EX-99

National Fuel Gas Company

Investor Presentation

April 2015

Exhibit

Corporate

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;

impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the price of natural gas or oil; 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 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; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns

to effect changes at the Company; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural

gas or oil; 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; changes in demographic patterns and weather conditions;

changes in the availability, price or accounting treatment of derivative financial instruments; 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; 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, 2014 and the Forms 10-Q for the quarters ended December 31, 2014 and March 31, 2015. 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.

Safe Harbor For Forward Looking Statements

Corporate

3 Million BBls of Annual Crude Oil Production

$265 Million of Midstream Adjusted EBITDA

(2)

800,000+ Net Acres in Pennsylvania

1.9 Tcfe of Proved Reserves

(1)

Quality Assets, Exceptional Location, Unique Integration

(1)

Total proved reserves are as of September 30, 2014.

(2)

For the trailing twelve months ended March 31, 2015. 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.

Corporate

Unique Integrated Business Model Provides Competitive Advantage

The National Fuel Value Proposition

(1) Per NGI’s Shale Daily

(January 5, 2015). The Company has identified 780,000 acres as prospective in Marcellus Shale.

800,000+

net

acres

Pennsylvania

–

largest

acreage

position

Marcellus

Shale

(1)

WDA mineral ownership = no royalty or drilling commitments

Stacked pay potential in Marcellus, Utica and Geneseo shales

Coordinated midstream infrastructure build-out

Opportunity for further pipeline expansion to accommodate Appalachian supply growth

Creating sustainable value for shareholders remains our #1 priority

Considerable Upstream and Midstream Growth Opportunities in Appalachia

Integration significantly reduces operational and financing costs

Diversified cash flows provide stability in challenging commodity price environment

Strong Balance Sheet and History of Disciplined Financial Management

Investment grade credit rating and liquidity to support Appalachian growth strategy

Disciplined capital investment focused on economic returns

112-year commitment to the dividend

Corporate

Upstream & Midstream –

Common Vision For Growth

Western Development Area

Tier I Acreage: 200,000 Acres

Clermont Gathering System

NFG Supply & Other Interconnects

High quality

Marcellus acreage

Connected to our

interstate pipeline

network

Pipeline capacity to premium

and alternate markets

Northern Access Projects

490 MMcf/d to Canada by 2016

Corporate

EBITDA Contribution by Segment

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.

Corporate

Adjusting Capex to Capitalize on Opportunities

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

Corporate

Maintaining a Strong Balance Sheet

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 and short-term debt of $157.5 million.

Total Debt

(1)

41%

$4.4 Billion

As of March 31, 2015

Debt/Adjusted EBITDA

Capitalization

Corporate

Dividend Track Record

(1) As of April 29, 2015.

Current

Dividend Yield

(1)

2.4%

Dividend Consistency

Consecutive Dividend Payments

112 Years

Consecutive Dividend Increases

44 Years

Current Annualized Dividend Rate

$1.54 per Share

Upstream Overview

Exploration & Production

Upstream

Proven Record of Reserve Growth

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

Fiscal

Years

3-Year

F&D Cost

(1)

($/Mcfe)

2007-2009

$5.35

2008-2010

$2.37

2009-2011

$2.09

2010-2012

$1.87

2011-2013

$1.67

2012-2014

$1.38

•

2014 F&D Cost = $1.15

•

Marcellus F&D: $1.00

•

327% Reserve

Replacement Rate

•

73% Proved Developed

Upstream

Marcellus Shale Driving Production Growth

Upstream

Disciplined Capital Spending

Upstream

Highly Competitive Cost Structure

(1)

Represents the midpoint of current General & Administrative Expense guidance of $0.40 to $0.45 per Mcfe for fiscal 2015.

(2)

The total of the two LOE components represents the midpoint of current LOE guidance of $1.00 to $1.10 per Mcfe for fiscal 2015.

(3)

The cost of firm transportation is reflected in price realizations (a deduction to gross revenues). As such, it is not included in LOE.

(1)

(2)

(3)

Upstream

Marcellus Shale: Prolific Pennsylvania Acreage

Eastern Development Area (EDA)

•

Mostly leased (16-18% royalty)

•

No near-term lease expiration

•

Limited development drilling until firm

transportation capacity on Atlantic

Sunrise becomes available in late 2017

o

Drilling activity will HBP key acreage

Western Development Area (WDA)

•

Average

net

revenue

interest

(NRI):

98%

o

No lease expiration

o

No royalty on most acreage

•

Highly contiguous

o

Significant economies of scale

•

1,700 to 2,000 locations de-risked

Seneca Lease

Seneca Fee

720,000 Acres

60,000 Acres

Upstream

EDA Delivering Significant Growth

(1) One well included in the total for both Tract 595 and Tract 100 is drilled into and producing from the Geneseo Shale.

Covington –

Fully Developed

•

Productive

Capacity:

~45MMcf

per

Day

•

47 Wells Producing

Gamble

•

30 to 50 future Marcellus locations

•

1 Well Producing

•

Opportunity for Geneseo development

Upstream

Focusing on WDA Development

Note:

Assumes

6,000’

treated

lateral

length.

4 -

6 BCF/well

4 -

6 BCF/well

6 -

8 BCF/well

2-4 BCF/well

SRC Lease Acreage

SRC Fee Acreage

EOG Earned JV Acreage

Seneca’s Tier I Acreage:

•

200,000 Acres

•

860+ locations economic at

realized prices <$2.70 /MMbtu

CRV

Hemlock

Ridgway

Upstream

Clermont/Rich Valley (CRV) Area

Currently Drilling

Drilled Wells

Producing Wells

Clermont/Rich

Valley

Area

•

200-250 Planned Horizontal Locations

•

Current Productive Capacity: 30 Wells; 95 MMcfd

•

IP Range: 5-11 MMcfd

Pad D08-G

Drilling 11 Wells

Pad C8-X

Drilling 7 wells

Pad E8-D

Drilling 8 wells

Pad E09-E

10 Wells Completing

Upstream

Marcellus Well Results

(1)

Does not include a well drilled into and producing from the Geneseo Shale.

(2)

Excludes

wells

drilled

and

completed

without

sufficient

production

data

for

inclusion

table.

Also

excludes

wells

now

operated

Seneca

that

were

drilled

prior

operator

part

joint-venture.

Area

Producing Well

Count

Average IP Rate

(MMcfd)

Average

7-Day (MMcf/d)

Average Treatable

Lateral Length (ft)

Clermont/Rich Valley

(CRV) & Hemlock

Elk, Cameron &

McKean counties

(2)

7.7

6.9

5,558’

WDA Development Wells:

EDA Development Wells:

Area

Producing Well

Count

Average IP Rate

(MMcfd)

Average

7-Day (MMcf/d)

Average Treatable

Lateral Length (ft)

Covington

Tioga

County

5.2

4.7

4,023’

Tract 595

Tioga

County

(1)

7.4

6.1

4,765’

Tract 100

Lycoming

County

(1)

16.8

14.8

5,270’

Upstream

Marcellus Drilling and Completion Efficiencies

$8.7 MM

Well Cost

$6.3 MM

Well Cost

Fiscal 2012 Average Development Well

Fiscal 2015

(1)

Average Development Well

Lateral

Length:

5,100

Measured

Depth:

13,700

Completion

Stages:

Lateral

Length:

7,200

Measured

Depth:

14,300

Completion

Stages:

Drilling Cost per Foot

(2)

Completion Cost per Stage

(2)

(000s)

(1)

Estimated fiscal year-to-date through March 31, 2015.

(2)

Includes dollars spent to drill and complete development wells only. Excludes exploration and delineation wells.

Upstream

Prospect

Product

Locations

Remaining

to Be Drilled

Completed

Lateral

Length (ft)

Average

EUR

(Bcf)

BTU

$4.00

Dawn/Nymex

IRR %

$3.50

Dawn/Nymex

IRR %

15% IRR

Realized Price

DCNR 100

Dry Gas

5,582

13-14

1030

86%

57%

$1.83

Gamble

Dry Gas

4,605

10.5-11.5

1030

58%

50%

$2.07

Clermont -

Rich Valley

Dry Gas

142

7,000

7.5-8.5

1050

41%

26%

$2.31

Hemlock

Dry Gas

157

7,000

6.5-7.5

1050

29%

18%

$2.57

Ridgway

Dry Gas

564

7,000

6-7

1111

26%

15%

$2.69

Remaining

Tier 1

Dry Gas

1,020

7,000

5.5-6.5

1030 - 1100

21%

12%

> $3.00

Future

Resource

Dry & Wet

Gas

1,620

7,000

5.5-6.5

1030 - 1350

14%

> $3.25

Marcellus Shale Program Economics

(1)

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

(2)

Additional delineation required.

(1)

(2)

~2,000 WDA Locations Economic Below $4/MMbtu

Upstream

WDA Mineral Interests Significantly Enhance Returns

(1)

Internal

Rate

Return

(IRR)

includes

estimated

well

costs

under

current

cost

structure,

LOE,

and

Gathering

tariffs

anticipated

for

each

prospect.

($/Mcf)

The Seneca

Advantage

0% Royalty

Realized Price

$ 2.31

Less: Royalty Payment

(0.00)

Less: Cash Operating Expenses

(0.65)

Cash Margin

$ 1.66

Before Tax IRR

(1)

15%

A producer burdened by a 15% royalty would

require a $0.41 higher realized price to achieve

same level of economics as Seneca Resources

Producer

Paying

15% Royalty

$ 2.31

(0.35)

(0.65)

$ 1.31

Clermont/Rich Valley Example

Upstream

Adding Long-Term Firm Transport to the Portfolio

(1)

large

majority

the

executed

firm

sales

agreements

continue

for

the

remainder

the

firm

transportation

contract

term.

(2)

Excludes

throughput-based

commodity

charges,

fuel

charges

and

other

surcharges.

Project

(Counterparty)

In-

Service

Date

Contract

Term

Delivery

Market

FT Capacity (Dth/day)

Matched Firm

Sales Contracts

Fiscal

2015

Fiscal

2016

Fiscal

2017

Fiscal

2018

Northeast Supply

Diversification

Project (TGP)

Nov.

2012

15 years

Canada

50,000

Executed Contracts

50,000 Dth/d

for 10 years

Niagara Expansion/

TETCO (TGP & NFG)

Nov.

2015

15 years

Canada

---

158,000

Executed Contracts

140,000 Dth/d

for 15 years

TETCO

---

12,000

Northern Access

2016 (NFG/

TransCanada/

Union)

Late

2016

15 years

Canada

---

350,000

Executed Contracts

75,000 Dth/d

for 7.5 years

Evaluating Further

Opportunities

TGP 200

(NY)

---

140,000

Atlantic Sunrise

(Transco)

Nov.

2017

15 years

Mid-

Atlantic/

Southeast

---

189,405

Executed Contracts

189,405 Dth/d

for first 5 years

(1)

Total Firm Transportation Capacity

50,000

220,000

710,000

899,405

Weighted Average Reservation Charge per Dth

(2)

$0.29

$0.42

$0.56

$0.59

Upstream

Significant Base of Long-Term Firm Contracts

Atlantic Sunrise

Williams Co. (Transco)

189,405 Dth/d

Northern Access 2016

NFG , TransCanada & Union

490,000 Dth/d

Niagara Expansion / TETCO

TGP & NFG

170,000 Dth/d

Current Firm Sales

(1)

& FT

914,405 Dth per day

(1)

Total Firm Contracts by FY 2018

(1)

Includes base firm sales contracts not tied to firm transportation capacity.

Upstream

Reaching High Value Markets

Seneca FT Capacity by Fiscal 2018

(Dth per day)

Canadian Markets

558,000

Mid-Atlantic, Southeast & Other

+ 341,405

Total Firm Transport Capacity

899,405

To Mid-Atlantic

& Southeast

Markets

To Canadian

Markets

Upstream

Firm Sales Provide Market for Appalachian Production

(1)

Includes

new

50,000

Dth

per

day

firm

sales

contractstarting

May1,

2015at$3.00

per

Dth.

(2)

EDA

and

WDA

carry

average

net

revenue

interest

(NRI)

82%

84%

and

98%,

respectively.

Note:

Values

shown

represent

the

price

differential

reference

price

(netback

price)

the

point

sale,

including

the

cost

all

downstream

transportation.

EDA

(2)

280,036 /d

226,993 /d

200,036 /d

160,036 /d

WDA

(2)

94,952 /d

110,900 /d

175,878 /d

208,900 /d

208,000 /d

Fiscal 2015

Fiscal 2016

Pricing

Index

Key:

EDA/WDA Split:

(1)

Upstream

Natural

Gas

Financial

Hedge

Positions

(1)

Excludes fixed price physical firm sales.

(2)

For the remaining six months of fiscal 2015. A table of volumes and average hedge prices by index are included in the Appendix.

Upstream

FY 2015 Production –

Firm Sales & Spot Exposure

(1)

Spot price assumptions reflected in fiscal 2015 earnings guidance range.

(2)

Indicates firm sales not backed by financial hedges. DOM Firm Sales include 3.7 Bcf of non-operated WDA production volumes.

(3)

EPS

guidance

assumesspot

volumes

aresoldat

$1.75

$2.00

per

Mcf.

Firm Sales with Price Certainty

56 Bcf Realizing ~$3.60/Mcf

4.6 Bcf of Additional Basis Protection

4.0 Bcf

(2)

4.3 Bcf

(2)

Upstream

FY 2016 Productive Capacity

(1)

FY 2016 Productive Capacity Summary

Hedged Firm & Fixed Sales

99 Bcf

Unhedged Firm Sales

(2)

34 Bcf

Productive Capacity Exposed to Spot

47 -

55 Bcf

Total East Div. Productive Capacity

180 -

188 Bcf

West Division (California)

20 -

22 Bcfe

Total SRC Productive Capacity

200 -

210 Bcfe

Total

East Division

Productive Capacity

Price Certainty

at ~$3.60 /Mcf

(1)

Productive capacity reflects firm sales commitments and assumes no price-related curtailments on projected production exposed to local Appalachian spot pricing.

Productive capacity is not intended to reflect production guidance for fiscal 2016.

(2)

Unhedged firm sales includes non-operated WDA production volumes.

(2)

Upstream

Utica/Point Pleasant: Industry Activity

Range

59 Mmcf/d

Rice

Mmcf/d

Shell

26.5

Mmcf/d

PGE

Permitted

Drilling

Completed

Production

Seneca Vert.

Seneca Horiz.

MHR

46 Mmcf/d

Color-filled contours are Trenton TVDSS; CI = 1000’

Seneca -

DCNR 007

IP: 22.7 MMcfd

Seneca –

Mt. Jewett

IP: 8.9 MMcfd

Upstream

Utica/Point Pleasant Shale: EDA Opportunities

Shell: Gee

11.2 Mmcf/d

PGE

Currently Drilling

Permitted

Drilling

Completed

Producing

Seneca

Horizontal

Shell: Neal

26.5 Mmcf/d

Other Operators

Upstream

California: Stable Production; Modest Growth

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

Upstream

South Midway Sunset Development

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

•

Significantly increased daily production

•

Drilled 135 new producers

•

Added 3.8 MMBO of proven reserves

•

Increased steam capacity by 600%

•

Identified opportunities for additional

pool development

Upstream

Focused on High Return Opportunities

CALIFORNIA

Field

Average

Well Cost

Average

EUR

(MBO)

Estimated

IRR

@$55/Bbl

Fiscal 2015

Locations

South Midway Sunset

$250,000

57%

North Midway Sunset

$300,000

25%

East Coalinga

$420,000

15%

Upstream

California: Modest Growth Anticipated in 2015

Upstream

Strong Margins Support Significant Free Cash Flow

Average Revenue

for FYTD 2015

(1)

$68.34 per BOE

(1)

Reflects the six month period ended March 31, 2015. Average revenue per BOE includes impact of hedging.

Midstream Overview

Pipeline & Storage

Gathering

Midstream

Covington

Gathering System

(In-Service)

Trout Run

Gathering System

(In-Service)

Gathering Interconnects

TGP 300

Transco

Gathering is the First Step to Reaching a Market

(1)

Fiscal 2015 estimated revenue reflects projected throughput based on the range of Seneca’s Fiscal 2015 production guidance (155-175 Bcfe).

Clermont

Gathering System

(In-Service)

(1)

Midstream

Gathering Supporting Seneca’s EDA Production

(1) Fiscal 2015 estimated throughput reflects the midpoint of Seneca’s Fiscal 2015 production guidance range (155-175 Bcfe).

•

In-Service Date: November 2009

•

Capacity: 220,000 Dth per day

•

Interconnect: TGP 300

•

Capital Expenditures (to date): $32 Million

Interconnects

(1)

•

In-Service Date: May 2012

•

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

•

Interconnect: Transco –

Leidy Lateral

•

Capital Expenditures (to date): $163 Million

Covington Gathering System

Trout Run Gathering System

Midstream

•

In-Service: July 2014

•

Ultimate Trunkline Capacity:

o

Approx. 1 Bcf per day

•

Interconnects:

o

TGP 300 (current)

o

NFG Supply Corporation

(Northern Access 2016)

•

Capital Expenditures:

o

To date: $150 Million

o

2015

(1)

: $70 -

$90 Million

Clermont Gathering System has Large Expandability

CInterconnect

Clermont Gathering System

Compressor Station

(1)

For the remaining six months of fiscal 2015.

Midstream

Pipeline & Storage: Premier Appalachian Position

NFG is uniquely positioned to expand our regional pipeline systems and

provide valuable outlets for producers and shippers in Appalachia

Canada

New England

& Northeast

Midwest &

Southeast

Mid-Atlantic

Midstream

Major Expansion Designed for Canadian Deliveries

Northern Access 2015

Northern

Access 2015

(November 2015)

•

Customer: Seneca Resources

•

In-Service: November 2015

•

System: NFG Supply Corp.

•

Capacity: 140,000 Dth per day

o

Lease to TGP as part of their

Niagara Expansion project

•

Interconnect

o

Niagara (TransCanada)

•

Total Cost: $66 Million

•

Major Facilities

o

23,000 HP Compression

•

FERC Status

o

Certificate received Feb. 2015

Midstream

Northern Access 2016 Provides Access to Canada

Northern Access 2016

Northern

Access 2016

(Late 2016)

•

Customer: Seneca Resources

•

In-Service: Targeting Late 2016

•

Capacity: 490,000 Dth/d

•

Interconnects:

o

TransCanada –

Chippawa

(350,000 Dth/d)

o

TGP 200 –

East Aurora

(140,000 Dth/d)

•

Total Cost: ~$451 Million

•

FERC Status

o

Pre-filing: July 2014

o

Certificate filing: March 2015

Midstream

Recent

Party

Expansions

Highly

Successful

Completed Expansions

Capacity (Dth/day)

Northern Access 2012

320,000

Tioga County Ext. & Lamont

440,000

Line N & Mercer Expansion

458,000

Total New Capacity

1,218,000

Capital Cost ($Millions)

Northern Access 2012

$72

Tioga County Ext. & Lamont

$72

Line N & Mercer Expansion

$138

Total Capital Expenditures

$282

Annual Revenues ($Millions)

Northern Access 2012

$16.1

Tioga County Ext. & Lamont

$33.4

Line N & Mercer Expansion

$23.1

Total Reservation Charges

$72.6

Line N Projects

Northern

Access 2012

Tioga

County

Extension

Midstream

Pairing Line N Expansions with System Modernization

Westside Expansion &

Modernization

Mercer

(TGP Station 219)

Holbrook (TETCO)

Westside

Expansion &

Modernization

•

In-Service: November 2015

•

System: NFG Supply Corp.

•

Capacity: 175,000 Dth per day

o

Range Resources (145,000 Dth/d)

o

Seneca Resources (30,000 Dth/d)

•

Interconnect

o

Mercer (TGP Station 219)

o

Holbrook (TETCO)

•

Total Cost: $86 Million

o

Expansion: $45 Million

o

Modernization: $41 Million

•

Major Facilities

o

3,550 HP Compressor

o

23.3 miles –

24”

Replacement Pipe

•

FERC Status

o

Certificate received March 2015

Midstream

Developing Unique Solutions for Shippers

Tuscarora Lateral

Tuscarora

Lateral

•

In-Service: November 2015

•

System: NFG Supply & Empire Pipeline

•

New No-Notice Services

o

Precedent agreements executed with

RG&E, NYSEG & NFG Utility

o

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

o

Preserving 20,000 Dth per day (NYSEG)

o

Retained Storage: 3.3 Bcf

o

New incremental transportation

capacity of 49,000 Dth per day

•

Interconnect

o

Tuscarora (NFG/Supply)

•

Total Cost: $58.5 Million

•

Major Facilities

o

1,384 HP Compressor

o

17 miles –

12”/16”

Pipeline

•

FERC Status

o

Certificate received March 2015

Midstream

Significant Expansions Are Driving Growth

Total Expansion (2009-2016+)

Capacity

Additions

2,072,000 Dth/day

Planned Projects (2015+)

Precedent Agreements Executed

In-Service 2015

364,000 Dth/day

In-Service 2016+

490,000 Dth/day

Delivering Gas North

Tioga County Extension

Northern Access 2012

Northern Access 2015

Northern Access 2016

Total Capacity

1,300 MDth/d

Other Projects

Lamont Compressor

Tuscarora Lateral

Total Capacity

139 MDth/d

Line N Corridor

Line “N”

Expansion

Line “N”

2012 Expansion

Line “N”

2013 Expansion

Mercer Expansion

West Side Expansion

Total Capacity

633 MDth/d

Completed Projects (Since 2009)

Recent Capacity

Additions

1,218,000 Dth/day

Downstream Overview

Utility

Energy Marketing

Downstream

New York & Pennsylvania Service Territories

New York

Pennsylvania

Total Customers: 524,300

ROE:

9.1%

(NY

PSC

Rate

Case

Settlement,

May

2014)

Rate Mechanisms:

Total Customers: 213,500

ROE:

Black

Box

Settlement

(2007)

Rate Mechanisms:

o

Low Income Rates

o

Merchant Function Charge

o

Earnings Sharing

o

Revenue Decoupling

o

Weather Normalization

o

Low Income Rates

o

Merchant Function Charge (Uncollectibles Adj.)

o

90/10 Sharing (Large Customers)

Downstream

Utility: Shifting Trends in Customer Usage

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

Downstream

A Proven History of Controlling Costs

Downstream

Utility: Strong Commitment to Safety

The Utility remains focused on maintaining the

ongoing safety and reliability of its system

Near-term increase due

to ~$60MM upgrade of

the Utility’s Customer

Information System and

~$25MM NRG Dunkirk

power plant project

Appendix

Appendix

Natural Gas Hedge Positions

(1)

For

the

remaining

six

months

fiscal

2015.

(2)

Includes

new

50,000

Dth

per

day

firm

sales

contract

starting

May

2015

and

ending

March

31,

2017

$3.00

per

Dth

+/-

NYMEX

Henry

Hub

Dawn

differential.

Differential assumed to be $0.00 per Dth for presentation purposes.

(Volumes in thousands Mmbtu; Prices in $/Mmbtu)

Fiscal 2015

(1)

Fiscal 2016

Fiscal 2017

Fiscal 2018

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

NYMEX Swaps

28,920

$ 4.18

32,350

$ 4.24

23,130

$ 4.50

5,550

$4.59

Dominion

Swaps

12,420

$ 3.74

18,840

$3.78

12,720

$ 3.87

SoCal Swaps

600

$ 4.35

MichCon

Swaps

9,000

$ 4.10

3,000

$ 4.10

Dawn Swaps

5,490

$ 4.36

7,950

$ 4.14

Fixed Price

Physical

Sales

(2)

16,800

$ 3.42

36,600

$ 3.39

27,350

$ 3.51

1,550

$ 3.77

Total

58,740

$ 3.87

102,280

$ 3.84

74,150

$ 3.97

7,100

$ 4.41

Appendix

Crude Oil Hedge Positions

(1) For the remaining six months of fiscal 2015.

Fiscal 2015

(1)

Fiscal 2016

Fiscal 2017

Fiscal 2018

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Midway

Sunset

(MWSS)

Swaps

182,000

$68.62

36,000

$92.10

Brent

Swaps

510,000

$98.32

933,000

$95.18

384,000

$92.30

75,000

$91.00

NYMEX

Swaps

198,000

$90.14

300,000

$86.09

Total

890,000

$90.43

1,269,000

$92.95

384,000

$92.30

75,000

$91.00

(Volumes & Prices in Bbl)

Appendix

WDA Delineation Well Results

Area

Producing

Well Count

Peak 24-Hour

Rate (MMcfd)

Average

7-Day (MMcf/d)

Average Treatable

Lateral Length (ft)

Ridgway

Elk County

7.1

6.4

5,537’

Church Run

Elk & Jefferson

counties

4.8

4.5

4,690’

Hemlock

Elk County

5.4

5.2

7,067’

Owl’s Nest

Elk & Forest counties

6.1

5.8

6,137’

Sulger Farms

Jefferson County

6.1

5.6

5,778’

Appendix

Comparable GAAP Financial Measure Slides & 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

the

slides

that

follow.

The

Company

believes

that

its

non-GAAP

financial

measures

are

useful

investors

because

they

provide

alternative

method

for

assessing

the

Company’s

ongoing

operating

results,

for

measuring

the

Company’s

cash

flow

d liquidity,

and

for

comparing

the

Company’s

financial

performance

other

companies.

The

Company’s

management

uses

these

non-GAAP

financial

measures

for

the

same

purpose,

and

for

planning

and

forecasting

purposes.

The

presentation

non-GAAP

financial

measures

not

meant

substitute

for

financial

measures

prepared

accordance

with

GAAP.

The

Company

defines

Adjusted

EBITDA

reported

GAAP

earnings

before

the

following

items:

interest

expense,

depreciation,

depletion

and

amortization,

interest

and

other

income,

impairments,

items

impacting

comparability

and

income

taxes.

Appendix

National Fuel Gas Company

Reconciliation of Adjusted EBITDA to Consolidated Net Income

($ Thousands)

FY 2010

FY 2011

FY 2012

Exploration & Production - West Division Adjusted EBITDA

187,838

187,603

226,897

215,042

217,150

177,646

Exploration & Production - All Other Divisions Adjusted EBITDA

139,624

189,854

170,232

277,341

322,322

325,397

Total Exploration & Production Adjusted EBITDA

327,462

377,457

397,129

492,383

539,472

503,043

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

327,462

377,457

397,129

492,383

539,472

503,043

Pipeline & Storage Adjusted EBITDA

120,858

111,474

136,914

161,226

186,022

190,439

Gathering Adjusted EBITDA

2,021

9,386

14,814

29,777

64,060

74,546

Utility Adjusted EBITDA

167,328

168,540

159,986

171,669

164,643

167,970

Energy Marketing Adjusted EBITDA

13,573

13,178

5,945

6,963

10,335

11,686

Corporate & All Other Adjusted EBITDA

408

(12,346)

(10,674)

(9,920)

(11,078)

(11,440)

Total Adjusted EBITDA

631,650

667,689

704,114

852,098

953,454

936,244

Total Adjusted EBITDA

631,650

667,689

704,114

852,098

953,454

936,244

Minus: Interest Expense

(93,946)

(78,121)

(86,220)

(94,111)

(94,277)

(93,364)

Plus: Interest and Other Income

9,855

8,863

8,842

9,032

13,631

11,202

Minus: Income Tax Expense

(137,227)

(164,381)

(150,554)

(172,758)

(189,614)

(128,390)

Minus: Depreciation, Depletion & Amortization

(191,199)

(226,527)

(271,530)

(326,760)

(383,781)

(386,125)

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

(120,348)

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

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)

Plus: Reversal of Plugging and Abandonment Accrual (E&P)

4,140

Rounding

(1)

Consolidated Net Income

225,913

258,402

220,117

260,001

299,413

223,359

Consolidated Debt to Total Adjusted EBITDA

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

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

85,600

157,500

Total Debt (End of Period)

1,249,000

1,089,000

1,570,000

1,649,000

1,734,600

1,806,500

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

1,249,000

1,049,000

899,000

1,149,000

1,649,000

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

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)

1,249,000

1,089,000

1,570,000

1,649,000

Average Total Debt

1,249,000

1,169,000

1,329,500

1,609,500

1,691,800

1,727,750

Average Total Debt to Total Adjusted EBITDA

1.98 x

1.75 x

1.89 x

1.77 x

1.85 x

FY 2013

12-Months

Ended 3/31/15

FY 2014

Appendix

National Fuel Gas Company

Reconciliation of Segment Capital Expenditures to

Consolidated Capital Expenditures

($ Thousands)

FY 2015

FY 2016

FY 2010

FY 2011

FY 2012

FY 2013

FY 2014

Forecast

Capital Expenditures from Continuing Operations

Exploration & Production Capital Expenditures

398,174

648,815

693,810

533,129

602,705

$525,000-575,000

$400,000-475,000

Pipeline & Storage Capital Expenditures

37,894

129,206

144,167

56,144

139,821

$225,000-275,000

$500,000-550,000

Gathering Segment Capital Expenditures

6,538

17,021

80,012

54,792

137,799

$125,000-175,000

$100,000-125,000

Utility Capital Expenditures

57,973

58,398

58,284

71,970

88,810

$115,000-130,000

$75,000-100,000

Energy Marketing, Corporate & All Other Capital Expenditures

773

746

1,121

1,062

772

Total Capital Expenditures from Continuing Operations

501,352

854,186

977,394

717,097

969,907

$990,000-1,155,000

$1,075,000-1,250,000

Capital Expenditures from Discountinued Operations

All Other Capital Expenditures

150

Plus (Minus) Accrued Capital Expenditures

Exploration & Production FY 2014 Accrued Capital Expenditures

(80,108)

Exploration & Production FY 2013 Accrued Capital Expenditures

(58,478)

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

19,517

Pipeline & Storage FY 2014 Accrued Capital Expenditures

(28,122)

Pipeline & Storage FY 2013 Accrued Capital Expenditures

(5,633)

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

Gathering FY 2014 Accrued Capital Expenditures

(20,084)

Gathering FY 2013 Accrued Capital Expenditures

(6,700)

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

Utility FY 2014 Accrued Capital Expenditures

(8,315)

Utility FY 2013 Accrued Capital Expenditures

(10,328)

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

(58,401)

(39,908)

57,613

(13,636)

(55,490)

Eliminations

Total Capital Expenditures per Statement of Cash Flows

443,101

814,278

1,035,007

703,461

914,417

$990,000-1,155,000

$1,075,000-1,250,000