EX-99

National Fuel Gas Company

Investor Presentation

May 2013

Exhibit 99

National Fuel Gas Company

Safe Harbor For Forward Looking Statements

May 2013

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 and March 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

Our Business Mix Leads to Long-Term Value Creation

Upstream

Crude Oil

Midstream

Downstream

National Fuel Gas

Supply Corporation

Empire Pipeline, Inc.

National Fuel Gas

Midstream Corporation

National Fuel Gas

Distribution

Corporation

National Fuel

Resources, Inc.

The strategic, operational and financial benefits, along with capital

flexibility and consistent growth opportunities generated by this

integrated mix of businesses continues to create significant

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

economic and commodity price scenarios

Upstream

Natural Gas

Seneca Resources

Corporation

(West Division)

Seneca Resources

Corporation

(East Division)

May 2013

National Fuel Gas Company

Integrated Businesses with Significant Marcellus Exposure…

May 2013

National Fuel Gas Company

…And Exposure to Growth from the Utica Shale

May 2013

National Fuel Gas Company

EBITDA Growth Driven by Stability and Continued Success

$164

28%

$167

26%

$169

25%

$160

23%

$171

22%

$131

23%

$121

19%

111

17%

$137

19%

$153

20%

$280

48%

$327

52%

$377

57%

$397

56%

$427

56%

$581

$632

$668

$704

$768

$250

$500

$750

$1,000

2009

2010

2011

2012

12 Months Ended

3/31/2013

Fiscal Year

Utility Segment

Exploration & Production Segment

Midstream, Energy Marketing & Other

Pipeline & Storage Segment

May 2013

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.

National Fuel Gas Company

Capital Spending Flexibility to Maintain Financial Strength

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

(1)

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

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

$56

$58

$65-$70

$53

$38

$129

$144

$70-$90

$80-$100

$81

$50-$75

$75-$125

$188

$398

$649

$694

$525-

$585

$550-

$650

$307

(1)

$501

$854

$977

$710-$820

$770-$945

$250

$500

$750

$1,000

$1,250

2009

2010

2011

2012

2013 Forecast

2014 Forecast

Fiscal Year

Utility Segment

Exploration & Production Segment

Midstream, Energy Marketing & Other

Pipeline & Storage Segment

May 2013

Total Debt

(1)

45%

National Fuel Gas Company

Strong Balance Sheet and Liquidity Position

$3.691 Billion

As of March 31, 2013

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

(1)

Long-Term Debt of $1.649 billion

Debt / Adjusted EBITDA

Capitalization

The Company has a total short-term debt capacity of

$1.085 billion of which all remains available

Fiscal Year

May 2013

Shareholders’

Equity

55 %

2009

2010

2011

2012

12-Months

Ended

3/31/13

0.0

0.5

1.0

1.5

2.0

2.5

2.02

1.98

1.75

1.89

2.00

National Fuel Gas Company

Forecasted Cash Flow Position for Fiscal Year 2013

Fiscal 2013 Cash from

Operations will likely

equal or exceed Capital

Expenditures

$775

$ 495

$765

$123

$421

$500

$1,000

$1,500

Debt Repayment

Dividend

CapEx

Cash on Hand

New Financing

Asset Sales & Other

May 2013

Cash from Ops

National Fuel Gas Company

Dividend Track Record

Current

Dividend Yield

(1)

2.3%

Dividend Consistency

Consecutive Dividend Payments

110 Years

Consecutive Dividend Increases

42 Years

Current Annualized Dividend Rate

$1.46 per Share

(1) As of April 30, 2013

$0.00

$0.50

$1.00

$1.50

$2.00

Annual Rate at Fiscal Year End

May 2013

May 2013

Exploration & Production

May 2013

Seneca Resources

Efficiently Deploying Capital Towards the Best Opportunities

$31

$28

$47

$63

$80-$110

$90-$130

$139

$356

$596

$631

$445-

$475

$460-

$520

$188

(1)

$398

$649

$694

$525-$585

$550-$650

$250

$500

$750

$1,000

2009

2010

2011

2012

2013 Forecast

2014 Forecast

Fiscal Year

Gulf of Mexico (Divested in 2011)

East Division (Appalachia)

West Division (California/Kansas)

(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

May 2013

Seneca Resources

Production Continues to Grow

20.1

19.8

19.2

20.5

20-22

21-23

8.7

16.5

43.2

62.9

90-96

111–119

13.7

13.3

5.2

42.5

49.6

67.6

83.4

110

118

132-142

100

125

150

2009

2010

2011

2012

2013 Forecast

2014 Forecast

Fiscal Year

Gulf of Mexico (Divested in 2011)

East Division (Appalachia)

West Division (California/Kansas)

May 2013

Seneca Resources

Continuing to Focus on Improving Its Cost Structure

Even after the new Pennsylvania Impact

Fee, 2012 unit cash costs decreased

from the prior year. We expect this

trend to continue in Fiscal 2013.

(1)

Represents the midpoint of current General & Administrative Expense guidance of $60 to $62 million, divided by the midpoint of current production

guidance of 110 to 118 Bcfe

(2)

Represents the midpoint of current Lease Operating Expense Guidance of $0.95 to $1.05 per Mcfe

$1.36

$1.27

$1.24

$1.08

$1.00

(2)

$0.60

$0.69

$0.64

$0.73

$0.65

$0.54

(1)

$2.57

$2.42

$2.22

$2.09

$2.01

$1.82

$0.00

$1.50

$3.00

$4.50

2008

2009

2010

2011

2012

2013 Forecast

Fiscal Year

Property, Franchise & Other Taxes

Other O&M Expense

General & Administrative Expense

Lease Operating Expense

May 2013

Seneca Resources

California: Stable Production and Increasing Cash Flows

Net Acreage: 18,418 Acres

Net Wells: 1,478

Oil Gravity: 12 –

37°

Api

NRI: 87.64

Rank

Company

California

2012

BOEPD

(1)

Occidental

187,376

Chevron

160,611

Aera (Shell/Exxon)

143,983

Plains Exploration

36,365

Berry Petroleum

19,589

Macpherson Oil

10,416

Seneca Resources

10,154

Venoco Inc

6,113

E&B Natural Resources

6,042

ExxonMobil

3,664

(1)

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

May 2013

Seneca Resources

California: Stable Production Fields

South Lost Hills

~1,500 BOEPD

Monterey Shale

Primary

219 Active Wells

Sespe

~1,100 BOEPD

Sespe Formation

Primary

172 Active Wells

North Lost Hills

~1,100 BOEPD

Tulare & Etchegoin Formation

Primary & Steamflood

175 Active Wells

North Midway Sunset

~4,100 BOEPD

Potter & Tulare Formation

Steamflood

728 Active Wells

South Midway Sunset

~1,200 BOEPD

Antelope Formation

Steamflood

110 Active Wells

East Coalinga

~100 BOEPD

Temblor Formation

Primary

May 2013

Seneca Resources

California: Strong Margins Support Significant Free Cash Flow

Average Revenue

(12 Months Ended 3/31/13)

$85.90 per BOE

$9.78

$3.35

$3.44

$2.28

$1.20

$65.85

Non-Steam Fuel LOE

Steam Fuel

G&A

Production & Other Taxes

Other Operating Costs

Adjusted EBITDA

Adjusted EBITDA per BOE

(1)

(12 Months Ended March 31, 2013)

(1) Total production from the Exploration & Production segment’s properties in California was 3,323 Mboe for the 12 months ended March 31, 2013.

Note: A reconciliation of Exploration & Production West Division Adjusted EBITDA to Exploration & Production Segment Net Income is included at the end

of this presentation.

May 2013

California: Midway Sunset South Activity Update

Seneca Resources

500’

2012 Drill Program: 21 Wells / 3 Injectors

2013 Drill Program: 23 Wells / 5 Injectors

2014 Drill Program: 23 Wells / 4 Injectors

0 ft

50 ft

100 ft

50 ft

Antelope “A-1”

and “A-2”

Sands

Antelope “B”

and “C”

Sands

Antelope “A-1”

Sand

Seneca 232M

Extended 252 Pool to the West

Seneca 252I

Extended 252 Pool to the East

Seneca 222W

Extended S Ext Pool to the East

Seneca 251U

Extended 251 Pool to the West

100 ft

50 ft

100 ft

50 ft

0 ft

50 ft

0 ft

2012 Drill Program

2013 Drilling Locations

Producers

Injectors

Producers

Injectors

WS 48-33

IP: 80 BOEPD

Oil

09/12

“X”

SANDS ISOCHORE (Thickness)

Seneca Resources

California:

Sespe

Field

–

Drilling

Programs

and

Results

1 Mile

Oak Flat 1-31

IP: 110 BOEPD

Oil 08/12

FA 502-33

IP: 75 BOEPD

Oil 1/13

FA 501-33

IP: 100 BOEPD

Oil 1/13

Oak Flat 2-31

IP: 100 BOEPD

Oil 08/12

TG 562-29

IP: 190 BOEPD

Oil 2/13

TG 53-29

IP: 90 BOEPD

Oil 3/13

2011 Sespe Wells (5)

2012 Sespe Wells (6)

2013 Sespe Wells (6)

2014 Sespe Wells (4)

May 2013

May 2013

Seneca Resources

California: East Coalinga Overview

Seneca became operator on January 30, 2013

Previous Operator: Chevron

7,764 net acres

~170 wells (60 active)

~350 BOPD (Up from 230 BOPD on 1/30/13)

$30 million capital commitment over first

three years

$100 million of potential opportunities over

the next five to seven years

2013 Plans

Drill ~12 evaluation wells across acreage

block

Place ~50% of currently idled wells back on

production

Have put 20 on since 1/30/13

Upgrade surface facilities

Active Well

Idle Well

May 2013

Seneca Resources

California: Recent Initiatives Driving Near-Term Growth

Forecast

Key Areas of Focus in 2013

South Midway Sunset Field Extensions

Sespe Infill Drill Program

East Coalinga Evaluation

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

6,000

May 2013

Seneca Resources

Expansive Pennsylvania Acreage Position

SRC Lease Acreage

SRC Fee Acreage

Eastern Development Area

Net Acreage: 55,000 acres

Mostly leased (16-18% royalty)

No near-term lease expiration

First large expiration: 2018

Ongoing development drilling in

Tioga and Lycoming Counties

Western Development Area

Net acreage:

~720,000 acres

Own most mineral rights

Minimal

royalty obligation

Minimal

lease expiration

Evaluating rich-gas potential and

initiating dry gas development

NFG Storage Acreage

May 2013

Seneca Resources

Eastern Development Area (EDA)

DCNR Tract 595

Gross Production: ~80 MMcf per Day

34 Wells Drilled

26 Wells Producing

Covington –

Fully Developed

Gross Production: ~60 MMcf per Day

47 Wells Drilled and Producing

DCNR Tract 100

Gross Production: ~155 MMcf per Day

33 Wells Drilled

21 Wells Producing

SRC Lease Acreage

SRC Fee Acreage

May 2013

Seneca Resources

Lycoming and Tioga Counties Are Highly Productive Areas

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’

Lateral

(Bcfe)

Covington

Tioga

County

5.2

4.7

4.1

5.7

4,023’

1.42

Tract 595

Tioga

County

7.1

6.0

5.1

8.0

4,629’

1.73

Tract 100

Lycoming

County

15.2

13.3

10.3

11.0

5,137’

2.14

May 2013

Seneca Resources

Western Development Area Marcellus Delineation Program

Owl’s Nest

2 Wells Drilled

3D Seismic Coverage Complete

Church Run

1 Well Drilled

Ridgway

1 Well Drilled

Rich Valley (1 Well)

Peak 7-Day IP: 7.8 MMcf per Day

30-Day Rate: 6.7 MMcf per Day

Estimated EUR: 7 Bcf

BTU

Contours

Clermont

Two Wells Drilled

Tionesta

1 Well Planned

SRC Lease Acreage

SRC Fee Acreage

Horizontal Well

May 2013

Seneca Resources

Rich Valley/Clermont Marcellus Development Area

Rich Valley/Clermont Development Area

Area of high porosity and GIP

150-200 Horizontal Locations

Anticipated EURs: 5-8 Bcf

WDA Pilot Development Program

Upon completion of initial delineation

drilling, a pilot development program

will begin this summer.

Full development planned for 2014.

SRC Lease Acreage

SRC Fee Acreage

Delineation Well

May 2013

Marcellus Shale

Clermont / Rich Valley Pilot Development Project

Clermont

Rich Valley

Rich Valley 27H

7-day IP: 7.8 MMcf/d

30-day IP: 6.7 MMcf/d

Pad A: 2 Wells

Production: Q4 FY13

Pad N: 3 Wells

Production: Q3/Q4 FY14

Rich Valley 2

Well

Production: Q1/Q2 FY14

Marcellus Faults

Marcellus & Basement Faults

Pad E: 3 Wells

Production: Q3/Q4 FY14

May 2013

Seneca Resources

Rich Valley 27H Type Curve

Lateral Length: 6,300’

Completion Stages: 42 (Reduced Cluster Spacing)

0.0

2.0

4.0

6.0

8.0

10.0

Months

Rich Valley 27H

7 Bcf Typecurve

May 2013

Seneca Resources

Ongoing Production Growth in the East Division

Forecast

100

150

200

250

300

Tract 100 (Lycoming)

Tract 595 (Tioga)

Covington (Tioga)

WDA/Other

EOG JV

Shallow Devonian (Historical Production)

May 2013

Seneca Resources

Utica Shale –

Activity Summary

Permitted

Drilled/Drilling

Completed

Producing

Range Resources

1.4 MMcfd

“Not Effectively Stimulated”

Mt. Jewett

Tested 3 Frac Stages at 1.6 MMcfd

(Typical Well: 17 Frac Stages)

Horizontal: Moving in Rig

Rex

9.2 MMcfd

Henderson

Vertical Well: Tested

Tionesta

Horizontal: Completed Fall 2012

Peak 24-Hour Rate: 3.9 MMcfd

Range Resources

4.4 MMcfd

Chesapeake

6.4 MMcfd

May 2013

Seneca Resources

Initial Entry into the Mississippian Lime Play in Kansas

Total Net Acres: 9,300

Unit

30-day IP:

352 BOED

(92% Oil/NGLs)

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

of maintaining a significant contribution from oil-producing properties

100% working interest in 4,600

gross acres

25% net working interest in

18,500 gross acres

2013: Participate in 3 to 5

gross horizontal wells

Midstream Businesses

Pipeline & Storage/NFG Midstream

May 2013

May 2013

Midstream Businesses

Pipeline Expansions to Transport Appalachian Production

Line N

Corridor

Expansions

Gathering

Marcellus

Production

Shipping Gas

to Canada &

Northeast

May 2013

Midstream Businesses

A Closer Look at the Expansion Progress

LINE “N”

2013

EXPANSION

(Nov. 2013)

LINE “N”

EXPANSION

(In-Service)

MERCER

EXPANSION

PROJECT

(Nov. 2014)

WEST SIDE

EXPANSION

(2015)

LINE “N”

2012

EXPANSION

(In-Service)

TIONESTA

GATHERING

SYSTEM

(In-Service)

NORTHERN ACCESS

EXPANSION

(In-Service)

TIOGA COUNTY

EXTENSION

(In-Service)

CENTRAL TIOGA

COUNTY EXTENSION

(2015/2016)

COVINGTON

GATHERING

SYSTEM

(In-Service)

TROUT RUN

GATHERING SYSTEM

(In-Service)

MT. JEWETT

GATHERING SYSTEM

(Under Construction)

May 2013

Midstream Businesses

Pursuing Additional Opportunities Near the Line N Corridor

Activity in the Marcellus and Utica shales

along the Pennsylvania/Ohio border

continues to remain robust

NFG Supply Corporation’s Line N system is

well-positioned for continued expansion

NFG Midstream Corporation is focused on

building new high-pressure wet and dry gas

gathering systems

Significant expansion opportunities may be

present in the next few years

2013:

Smaller pipeline expansions

2014+:

Larger expansion projects, possibly

including an integrated wet gas solution,

with NFG Midstream focused on the high-

pressure wet gas gathering systems and

NFG Supply transporting dry gas on its

interstate system

Line N

Focus Area

May 2013

Midstream Businesses

NFG Midstream is Focused on Serving Appalachian Producers

Midstream’s gathering systems are

critical to unlock remote, but highly

productive Marcellus acreage

History of operational success and

efficiency within Pennsylvania

Current focus is on developing and

expanding gathering infrastructure

for both Seneca and other producers

in the Appalachian Basin

May 2013

Utility

May 2013

Total Customers: 520,000

Rate Mechanisms:

Revenue Decoupling

Weather Normalization

Low Income Rates

Choice Program/Purchase of

Merchant Function Charge

90/10 Sharing (Large Customers)

Natural Gas Vehicle Pilot Program

Allowed ROE: 9.1%

Utility

New York Service Territory

(Uncollectibles Adjustment)

Return on Equity

Fiscal Year

Receivables (POR)

May 2013

Utility

New York -

Earnings Sharing Proposal and Show Cause Order

March 27, 2013

Filed a plan with the NY PSC

to adopt an earnings

sharing and stabilization

mechanism on earnings

above a 9.96% ROE

April 19, 2013

NY PSC issued an Order

to Show Cause (OTSC)

commencing a

proceeding to establish

“temporary rates”

June 1, 2013

OTSC suggests

“temporary rates”

could

become effective

May 8, 2013

Company responds to

OTSC

Further proceedings

would follow to establish

permanent rates

Most recent NY PSC multi-

year plan include:

ROE: 9.4%

Equity Ratio: 48%

National Fuel continues to

maintain a dialogue with

regulators and is

responding to the OTSC

May 2013

Utility

Pennsylvania Service Territory

Total Customers: 213,000

Rate Mechanisms:

Low Income Rates

Choice Program/Purchase of

Merchant Function Charge

Allowed ROE: N/A

(1)

Black Box Settlement

Return on Equity

Fiscal Year

Receivables (POR)

May 2013

Utility

Consistently Delivering Excellent Customer Service

National

Fuel

has

ranked

among

Gas

Utilities

the

East Region for business customer service in each of the

past three years and continues to focus on safety,

corporate citizenship and quality customer service

Study Year

(March)

Customer Satisfaction

Study Rank

2013

2012

2011

and $50,000 monthly on natural gas.

Source: J.D. Power and Associates Gas Utility Business Customer Satisfaction Study for the years 2009-2013 - businesses that spend between $200

May 2013

Utility

Lower Natural Gas Prices Led to Increased Normalized Usage

Residential

Industrial

(1)

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

Industrial load increasing

slightly for Fiscal Year 2013

Twelve Months Ended March 31

102.3

98.5

97.8

101.5

100.8

26,410

24,227

25,838

25,290

27,886

Utility

Continued Cost Control Helps Provide Earnings Stability

Low natural gas prices,

combined with a focus on

cost control, continue to

help reduce expenses

$178

$164

$167

$168

$25

$27

$14

$11

$203

$191

$181

$179

$177

$175

$50

$100

$150

$200

$250

2008

2009

2010

2011

2012

12 Months

Ended 03/31/13

Fiscal Year

All Other O&M Expenses

O&M Uncollectible Expense

May 2013

Utility

Strong Commitment to Safety

The anticipated increase in 2013

capital expenditures is largely due

to the implementation of a new

Customer Information System

The Utility remains

focused on consistent

spending to maintain

the ongoing safety and

reliability of its system

$45.1

$44.4

$45.0

$44.3

$43.8

$57.5

$56.2

$58.0

$58.4

$58.3

$65-$70

$20

$40

$60

$80

2008

2009

2010

2011

2012

2013

Forecast

Fiscal Year

Capital Expenditures for Safety

Total Capital Expenditures

May 2013

National Fuel Gas Company

Capital Deployment Has Led to Significant Accomplishments

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.

May 2013

136% Increase in Proved Reserves Since 2009

Total oil and gas proved reserves reached 1,246 Bcfe at September 30, 2012, with a 3-year

average F&D cost of $1.87/Mcfe

96% Production Growth Since 2009

Despite

the

2011

sale

its

offshore

Gulf

Mexico

properties,

Seneca

has

increased

production from 42.5 Bcfe in 2009 to 83.4 Bcfe in 2012

37% Increase in Pipeline & Storage Adjusted EBITDA since Fiscal 2011

As a result of major Appalachian pipeline expansions, Adjusted EBITDA reached $153 million

for the last 12 months and new projects will continue to drive growth beyond fiscal 2013

44.3 Bcfe in 2012 NFG Midstream Gathering Volumes

NFG Midstream gathered more than 44 Bcfe of volumes for Seneca Resources, eliminating

the need to rely upon and provide payment to third party infrastructure operators

National Fuel Gas Company

Appendix

May 2013

National Fuel Gas Company

Fiscal Year 2013 Earnings Guidance Drivers

2013 Forecast

GAAP Earnings per Share

$2.95 -

$3.10

Exploration & Production Drivers

Total Production (Bcfe)

110 -

118

DD&A Expense (per Mcfe)

$2.05 -

$2.15

LOE Expense (per Mcfe)

$0.95 -

$1.05

G&A Expense

$60 -

$62 MM

Pipeline & Storage Drivers

O&M Expense

+3%

Revenue

$260 -

$265 MM

Utility Drivers

O&M Expense

+3%

Normal Weather in PA

Energy Marketing Drivers

Operating Income

$5 -

$10 MM

May 2013

May 2013

National Fuel Gas Company

No Debt Maturities Until Fiscal 2018

Embedded Cost of

Long-Term Debt

5.58%

In February, the Company

Issued $500 million in

10-year notes at 3.75%

Midstream Businesses

Appendix

May 2013

May 2013

Midstream Businesses

Regulated Interstate Expansion Initiatives (Pipeline & Storage)

Project Name

Capacity

(Dth/D)

Est.

CapEx

In-Service

Market

Status

Lamont Compressor Station

90,000

$14 MM

2010/2011

Fully Subscribed

Completed –

Two Phases

Line “N”

Expansion

160,000

$22 MM

10/2011

Fully Subscribed

Completed

Tioga County Extension

350,000

$58 MM

11/2011

Fully Subscribed

Completed

Northern Access Expansion

320,000

$77 MM

11/2012

Fully Subscribed

Completed

Line “N”

2012 Expansion

163,000

$40 MM

11/2012

Fully Subscribed

Completed

Line “N”

2013 Expansion

30,000

~$5 MM

11/2013

Fully Subscribed

Executed Precedent Agreement

Mercer Expansion Project

105,000

~$30 MM

11/2014

Fully Subscribed

Executed Precedent Agreement

West Side Expansion

95,000+

~$65 MM

2015

OS Concluded

Negotiating Precedent Agreements

Central Tioga County

Extension

260,000

~$150 MM

2015/2016

OS Concluded

Discussions with anchor shipper

West to East

~425,000

~$290 MM

~2016

29% Subscribed

Marketing continues with producers in

various stages of exploratory drilling

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

Capital Investment: ~$751 MM

May 2013

Midstream Businesses

Gathering Expansion Initiatives (NFG Midstream)

Project Name

Capacity

(Mcf/D)

Est.

CapEx

In-Service

Date

Market

Comments

Covington Gathering System

220,000

$40 MM

Multiple

Phases -

Most

In-Service

Capacity Available

[Marketing to

Third Parties]

Completed

–

Flowing

into

TGP

300

Line. This includes ~$10 million of

current and future spending to

build pipeline to connect additional

wells

Trout Run Gathering System

466,000

$185 MM

May 2012

Capacity Available

[Marketing to

Third Parties]

Completed

–

Flowing

into

Transco

Leidy Line. This includes ~$90

million of current and future

spending to build compression and

pipeline to connect additional wells

Tionesta Gathering System

10,000

$2.1 MM

April 2012

Fully Subscribed

Completed

–

Flowing

into

TGP

300

Line.

Mt. Jewett Gathering System

10,000

$3.9 MM

FY2013

Fully Subscribed

Under Construction

Total Firm Capacity: ~706,000 Mcf/D

Capital Investment: ~$231 MM

Exploration & Production

Appendix

May 2013

May 2013

Seneca Resources

Another Strong Year of Reserve Growth

Fiscal

Years

3-Year

F&D Cost

(1)

($/Mcfe)

2006-2008

$7.63

2007-2009

$5.35

2008-2010

$2.37

2009-2011

$2.09

2010-2012

$1.87

Seneca has more than doubled

its proved reserves since 2009,

while maintaining a relatively

high percentage of proved

developed reserves (67%),

given its large resource base

(1)

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

May 2013

Seneca Resources

Hedge Positions and Strategy

Natural Gas

Swaps

Volume

(Bcf)

Average

Hedge Price

Fiscal 2013

38.7

$4.49 / Mcf

Fiscal 2014

62.7

$4.28 / Mcf

Fiscal 2015

39.7

$4.27 / Mcf

Fiscal 2016

37.3

$4.35 / Mcf

Fiscal 2017

23.0

$4.19 / Mcf

Oil Swaps

Volume

(MMBbl)

Average

Hedge Price

Fiscal 2013

0.9

$94.92 / Bbl

Fiscal 2014

1.6

$100.26 / Bbl

Fiscal 2015

0.6

$93.66 / Bbl

Fiscal 2016

0.4

$88.39 / Bbl

Most hedges executed at sales point to eliminate basis risk

Seneca has hedged approximately 73% of its

forecasted production for Fiscal 2013

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

May 2013

Seneca Resources

Operational Efficiencies Continue to Drive Production Growth

Ongoing efficiency allows for more activity with a flat rig count

(1)

RCS – Reduced Cluster Spacing

(2)

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

May 2013

Marcellus Shale

Targeting Continued Cost Reductions

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

May 2013

National Fuel Gas Company

Comparable GAAP Financial Measure Slides and Reconciliations

This presentation contains certain non-GAAP financial measures. For pages

that contain non-GAAP financial measures, pages containing the most directly

comparable GAAP financial measures and reconciliations are provided in the

slides that follow.

The Company believes that its non-GAAP financial measures are useful to

investors because they provide an alternative method for assessing the

Company’s operating results in a manner that is focused on the performance

of the Company’s ongoing operations, or on earnings absent the effect of

certain credits and charges, including interest, taxes, and depreciation,

depletion and amortization. The Company’s management uses these non-

GAAP financial measures for the same purpose, and for planning and

forecasting purposes. The presentation of non-GAAP financial measures is not

meant to be a substitute for financial measures prepared in accordance with

GAAP.

May 2013

Reconciliation of Exploration & Production West Division Adjusted EBITDA

to Exploration & Production Segment Net Income

($ Thousands)

12 Months Ended

March 31, 2013

Exploration & Production - West Division Adjusted EBITDA

218,842

Exploration & Production - All Other Divisions Adjusted EBITDA

208,620

Total Exploration & Production Adjusted EBITDA

427,462

Minus: Exploration & Production Net Interest Expense

(33,788)

Minus: Exploration & Production Income Tax Expense

(80,420)

Minus: Exploration & Production Depreciation, Depletion & Amortization

(214,871)

Exploration & Production Net Income

98,383

Exploration & Production Net Income

98,383

Pipeline & Storage Net Income

71,455

Utility Net Income

68,356

Energy Marketing Net Income

5,208

Corporate & All Other Net Income

2,248

Consolidated Net Income

245,650

May 2013

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

218,842

Exploration & Production - All Other Divisions Adjusted EBITDA

108,139

139,624

189,854

170,232

208,620

Total Exploration & Production Adjusted EBITDA

279,711

327,462

377,457

397,129

427,462

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

279,711

327,462

377,457

397,129

427,462

Utility Adjusted EBITDA

164,443

167,328

168,540

159,986

170,824

Pipeline & Storage Adjusted EBITDA

130,857

120,858

111,474

136,914

152,563

Energy Marketing Adjusted EBITDA

11,589

13,573

13,178

5,945

7,656

Corporate & All Other Adjusted EBITDA

(5,575)

2,429

(2,960)

4,140

9,773

Total Adjusted EBITDA

581,025

631,650

667,689

704,114

768,278

Total Adjusted EBITDA

581,025

631,650

667,689

704,114

768,278

Minus: Net Interest Expense

(81,013)

(90,217)

(75,205)

(82,551)

(87,061)

Plus: Other Income

9,762

6,126

5,947

5,133

4,646

Minus: Income Tax Expense

(52,859)

(137,227)

(164,381)

(150,554)

(163,691)

Minus: Depreciation, Depletion & Amortization

(170,620)

(191,199)

(226,527)

(271,530)

(298,194)

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)

Rounding

(1)

Consolidated Net Income

100,708

225,913

258,402

220,077

245,650

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

1,089,000

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

20,000

Total Debt (Start of Period)

1,099,000

1,249,000

1,089,000

1,419,000

Average Total Debt

1,174,000

1,249,000

1,169,000

1,329,500

1,534,000

Average Total Debt to Total Adjusted EBITDA

2.02

1.98

1.75

1.89

2.00

12-Months Ended

3/31/13

May 2013

Reconciliation of Segment Capital Expenditures to

Consolidated Capital Expenditures

($ Thousands)

FY 2013

FY 2009

FY 2010

FY 2011

FY 2012

Forecast

Capital Expenditures from Continuing Operations

Exploration & Production Capital Expenditures

188,290

398,174

648,815

693,810

$525,000-585,000

Pipeline & Storage Capital Expenditures - Expansion

52,504

37,894

129,206

144,167

$70,000-90,000

Utility Capital Expenditures

56,178

57,973

58,398

58,284

$65,000-70,000

Marketing, Corporate & All Other Capital Expenditures

9,829

7,311

17,767

81,133

$50,000-75,000

Total Capital Expenditures from Continuing Operations

306,801

501,352

854,186

977,394

$710,000-820,000

Capital Expenditures from Discountinued Operations

All Other Capital Expenditures

216

150

Plus (Minus) Accrued Capital Expenditures

Exploration & Production FY 2012 Accrued Capital Expenditures

(38,861)

Exploration & Production FY 2011 Accrued Capital Expenditures

(103,287)

103,287

Exploration & Production FY 2010 Accrued Capital Expenditures

(78,633)

78,633

Exploration & Production FY 2009 Accrued Capital Expenditures

(9,093)

19,517

Pipeline & Storage FY 2012 Accrued Capital Expenditures

(2,696)

Pipeline & Storage FY 2011 Accrued Capital Expenditures

(7,271)

7,271

Pipeline & Storage FY 2008 Accrued Capital Expenditures

16,768

All Other FY 2012 Accrued Capital Expenditures

(11,000)

All Other FY 2011 Accrued Capital Expenditures

(1,389)

1,389

All Other FY 2009 Accrued Capital Expenditures

(715)

715

Total Accrued Capital Expenditures

6,960

(58,401)

(33,314)

59,390

Eliminations

(344)

Total Capital Expenditures per Statement of Cash Flows

313,633

443,101

820,872

1,036,784

$710,000-820,000