasted

Actual

Peak Demand (24-25 Bcf per day)

Median Demand (11.5 Bcf per day)

Supply exceeds demand for

70% of the year by 2016

Midstream Businesses

Focusing on Projects to Non-Traditional Demand Markets

111

The markets of Eastern

Canada, the Mid-Atlantic

and Southeast look to be

the most desirable

markets for shippers to

reach over the long-term

Pipeline & Storage

Delivering Into the Eastern Canadian Market is Valuable

112

Pipeline & Storage

Northeast PA Spot Markets are Heavily Discounted

113

Pipeline & Storage

Major Expansion Designed for Canadian Deliveries

114

Northern

Access 2015

Niagara (TCPL)

Delivery Point

In-Service: November 2015

System: NFG Supply Corp.

Capacity: 140,000 Dth per day

Interconnect

Niagara (TransCanada)

Total Cost: $67 Million

Major Facilities

23,000 HP Compressor

Northern Access 2015

Canada &

Eastern

U.S.

Clermont

Pipeline & Storage

Clermont to Chippawa Provides Delivery Options

115

Delivery Point

Clermont to

Chippawa

Chippawa (TCPL)

Hopewell

(TGP 200)

Corning

(Millennium)

In-Service: 2016

System: Supply & Empire

Capacity

250,000+ Dth per day

Interconnects

Corning (Millennium)

Hopewell (TGP 200)

Chippawa (TransCanada)

Total Cost: ~$250 Million

Clermont to Chippawa

Canada &

Eastern U.S.

New

England

New York

City

Clermont

Pipeline & Storage

Longer-Term: Reaching Markets Along the Atlantic

116

Transco

In-Service: 2017

System: NFG Supply Corp.

Capacity

300,000 to 500,000 Dth per day

Interconnect

Transco Leidy Line

Total Cost: $100 to $150 Million

Clermont to Transco

To Mid-Atlantic

&

Southeast

Clermont to

Transco

Delivery Point

Clermont

Pipeline & Storage

Expansions to Move Gas from the WDA are Significant

117

Projects to Support WDA Growth

Project

Capacity (Dth/day)

Northern Access 2015

140,000

Clermont to Chippawa

250,000+

Clermont to Transco

300,000-500,000

Total New Capacity

690,000-890,000+

Project

Capital Cost

Northern Access 2015

$67 million

Clermont to Chippawa

$250 million

Clermont to Transco

$100-$150 million

Total Capital

Expenditures

$417-$467 million

Northern

Access 2015

Clermont to

Chippawa

Longer-Term

WDA Expansion

Clermont

Pipeline & Storage

Seneca Currently Represents a Small Portion of Capacity

118

Total Contracted Transportation Capacity (at 9/30/13): 3.6 MMDth

per Day

Pipeline & Storage

Recent 3

rd

Party Expansions Have Been Highly Successful

119

Projects to  Support 3

rd

Parties

Project

Capacity

(Dth/day)

Northern Access 2013

320,000

Tioga County Extension

350,000

Line N (2011, 2012 & 2013)

353,000

Total New Capacity

1,023,000

Project

Capital Cost

Northern Access 2013

$72 million

Tioga County Extension

$58 million

Line N (2011, 2012 & 2013)

$104 million

Total Capital Expenditures

$234 million

Northern

Access 2013

Tioga County

Extension

Line N Projects

Pipeline & Storage

NFGSC is Now a Net Exporter of Natural Gas to Canada

120

Northern Access project

was placed in-service

November 2011

Pipeline & Storage

National Fuel Becoming a Major SW PA Transporter

121

National Fuel Gas Supply Corp. went

from no SW Pennsylvania receipts in

2008 to nearly 40% of all volumes today

Pipeline & Storage

Additional Line N Expansions Planned for the Future

122

In-Service: November 2014

System: NFG Supply Corp.

Capacity: 105,000 Dth per day

Precedent agreements signed for all

available capacity

Interconnect

Mercer (TGP Station 219)

Total Cost: $30 Million

Expansion: $27 million

System Modernization: $3 million

Major Facilities

3,500 HP Compressor

2.1 miles –

24”

Replacement Pipeline

Mercer Expansion

Mercer

(TGP Station 219)

Mercer

Expansion

Mercer

(TGP Station 219)

Pipeline & Storage

Pairing Line N Expansions with System Modernization

123

In-Service: November 2015

System: NFG Supply Corp.

Capacity: 175,000 Dth per day

Precedent agreements signed for

145,000 Dth per day

Interconnect

Mercer (TGP Station 219)

Holbrook (TETCO)

Total Cost: $74 Million

Expansion: $39 million

System Modernization: $35 million

Major Facilities

3,600 HP Compressor

23.5 miles –

24”

Replacement Pipeline

Westside Expansion &

Modernization

Holbrook (TETCO)

Westside

Expansion &

Modernization

Pipeline & Storage

Developing Unique Solutions for Shippers

124

In-Service: November 2015

System: NFG Supply & Empire Pipeline

New No-Notice Services

Preserving 172,500 Dth per day (RG&E)

Preserving 20,000 Dth per day (NYSEG)

Precedent agreement executed with

RG&E

Capacity

Transportation: 69,000 Dth per day

Retained Storage: 3.3 Bcf

Interconnect

Tuscarora (NFG/Supply)

Total Cost: $56 Million

Major Facilities

1,500 HP Compressor

18 miles –

20”

Replacement Pipeline

Tuscarora Lateral

Tuscarora

Lateral

Pipeline & Storage

Significant Expansions Are Driving Growth

125

Completed Projects

Project

Capacity

(Dth/day)

Lamont Compressor Station

90,000

Line “N”

Expansion

160,000

Tioga County Extension

350,000

Northern Access Expansion

320,000

Line “N”

2012 Expansion

163,000

Line “N”

2013 Expansion

30,000

New Capacity Additions

1,113,000

Mercer Expansion Project

105,000

West Side Expansion

145,000

Northern Access 2015

140,000

Tuscarora Lateral

69,000

Planned Capacity Additions

459,000

Line N Corridor

Line “N”

Expansion

Line “N”

2012 Expansion

Line “N”

2013 Expansion

Mercer Expansion

West Side Expansion

Total Capacity

603 MDth/d

Delivering Gas North

Tioga County Extension

Northern Access

Northern Access 2015

Clermont to Chippawa

Total Capacity

1,060 MDth/d

Leaving the WDA

Lamont Compressor

Clermont to Transco

Total Capacity

390 to 590 MDth/d

Planned Projects

Clermont to Chippawa

~250,000

Clermont to Transco

300,000 –

500,000

Potential Capacity Additions

550,000 –

750,000

Potential Projects

Pipeline & Storage

Expansion Project Revenue Growth

126

Larger projects under consideration

for fiscal 2016 and 2017 will drive

significant revenue growth

Midstream Businesses

New Shale Production Driving Tremendous Growth

127

Utility

Overview

Utility

New York & Pennsylvania Service Territories

129

New York

Total Customers: 520,000

Rate Mechanisms:

Revenue Decoupling

Weather Normalization

Low Income Rates

Choice Program/Purchase of

Receivables

Merchant Function Charge

(Uncollectibles Adjustment)

90/10 Sharing (Large Customers)

Natural Gas Vehicle Pilot Program

ROE: 9.1% (Litigated -

2007)

Pennsylvania

Total Customers: 213,000

Rate Mechanisms:

Low Income Rates

Choice Program/Purchase of

Receivables

Merchant Function Charge

ROE: Black Box Settlement (2007)

Utility

Customer Usage

130

Residential Usage

Industrial Usage

Utility

Continued Cost Control Helps Provide Earnings Stability

131

Utility

Capital Spending Largely Focused on Maintenance

132

The Utility remains focused

on spending to maintain

the ongoing safety and

reliability of its system

Utility

Providing Predictability and Stability

133

Utility

Working Towards a Settlement in New York

134

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

An agreement in principle has been

reached with five parties and the

litigation schedule has been extended

indefinitely to allow the settlement

process to move forward

May 8, 2013

Company responds to

OTSC

June 14, 2013

“Temporary rates”

become effective

July 26, 2013

Settlement discussions

commence for

permanent rates

Hedging

Overview

Hedging Overview

How Does Seneca Sell its Production?

136

Well Head

Interconnection

with Interstate

Pipeline Network

Gathering

System

3rd Party

Marketer

(or spot market)

Firm Transport

Demand Center

(firm sales or

spot market)

Contracted Basis

Differential

FT Rate

The 1,700 to 2,000 economic locations

at less than $4.00/Mcf are based on a

realized price after gathering

Spot Market

Hedging Overview

Firm Sales Provide a Market for Appalachian Production

52

Prices shown represent the sales (netback

price) at the first non-affiliated interstate

pipeline, including the cost of all related

downstream transportation.

137

Hedging Overview

Seneca Methodically Layers in Index Hedges Over Time

138

Hedging Overview

Current Hedge Book has Seneca Positioned Very Well

139

Commodity Risk Management

Oil & Natural Gas Hedges are Above the Current Strip

(1)

140

Hedging Overview

Determining Seneca’s Realized Price on Firm Sales

141

NYMEX & Dominion

Monthly Settlement Prices

Natural Gas Index Swaps

Negotiated at time of Agreement

Based on Current Market at Sales/Delivery Point

Hedging Overview

The Impact of Firm Sales on Realized Price

57

Determining the Price of a Firm Sales Contract

Contract Reference Point

NYMEX

Dominion

December Settlement

$4.000

$3.650

Less: Average Sales Basis Differential

($0.284)

($0.265)

Average Realized Price (Before Hedging)

$3.716

$3.235

142

Hedging Overview

Pairing Firm Sales with Hedges Leads to Price Certainty

58

Determining the Price of a Firm Sales Contract

With a $4.25/MMBtu Hedge at the Reference Point

Contract Reference Point

NYMEX

Dominion

December Settlement

$4.000

$3.650

Less: Average Sales Basis Differential

($0.284)

($0.265)

Average Realized Price (Before Hedging)

$3.716

$3.385

December Hedge

$4.250

$4.250

Less: December Settlement

$4.000

$3.650

Hedge Gain

$0.250

$0.600

Average Realized Price (After Hedging)

$3.966

$3.985

143

Hedging Overview

Price Certainty only if Firm Sales & Hedge Index Match

59

Hedging Dominion Firm Sales Contracts

With a $4.25/MMBtu Hedge at NYMEX vs. Dominion

Contract Reference Point

Dominion

Dominion

December Settlement

$3.650

$3.650

Less: Average Sales Basis Differential

($0.265)

($0.265)

Average Realized Price (Before Hedging)

$3.385

$3.385

Hedge Reference Point

NYMEX

Dominion

December Hedge

$4.250

$4.250

Less: December Settlement

$4.000

$3.650

Hedge Gain

$0.250

$0.600

Average Realized Price (After Hedging)

$3.635

$3.985

Dominion to NYMEX Basis

144

Difference: $0.35

Hedging Overview

FY 2014 Production –

Firm Sales & Hedge Composition

145

Price Certainty

100% Hedged

@ $4.24 /MMcf

Price Certainty

92% Hedged

@ $4.26/MMcf

Seneca has an additional 12.7

Bcf of NYMEX hedges to help

mitigate commodity exposure

on its WDA sales

EDA NYMEX

Firm Sales

EDA DOM

Firm Sales

EDA

Spot Sales

WDA      

Production

Total

East Division

Production

Financial

Overview

National Fuel Gas Company

Targeting Sustained Growth for the Next Five Years

147

National Fuel Gas Company

Capital Spending Adjusts to Capitalize on Opportunities

148

National Fuel Gas Company

Forecasting a Modest Outspend in 2014

2014

Forecast

149

National Fuel Gas Company

Maintaining a Strong Balance Sheet

150

Total Debt

(1)

43%

$3.843 Billion

As of September 30, 2013

Debt / Adjusted EBITDA

Capitalization

National Fuel Gas Company

Strong Liquidity with an Investment Grade Rating

151

5.58%

Embedded Cost of

Long-Term Debt

Liquidity ($Millions)

Cash and Temporary Investments

$     65

Available Short-Term Credit Facilities

$1,085

Total Short-term Liquidity

$1,150

National Fuel Gas Company

Focused on Delivering Strong Returns

152

2009-2011

2010-2012

2011-2013

NFG Percentile

81%

75%

88%

National Fuel Gas Company

Dividend Track Record

153

Current

Dividend Yield

(1)

2.1%

Dividend Consistency

Consecutive Dividend Payments

111 Years

Consecutive Dividend Increases

43 Years

Current Annualized Dividend Rate

$1.50 per Share

National Fuel Gas Company

A History of Success & A Future of Opportunity

154

30% CAGR

Since 2009

Adjusted

EBITDA

Growth

Production

Growth

Midstream

Businesses

EBITDA

10-15% CAGR

2014 to 2018

Adjusted

EBITDA

Growth

15-25% CAGR

2014 to 2018

Production

Growth

10-15% CAGR

2014 to 2018

Midstream

Businesses

EBITDA

A History of Success

10% CAGR

Since 2009

10% CAGR

Since 2009

A Future of Opportunity

Appendix

Gathering

Historical Financials –

2010 & 2011

156

QTD ended

QTD ended

QTD ended

QTD ended

12/31/2009

3/31/2010

6/30/2010

9/30/2010

FISCAL 2010

Operating Revenue

94

$                       

843

$                    

1,224

$                 

1,237

$                 

3,398

$                   

Operating Expenses:

Operation & Maintenance Expense

143

344

398

484

1,369

Property, Franchise & Other Taxes

1

7

1

-

9

Depreciation, Depletion & Amortization

-

129

153

104

386

144

480

552

588

1,764

Operating Income

(50)

$                     

363

$                    

672

$                    

649

$                    

1,634

$                   

Capital Expenditures

6,538

$                   

QTD ended

QTD ended

QTD ended

QTD ended

12/31/2010

3/31/2011

6/30/2011

9/30/2011

FISCAL 2011

Operating Revenue

1,999

$                 

2,974

$                 

3,043

$                 

3,235

$                 

11,251

$                 

Operating Expenses:

Operation & Maintenance Expense

437

535

435

437

1,844

Property, Franchise & Other Taxes

8

4

8

2

22

Depreciation, Depletion & Amortization

173

159

161

168

661

618

698

604

607

2,527

Operating Income

1,381

$                 

2,276

$                 

2,439

$                 

2,628

$                 

8,724

$                   

Capital Expenditures

17,021

$                 

Gathering

Historical Financials –

2012 & 2013

157

QTD ended

QTD ended

QTD ended

QTD ended

12/31/2011

3/31/2012

6/30/2012

9/30/2012

FISCAL 2012

Operating Revenue

3,565

$                 

3,346

$                 

4,494

$                 

6,069

$                 

17,474

$                 

Operating Expenses:

Operation & Maintenance Expense

493

534

633

780

2,440

Property, Franchise & Other Taxes

25

25

4

169

223

Depreciation, Depletion & Amortization

166

167

444

913

1,690

684

726

1,081

1,862

4,353

Operating Income

2,881

$                 

2,620

$                 

3,413

$                 

4,207

$                 

13,121

$                 

Capital Expenditures

80,012

$                 

QTD ended

QTD ended

QTD ended

QTD ended

12/31/2012

3/31/2013

6/30/2013

9/30/2013

FISCAL 2013

Operating Revenue

5,682

$                 

8,222

$                 

10,586

$             

10,291

$             

34,781

$                 

Operating Expenses:

Operation & Maintenance Expense

943

1,027

1,311

1,447

4,728

Property, Franchise & Other Taxes

141

51

41

44

277

Depreciation, Depletion & Amortization

680

1,062

1,064

1,138

3,944

1,764

2,140

2,416

2,629

8,949

Operating Income

3,918

$                 

6,082

$                 

8,170

$                 

7,662

$                 

25,832

$                 

Capital Expenditures

54,792

$                 

National Fuel Gas Company

Comparable GAAP Financial Measure Slides and Reconciliations

158

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

ongoing

operating

results,

for

measuring

the

Company’s

cash

flow

and

liquidity,

and

for

comparing

the

Company’s

financial

performance

to

other

companies.

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.

159

Reconciliation of Exploration & Production West Division Adjusted EBITDA

to Exploration & Production Segment Net Income

($ Thousands)

FY 2013

Exploration & Production - West Division Adjusted EBITDA

215,042

$        

Exploration & Production - All Other Divisions Adjusted EBITDA

277,341

Total Exploration & Production Adjusted EBITDA

492,383

$        

Minus: Exploration & Production Net Interest Expense

(38,244)

Minus: Exploration & Production Income Tax Expense

(95,317)

Minus: Exploration & Production Depreciation, Depletion & Amortization

(243,431)

Exploration & Production Net Income

115,391

$        

Exploration & Production Net Income

115,391

$        

Pipeline & Storage Net Income

63,245

Gathering Net Income

13,321

Utility Net Income

65,686

Energy Marketing Net Income

4,589

Corporate & All Other Net Income

(2,231)

Consolidated Net Income

260,001

$     

160

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

$          

215,042

$             

Exploration & Production -

East Division Adjusted EBITDA

57,179

$            

75,098

$            

175,392

$          

167,806

$          

283,509

$             

Exploration & Production -

All Other Divisions Adjusted EBITDA

50,960

64,526

14,462

2,426

(6,168)

Total Exploration & Production Adjusted EBITDA

279,711

$          

327,462

$          

377,457

$          

397,129

$          

492,383

$             

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

279,711

$          

327,462

$          

377,457

$          

397,129

$          

492,383

$             

Pipeline & Storage Adjusted EBITDA

130,857

120,858

111,474

136,914

161,226

Gathering Adjusted EBITDA

(141)

2,021

9,386

14,814

29,777

Utility Adjusted EBITDA

164,443

167,328

168,540

159,986

171,669

Energy Marketing Adjusted EBITDA

11,589

13,573

13,178

5,945

6,963

Corporate & All Other Adjusted EBITDA

(5,434)

408

(12,346)

(10,674)

(9,920)

Total Adjusted EBITDA

581,025

$          

631,650

$          

667,689

$          

704,114

$          

852,098

$             

Total Adjusted EBITDA

581,025

$          

631,650

$          

667,689

$          

704,114

$          

852,098

$             

Minus: Net Interest Expense

(81,013)

(90,217)

(75,205)

(82,551)

(89,776)

Plus:  Other Income

9,762

6,126

5,947

5,133

4,697

Minus: Income Tax Expense

(52,859)

(137,227)

(164,381)

(150,554)

(172,758)

Minus: Depreciation, Depletion & Amortization

(170,620)

(191,199)

(226,527)

(271,530)

(326,760)

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

-

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

-

-

-

(6,206)

-

Minus: New York Regulatory Adjustment (Utility)

-

-

-

-

(7,500)

Rounding

-

-

-

(1)

-

Consolidated Net Income

100,708

$          

225,913

$          

258,402

$          

220,076

$          

260,001

$             

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

171,000

Total Debt (Start of Period)

1,099,000

$    

1,249,000

$    

1,249,000

$    

1,089,000

$    

1,570,000

$      

Average Total Debt

1,174,000

$    

1,249,000

$    

1,169,000

$    

1,329,500

$    

1,609,500

$      

Average Total Debt to Total Adjusted EBITDA

2.02

1.98

1.75

1.89

1.89

FY 2013

161

Reconciliation of Segment Capital Expenditures to

Consolidated Capital Expenditures

($ Thousands)

FY 2014

FY 2009

FY 2010

FY 2011

FY 2012

FY 2013

Forecast

Capital Expenditures from Continuing Operations

Exploration & Production Capital Expenditures

188,290

$ 

398,174

$       

648,815

$       

693,810

$       

533,129

$       

$550,000-650,000

Pipeline & Storage Capital Expenditures

52,504

37,894

129,206

144,167

56,144

$         

$115,000-135,000

Gathering Segment Capital Expenditures

9,433

6,538

17,021

80,012

54,792

$         

$100,000-150,000

Utility Capital Expenditures

56,178

57,973

58,398

58,284

71,970

$         

$80,000-90,000

Energy Marketing, Corporate & All Other Capital Expenditures

396

773

746

1,121

1,062

$           

-

Total Capital Expenditures from Continuing Operations

306,801

$ 

501,352

$       

854,186

$       

977,394

$       

717,097

$       

$845,000-1,025,000

Capital Expenditures from Discountinued Operations

All Other Capital Expenditures

216

150

$                

-

$                 

-

$                 

-

$                 

-

$                                

Plus (Minus) Accrued Capital Expenditures

Exploration & Production FY 2013 Accrued Capital Expenditures

-

$          

-

$                 

-

$                 

-

$                 

(58,478)

$        

-

$                                

Exploration & Production FY 2012 Accrued Capital Expenditures

-

-

-

(38,861)

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 2013 Accrued Capital Expenditures

-

-

-

-

(5,633)

-

Pipeline & Storage FY 2012 Accrued Capital Expenditures

-

-

-

(12,699)

12,699

-

Pipeline & Storage FY 2011 Accrued Capital Expenditures

-

-

(16,431)

16,431

-

-

Pipeline & Storage FY 2010 Accrued Capital Expenditures

-

-

3,681

-

-

-

Pipeline & Storage FY 2008 Accrued Capital Expenditures

16,768

-

-

-

-

-

Gathering FY 2013 Accrued Capital Expenditures

-

-

-

-

(6,700)

-

Gathering FY 2012 Accrued Capital Expenditures

-

-

-

(12,690)

12,690

-

Gathering FY 2011 Accrued Capital Expenditures

-

-

(3,079)

3,079

-

-

Gathering FY 2009 Accrued Capital Expenditures

(715)

715

-

-

-

-

Utility FY 2013 Accrued Capital Expenditures

-

-

-

-

(10,328)

-

Utility FY 2012 Accrued Capital Expenditures

-

-

-

(3,253)

3,253

-

Utility FY 2011 Accrued Capital Expenditures

-

-

(2,319)

2,319

-

-

Utility FY 2010 Accrued Capital Expenditures

-

-

2,894

-

-

-

Total Accrued Capital Expenditures

6,960

$      

(58,401)

$        

(39,908)

$        

57,613

$         

(13,636)

$        

-

$                                

Eliminations

(344)

$        

-

$                 

-

$                 

-

$                 

-

$                 

-

$                                

Total Capital Expenditures per Statement of Cash Flows

313,633

$ 

443,101

$       

814,278

$       

1,035,007

$   

703,461

$       

$845,000-1,025,000