National Fuel Gas Company

Investor Presentation

March 2014

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,

objectives,

goals,

projections,

estimates

of

oil

and

gas

quantities,

strategies,

future

events

or

performance

and

underlying

assumptions,

capital

structure,

anticipated

capital

expenditures,

completion

of

construction

projects,

projections

for

pension

and

other

post-retirement

benefit

obligations,

impacts

of

the

adoption

of

new

accounting

rules,

and

possible

outcomes

of

litigation

or

regulatory

proceedings,

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

are

expressed

in

good

faith

and

are

believed

by

the

Company

to

have

a

reasonable

basis,

but

there

can

be

no

assurance

that

management’s

expectations,

beliefs

or

projections

will

result

or

be

achieved

or

accomplished.

In

addition

to

other

factors,

the

following

are

important

factors

that,

in

the

view

of

the

Company,

could

cause

actual

results

to

differ

materially

from

those

discussed

in

the

forward-looking

statements:

factors

affecting

the

Company’s

ability

to

successfully

identify,

drill

for

and

produce

economically

viable

natural

gas

and

oil

reserves,

including

among

others

geology,

lease

availability,

title

disputes,

weather

conditions,

shortages,

delays

or

unavailability

of

equipment

and

services

required

in

drilling

operations,

insufficient

gathering,

processing

and

transportation

capacity,

the

need

to

obtain

governmental

approvals

and

permits,

and

compliance

with

environmental

laws

and

regulations;

changes

in

laws,

regulations

or

judicial

interpretations

to

which

the

Company

is

subject,

including

those

involving

derivatives,

taxes,

safety,

employment,

climate

change,

other

environmental

matters,

real

property,

and

exploration

and

production

activities

such

as

hydraulic

fracturing;

governmental/regulatory

actions,

initiatives

and

proceedings,

including

those

involving

rate

cases

(which

address,

among

other

things,

target

rates

of

return,

rate

design

and

retained

natural

gas),

environmental/safety

requirements,

affiliate

relationships,

industry

structure,

and

franchise

renewal;

changes

in

the

price

of

natural

gas

or

oil;

changes

in

price

differentials

between

similar

quantities

of

natural

gas

or

oil

sold

at

different

geographic

locations,

and

the

effect

of

such

changes

on

commodity

production,

revenues

and

demand

for

pipeline

transportation

capacity

to

or

from

such

locations;

other

changes

in

price

differentials

between

similar

quantities

of

natural

gas

or

oil

having

different

quality,

heating

value,

hydrocarbon

mix

or

delivery

date;

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;

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;

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,

2013

and

the

Form

10-Q

for

the

quarter

ended

December

31,

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

Exceptional Assets, Focused on Execution

3

1.549

Tcfe

of

Proved

Reserves

(1)

800,000 Net Acres in Pennsylvania

2.8

MMBbl

of

Crude

Oil

Production

(2)

$207

Million

of

Midstream

Adjusted

EBITDA

(2)

(1)

As of September 30, 2013

(2)

12 months ended December 31, 2013

National Fuel Gas Company

Targeting Sustained Growth Over the Next Five Years

4

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.

2014 –

2018

10-15%

Forecasted

Adjusted EBITDA

CAGR

National Fuel Gas Company

Capital Spending Adjusts to Capitalize on Opportunities

5

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

National Fuel Gas Company

Maintaining a Strong Balance Sheet

6

Total Debt

(1)

42%

$3.900 Billion

As of December 31, 2013

Debt / Adjusted EBITDA

Capitalization

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

National Fuel Gas Company

Dividend Track Record

7

(1) As of March 18, 2014

Current

Dividend Yield

(1)

2.0%

Annual Rate at Fiscal Year End

8

Exploration & Production

Overview

Seneca Resources

Proven Record of Growth

9

(1)

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

2013 F&D Cost = $1.31

Marcellus F&D: $0.99

Doubled Proved Reserves

Since 2010

71% Proved Developed

Seneca Resources

Delivering Tremendous Production Growth

10

Seneca Resources

Disciplined Capital Spending

11

(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

Seneca Resources

LOE: Operating Costs Down; Transportation Costs Up

12

(1)

Represents the midpoint of current General & Administrative Expense guidance of $0.40 to $0.45 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 $0.90 to $1.10 per Mcfe for fiscal 2014

Seneca expects to convert its long-term firm

transport (FT) contracts into firm sales (FS)

agreements, with the cost reflected in price

realization.  As such, it is not included in LOE.

Marcellus Shale

Prolific Pennsylvania Acreage

13

Marcellus Shale

EDA Delivering Significant Growth

14

(1)

One well included in this total is producing from the Geneseo Shale

Marcellus Shale

EDA –

Historical Well Results Are Exceptional

15

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

5.8

4,023’

1.44

Tract 595

Tioga

County

32

7.4

6.1

5.1

8.1

4,736’

1.72

Tract 100

Lycoming

County

30

(1)

16.1

14.2

11.9

11.5

5,210’

2.21

Seneca is the industry leader in Lycoming County

(1)

5

wells

currently

producing

in

Tract

100

in

Lycoming

County,0

Pa.

Have

limited

production

history

and

have

been

excluded

from

this

table.

Marcellus Shale

Seneca’s Lycoming Economics are in the Top 3

16

Source: ITG IR, raw data provided by didesktop and state agencies

There are an additional 109 breakeven

data points greater than $3.69/Mcf

Marcellus Shale

Huge Position –

Varies in Understanding

17

Understanding Seneca’s

780,000 Net Acres

Marcellus Shale

2013 & 2014 WDA Delineation Program

18

Marcellus Shale

Strong Wells Across WDA Acreage

19

(1)

RCS –

Reduced Cluster Spacing

Well Name

Completion

Design

Treatable

Lateral

Length

Stages

Peak

24-Hour

Rate

(MMcfd)

Peak

7-Day

Rate

(MMcfd)

EUR

(Bcf)

Status

Clermont 9H

RCS1

5,500’

37

11.4

10.0

8.6

Producing

Clermont 10H

Non-RCS

5,565’

23

8.1

7.3

6.6

Producing

Rich Valley 27H

RCS

6,372’

42

8.1

7.8

7.4

Producing

Rich Valley 25H

RCS

4,492’

30

5.0

4.5

4.5

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

4.5-5.5

Producing

Owl’s Nest 54H

RCS

6,139’

41

6.1

5.8

4-7

Flowback

Test

Marcellus Shale

Clermont Wells Improved from Early Non-Op JV Wells

20

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’

Larger casing: 5.5”

Increased pump rates

9H (RCS): 150’

spacing

10H (Standard): 240’

spacing

“Soaked”

both wells: 30 Days

Marcellus Shale

Rich Valley/Clermont is in Full Development Mode

21

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

9 of 9 Wells Drilled

JV Wells

Pad D

Pad E

Pad O

Clermont

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

Non-RCS: 10H 7-day IP:  7.3 MMcf/d

Rich Valley

7-day IP: 7.8 MMcf/d

EUR: 7.4 BCF

Lateral Length: 6,372’

SRC Lease Acreage

SRC Fee Acreage

Pad H

6 of 6 Wells Drilled

nd

Marcellus Shale

200,000 Acres With 6-8 Bcfe EUR Wells

22

Note: Assumes 6,000’

treated lateral length

Marcellus Shale

~2,000 Economic Locations at $2.00 to $3.80/Mcfe

23

Prospect

County

Product

Approx.

Remaining

Locations

EUR

(Bcfe)

BTU

IRR

(1)

@

$4/MMBtu

15% IRR

(1)

Breakeven Price

($/Mcf)

Tract 100

Lycoming

Dry Gas

34

11.5-12.5

1,030

90%

$1.92

Gamble

Lycoming

Dry Gas

29

10-11

1,030

77%

$2.05

Tract 595

Tioga

Dry Gas

20

8.1

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

5.8

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

(1)

Internal Rate of Return (IRR) includes estimated well costs, LOE, and Gathering tariffs anticipated for each prospect

Natural Gas Marketing

How Does Seneca Sell its Production?

24

Natural Gas Marketing

Adding Long-Term Firm Transport to the Portfolio

25

Project

Volume

(Dth/d)

In-Service

Date

Comments

Northeast Supply

Diversification Project (TGP)

50,000

2012

Executed firm sales agreements for entire

capacity over 15 years

Niagara Expansion (TGP/NFG)

170,000

November

2015

Executed firm sales agreements for 140,000

Dth/d for the entire 15 years

Atlantic Sunrise (Transco)

189,405

2017

Evaluating marketing opportunities

Agreements Executed

Project

Volume

(Dth/d)

Target In-

Service

Date

Comments

Northern Access 2016 (NFG)/

TransCanada Open Season

350,000

2016

Evaluating market potential for transportation

path from WDA into Canada

Under Evaluation

Additional current and future Appalachian marketing

opportunities are continuously under evaluation

Natural Gas Marketing

Firm Sales Provide a Market for Appalachian Production

26

(1)

Long-term firm sales represent gross volumes

26

Natural Gas Marketing

Current Natural Gas Hedge Positions

27

(1)

2014 hedge positions are for the remaining nine months of the fiscal year

Natural Gas Marketing

Current Hedge Book has Seneca Positioned Very Well

28

(1)

2014 hedge positions are for the remaining nine months of the fiscal year

Note: Hedge positions for fiscal years 2016-2018 reflect the midpoint of Seneca’s target annual production growth (20%) starting with the midpoint of Fiscal 2015 guidance (180-220 Bcfe)

Natural Gas

$4.27/Mcf

$4.29/Mcf

$4.33/Mcf

$4.44/Mcf

$4.81/Mcf

Crude Oil

$100.22/Bbl

$95.27/Bbl

$92.97/Bbl

$92.30/Bbl

$91.00/Bbl

Natural Gas Marketing

FY 2014 Production –

Firm Sales & Hedge Composition

29

Geneseo Shale

Path to Geneseo Development –

2018/2019 Start

30

1

st

Well (Tract 100 –

Pad N)

Peak IP: 14.1 MMcf per day

30-Day Average Rate: 8.6 MMcf per day

Estimated EUR: 7.0 Bcf

Lateral Length: 4,920’

Frac Stages: 33 stages

Current developed infrastructure from DCNR

100 & Gamble:

14 well pads

3 compressor pads

3 water impoundments

Gathering infrastructure

Savings estimate of ~$300,000 per well from

shared infrastructure

•

>125 Wells

•

Water Infrastructure = $13MM

•

Usable Pads = $16MM

•

Road Infrastructure = $16MM

Tract 100/Gamble (Lycoming County)

Point Pleasant & Utica Shale

Industry Activity & 2014 Appraisal Program

31

California

Stable Production Fields; Modest Growth Potential

32

California

East Coalinga Summary

33

Production has increased from 214 BOPD to

559 BOPD

•

Highest on leases since 2000

Drilled 12 evaluation wells in 2013

•

9 of 12 new wells are on line and making ~200

BOPD

Plan to drill 28 new producers and 2 water

disposal wells in 2014

California

South Midway Sunset Has Delivered Significant Growth

34

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

252 Pool

97X Pool

SE Pool

251 Pool

B Pool

A Pool

Extended Pool Boundary

Original Pool Boundary

Existing Wells

1000’

16X Pool

California

Evaluating the Monterey Shale at South Lost Hills

35

California

Limited Growth Opportunities, But Strong Economics

36

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 –

Coldwater

$2,800,000

180

35%

4

California

Modest Growth Anticipated in 2014 and 2015

37

California

Outstanding Cash Flow

(1)

38

(1)

Adjusted EBITDA and Capital Expenditures represent Seneca Resources Corporation’s West Division, which includes its activity in Kansas

California

Looking Forward

39

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

Mississippian Lime

Commenced Evaluation Program in Fiscal 2014

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

-

Mississippian Rocks Absent

Drilled and completed first two

horizontal appraisal wells and two

salt water disposal (SWD) wells

Monitoring significant industry

activity

40

Seneca Resources

What Will Seneca Look Like Moving Forward?

41

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

42

Midstream Businesses

Overview

Midstream Businesses

Positioned to Serve Seneca’s Rapidly Growing Production

43

Gathering

Gathering is the First Step to Reaching a Market

44

Gathering

Existing Systems Supporting Seneca’s Near-Term Growth

45

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): $137 million

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

Interconnects

Gathering

Clermont Gathering System has Large Expandability

46

Clermont Gathering

System

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)

Capital:

2014: $60-

$92 million

2015: $75 -

$125 million

Seneca Pads Connected

Up to 25 pads connected

following the 2015

expansion

Gathering

Capital Deployment Will Deliver Long-Term Growth

47

Revenue Growth (2013 to 2015): ~60%

CAGR

Capital Investment (2013 to 2015): ~60%

CAGR

Pipeline & Storage

Project Opportunities to Support WDA Growth

48

Develop multiple outlets

to high-value markets

Pipeline & Storage

Northeast PA Spot Markets are Heavily Discounted

49

Pipeline & Storage

Expansions to Move Gas from the WDA are Significant

50

Projects to Support WDA Growth

Project

Capacity (Dth/day)

Northern Access 2015

140,000

Northern Access 2016

1

350,000

Total New Capacity

490,000

Project

Capital Cost

Northern Access 2015

$67 million

Northern Access 2016

1

$360 million

Total Capital

Expenditures

$427 million

Northern

Access 2015

(November 2015)

Northern

Access 2016

(2016)

Clermont

(1)

Previously referred to as the Clermont to Chippawa expansion project

Pipeline & Storage

Major Expansion Designed for Canadian Deliveries

51

In-Service: November 2015

System: NFG Supply Corp.

Capacity: 140,000 Dth per day

Lease to TGP (Kinder) as part of

their Niagara Expansion project

Interconnect

Niagara (TransCanada)

Total Cost: $67 Million

Major Facilities

23,000 HP Compressor

Northern Access 2015

Northern

Access 2015

(November 2015)

Clermont

Pipeline & Storage

Northern Access 2016 Provides Additional Access to Canada

52

In-Service: 2016

System: NFG Supply Corp. &

Empire Pipeline, Inc.

Capacity

350,000 Dth per day

Interconnect

Chippawa (TransCanada)

Total Cost: ~$360 Million

Northern

Access 2016

(2016)

Clermont

Northern Access 2016

(1)

(1)

Previously referred to as the Clermont to Chippawa expansion project

Pipeline & Storage

Recent 3

rd

Party Expansions Have Been Highly Successful

53

Completed Expansions

for 3

rd

Parties

Project

Capacity

(Dth/day)

Northern Access 2012

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 2012

$72 million

Tioga County Extension

$58 million

Line N (2011, 2012 & 2013)

$104 million

Total Capital Expenditures

$234 million

Northern

Access 2012

Tioga County

Extension

Line N Projects

Pipeline & Storage

Additional Line N Expansions Planned for the Future

54

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: $34 Million

Expansion: $30 million

System Modernization: $4 million

Major Facilities

3,550 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

55

In-Service: November 2015

System: NFG Supply Corp.

Capacity: 175,000 Dth per day

Precedent agreements signed for all

available capacity

Interconnect

Mercer (TGP Station 219)

Holbrook (TETCO)

Total Cost: $76 Million

Expansion: $39 million

System Modernization: $37 million

Major Facilities

3,550 HP Compressor

23.3 miles –

24”

Replacement Pipeline

Westside Expansion &

Modernization

Holbrook (TETCO)

Westside

Expansion &

Modernization

Pipeline & Storage

Developing Unique Solutions for Shippers

56

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)

Retained Storage: 3.3 Bcf

New Incremental Transportation

Capacity of 64,000 Dth per day

Precedent agreements executed with

RG&E and NYSEG

Interconnect

Tuscarora (NFG/Supply)

Total Cost: $45 Million

Major Facilities

1,500 HP Compressor

17 miles –

12”

Pipeline

Tuscarora Lateral

Tuscarora

Lateral

Pipeline & Storage

Significant Expansions Are Driving Growth

57

Completed Projects (Since 2009)

Recent Capacity Additions

1,113,000

Dth/day

Line N Corridor

Line “N”

Expansion

Line “N”

2012 Expansion

Line “N”

2013 Expansion

Mercer Expansion

West Side Expansion

Total Capacity

633 MDth/d

Delivering Gas North

Tioga County Extension

Northern Access 2012

Northern Access 2015

Northern Access 2016

(1)

Total Capacity

1,160 MDth/d

Other Projects

Lamont Compressor

Tuscarora Lateral

Total Capacity

154 MDth/d

Planned Projects (2014 -2015)

Precedent Agreements Executed

Planned Capacity Additions

484,000

Dth/day

Potential Projects (2016+)

Currently Evaluating

Potential Capacity Additions

350,000

Dth/day

Total (2009-2016+)

Capacity Additions

1,947,000

Dth/day

(1)

Previously referred to as the Clermont to Chippawa expansion project

Pipeline & Storage

Expansion Project Revenue Growth

58

Larger projects under consideration

for fiscal 2016 and 2017 will drive

significant revenue growth

59

Utility

Overview

Utility

New York & Pennsylvania Service Territories

60

New York

Total Customers: 522,000

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

Target 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

61

(1)

Weighted Average of New York and Pennsylvania service territories (assumes normal weather)

Utility

Continued Cost Control Helps Provide Earnings Stability

62

Utility

Capital Spending Largely Focused on Maintenance

63

Utility

Achieved a Settlement in New York

64

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

Following further proceedings,

we anticipate that the PSC will

likely consider the Joint

Proposal in April 2014

May 8, 2013

Company responds

to OTSC

June 14, 2013

“Temporary rates”

become effective

July 26, 2013

Settlement

discussions

commence for

permanent

rates

December 6, 2013

Joint Proposal filed

October 1, 2013

Effective date of

two-year rate plan

under proposed

settlement

National Fuel Gas Company

A History of Success & A Future of Opportunity

65

30% CAGR

Since 2009

Adjusted

EBITDA

Growth

Production

Growth

Midstream

Businesses

Adjusted

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

Adjusted

EBITDA

A History of Success

10% CAGR

Since 2009

10% CAGR

Since 2009

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. 

A Future of Opportunity

66

Appendix

National Fuel Gas Company

Current Hedge Positions

67

Fiscal

Year

NYMEX

Volume

(Bcf)

Average

Price

($/Mcf)

Dominion

Volume

(Bcf)

Average

Price

($/Mcf)

SoCal

Volume

(Bcf)

Average

SoCal

Price

Total

Volume

(Bcf)

Average

Price

($/Mcf)

2014

(1)

61.5

$4.27

20.6

$4.26

0.9

$4.57

82.9

$4.27

2015

63.2

$4.35

17.8

$4.07

1.1

$4.57

82.1

$4.29

2016

35.7

$4.46

17.9

$4.07

-

-

53.6

$4.33

2017

23.8

$4.71

17.9

$4.07

-

-

41.7

$4.44

2018

5.3

$4.81

-

-

-

-

5.3

$4.81

Natural Gas Hedges

Fiscal

Year

MWSS

Volume

(MMBbl)

Average

Price

($/Bbl)

Brent

Volume

(MMBbl)

Average

Price

($/Bbl)

NYMEX

Volume

(MMBbl)

Average

Price

($/Bbl)

Total

Volume

(MMBbl)

Average

Price

($/Bbl)

2014

(1)

0.47

$95.68

1.01

$102.32

-

-

1.48

$100.22

2015

0.26

$92.10

0.90

$98.42

0.40

$90.14

1.56

$95.27

2016

0.04

$92.10

0.93

$95.18

0.30

$86.09

1.27

$92.95

2017

-

-

0.38

$92.30

-

-

0.38

$92.30

2018

-

-

0.08

$91.00

-

-

0.08

$91.00

Crude Oil Hedges

(1)

2014 hedge positions are for the remaining nine months of the fiscal year

National Fuel Gas Company

Comparable GAAP Financial Measure Slides and Reconciliations

68

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. 

The

Company

defines

Adjusted

EBITDA

as

reported

GAAP

earnings

before

the

following

items:

interest

expense,

depreciation,

depletion

and

amortization,

interest

and

other

income,

impairments,

items

impacting

comparability

and

income taxes.

69

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

$              

212,540

$        

Exploration & Production - All Other Divisions Adjusted EBITDA

108,139

139,624

189,854

170,232

277,341

308,975

Total Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

492,383

$              

521,515

$        

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

492,383

$              

521,515

$        

Pipeline & Storage Adjusted EBITDA

130,857

120,858

111,474

136,914

161,226

168,747

Gathering Adjusted EBITDA

(141)

2,021

9,386

14,814

29,777

38,564

Utility Adjusted EBITDA

164,443

167,328

168,540

159,986

171,669

173,644

Energy Marketing Adjusted EBITDA

11,589

13,573

13,178

5,945

6,963

8,797

Corporate & All Other Adjusted EBITDA

(5,434)

408

(12,346)

(10,674)

(9,920)

(9,012)

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

852,098

$              

902,255

$        

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

852,098

$              

902,255

$        

Minus: Net Interest Expense

(81,013)

(90,217)

(75,205)

(82,551)

(89,776)

(91,780)

Plus:  Other Income

9,762

6,126

5,947

5,133

4,697

3,510

Minus: Income Tax Expense

(52,859)

(137,227)

(164,381)

(150,554)

(172,758)

(184,633)

Minus: Depreciation, Depletion & Amortization

(170,620)

(191,199)

(226,527)

(271,530)

(326,760)

(347,543)

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)

(7,500)

Rounding

-

-

-

(1)

-

-

Consolidated Net Income

100,708

$           

225,913

$           

258,402

$           

220,077

$           

260,001

$              

274,309

$        

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

$          

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

$       

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

1,149,000

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

100,000

-

200,000

150,000

250,000

250,000

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

-

-

-

40,000

171,000

238,000

Total Debt (Start of Period)

1,099,000

$     

1,249,000

$     

1,249,000

$     

1,089,000

$     

1,570,000

$       

1,637,000

$   

Average Total Debt

1,174,000

$     

1,249,000

$     

1,169,000

$     

1,329,500

$     

1,609,500

$       

1,643,000

$   

Average Total Debt to Total Adjusted EBITDA

2.02

1.98

1.75

1.89

1.89

1.82

FY 2013

12-Months

Ended 12/31/13

70

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

$          

$90,000-100,000

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

$        

$855,000-1,035,000

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

$        

$855,000-1,035,000