EX-99 2 d671900dex99.htm EX-99 EX-99
National Fuel Gas Company
Investor Presentation
February 2014
Exhibit 99

National Fuel Gas Company
Safe Harbor For Forward Looking Statements
2
This presentation may contain “forward-looking statements”
as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects,
plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated
capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules,
and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words
“anticipates,”
“estimates,”
“expects,”
“forecasts,”
“intends,”
“plans,”
“predicts,”
“projects,”
“believes,”
“seeks,”
“will,”
“may,”
and similar expressions.  Forward-looking statements involve risks and uncertainties which could
cause actual results or outcomes to differ materially from those
expressed in the forward-looking statements.  The Company’s expectations, beliefs and projections are expressed
in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be
achieved or accomplished.
In addition to other factors, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the
forward-looking statements:  factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including
among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations,
insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations;
changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives,
taxes, safety, employment, climate change, other
environmental matters, real property, and exploration and production activities such as hydraulic fracturing; governmental/regulatory actions, initiatives and proceedings,
including those involving rate cases (which address, among other
things, 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; changes in price
differentials between similar quantities of natural gas
or oil sold at different geographic locations, and the effect of
such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such
locations; other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date;
impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;  uncertainty of oil and gas reserve estimates; significant differences between the Company’s
projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment
of derivative financial instruments; delays or changes in costs or plans with respect to Company projects or related projects of
other companies, including difficulties or delays in
obtaining necessary governmental approvals, permits or orders or
in obtaining the cooperation of interconnecting facility operators; financial and economic conditions, including
the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments,
including any downgrades in the Company’s credit ratings and changes in interest rates and other capital
market conditions; changes in economic conditions, including global,
national or regional recessions, and their effect on the demand for, and customers’
ability to pay for, the Company’s products and services;  the creditworthiness or performance
of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters,
terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses;
changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits,
which can affect future funding obligations and costs and plan liabilities; the cost and effects of legal and administrative claims against the Company or activist shareholder
campaigns to effect changes at the Company; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-
retirement benefits;
or increasing costs of insurance, changes in coverage and the ability to obtain insurance.
Forward-looking statements include estimates of oil and gas quantities.
Proved oil and gas reserves are those quantities of oil and gas
which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. 
Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates
of proved reserves.  Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely
the disclosure in our Form 10-K available at www.nationalfuelgas.com.
You can also obtain this form on the SEC’s website at www.sec.gov.
For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see
“Risk Factors”
in the Company’s Form 10-K for the fiscal year ended September 30, 2013 and the Form 10-Q for the quarter ended December 31, 2013. The Company disclaims
any
obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events.

National Fuel Gas Company
Exceptional Assets, Focused on Execution
3
1.549 Tcfe of Proved Reserves
(1)
800,000 Net Acres in Pennsylvania
2.8 MMBbl of Crude Oil Production
(2)
$208 Million of Midstream Adjusted EBITDA
(2)
(1)
As of September 30, 2013
(2)
12 months ended December 31, 2013

National Fuel Gas Company
Targeting Sustained Growth for the Next Five Years
4
Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this presentation.
2014 –
2018
10-15%
Forecasted
Adjusted EBITDA
CAGR

National Fuel Gas Company
Capital Spending Adjusts to Capitalize on Opportunities
5
Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.
(1)
Does not include the $34.9 MM Seneca Resources Corporation’s acquisition of Ivanhoe’s U.S.-based assets in California, as this was accounted for as an investment in subsidiaries on the
Statement
of
Cash
Flows,
and
was
not
includedin
the
Exploration
&
Production
segment’s
Capital
Expenditures

National Fuel Gas Company
Maintaining a Strong Balance Sheet
6
Total Debt
(1)
42%
$3.900 Billion
As of December 31, 2013
Debt / Adjusted EBITDA
Capitalization
Note:  A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation
(1)
Long-Term Debt of $1.649 billion

National Fuel Gas Company
Dividend Track Record
7
Current
Dividend Yield
(1)
2.0%
(1) As of January 28, 2014

8
Exploration & Production
Overview

Seneca Resources
Proven Record of Growth
9
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
10

Seneca Resources
Disciplined Capital Spending
11
(1)
Does not include the $34.9 MM acquisition of Ivanhoe’s U.S.-based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not
included in Capital Expenditures

Seneca Resources
LOE: Operating Costs Down; Transportation Costs Up
12
(1)
Represents the midpoint of current General & Administrative Expense guidance of $0.40 to $0.45 per Mcfe for fiscal 2014
(2)
The total of the two Lease Operating Expense components represents the midpoint of current Lease Operating Expense guidance of $0.90 to $1.10 per Mcfe for fiscal 2014

Marcellus Shale
Prolific Pennsylvania Acreage
13

Marcellus Shale
EDA Delivering Significant Growth
14
Covington –
Fully Developed
Gross Production: ~45 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:  ~240 MMcf per Day
57 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
5.8
4,023’
1.44
Tract 595
Tioga
County
32
7.4
6.1
5.1
8.1
4,736’
1.72
Tract 100
Lycoming
County
30
(1)
16.1
14.2
11.9
11.5
5,210’
2.21
Seneca is the industry leader in Lycoming County
(1)
6
wells
currently
producing
in
Tract
100
in
Lycoming
County,
Pa.
have
been
producing
less
than
30
days
and
have
been
excluded
from
this
table.

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
Seneca Lease
Seneca Fee
Tier I
~200,000 Acres
Northeast Core
~30,000 acres in NE Core
Tier I Acres
~200,000 acres
Economic at $2.80 to $3.80/Mcfe
Longer-Term Evaluation
~250,000 acres
(Minimal Lease Expiration)
Requires Gas Price Above $4/Mcf
~300,000 acres
Understanding Seneca’s
780,000 Net Acres

Marcellus Shale
2013 & 2014 WDA Delineation Program
18

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
RCS¹
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; Gel²
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

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
(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; 1 to 2 Wells Planned in FY2014
24
Permitted
Drilled/Drilling
Completed
Producing
Mt. Jewett
Horizontal: completed September 2013
Peak 24-Hour Rate: 8.5 MMcf/d
Tionesta
Horizontal: Completed Fall 2012
Peak 24-Hour Rate: 3.9 MMcf/d
Rex
9.2 MMcf/d
Chesapeake
6.4 MMcf/d
Range Resources
4.4 MMcf/d
Range Resources
1.4 MMcf/d
“Not Effectively Stimulated”
Halcon
6.6 MMcf/d,
750 Bbls/d
Halcon
2.5 MMcf/d,
360 Bbls/d
Halcon
4.5 MMcf/d,
860 Bbls/d
Eastern Ohio
Point Pleasant Core
Point Pleasant
Northern Boundary

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
Year
Target
# of
Wells
Average IP
(BOEPD)
2011
Sespe (5-Acre Infill)
2
75
2011
Sespe (10-Acre)
3
90
2012
Sespe (5-Acre Infill)
2
70
2012
Coldwater
2
125
2012
Sespe (10 Acre)
2
110
2013
Sespe (5-Acre Infill)
2
55
2013
Coldwater
2
130
2013
Sespe (10 Acre)
2
85

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

Hedging Overview
How Does Seneca Sell its Production?
35
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
1
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
Dominion
105,000
Less: $0.26
Dominion
142,143
Less: $0.44
Dominion
95,000
Less: $0.43
NYMEX
202,745
Less: $0.28
NYMEX
189,091
Less: $0.45
NYMEX
180,000
Less: $0.37
Fixed Price
14,000
$3.18/MMBtu
321,745
331,234
290,000
0
100,000
200,000
300,000
400,000
500,000
Fiscal 2014                         
2nd Quarter
Summer  2014                          
(April -
October)
Other
Fixed Price Sale
NYMEX
Dominion South Point
(November -
March)
Winter 2014/2015

Hedging Overview
Current Natural Gas Hedge Positions
37
(1)
2014 hedge positions are for the remaining nine months of the fiscal year

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
80%
65%
43%
43%
41%
24%
13%
15%
3%
2%
100%
80%
60%
40%
20%
0%
Hedging Policy Range
Oil Hedges
Natural Gas Hedges
Fiscal
2014
Fiscal
2015
Fiscal
2016
Fiscal
2017
Fiscal
2018

Hedging Overview
FY 2014 Production –
Firm Sales & Hedge Composition
39
Seneca has an additional ~17.5 Bcf of
NYMEX hedges to help mitigate
commodity exposure on its sales

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
Gathering is the First Step to Reaching a Market
43

Gathering
Existing Systems Supporting Seneca’s Near-Term Growth
44
Covington Gathering System
In-service date: November 2009
Capacity: 220,000 Dth per day
Interconnect: TGP 300
Capital expenditures (to date): $28.3 million
Capital expenditures (future): $7.5 million
Trout Run Gathering System
In-service date: May 2012
Capacity: 466,000 to 585,000 Dth per day
Interconnect: Transco –
Leidy Lateral
Capital expenditures (to date): $137 million
Capital expenditures (future): $60 to $90 million

Gathering
Clermont Gathering System has Large Expandability
45
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
46

Pipeline & Storage
Project Opportunities to Support WDA Growth
47
Develop multiple outlets
to high-value markets

Pipeline & Storage
Northeast PA Spot Markets are Heavily Discounted
48

Pipeline & Storage
Expansions to Move Gas from the WDA are Significant
49
Projects to Support WDA Growth
Project
Capacity (Dth/day)
Northern Access 2015
140,000
Clermont to Chippawa
350,000
Total New Capacity
490,000
Project
Capital Cost
Northern Access 2015
$67 million
Clermont to Chippawa
$360 million
Total Capital
Expenditures
$427 million

Pipeline & Storage
Recent 3
rd
Party Expansions Have Been Highly Successful
50
Completed Expansions
for 3
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
rd

Pipeline & Storage
Additional Line N Expansions Planned for the Future
51
In-Service: November 2014
System: NFG Supply Corp.
Capacity: 105,000 Dth per day
Precedent agreements signed for all
available capacity
Interconnect
Mercer (TGP Station 219)
Total Cost: $34 Million
Expansion: $30 million
System Modernization: $4 million
Major Facilities
3,550 HP Compressor
2.1 miles –
24”
Replacement Pipeline
Mercer Expansion
Mercer
(TGP Station 219)
Mercer
Expansion

Mercer
(TGP Station 219)
Pipeline & Storage
Pairing Line N Expansions with System Modernization
52
In-Service: November 2015
System: NFG Supply Corp.
Capacity: 175,000 Dth per day
Precedent agreements signed for all
available capacity
Interconnect
Mercer (TGP Station 219)
Holbrook (TETCO)
Total Cost: $76 Million
Expansion: $39 million
System Modernization: $37 million
Major Facilities
3,550 HP Compressor
23.3 miles –
24”
Replacement Pipeline
Westside Expansion &
Modernization
Holbrook (TETCO)
Westside
Expansion &
Modernization

Pipeline & Storage
Developing Unique Solutions for Shippers
53
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: $45 Million
Major Facilities
1,500 HP Compressor
17 miles –
12”
Replacement Pipeline
Tuscarora Lateral
Tuscarora
Lateral

Pipeline & Storage
Significant Expansions Are Driving Growth
54
Completed Projects (Since 2009)
Recent Capacity Additions
1,113,000
Dth/day
Line N Corridor
Line “N”
Expansion
Line “N”
2012 Expansion
Line “N”
2013 Expansion
Mercer Expansion
West Side Expansion
Total Capacity
633 MDth/d
Delivering Gas North
Tioga County Extension
Northern Access
Northern Access 2015
Clermont to Chippawa
Total Capacity
1,160 MDth/d
Leaving the WDA
Lamont Compressor
Tuscarora Lateral
Total Capacity
159 MDth/d
Planned Projects (2014 -2015)
Precedent Agreements Executed
Planned Capacity Additions
489,000
Dth/day
Potential Projects (2016+)
Currently Evaluating
Potential Capacity Additions
350,000
Dth/day
Total (2009-2016+)
Capacity Additions
1,952,000
Dth/day

Pipeline & Storage
Expansion Project Revenue Growth
55
Larger projects under
consideration for fiscal 2016 and
2017 will drive significant revenue
growth

56
Utility
Overview

Utility
New York & Pennsylvania Service Territories
57
New York
Total Customers: 522,000
Rate Mechanisms:
Revenue Decoupling
Weather Normalization
Low Income Rates
Choice Program/Purchase of
Receivables
Merchant Function Charge
(Uncollectibles Adjustment)
90/10 Sharing (Large Customers)
Natural Gas Vehicle Pilot Program
ROE: 9.1% (Litigated -
2007)
Pennsylvania
Total Customers: 213,000
Rate Mechanisms:
Low Income Rates
Choice Program/Purchase of
Receivables
Merchant Function Charge
ROE: Black Box Settlement (2007)

Utility
Customer Usage
58
(1)
Weighted Average of New York and Pennsylvania service territories (assumes normal weather)

Utility
Continued Cost Control Helps Provide Earnings Stability
59

Utility
Capital Spending Largely Focused on Maintenance
60
The Utility remains focused
on spending to maintain
the ongoing safety and
reliability of its system

Utility
Achieved a Settlement in New York
61
March 27, 2013
Filed a plan with the
NY PSC to adopt an
earnings sharing and
stabilization
mechanism on
earnings above a
9.96% ROE
April 19, 2013
NY PSC issued an
Order to Show Cause
(OTSC) commencing
a proceeding to
establish “temporary
rates”
June 1, 2013
OTSC
suggests
“temporary
rates”
could
become
effective
Following further proceedings,
we anticipate that the PSC will
consider the Joint Proposal in
March or April 2014
May 8, 2013
Company responds
to OTSC
June 14, 2013
“Temporary rates”
become effective
July 26, 2013
Settlement
discussions
commence for
permanent
rates
December 6, 2013
Joint Proposal filed
October 1, 2013
Effective date of
two-year rate plan
under proposed
settlement

National Fuel Gas Company
A History of Success & A Future of Opportunity
62
A History of Success
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. 

63
Appendix

National Fuel Gas Company
Current Hedge Positions
64
Fiscal
Year
NYMEX
Volume
(Bcf)
Average
Price
($/Mcf)
Dominion
Volume
(Bcf)
Average
Price
($/Mcf)
SoCal
Volume
(Bcf)
Average
SoCal
Price
Total
Volume
(Bcf)
Average
Price
($/Mcf)
2014
(1)
61.5
$4.27
20.6
$4.26
0.9
$4.57
82.9
$4.27
2015
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
(1)
0.47
$95.68
1.01
$102.32
-
-
1.48
$100.22
2015
-
-
0.90
$98.42
0.40
$90.14
1.30
$95.90
2016
-
-
0.93
$95.18
0.30
$86.09
1.23
$92.97
2017
-
-
0.38
$92.30
-
-
0.38
$92.30
2018
-
-
0.08
$91.00
-
-
0.08
$91.00
Crude Oil Hedges
(1)
2014 hedge positions are for the remaining nine months of the fiscal year

National Fuel Gas Company
Comparable GAAP Financial Measure Slides and Reconciliations
65
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.

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
$              
212,540
$        
Exploration & Production - All Other Divisions Adjusted EBITDA
108,139
             
139,624
             
189,854
             
170,232
             
277,341
                
308,975
           
Total Exploration & Production Adjusted EBITDA
279,711
$           
327,462
$           
377,457
$           
397,129
$           
492,383
$              
521,515
$        
Total Adjusted EBITDA
Exploration & Production Adjusted EBITDA
279,711
$           
327,462
$           
377,457
$           
397,129
$           
492,383
$              
521,515
$        
Pipeline & Storage Adjusted EBITDA
130,857
             
120,858
             
111,474
             
136,914
             
161,226
                
168,747
        
Gathering Adjusted EBITDA
(141)
                     
2,021
                   
9,386
                   
14,814
                
29,777
                   
38,564
         
Utility Adjusted EBITDA
164,443
             
167,328
             
168,540
             
159,986
             
171,669
                
173,644
        
Energy Marketing Adjusted EBITDA
11,589
                
13,573
                
13,178
                
5,945
                   
6,963
                      
8,797
           
Corporate & All Other Adjusted EBITDA
(5,434)
                 
408
                      
(12,346)
              
(10,674)
              
(9,920)
                    
(9,012)
          
Total Adjusted EBITDA
581,025
$           
631,650
$           
667,689
$           
704,114
$           
852,098
$              
902,255
$        
Total Adjusted EBITDA
581,025
$           
631,650
$           
667,689
$           
704,114
$           
852,098
$              
902,255
$        
Minus: Net Interest Expense
(81,013)
              
(90,217)
              
(75,205)
              
(82,551)
              
(89,776)
                 
(91,780)
            
Plus:  Other Income
9,762
                   
6,126
                   
5,947
                   
5,133
                   
4,697
                      
3,510
               
Minus: Income Tax Expense
(52,859)
              
(137,227)
            
(164,381)
            
(150,554)
            
(172,758)
               
(184,633)
         
Minus: Depreciation, Depletion & Amortization
(170,620)
            
(191,199)
            
(226,527)
            
(271,530)
            
(326,760)
               
(347,543)
         
Minus: Impairment of Oil and Gas Properties (E&P)
(182,811)
            
-
                       
-
                       
-
                       
-
                          
-
                     
Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax (Corp. & All Other)
(2,776)
                 
6,780
                   
-
                       
-
                       
-
                          
-
                     
Plus: Gain on Sale of Unconsolidated Subsidiaries (Corp. & All Other)
-
                       
-
                       
50,879
                
-
                       
-
                          
-
                     
Plus: Elimination of Other Post-Retirement Regulatory Liability (P&S)
-
                       
-
                       
-
                       
21,672
                
-
                          
-
                     
Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P)
-
                       
-
                       
-
                       
(6,206)
                 
-
                          
-
                     
Minus: New York Regulatory Adjustment (Utility)
-
                       
-
                       
-
                       
-
                       
(7,500)
                    
(7,500)
              
Rounding
-
                       
-
                       
-
                       
(1)
                          
-
                          
-
                     
Consolidated Net Income
100,708
$           
225,913
$           
258,402
$           
220,077
$           
260,001
$              
274,309
$        
Consolidated Debt to Total Adjusted EBITDA
Long-Term Debt, Net of Current Portion (End of Period)
1,249,000
$        
1,049,000
$        
899,000
$           
1,149,000
$        
1,649,000
$          
1,649,000
$     
Current Portion of Long-Term Debt (End of Period)
-
                       
200,000
             
150,000
             
250,000
             
-
                          
-
                     
Notes Payable to Banks and Commercial Paper (End of Period)
-
                  
-
                  
40,000
           
171,000
          
-
                    
-
                
Total Debt (End of Period)
1,249,000
$     
1,249,000
$     
1,089,000
$     
1,570,000
$     
1,649,000
$       
1,649,000
$   
Long-Term Debt, Net of Current Portion (Start of Period)
999,000
          
1,249,000
       
1,049,000
       
899,000
          
1,149,000
         
1,149,000
     
Current Portion of Long-Term Debt (Start of Period)
100,000
          
-
                  
200,000
          
150,000
          
250,000
            
250,000
        
Notes Payable to Banks and Commercial Paper (Start of Period)
-
                  
-
                  
-
                  
40,000
           
171,000
            
238,000
        
Total Debt (Start of Period)
1,099,000
$     
1,249,000
$     
1,249,000
$     
1,089,000
$     
1,570,000
$       
1,637,000
$   
Average Total Debt
1,174,000
$     
1,249,000
$     
1,169,000
$     
1,329,500
$     
1,609,500
$       
1,643,000
$   
Average Total Debt to Total Adjusted EBITDA
2.02
               
1.98
               
1.75
               
1.89
               
1.89
                 
1.82
             
FY 2013
12-Months
Ended 12/31/13

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
$         
$90,000-100,000
Energy Marketing, Corporate & All Other Capital Expenditures
396
773
746
1,121
1,062
$           
-
Total Capital Expenditures from Continuing Operations
306,801
$ 
501,352
$       
854,186
$       
977,394
$       
717,097
$       
$855,000-1,035,000
Capital Expenditures from Discountinued Operations
All Other Capital Expenditures
216
150
$                
-
$                 
-
$                 
-
$                 
-
$                              
Plus (Minus) Accrued Capital Expenditures
Exploration & Production FY 2013 Accrued Capital Expenditures
-
$          
-
$                 
-
$                 
-
$                 
(58,478)
$        
-
$                              
Exploration & Production FY 2012 Accrued Capital Expenditures
-
-
-
(38,861)
38,861
-
Exploration & Production FY 2011 Accrued Capital Expenditures
-
-
(103,287)
103,287
-
-
Exploration & Production FY 2010 Accrued Capital Expenditures
-
(78,633)
78,633
-
-
-
Exploration & Production FY 2009 Accrued Capital Expenditures
(9,093)
19,517
-
-
-
-
Pipeline & Storage FY 2013 Accrued Capital Expenditures
-
-
-
-
(5,633)
-
Pipeline & Storage FY 2012 Accrued Capital Expenditures
-
-
-
(12,699)
12,699
-
Pipeline & Storage FY 2011 Accrued Capital Expenditures
-
-
(16,431)
16,431
-
-
Pipeline & Storage FY 2010 Accrued Capital Expenditures
-
-
3,681
-
-
-
Pipeline & Storage FY 2008 Accrued Capital Expenditures
16,768
-
-
-
-
-
Gathering FY 2013 Accrued Capital Expenditures
-
-
-
-
(6,700)
-
Gathering FY 2012 Accrued Capital Expenditures
-
-
-
(12,690)
12,690
-
Gathering FY 2011 Accrued Capital Expenditures
-
-
(3,079)
3,079
-
-
Gathering FY 2009 Accrued Capital Expenditures
(715)
715
-
-
-
-
Utility FY 2013 Accrued Capital Expenditures
-
-
-
-
(10,328)
-
Utility FY 2012 Accrued Capital Expenditures
-
-
-
(3,253)
3,253
-
Utility FY 2011 Accrued Capital Expenditures
-
-
(2,319)
2,319
-
-
Utility FY 2010 Accrued Capital Expenditures
-
-
2,894
-
-
-
Total Accrued Capital Expenditures
6,960
$      
(58,401)
$        
(39,908)
$        
57,613
$         
(13,636)
$        
-
$                              
Eliminations
(344)
$        
-
$                 
-
$                 
-
$                 
-
$                 
-
$                              
Total Capital Expenditures per Statement of Cash Flows
313,633
$ 
443,101
$       
814,278
$       
1,035,007
$   
703,461
$       
$855,000-1,035,000