National Fuel Gas Company

Investor Presentation

May 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 Forms 10-Q for the quarters ended December 31, 2013 and March 31, 2014. 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

2.9 MMBbl of Crude Oil Production

(2)

$221 Million of Midstream Adjusted EBITDA

(2)

(1)

As of September 30, 2013

(2)

12 months ended March 31, 2014.  Includes the Pipeline & Storage segment and Gathering segment. 

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

National Fuel Gas Company

Targeting Sustained Growth Over the Next Five Years

4

2014 –

2018

10-15%

Forecasted

Adjusted EBITDA

CAGR

$164

$167

$169

$160

$172

$177

$131

$121

$111

$137

$161

$176

$45

$280

$327

$377

$397

$492

$537

$581

$632

$668

$704

$852

$934

$0

$250

$500

$750

$1,000

$1,250

2009

2010

2011

2012

2013

12-Months

Ended

3/31/14

2014

Forecast

2015

Forecast

Fiscal Year

Exploration & Production Segment

Gathering Segment

Pipeline & Storage Segment

Utility Segment

Energy Marketing & Other

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

National Fuel Gas Company

Capital Spending Adjusts to Capitalize on Opportunities

5

$56

$58

$58

$58

$72

$85-$95

$90-$100

$53

$38

$129

$144

$56

$115-

$135

$225-

$275

$80

$55

$100-

$145

$100-

$150

$188

$398

$649

$694

$533

$550-

$625

$650-

$750

$307

(1)

$501

$854

$977

$717

$850-

$1,000

$1,065-

$1,275

$0

$250

$500

$750

$1,000

$1,250

$1,500

2009

2010

2011

2012

2013

2014

Forecast

2015

Forecast

Fiscal Year

Exploration & Production Segment

Gathering Segment

Pipeline & Storage Segment

Utility Segment

Energy Marketing & Other

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%

$3.949 Billion

As of March 31, 2014

2.02 x

1.98 x

1.75 x

1.89 x

1.89 x

1.76 x

0.0

0.5

1.0

1.5

2.0

2.5

2009

2010

2011

2012

2013

12-Months

Ended

3/31/14

Fiscal Year

Debt / Adjusted EBITDA

Capitalization

Shareholders’

Equity

58%

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 May 7, 2014

Current

Dividend Yield

(1)

2.0%

Dividend Consistency

Consecutive Dividend Payments

111 Years

Consecutive Dividend Increases

43 Years

Current

Annualized Dividend Rate

$1.50

per Share

$0.00

$0.50

$1.00

$1.50

$2.00

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

46.2

46.6

45.2

43.3

42.9

41.6

226

249

428

675

988

1,300

503

528

700

935

1,246

1,549

0

500

1000

1500

2000

2008

2009

2010

2011

2012

2013

At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

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

Seneca Resources

Delivering Tremendous Production Growth

10

19.8

19.2

20.5

20.0

20-22

21-23

16.5

43.2

62.9

100.7

135-143

159-197

13.3

49.7

67.6

83.4

120.7

155-165

180-220

0

75

150

225

2010

2011

2012

2013

2014                      

Forecast

Fiscal Year

Gulf of Mexico (Divested in 2011)

East Division (Appalachia)

West Division (California/Kansas)

Forecast

2015                  

Seneca Resources

Disciplined Capital Spending

11

(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

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 $0.95 to $1.05 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

Eastern

Development

Area

(EDA)

Average net revenue interest (NRI): 98%

No lease expiration

No royalty on most acreage

Highly contiguous

Significant economies of scale

1,700 to 2,000 locations de-risked

720,000 Acres

60,000 Acres

No

near-term

lease

expiration

Drilling activity will HBP key acreage

Ongoing

development

drilling

in

Tioga

and

Lycoming

counties

Mostly

leased

(16-18%

royalty)

Seneca Lease

Seneca Fee

Western

Development

Area

(WDA)

Marcellus Shale

EDA Delivering Significant Growth

14

Covington –

Fully Developed

Gross Production: ~50 MMcf per Day

47 Wells Drilled and Producing

DCNR Tract 595

Gross Production: ~80 MMcf per Day

39 Wells Drilled (52 Total Locations)

32 Wells Producing

DCNR Tract 100

Gross Production:  ~300 MMcf per Day

58 Wells Drilled

(70 Total Locations)

43 Wells Producing

Gamble

Recently, 30 to 50 future locations

3 Wells Drilled; 1 Well Producing

were added in Lycoming County

1

1

(1)

One well included in this total is drilled into and 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

36

(1)

15.9

14.0

11.6

11.6

5,153’

2.24

Seneca is the industry leader in Lycoming County

(1)

Includes one horizontal well producing from the Geneseo Shale.  Does not include seven new Marcellus Shale wells with less than 30 days of production history.

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

Seneca Lease

Seneca Fee

Tier I

~200,000 Acres

Northeast Core

~30,000 acres in NE Core

Tier I Acres

~200,000 acres

Economic at $2.80 to $3.80/Mcfe

Longer-Term Evaluation

~250,000 acres

(Minimal Lease Expiration)

Requires Gas Price Above $4/Mcf

~300,000 acres

Understanding Seneca’s

780,000 Net Acres

Size of combined EDA

current development areas

Marcellus Shale

2013 & 2014 WDA Delineation Program

18

Rich Valley –

Full Development

2 Wells Completed

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

2

nd

Well 7-Day IP: 4.5 MMcf/d

Clermont –

Full Development

2 Wells Completed

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

10H: 7-Day IP of 7.3 MMcf/d & EUR of 6.6 Bcf

Owl’s Nest –

Delineating

2 High Btu Wells Completed

Tested Two Completion Designs

Church Run –

Delineating

1 Well Completed

Tionesta –

Delineating

1 Well Completed

Heath –

Delineating

1 Well Planned

Seneca Operated

Sulger Farms –

Delineating

1 Well Drilled

Hemlock –

Delineating

1 Well Drilled

Ridgway –

Delineating

1 Well Completed

2013 Drill Program

2014 Drill Program

SRC Lease Acreage

SRC Fee Acreage

EOG Earned JV Acreage

Marcellus Shale

Strong Wells Across WDA Acreage

19

Well Name

Completion

Design

Treatable

Lateral

Length

Stages

Peak

24-Hour

Rate

(MMcfd)

Peak

7-Day

Rate

(MMcfd)

EUR

(Bcf)

Status

Clermont 9H

RCS

1

5,500’

37

11.4

10.0

8.6

Producing

Clermont 10H

Non-RCS

5,565’

23

8.1

7.3

6.9

Producing

Rich Valley 27H

RCS

6,372’

42

8.1

7.8

7.9

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

6-8

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

(1)

RCS – Reduced Cluster Spacing

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

Clermont/Rich Valley RCS Wells Outperforming Typecurve

21

Marcellus Shale

CRV is in Full Development Mode

22

Marcellus Faults

Marcellus & Basement Faults

200-250 Horizontal Locations

SRC Lease Acreage

SRC Fee Acreage

Planned Wells

Drilled Wells

Producing Wells

Pad D08-N:

Spacing Test

JV Wells

Pad

E09-H

Pad

E09-E

Rich Valley 2

nd

Well

7-day IP: 4.5 MMcf/d

Lateral Length: 4,492’

Rich Valley

7-day IP: 7.8 MMcf/d

EUR: 7.4 BCF

Lateral Length: 6,372’

Clermont

RCS: 9H 7-day IP:  10.0 MMcf/d

(EUR: 8.6 Bcf)

Non-RCS: 10H 7-day IP:  7.4 MMcf/d

Pad

D08-G

Pad

C08-F

Pad

D09-D

Pad

C08-G

Marcellus Shale

200,000 Acres With 6-8 Bcfe EUR Wells

23

Note: Assumes 6,000’

treated lateral length

Marcellus Shale

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

24

Prospect

County

Product

Approx.

Remaining

Locations

EUR

(Bcfe)

BTU

IRR

(1)

@

$4/MMBtu

15% IRR

(1)

Breakeven Price

($/Mcf)

Tract 100

Lycoming

Dry Gas

28

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

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

(1)

Natural Gas Marketing

How Does Seneca Sell its Production?

25

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

Breakeven economics based on a

realized price after gathering

Spot Market

Natural Gas Marketing

Adding Long-Term Firm Transport to the Portfolio

26

Project

Volume

(Dth/d)

In-Service

Date

Comments

Northeast Supply

Diversification Project (TGP)

50,000

2012

Executed firm sales agreements for entire

capacity over 10 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

Significant Base of Long-Term Firm Contracts

27

Atlantic Sunrise

Northern Access 2016

(Under Evaluation)

Niagara Expansion/

Northern Access 2015

-

250

500

750

1,000

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

Gross Firm Sales

Firm Transport

Over time, Seneca plans to convert most or all of its

firm transportation capacity to firm sales agreements

Natural Gas Marketing

Firm Sales Provide a Market for Appalachian Production

28

(1)

Subject to change in transport rates on TransCanada Pipeline

28

EDA

311,834 MMBtu/Day

270,036 MMBtu/Day

230,036 MMBtu/Day

WDA

21,314 MMBtu/Day

41,100 MMBtu/Day

20,000 MMBtu/Day

Values shown represent the price or differential to a reference

price (netback price) at the first non-affiliated interstate pipeline,

including the cost of all related downstream transportation.

Natural Gas Marketing

Current Natural Gas Hedge Positions

29

(1)

2014 hedge positions are for the remaining six months of the fiscal year.  Full details can be found in the appendix.

(1)

Natural Gas Marketing

Current Hedge Book has Seneca Positioned Very Well

30

(1)

2014 hedge positions are for the remaining six 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

$4.07/MMBtu

$4.10/MMBtu

$4.12/MMBtu

$4.23/MMBtu

$4.59/MMBtu

Crude Oil

$100.22/Bbl

$95.27/Bbl

$92.95/Bbl

$92.30/Bbl

$91.00/Bbl

(1)

Natural Gas Marketing

FY 2014 Production –

Firm Sales & Hedge Composition

31

Price Certainty

Seneca has an additional ~13 Bcf of

NYMEX hedges to help mitigate

commodity exposure on its sales

Price Certainty

There were no spot

volume curtailments in

April 2014

64 Bcf

29

Bcf

13.7 Bcf

0.5 Bcf

13.5 Bcf

11 Bcf

7.3

Bcf

135-143

0

30

60

90

120

150

Q1 & Q2                                          DOM

Production

NYMEX

Firm Sales

Firm Sales

Fixed Price

Sales

EDA

Spot Sales

WDA                      Total

Spot Sales

East Division

Production

Natural Gas Marketing

FY 2015 Production –

Firm Sales & Hedge Composition

32

Price Certainty

Seneca will continue to pursue firm

sales agreements to mitigate spot

market exposure during the year

Price Certainty

54 Bcf

17.8 Bcf

4 Bcf

56 Bcf

36 Bcf

10.2

Bcf

159-197

0

50

100

150

200

NYMEX

Firm Sales

DOM

Firm Sales

Dawn                              EDA

Firm Sales

Spot Sales

WDA                     

Spot Sales

Total

East Division

Production

Geneseo Shale

Path to Geneseo Development –

2018/2019 Start

33

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:

13 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)

Geneseo Well

Point Pleasant & Utica Shale

Industry Activity & 2014 Appraisal Program

34

MT JEWETT

Horizontal: Completed September 2013

Peak 24-Hour Rate: 8.5 MMcf/d

RANGE RESOUCES

1.4 MMcf/d

“Not Effectively

Stimulated”

HALCON

2.5 MMcf/d,

360 Bbls/d

HALCON

4.5 MMcf/d,

860 Bbls/d

HALCON

6.6 MMcf/d,

750 Bbls/d

REX

9.2 MMcf/d

RANGE

4.4 MMcf/d

CHESAPEAKE

6.4 MMcf/d

TIONESTA

Horizontal: Completed Fall 2012

Peak 24-Hour Rate: 3.9 MMcf/d

HEATH

Core Pilot

DCNR 007

Core & Drill

California

Stable Production Fields; Modest Growth Potential

35

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.

South Lost Hills Monterey Evaluation

California

East Coalinga Summary

36

Production has increased from 214 BOPD to

849 BOPD

•

Highest on leases since 2000

Drilled 12 evaluation wells in 2013

•

Producing ~150 BOPD

Currently drilling 33 new producers and 2

water disposal wells in 2014

California

South Midway Sunset Has Delivered Significant Growth

37

252 Pool

97X Pool

SE Pool

251 Pool

B Pool

A Pool

Extended Pool Boundary

Original Pool Boundary

Existing Wells

1000’

16X Pool

Seneca Acquired

in June 2009

Highlights Since Acquisition

Increased daily production 310% to

approximately 1,700 BOPD

Drilled 102 new producers

Added 3.3 MMBO of proven reserves

Increased steam capacity by 280%

Identified opportunities for additional

pool development

California

Evaluating the Monterey Shale at South Lost Hills

38

Upper Antelope A

Upper Antelope B

Truman 1H

2013

190 BOEPD

Citrus 2H

Waiting on

Completion

Truman 2H

Waiting on

Completion

GR

SP

ResD

Brittleness

Gas

Oil

18 potential locations in

each of the three

horizons (concept)

Seneca Lease

1000’

Lower Reef Ridge

McDonald

Citrus 11

California

Limited Growth Opportunities, But Strong Economics

39

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%

33

Sespe –

Coldwater

$2,800,000

180

35%

4

California

Modest Growth Anticipated in 2014 and 2015

40

Forecast

Fiscal Year

California

Outstanding Cash Flow

(1)

41

(1)

Adjusted EBITDA and Capital Expenditures represent Seneca Resources Corporation’s West Division, which includes its activity in Kansas.  A reconciliation of Adjusted EBITDA to Net Income

is included at the end of this presentation. 

California

Looking Forward

42

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

What Will Seneca Look Like Moving Forward?

43

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

44

Midstream Businesses

Overview

Midstream Businesses

Positioned to Serve Seneca’s Rapidly Growing Production

45

Gathering

Gathering is the First Step to Reaching a Market

46

TGP 300

Transco

TGP 200

Trout Run

Gathering System

(In-Service)

Covington

Gathering System

(In-Service)

Clermont

Gathering System

(Under Construction)

Gathering Interconnects

(In-Service and Under

Construction)

Gathering

Existing Systems Supporting Seneca’s Near-Term Growth

47

Covington Gathering System

In-service date: November 2009

Capacity: 220,000 Dth per day

Interconnect: TGP 300

Capital expenditures (to date): $31.2 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): $144 million

Capital expenditures (future): $50 to $80 million

Interconnects

Gathering

Clermont Gathering System has Large Expandability

48

C

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

C

C

Compressor Station

Interconnect

C

Gathering

Capital Deployment Will Deliver Long-Term Growth

49

Revenue Growth (2013 to 2015): ~60%

CAGR

Capital Investment (2013 to 2015): ~60%

CAGR

Pipeline & Storage

Project Opportunities to Support WDA Growth

50

Develop multiple outlets

to high-value markets

Pipeline & Storage

Expansions to Move Gas from the WDA are Significant

51

Projects to Support WDA Growth

Project

Capacity (Dth/day)

Northern Access 2015

140,000

Northern Access 2016¹

350,000

Total New Capacity

490,000

Project

Capital Cost

Northern Access 2015

$66 million

Northern Access 2016¹

$410 million

Total Capital

Expenditures

$476 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

52

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: $66 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

53

In-Service: 2016

System: NFG Supply Corp. &

Empire Pipeline, Inc.

Capacity

350,000 Dth per day

Interconnect

Chippawa (TransCanada)

Total Cost: ~$410 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

54

Completed Expansions

for 3

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

rd

Pipeline & Storage

Additional Line N Expansions Planned for the Future

55

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

56

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

57

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 49,000 Dth per day

Precedent agreements executed with

RG&E and NYSEG

Negotiating an additional precedent

agreement with a third shipper

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

58

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

59

Larger projects under consideration

for fiscal 2016 and 2017 will drive

significant revenue growth

Annual Expansion Revenue

Projects Placed in Service Since Fiscal 2011

60

Utility

Overview

Utility

New York & Pennsylvania Service Territories

61

Total Customers: 522,000

Rate Mechanisms:

Natural Gas Vehicle Pilot Program

Target ROE: 9.1% (Litigated -

2007)

Pennsylvania

Total Customers: 213,000

Rate Mechanisms:

ROE: Black Box Settlement (2007)

New York

Revenue Decoupling

Weather Normalization

Low Income Rates

Choice Program/Purchase of

Receivables

Merchant Function Charge

(Uncollectibles Adjustment)

90/10 Sharing (Large Customers)

Low Income Rates

Choice Program/Purchase of

Receivables

Merchant Function Charge

Utility

Customer Usage

62

Residential Usage

Industrial Usage

(1)

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

80

90

100

110

120

12-Months Ended March 31

15

20

25

30

35

12-Months Ended March 31

Utility

Ongoing Cost Control Helps Provide Earnings Stability

63

$178

$164

$167

$168

$168

$172

$178

$25

$27

$14

$11

$9

$6

$7

$203

$191

$181

$179

$177

$178

$185

$0

$50

$100

$150

$200

$250

2008

2009

2010

2011

2012

2013

12 Months

Ended

3/31/14

Fiscal Year

All Other O&M Expenses

O&M Uncollectible Expense

Utility

Capital Spending Largely Focused on Maintenance

64

The Utility remains focused

on spending to maintain

the ongoing safety and

reliability of its system

$44.4

$45.0

$44.3

$43.8

$48.1

$56.2

$58.0

$58.4

$58.3

$72.0

$85-$95

$90-$100

$0

$20

$40

$60

$80

$100

2009

2010

2011

2012

2013

2014          

Forecast

2015          

Forecast

Fiscal Year

Capital Expenditures for Safety

Total Capital Expenditures

Utility

Achieved a Settlement in New York

65

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

NY PSC approved the Joint

Proposal on May 8, 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

66

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

67

Appendix

National Fuel Gas Company

Current Hedge Positions

68

Fiscal

Year

NYMEX

Volume

(MMBtu)

Average

Price

($/MMBtu)

Dominion

Volume

(MMBtu)

Average

Price

($/MMBtu)

SoCal

Volume

(MMBtu)

Average

Price

($/MMBtu)

Total

Volume

(MMBtu)

Average

Price

($/MMBtu)

2014

(1)

44,100,000

$4.07

14,400,000

$4.06

600,000

$4.35

59,100,000

$4.07

2015

69,590,000

$4.16

18,720,000

$3.88

1,200,000

$4.35

89,510,000

$4.10

2016

37,740,000

$4.25

18,840,000

$3.88

-

-

56,580,000

$4.12

2017

24,960,000

$4.49

18,840,000

$3.88

-

-

43,800,000

$4.23

2018

5,550,000

$4.59

-

-

-

-

5,550,000

$4.59

Natural Gas Hedges

Fiscal

Year

MWSS

Volume

(Bbl)

Average

Price

($/Bbl)

Brent

Volume

(Bbl)

Average

Price

($/Bbl)

NYMEX

Volume

(Bbl)

Average

Price

($/Bbl)

Total

Volume

(Bbl)

Average

Price

($/Bbl)

2014

(1)

312,000

$95.68

672,000

$102.32

-

-

948,000

$100.22

2015

258,000

$92.10

903,000

$98.42

396,000

$90.14

1,557,000

$95.27

2016

36,000

$92.10

933,000

$95.18

300,000

$86.09

1,269,000

$92.95

2017

-

-

384,000

$92.30

-

-

384,000

$92.30

2018

-

-

75,000

$91.00

-

-

75,000

$91.00

Crude Oil Hedges

(1)

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

National Fuel Gas Company

Comparable GAAP Financial Measure Slides and Reconciliations

69

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.

70

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

$              

212,153

$        

Exploration & Production - All Other Divisions Adjusted EBITDA

108,139

139,624

189,854

170,232

277,341

324,820

Total Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

492,383

$              

536,973

$        

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

492,383

$              

536,973

$        

Pipeline & Storage Adjusted EBITDA

130,857

120,858

111,474

136,914

161,226

175,852

Gathering Adjusted EBITDA

(141)

2,021

9,386

14,814

29,777

45,478

Utility Adjusted EBITDA

164,443

167,328

168,540

159,986

171,669

177,432

Energy Marketing Adjusted EBITDA

11,589

13,573

13,178

5,945

6,963

7,942

Corporate & All Other Adjusted EBITDA

(5,434)

408

(12,346)

(10,674)

(9,920)

(9,395)

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

852,098

$              

934,282

$        

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

852,098

$              

934,282

$        

Minus: Net Interest Expense

(81,013)

(90,217)

(75,205)

(82,551)

(89,776)

(92,497)

Plus:  Other Income

9,762

6,126

5,947

5,133

4,697

7,548

Minus: Income Tax Expense

(52,859)

(137,227)

(164,381)

(150,554)

(172,758)

(195,543)

Minus: Depreciation, Depletion & Amortization

(170,620)

(191,199)

(226,527)

(271,530)

(326,760)

(357,488)

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)

Minus: Plugging and Abandonment Accrual (E&P)

-

-

-

-

-

(5,002)

Rounding

-

-

-

(1)

-

-

Consolidated Net Income

100,708

$           

225,913

$           

258,402

$           

220,077

$           

260,001

$              

283,800

$        

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

1,649,000

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

$          

1,649,000

$     

Average Total Debt

1,174,000

$        

1,249,000

$        

1,169,000

$        

1,329,500

$        

1,609,500

$          

1,649,000

$     

Average Total Debt to Total Adjusted EBITDA

2.02 x

1.98 x

1.75 x

1.89 x

1.89 x

1.76 x

FY 2013

12-Months

Ended 3/31/14

71

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

$        

$550,000-625,000

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

$          

$100,000-145,000

Utility Capital Expenditures

56,178

57,973

58,398

58,284

71,970

$          

$85,000-95,000

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

$        

$850,000-1,000,000

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

$        

$850,000-1,000,000