8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): January 14, 2014

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

New Jersey	1-3880	13-1086010
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

6363 Main Street, Williamsville, New York	14221
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (716) 857-7000

Former name or former address, if changed since last report: Not Applicable

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01 Regulation FD Disclosure.

National Fuel Gas Company (the “Company”) will participate in the BMO Capital Markets 11th Annual Unconventional Resource Conference in New York, New York on January 14, 2014. The Company also plans to hold meetings with certain industry analysts, money managers and other members of the financial community. A copy of materials to be presented by the Company during the conference and provided to participants in the Company’s meetings is furnished as part of this Current Report as Exhibit 99.

Neither the furnishing of the presentation as an exhibit to this Current Report nor the inclusion in such presentation of any reference to the Company’s internet address shall, under any circumstances, be deemed to incorporate the information available at such internet address into this Current Report. The information available at the Company’s internet address is not part of this Current Report or any other report filed or furnished by the Company with the Securities and Exchange Commission.

In addition to financial measures calculated in accordance with generally accepted accounting principles (“GAAP”), the presentation furnished as part of this Current Report as Exhibit 99 contains certain non-GAAP financial measures. The Company believes that such 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, 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 purposes, 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.

Certain statements contained herein or in the materials furnished as part of this Current Report, including statements regarding estimated future earnings and statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will” and “may” and similar expressions, are “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. There can be no assurance that the Company’s projections will in fact be achieved nor do these projections reflect any acquisitions or divestitures that may occur in the future. While the Company’s expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis, actual results may differ materially from those projected in forward-looking statements. Furthermore, each forward-looking statement speaks only as of the date on which it is made. In addition to other factors, the following are important factors that 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; 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 natural gas revenues and production, and 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. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit 99 Furnished presentation materials dated January 2014

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

NATIONAL FUEL GAS COMPANY
By:	/s/ James R. Peterson
	James R. Peterson
	Assistant Secretary

Dated: January 14, 2014

EXHIBIT INDEX

Exhibit Number	Description
99	Furnished presentation materials dated January 2014

EX-99

National Fuel Gas Company

Investor Presentation

January 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, 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; 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;

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;

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 natural gas revenues and production, and 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, 2013. The Company disclaims any obligation to update any forward-looking statements to reflect

events or circumstances after the date thereof or to reflect the

occurrence of unanticipated events.

National Fuel Gas Company

Exceptional Assets, Focused on Execution

3

1.549 Tcfe of Proved Reserves

(1)

800,000 Net Acres in Pennsylvania

2.8 MMBbl of Crude Oil Production

(2)

$191 Million of Midstream Adjusted EBITDA

(2)

(1)

As of September 30, 2013

(2)

Fiscal 2013

Gathering

Gathering is the First Step to Reaching a Market

4

TGP 300

Transco

Trout Run

Gathering System

(In-Service)

Covington

Gathering System

(In-Service)

Clermont

Gathering System

(Under Construction)

Gathering Interconnects

(In-Service

and

Under

Construction)

National Fuel Gas Company

Targeting Sustained Growth for the Next Five Years

5

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 Adjusts to Capitalize on Opportunities

6

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

7

Total Debt

(1)

43%

$3.843 Billion

As of September 30, 2013

Debt / Adjusted EBITDA

Capitalization

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

(1)

Long-Term Debt of $1.649 billion

National Fuel Gas Company

Dividend Track Record

8

Current

Dividend Yield

(1)

2.1%

Dividend Consistency

Consecutive Dividend Payments

111 Years

Consecutive Dividend Increases

43 Years

Current Annualized Dividend Rate

$1.50 per Share

(1) As of January 8, 2014

9

Exploration & Production

Overview

Seneca Resources

Proven Record of Growth

10

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

(1)

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

2013 F&D Cost = $1.31

Marcellus F&D: $0.99

Doubled Proved Reserves

Since 2010

71% Proved Developed

Seneca Resources

Delivering Tremendous Production Growth

11

Seneca Resources

Disciplined Capital Spending

12

(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

Marcellus Shale

Prolific Pennsylvania Acreage

13

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: ~85 MMcf per Day

34 Wells Drilled (52 Total Locations)

26 Wells Producing

DCNR Tract 100

Gross Production:  ~250 MMcf per Day

55 Wells Drilled (70 Total Locations)

36 Wells Producing

Gamble

Recently, 30 to 50 future

locations were added in

Lycoming County

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

5.7

4,023’

1.42

Tract 595

Tioga

County

26

7.1

6.0

5.1

8.4

4,639’

1.81

Tract 100

Lycoming

County

30

16.1

14.2

11.9

11.5

5,210’

2.21

Seneca is the industry leader in Lycoming County

Seneca’s Operations

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

Seneca Acreage

Huge Position –

Varies in Understanding

17

Northeast Core

~30,000 acres in NE Core

Tier I Acres

~200,000 acres

Economic at $2.80 to $3.80/Mcfe

Awaiting Evaluation

~250,000 acres

Requires Gas Price Above $4/Mcf

~300,000 acres

Understanding Seneca’s

780,000 Net Acres

SRC Lease Acreage

SRC Fee Acreage

EOG Earned JV Acreage

Marcellus Shale

2013 & 2014 WDA Delineation Program

18

Owl’s Nest –

Delineating

2 High Btu Wells Completed

Rich Valley –

Full Development

2 Wells Completed

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

2  

Well 7-Day IP: 4.5 MMcf/d

Tionesta –

Delineating

1 Well Completed

Ridgway –

Delineating

1 Well Completed

2013 Drill Program

Seneca Operated

Heath –

Delineating

1 Well Planned

Sulger Farms –

Delineating

1 Well Planned

Hemlock –

Delineating

1 Well Planned

2014 Drill Program

Church Run –

Delineating

1 Well Completed

Clermont –

Full Development

2 Wells Completed

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

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

nd

Marcellus Shale

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

Rich Valley 27H

RCS

6,372’

42

8.1

7.8

7.4

Producing

Clermont 9H

RCS

5,500’

37

11.4

10.0

8.6

Producing

Clermont 10H

Non-RCS

5,565’

23

8.1

7.3

6.6

Producing

Ridgway 19H

RCS

5,537’

37

7.1

6.4

5-8

Flowback

Test

Church Run 2H

RCS

4,435’

29

4.8

4.5

4-6

Flowback

Test

Owl’s Nest 54H

RCS

6,139’

41

6.1

5.8

4-7

Flowback

Test

Owl’s Nest 59H

RCS; Gel

5,371’

36

3.4

3.1

2-4

Flowback

Test

(1)

RCS –

Reduced Cluster Spacing

(2)

Completed using linear gel to place larger proppant near the wellbore

1

2

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’

Large casing: 5.5”

Increased pump rates

9H (RCS): 150’

spacing

10H (Standard): 240’

spacing

Soaked both wells: 30 Days

Marcellus Shale

Rich Valley/Clermont is in Full Development Mode

21

Marcellus Shale

200,000 Acres With 6-8 Bcfe EUR Wells

22

Note: Assumes 6,000’

treated lateral length

Marcellus Shale

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

23

Prospect

County

Product

Approx.

Remaining

Locations

EUR

(Bcfe)

BTU

IRR

(1)

@

$4/MMBtu

15% IRR

(1)

Breakeven Price

($/Mcf)

Tract 100

Lycoming

Dry Gas

40

11.5

1,030

90%

$2.20

Gamble

Lycoming

Dry Gas

29

10-11

1,030

77%

$2.33

Tract 595

Tioga

Dry Gas

20

8.4

1,030

45%

$2.63

Clermont/Rich Valley

Elk/Cameron

Dry Gas

228

6-8

1,050

38%

$2.80

Ridgway

Elk

Dry Gas

450-570

6-8

1,111

26%

$3.30

Hemlock

Elk

Dry Gas

130-170

6-8

1,070

23%

$3.40

Church Run

Elk

Dry Gas

60-70

6-8

1,125

22%

$3.45

(W) West Branch

McKean

Dry Gas

47

6-8

1,050

22%

$3.48

Covington

Tioga

Dry Gas

Developed

5.7

1,030

22%

$3.49

Heath

Jefferson

Dry Gas

260-330

5-8

1,060

19%

$3.65

Sulger Farms

Jefferson

Dry Gas

170-210

5-8

1,020

19%

$3.66

Owl’s Nest/James City

Elk/Forest

Dry Gas

120-160

5-8

1,125

18%

$3.69

Boone Mt.

Elk

Dry Gas

230-290

4-6

1,020

18%

$3.76

Church Run

Elk

Wet Gas

40-50

2-4

1,140

13%

$4.32

Tionesta

Forest/Venango

Wet Gas/

Liquids

300-340

4-6

1,325

12%

$4.50

Owl’s Nest/James City

Elk/Forest

Wet Gas

150-180

4-6

1,140

11%

$4.51

Mt. Jewett

McKean

Wet Gas

90-110

2-4

1,140

6%

$5.50

Beechwood

Cameron

Dry Gas

210-280

2-4

1,030

2%

$7.14

Red Hill

Cameron

Dry Gas

150-200

2-4

1,030

2%

$7.14

2013 Appraisal prospects

2014 Appraisal prospects

(1)

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

Point Pleasant & Utica Shale

Continuing to Delineate

24

California

Stable Production Fields; Modest Growth Potential

25

East Coalinga

Temblor Formation

Primary

North Lost Hills

Tulare & Etchegoin Formation

Primary/Steamflood

South Lost Hills

Monterey Shale

Primary

North

Midway

Sunset

Tulare

&

Potter

Formation

Steamflood

South Midway Sunset

Antelope Formation

Steamflood

Sespe

Sespe Formation

Primary

Key Areas of Focus in 2014

1.

East Coalinga Evaluation

2.

South Midway Sunset Extensions

3.

Sespe Coldwater Evaluation

California

Outstanding Cash Flow

(1)

26

(1)

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

California

Looking Forward

27

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

California

South Midway Sunset Has Delivered Significant Growth

28

Highlights Since Acquisition

Increased daily production by 130%

Drilled 80 new producers

Added 3.3 MMBO of proven reserves

Increased steam capacity by 280%

Identified opportunities for additional

pool development

California

South MWSS Growth Opportunities Continue into 2014

29

California

Early Success in Farm-In with Chevron at East Coalinga

30

Highlights Since Acquisition

Achieved highest field production in 10

years

Production increased 130% since 1/2013

Drilled 12 evaluation wells that confirmed

downspacing potential

Returned 40 idle wells back to production

California

Ongoing Evaluation of Long-Term Sespe Potential

31

California

Limited Growth Opportunities, But Strong Economics

32

Field

Average

Well Cost

Average

EUR

(MBO)

Estimated

IRR

@$100/Bbl

Fiscal 2014

Locations

South Midway Sunset

$250,000

30

75%

23

East Coalinga

$400,000

40

50%

30

Sespe –

5 Acre Infill

$2,800,000

150

25%

0

Sespe -

Coldwater

$2,800,000

180

35%

4

California

Modest Growth Anticipated in 2014 and 2015

33

Mississippian Lime

Commencing Evaluation Program in Fiscal 2014

34

Total Net Acres: 13,615

100% working interest in 4,400 

gross acres

55% net working interest in

17,365 gross acres

Negotiated an increase in Seneca’s

working interest and have taken

over as operator

Currently drilling second well

Will drill up to 5 evaluation wells in

2014

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

goal of maintaining a significant contribution from oil-producing properties

Unit

30-day IP:

352 BOED

(92% Oil/NGLs)

Hedging Overview

How Does Seneca Sell its Production?

35

Well Head

Interconnection

with Interstate

Pipeline Network

Gathering

System

3rd Party

Marketer

(or spot market)

Firm Transport

Demand Center

(firm sales or

spot market)

Contracted Basis

Differential

FT Rate

The 1,700 to 2,000 economic locations

at less than $4.00/Mcf are based on a

realized price after gathering

Spot Market

Hedging Overview

Firm Sales Provide a Market for Appalachian Production

36

Prices shown represent the sales (netback

price) at the first non-affiliated interstate

pipeline, including the cost of all related

downstream transportation.

(1)

Long-term firm sales represent gross volumes

36

Hedging Overview

Current Natural Gas Hedge Positions

37

Hedging Overview

Current Hedge Book has Seneca Positioned Very Well

38

(1)

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

Natural Gas

$4.27/Mcf

$4.27/Mcf

$4.33/Mcf

$4.44/Mcf

$4.81/Mcf

Crude Oil

$100.22/Bbl

$95.90/Bbl

$92.97/Bbl

$92.30/Bbl

$91.00/Bbl

Hedging Overview

FY 2014 Production –

Firm Sales & Hedge Composition

39

Price Certainty

Hedge Price -

Firm

Sales Differential

Seneca has an additional 19.7 Bcf of

NYMEX hedges to help mitigate

commodity exposure on its sales

Price Certainty

Hedge Price -

Firm

Sales Differential

Seneca Resources

What Will Seneca Look Like Moving Forward?

40

Consistent Production Growth: 15-25% CAGR

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

Maintain

Oil

Production

Expand

When

Possible

Excellent operator and significant cash flow generation

Disciplined Spending Driven by Rates of Return

Pace of development adapts to changing market dynamics

A Leader in Technology, Safety & Environmental Responsibility

Maintain a leadership role in using technology and developing best practices

41

Midstream Businesses

Overview

Midstream Businesses

Positioned to Serve Seneca’s Rapidly Growing Production

42

Gathering

Existing Systems Supporting Seneca’s Near-Term Growth

43

Covington Gathering System

In-service date: November 2009

Capacity: 220,000 Dth per day

Interconnect: TGP 300

Capital expenditures (to date): $28.3 million

Capital expenditures (future): $7.5 million

Trout Run Gathering System

In-service date: May 2012

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

Interconnect: Transco –

Leidy Lateral

Capital expenditures (to date): $128.0 million

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

Gathering

Clermont Gathering System has Large Expandability

44

Clermont Gathering

System

In-Service: Ongoing build-out

Ultimate Trunkline Capacity:

700 to 1,000 MMcf per day

Interconnects

TGP 300 and National Fuel

Gas Supply Corporation

(anticipated)

Capital:

2014: $60 -

$92 million

2015: $75 -

$125 million

Seneca Pads Connected

Up to 25 pads connected

following the 2015

expansion

Gathering

Capital Deployment Will Deliver Long-Term Growth

45

Revenue Growth (2013 to 2015): ~60%

CAGR

Capital Investment (2013 to 2015): ~60%

CAGR

Pipeline & Storage

Project Opportunities to Support WDA Growth

46

Pipeline & Storage

Northeast PA Spot Markets are Heavily Discounted

47

Pipeline & Storage

Expansions to Move Gas from the WDA are Significant

48

Projects to Support WDA Growth

Project

Capacity (Dth/day)

Northern Access 2015

140,000

Clermont to Chippawa

250,000+

Clermont to Transco

300,000-500,000

Total New Capacity

690,000-890,000+

Project

Capital Cost

Northern Access 2015

$67 million

Clermont to Chippawa

$250 million

Clermont to Transco

$100-$150 million

Total Capital

Expenditures

$417-$467 million

Northern

Access 2015

(November 2015)

Clermont to

Chippawa

(2016)

Longer-Term

WDA Expansion

(2016)

Clermont

Pipeline & Storage

Recent 3

rd

Party Expansions Have Been Highly Successful

49

Expansions for 3

rd

Parties

Project

Capacity

(Dth/day)

Northern Access 2013

320,000

Tioga County Extension

350,000

Line N (2011, 2012 & 2013)

353,000

Total New Capacity

1,023,000

Project

Capital Cost

Northern Access 2013

$72 million

Tioga County Extension

$58 million

Line N (2011, 2012 & 2013)

$104 million

Total Capital Expenditures

$234 million

Northern

Access 2013

Tioga

County

Extension

Line N Projects

Pipeline & Storage

Additional Line N Expansions Planned for the Future

50

In-Service: November 2014

System: NFG Supply Corp.

Capacity: 105,000 Dth per day

Precedent agreements signed for all

available capacity

Interconnect

Mercer (TGP Station 219)

Total Cost: $30 Million

Expansion: $27 million

System Modernization: $3 million

Major Facilities

3,500 HP Compressor

2.1 miles –

24”

Replacement Pipeline

Mercer Expansion

Mercer

(TGP Station 219)

Mercer

Expansion

Mercer

(TGP Station 219)

Pipeline & Storage

Pairing Line N Expansions with System Modernization

51

In-Service: November 2015

System: NFG Supply Corp.

Capacity: 175,000 Dth per day

Precedent agreements signed for

145,000 Dth per day

Interconnect

Mercer (TGP Station 219)

Holbrook (TETCO)

Total Cost: $74 Million

Expansion: $39 million

System Modernization: $35 million

Major Facilities

3,600 HP Compressor

23.5 miles –

24”

Replacement Pipeline

Westside Expansion &

Modernization

Holbrook (TETCO)

Westside

Expansion &

Modernization

Pipeline & Storage

Developing Unique Solutions for Shippers

52

In-Service: November 2015

System: NFG Supply & Empire Pipeline

New No-Notice Services

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

Preserving 20,000 Dth per day (NYSEG)

Precedent agreement executed with

RG&E

Capacity

Transportation: 69,000 Dth per day

Retained Storage: 3.3 Bcf

Interconnect

Tuscarora (NFG/Supply)

Total Cost: $56 Million

Major Facilities

1,500 HP Compressor

18 miles –

20”

Replacement Pipeline

Tuscarora Lateral

Tuscarora

Lateral

Pipeline & Storage

Significant Expansions Are Driving Growth

53

Completed Projects (Since 2009)

Recent Capacity Additions

1,113,000

Line N Corridor

Line “N”

Expansion

Line “N”

2012 Expansion

Line “N”

2013 Expansion

Mercer Expansion

West Side Expansion

Total Capacity

603 MDth/d

Delivering Gas North

Tioga County Extension

Northern Access

Northern Access 2015

Clermont to Chippawa

Total Capacity

1,060 MDth/d

Leaving the WDA

Lamont Compressor

Clermont to Transco

Total Capacity

390 to 590 MDth/d

Planned Projects (2014 -2015)

Planned Capacity Additions

459,000

Potential Projects (2016+)

Potential Capacity Additions

550,000

to

750,000

Total (2009-2016+)

Capacity Additions

2,122,000

to

2,322,000

Pipeline & Storage

Expansion Project Revenue Growth

54

Larger

projects

under

consideration

for

fiscal

2016

and

2017

will

drive

significant

revenue

growth

55

Utility

Overview

Utility

New York & Pennsylvania Service Territories

56

Total Customers: 522,000

Rate Mechanisms:

Revenue Decoupling

Weather Normalization

Low Income Rates

Choice Program/Purchase of Receivables

Merchant Function Charge

(Uncollectibles Adjustment)

90/10 Sharing (Large Customers)

Natural Gas Vehicle Pilot Program

ROE: 9.1% (Litigated -

2007)

Total Customers: 213,000

Rate Mechanisms:

Low Income Rates

Choice Program/Purchase of Receivables

Merchant Function Charge

ROE: Black Box Settlement (2007)

New York

Pennsylvania

Utility

Customer Usage

57

Residential Usage

Industrial Usage

(1)

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

Utility

Continued Cost Control Helps Provide Earnings Stability

58

Utility

Capital Spending Largely Focused on Maintenance

59

The Utility remains focused

on spending to maintain

the ongoing safety and

reliability of its system

Utility

Achieved a Settlement in New York

60

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

On December 6, 2013 a Joint Proposal

between National Fuel and other parties

was filed with the NYPSC.  This agreement

proposes to settle all outstanding issues

with the following key components:

May 8, 2013

Company responds to

OTSC

June 14, 2013

“Temporary rates”

become effective

July 26, 2013

Settlement discussions

commence for

permanent rates

Two-year rate plan effective 10/1/13

ROE: 9.1% (48% Equity Component)

Earnings Sharing Mechanism

National Fuel Gas Company

A History of Success & A Future of Opportunity

61

30% CAGR

Since 2009

Adjusted

EBITDA

Growth

Production

Growth

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. 

62

Appendix

National Fuel Gas Company

Current Hedge Positions

63

Fiscal

Year

NYMEX

Volume

(Bcf)

Average

Price

($/Mcf)

Dominion

Volume

(Bcf)

Average

Price

($/Mcf)

SoCal

Volume

(Bcf)

Average

SoCal

Price

Total

Volume

(Bcf)

Average

Price

($/Mcf)

2014

74.7

$4.26

27.4

$4.26

1.1

$4.57

103.3

$4.27

2015

58.9

$4.32

17.8

$4.07

1.1

$4.57

77.9

$4.27

2016

35.7

$4.46

17.9

$4.07

-

-

53.6

$4.33

2017

23.8

$4.71

17.9

$4.07

-

-

41.7

$4.44

2018

5.3

$4.81

-

-

-

-

5.3

$4.81

Natural Gas Hedges

Fiscal

Year

MWSS

Volume

(MMBbl)

Average

Price

($/Bbl)

Brent

Volume

(MMBbl)

Average

Price

($/Bbl)

NYMEX

Volume

(MMBbl)

Average

Price

($/Bbl)

Total

Volume

(MMBbl)

Average

Price

($/Bbl)

2014

0.624

$95.68

1.344

$102.32

-

-

1.968

$100.22

2015

-

-

0.903

$98.42

0.396

$90.14

1.299

$95.90

2016

-

-

0.933

$95.18

0.300

$86.09

1.233

$92.97

2017

-

-

0.384

$92.30

-

-

0.384

$92.30

2018

-

-

0.075

$91.00

-

-

0.075

$91.00

Crude Oil Hedges

National Fuel Gas Company

Comparable GAAP Financial Measure Slides and Reconciliations

64

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.

65

Reconciliation of Exploration & Production West Division Adjusted EBITDA

to Exploration & Production Segment Net Income

($ Thousands)

FY 2013

Exploration & Production - West Division Adjusted EBITDA

215,042

$        

Exploration & Production - All Other Divisions Adjusted EBITDA

277,341

Total Exploration & Production Adjusted EBITDA

492,383

$        

Minus: Exploration & Production Net Interest Expense

(38,244)

Minus: Exploration & Production Income Tax Expense

(95,317)

Minus: Exploration & Production Depreciation, Depletion & Amortization

(243,431)

Exploration & Production Net Income

115,391

$        

Exploration & Production Net Income

115,391

$        

Pipeline & Storage Net Income

63,245

Gathering Net Income

13,321

Utility Net Income

65,686

Energy Marketing Net Income

4,589

Corporate & All Other Net Income

(2,231)

Consolidated Net Income

260,001

$     

66

Reconciliation of Adjusted EBITDA to Consolidated Net Income

($ Thousands)

FY 2009

FY 2010

FY 2011

FY 2012

Exploration & Production - West Division Adjusted EBITDA

171,572

$           

187,838

$           

187,603

$           

226,897

$           

215,042

$              

Exploration & Production - East Division Adjusted EBITDA

57,179

$             

75,098

$             

175,392

$           

167,806

$           

283,509

$              

Exploration & Production - All Other Divisions Adjusted EBITDA

50,960

64,526

14,462

2,426

(6,168)

Total Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

492,383

$              

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

492,383

$              

Pipeline & Storage Adjusted EBITDA

130,857

120,858

111,474

136,914

161,226

Gathering Adjusted EBITDA

(141)

2,021

9,386

14,814

29,777

Utility Adjusted EBITDA

164,443

167,328

168,540

159,986

171,669

Energy Marketing Adjusted EBITDA

11,589

13,573

13,178

5,945

6,963

Corporate & All Other Adjusted EBITDA

(5,434)

408

(12,346)

(10,674)

(9,920)

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

852,098

$              

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

852,098

$              

Minus: Net Interest Expense

(81,013)

(90,217)

(75,205)

(82,551)

(89,776)

Plus:  Other Income

9,762

6,126

5,947

5,133

4,697

Minus: Income Tax Expense

(52,859)

(137,227)

(164,381)

(150,554)

(172,758)

Minus: Depreciation, Depletion & Amortization

(170,620)

(191,199)

(226,527)

(271,530)

(326,760)

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

(182,811)

-

-

-

-

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

(2,776)

6,780

-

-

-

Plus: Gain on Sale of Unconsolidated Subsidiaries (Corp. & All Other)

-

-

50,879

-

-

Plus: Elimination of Other Post-Retirement Regulatory Liability (P&S)

-

-

-

21,672

-

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

-

-

-

(6,206)

-

Minus: New York Regulatory Adjustment (Utility)

-

-

-

-

(7,500)

Rounding

-

-

-

(1)

-

Consolidated Net Income

100,708

$           

225,913

$           

258,402

$           

220,076

$           

260,001

$              

Consolidated Debt to Total Adjusted EBITDA

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

1,249,000

$        

1,049,000

$        

899,000

$           

1,149,000

$        

1,649,000

$          

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

-

200,000

150,000

250,000

-

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

-

-

40,000

171,000

-

Total Debt (End of Period)

1,249,000

$     

1,249,000

$     

1,089,000

$     

1,570,000

$     

1,649,000

$       

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

999,000

1,249,000

1,049,000

899,000

1,149,000

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

100,000

-

200,000

150,000

250,000

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

-

-

-

40,000

171,000

Total Debt (Start of Period)

1,099,000

$     

1,249,000

$     

1,249,000

$     

1,089,000

$     

1,570,000

$       

Average Total Debt

1,174,000

$     

1,249,000

$     

1,169,000

$     

1,329,500

$     

1,609,500

$       

Average Total Debt to Total Adjusted EBITDA

2.02

1.98

1.75

1.89

1.89

FY 2013

67

Reconciliation of Segment Capital Expenditures to

Consolidated Capital Expenditures

($ Thousands)

FY 2014

FY 2009

FY 2010

FY 2011

FY 2012

FY 2013

Forecast

Capital Expenditures from Continuing Operations

Exploration & Production Capital Expenditures

188,290

$  

398,174

$        

648,815

$        

693,810

$        

533,129

$        

$550,000-650,000

Pipeline & Storage Capital Expenditures

52,504

37,894

129,206

144,167

56,144

$          

$115,000-135,000

Gathering Segment Capital Expenditures

9,433

6,538

17,021

80,012

54,792

$          

$100,000-150,000

Utility Capital Expenditures

56,178

57,973

58,398

58,284

71,970

$          

$80,000-90,000

Energy Marketing, Corporate & All Other Capital Expenditures

396

773

746

1,121

1,062

$            

-

Total Capital Expenditures from Continuing Operations

306,801

$  

501,352

$        

854,186

$        

977,394

$        

717,097

$        

$845,000-1,025,000

Capital Expenditures from Discountinued Operations

All Other Capital Expenditures

216

150

$                

-

$                  

-

$                  

-

$                  

-

$                                 

Plus (Minus) Accrued Capital Expenditures

Exploration & Production FY 2013 Accrued Capital Expenditures

-

$           

-

$                  

-

$                  

-

$                  

(58,478)

$         

-

$                                 

Exploration & Production FY 2012 Accrued Capital Expenditures

-

-

-

(38,861)

38,861

-

Exploration & Production FY 2011 Accrued Capital Expenditures

-

-

(103,287)

103,287

-

-

Exploration & Production FY 2010 Accrued Capital Expenditures

-

(78,633)

78,633

-

-

-

Exploration & Production FY 2009 Accrued Capital Expenditures

(9,093)

19,517

-

-

-

-

Pipeline & Storage FY 2013 Accrued Capital Expenditures

-

-

-

-

(5,633)

-

Pipeline & Storage FY 2012 Accrued Capital Expenditures

-

-

-

(12,699)

12,699

-

Pipeline & Storage FY 2011 Accrued Capital Expenditures

-

-

(16,431)

16,431

-

-

Pipeline & Storage FY 2010 Accrued Capital Expenditures

-

-

3,681

-

-

-

Pipeline & Storage FY 2008 Accrued Capital Expenditures

16,768

-

-

-

-

-

Gathering FY 2013 Accrued Capital Expenditures

-

-

-

-

(6,700)

-

Gathering FY 2012 Accrued Capital Expenditures

-

-

-

(12,690)

12,690

-

Gathering FY 2011 Accrued Capital Expenditures

-

-

(3,079)

3,079

-

-

Gathering FY 2009 Accrued Capital Expenditures

(715)

715

-

-

-

-

Utility FY 2013 Accrued Capital Expenditures

-

-

-

-

(10,328)

-

Utility FY 2012 Accrued Capital Expenditures

-

-

-

(3,253)

3,253

-

Utility FY 2011 Accrued Capital Expenditures

-

-

(2,319)

2,319

-

-

Utility FY 2010 Accrued Capital Expenditures

-

-

2,894

-

-

-

Total Accrued Capital Expenditures

6,960

$       

(58,401)

$         

(39,908)

$         

57,613

$          

(13,636)

$         

-

$                                 

Eliminations

(344)

$         

-

$                  

-

$                  

-

$                  

-

$                  

-

$                                 

Total Capital Expenditures per Statement of Cash Flows

313,633

$  

443,101

$        

814,278

$        

1,035,007

$    

703,461

$        

$845,000-1,025,000