EX-99 2 d502618dex99.htm EX-99 EX-99
National Fuel Gas Company
Investor Presentation
March 2013
Exhibit 99

March 2013
National Fuel Gas Company
3
Our Business Mix Leads to Long-Term Value Creation
Upstream
Crude Oil
Midstream
Downstream
National Fuel Gas
Supply Corporation
Empire Pipeline, Inc.
National Fuel Gas
Midstream Corporation
National Fuel Gas
Distribution
Corporation
National Fuel
Resources, Inc.
The strategic, operational and financial benefits, along with capital
flexibility and consistent growth opportunities generated by this
integrated mix of businesses continues to create significant
long-term value for the Company’s shareholders in nearly all
economic and commodity price scenarios
Upstream
Natural Gas
Seneca Resources
Corporation
(West Division)
Seneca Resources
Corporation
(East Division)

March 2013
National Fuel Gas Company
4
Integrated Businesses with Significant Marcellus Exposure…

March 2013
National Fuel Gas Company
5
…And Exposure to Growth from the Utica Shale

March 2013
National Fuel Gas Company
6
EBITDA Growth Driven by Stability and Continued 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. 

March 2013
National Fuel Gas Company
7
Capital Spending Flexibility to Maintain Financial Strength
Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.
(1)
(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

March 2013
National Fuel Gas Company
8
Strong Balance Sheet and Liquidity Position
$3.653 Billion
(2)
As of December 31, 2012
(1)
Includes Long-Term Debt of $1.149 billion, the Current Portion of Long-Term Debt of $0.250 billion, and Notes Payable to Banks and Commercial Paper
of $0.238 billion, as of December 31, 2012.
(2)
Includes Notes Payable to Banks and Commercial Paper of $238.0 million and Current Portion of Long-Term Debt of $250.0 million as of December 31, 2012.
In February 2013, the Company issued $500
million in 10-year notes to repay a $250 maturity
and all
outstanding short-term debt
Capital Resources
Total Short-Term Capacity: $1,085 Million
Committed Credit Facility:  $750 Million
Syndicated facility extends until
January 6, 2017
Uncommitted Lines of Credit: $335 Million
$18.0 million of outstanding short-
term notes payable to banks as of
December 31, 2012
$300.0 Million Commercial Paper
Program backed by Committed Credit
Facility
$220.0 million of outstanding
commercial paper  as of
December 31, 2012

March 2013
Midstream Businesses
9
Pipeline & Storage/NFG Midstream

March 2013
Midstream Businesses
10
Pipeline Expansions to Transport Appalachian Production

March 2013
Exploration & Production
11

March 2013
Seneca Resources
12
Another Strong Year of Reserve Growth
Seneca has more than doubled
its proved reserves since 2009,
while maintaining a relatively
high percentage of proved
developed reserves (67%),
given its large resource base
(1)
Represents a three-year average U.S. finding and development cost

March 2013
Seneca Resources
13
Operational Efficiencies Continue to Drive Production Growth
Ongoing efficiency allows for more activity with a flat rig count
(1)
RCS –
Reduced Cluster Spacing
(2)
Drilling pace represents the average feet drilled per day from the time the well is spud until it reaches total depth (TD)

March 2013
Seneca Resources
14
Increased Oil Spending and Tempered Marcellus Spending
(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

March 2013
Seneca Resources
15

March 2013
Seneca Resources
16
California: Stable Production Fields

March 2013
Seneca Resources
17
California: Strong Margins Support Significant Free Cash Flow
(1)  Total production from the Exploration & Production segment’s properties in California  was 3,374 Mboe for the 12 months ended December 31, 2012.
Note: A reconciliation of Exploration & Production West Division
Adjusted EBITDA to Exploration & Production Segment Net Income is included at the end of this
presentation. 

March 2013
California: Midway Sunset South Activity Update
Seneca Resources
18

March 2013
19
“X”
SANDS ISOCHORE (Thickness)
Seneca Resources
California: Sespe Field –
Drilling Programs and Results

March 2013
Seneca Resources
20
California: East Coalinga Overview
Seneca became operator on January 30, 2013
Previous Operator: Chevron
7,764 net acres
~170 wells (60 active)
~250 BOPD
$30 million capital commitment over first
three years
$100 million of potential opportunities over
the next five to seven years
2013 Plans
Drill ~12 evaluation wells across acreage
block
Place ~50% of currently idled wells back on
production
Upgrade surface facilities
Active Well
Idle Well

March 2013
Seneca Resources
21
Expansive Pennsylvania Acreage Position

March 2013
Seneca Resources
22
Eastern Development Area (EDA)

March 2013
Seneca Resources
23
Lycoming and Tioga Counties Are Highly Productive Areas 
Development Area
Producing
Well
Count
Average
IP Rate
(MMcf/d)
Average
7-Day
(MMcf/d)
Average
30-Day
(MMcf/d)
Average
EUR
per Well
(Bcf)
Average
Lateral
Length
EUR per
1,000’
of
Lateral
(Bcfe)
Covington
Tioga
County
47
5.2
4.7
4.1
5.3
4,049’
1.30
Tract 595
(1)
Tioga
County
19
6.9
6.0
5.1
7.5
4,455’
1.68
Tract 100
Lycoming
County
14
15.4
13.3
10.3
11.0
5,256’
2.09
(1) Seven new wells on Tract 595 began production in February 2013 and are awaiting sufficient production history to include within the table

March 2013
Seneca Resources
24
Fiscal 2013 Western Development Area Delineation Program

March 2013
Seneca Resources
25
Rich Valley/Clermont Development Area

March 2013
Seneca Resources
26
Utica Shale –
Activity Summary
Permitted
Drilled/Drilling
Completed
Producing
Mt. Jewett
Tested 3 Frac Stages at 1.6 MMcfd
(Typical Well: 17 Frac Stages)
2
nd
Horizontal: FY 2013
Henderson
Vertical Well: Tested
Tionesta
Horizontal: Completed Fall 2012
Peak 24-Hour Rate: 3.9 MMcfd
Rex
9.2 MMcfd
Chesapeake
6.4 MMcfd
Range Resources
4.4 MMcfd
Range Resources
1.4 MMcfd
“Not Effectively
Stimulated”

March 2013
Seneca Resources
27
Initial Entry into the Mississippian Lime Play in Kansas
Total Net Acres: 9,300
1
st
Well Spud: FY2013 –
Q3
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)
100% working interest in 4,600
gross acres
25% net working interest in 18,500
gross acres
2013: Participate in 3 to 5 gross
horizontal wells

March 2013
National Fuel Gas Company
28
Capital Deployment Has Led to Significant Accomplishments
Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this
presentation. 
•
Total oil and gas proved reserves reached 1,246 Bcfe at September 30, 2012, with a 3-year
average F&D cost of $1.87/Mcfe
•
Despite the 2011 sale of its offshore Gulf of Mexico properties,
Seneca has increased
production from 42.5 Bcfe in 2009 to 83.4 Bcfe in 2012
31% Increase in Pipeline & Storage Adjusted EBITDA since Fiscal 2011
•
As a result of major Appalachian pipeline expansions, Adjusted EBITDA reached $146 million
for the last 12 months and new projects will continue to drive growth beyond fiscal 2013
44.3 Bcfe in 2012 NFG Midstream Gathering Volumes
•
NFG Midstream gathered more than 44 Bcfe of volumes for Seneca Resources, eliminating
the need to rely upon and provide payment to third party infrastructure operators

March 2013
National Fuel Gas Company
29
Appendix

March 2013
National Fuel Gas Company
30
Fiscal Year 2013 Earnings Guidance Drivers
2013 Forecast
GAAP Earnings per Share
$2.75 -
$3.00
Exploration & Production Drivers
Total Production (Bcfe)
102 -
112
DD&A Expense
$2.10 -
$2.25
LOE Expense
$0.90 -
$1.10
G&A Expense
$58 -
$62 MM
Pipeline & Storage Drivers
O&M Expense
+3%
Revenue
$255 -
$265 MM
Utility Drivers
O&M Expense
+3%
Normal Weather in PA
Energy Marketing Drivers
Operating Income
$5 -
$10 MM

March 2013
National Fuel Gas Company
31
Dividend Track Record
Current
Dividend Yield
(1)
2.5%
(1) As of March 12, 2013

March 2013
National Fuel Gas Company
32
No Debt Maturities Until Fiscal 2018

March 2013
Midstream Businesses
33
Appendix

March 2013
Midstream Businesses
34
A Closer Look at the Expansion Progress
COVINGTON
GATHERING
SYSTEM
(In-Service)
TROUT RUN
GATHERING SYSTEM
(In-Service)
TIOGA
COUNTY
EXTENSION
(In-Service)
LINE “N”
EXPANSION
(In-Service)
NORTHERN ACCESS
EXPANSION
(In-Service)
CENTRAL TIOGA
COUNTY EXTENSION
(2015/2016)
LINE “N”
2012
EXPANSION
(In-Service)
MERCER
EXPANSION
PROJECT
(Nov. 2014)
LINE “N”
2013
EXPANSION
(Nov. 2013)
WEST SIDE
EXPANSION
(2013 to 2015)
TIONESTA
GATHERING
SYSTEM
(Under Construction)
MT. JEWETT
GATHERING SYSTEM
(Under Construction)

March 2013
Midstream Businesses
35
Pursuing Additional Opportunities Near the Line N Corridor
Activity in the Marcellus and Utica shales
along the Pennsylvania/Ohio border
continues to remain robust
NFG Supply Corporation’s  Line N system is
well-positioned for continued expansion
NFG Midstream Corporation is focused on
building new high-pressure wet and dry gas
gathering systems
Significant expansion opportunities may be
present in the next few years
2013:
Smaller
pipeline
expansions
2014+:
Larger expansion projects, possibly
including an integrated wet gas solution,
with NFG Midstream focused on the high-
pressure wet gas gathering systems and
NFG Supply transporting dry gas on its
interstate system

March 2013
Midstream Businesses
36
Regulated Interstate Expansion Initiatives (Pipeline & Storage)
Project Name
Capacity
(Dth/D)
Est.
CapEx
In-Service
Market
Status
Lamont Compressor Station
90,000
$14 MM
2010/2011
Fully Subscribed
Completed –
Two Phases
Line “N”
Expansion
160,000
$22 MM
10/2011
Fully Subscribed
Completed
Tioga County Extension
350,000
$58 MM
11/2011
Fully Subscribed
Completed
Northern Access Expansion
320,000
$77 MM
11/2012
Fully Subscribed
Completed
Line “N”
2012 Expansion
163,000
$41 MM
11/2012
Fully Subscribed
Completed
Line “N”
2013 Expansion
30,000
~$5 MM
11/2013
Fully Subscribed
Executed Precedent Agreement
Mercer Expansion Project
105,000
~$30 MM
11/2014
Fully Subscribed
Executed Precedent Agreement
West Side Expansion
95,000+
TBD
2013 to
2015
OS Concluded
Negotiating Precedent Agreements
Central Tioga County
Extension
260,000
~$150MM
2015/2016
OS Concluded
Discussions with anchor shipper
West to East
~425,000
~$290 MM
~2016
29% Subscribed
Marketing continues with producers in
various stages of exploratory drilling
Total Firm Capacity:  ~1,998,000+ Dth/D
Capital Investment: ~$687+ MM

March 2013
Midstream Businesses
37
NFG Midstream is Focused on Serving Appalachian Producers
Midstream’s gathering systems are
critical to unlock remote, but highly
productive Marcellus acreage
History of operational success and
efficiency within Pennsylvania
Current focus is on developing and
expanding gathering infrastructure
for both Seneca and other producers
in the Appalachian Basin

March 2013
Midstream Businesses
38
Gathering Expansion Initiatives (NFG Midstream)
Project Name
Capacity
(Mcf/D)
Est.
CapEx
In-Service
Date
Market
Comments
Covington Gathering System
220,000
$40 MM
Multiple
Phases -
Most
In-Service
Capacity Available
[Marketing to
Third Parties]
Completed
–
Flowing into TGP 300
Line.  This includes ~$10 million of
current and future spending to
build pipeline to connect additional
wells
Trout Run Gathering System
466,000
$185 MM
May 2012
Capacity Available
[Marketing to
Third Parties]
Completed
–
Flowing into Transco
Leidy Line.  This includes ~$90
million of current and future
spending to build compression and
pipeline to connect additional wells
Tionesta Gathering System
10,000
$2.1 MM
FY2013
Q2
Fully Subscribed
Under Construction
Mt. Jewett Gathering System
10,000
$3.9 MM
FY2013
Q2
Fully Subscribed
Under Construction
Total Firm Capacity:  ~706,000 Mcf/D
Capital Investment: ~$231 MM

March 2013
Exploration & Production
39
Appendix

March 2013
Seneca Resources
40
Hedge Positions and Strategy
Natural Gas
Swaps
Volume
(Bcf)
Average
Hedge Price
Fiscal 2013
48.9
$4.57 / Mcf
Fiscal 2014
51.0
$4.24 / Mcf
Fiscal 2015
23.8
$4.12 / Mcf
Fiscal 2016
17.9
$4.07 / Mcf
Fiscal 2017
17.9
$4.07 / Mcf
Oil Swaps
Volume
(MMBbl)
Average
Hedge Price
Fiscal 2013
1.3
$94.92 / Bbl
Fiscal 2014
1.5
$100.01 / Bbl
Fiscal 2015
0.5
$92.54 / Bbl
Fiscal 2016
0.3
$86.09/Bbl
Most hedges executed at sales point to eliminate basis risk
Seneca has hedged approximately 69% of its
forecasted production for Fiscal 2013 
Note: Fiscal 2013 hedge positions are for the remaining nine months of the fiscal year

March 2013
Seneca Resources
41
Continuing to Focus on Improving Its Cost Structure
(1)
Represents the midpoint of current General & Administrative Expense guidance of $58 to $62 million, divided by the midpoint of current production guidance
of 95 to 107 Bcfe
(2)
Represents the midpoint of current Lease Operating Expense Guidance of $0.90 to $1.10 per Mcfe

March 2013
Seneca Resources
42
California: Stable Production and Increasing Cash Flows
Net Acreage:  18,418 Acres
Net Wells:  1,478
Oil Gravity:  12 –
37°
Api
NRI:  87.64
Rank
Company
California
2011
BOEPD
1
Occidental
164,796
2
Chevron
163,153
3
Aera (Shell/Exxon)
149,974
4
Plains Exploration
36,775
5
Venoco Inc.
18,988
6
Berry Petroleum
18,872
7
Seneca Resources
9,209
8
Macpherson Oil
9,022
9
E&B Natural Resources
5,992
10
ExxonMobil
3,238

March 2013
Seneca Resources
43
California: Recent Initiatives Driving Near-Term Growth

March 2013
Seneca Resources
44
Ramping Marcellus Shale Production

March 2013
Marcellus Shale
45
Targeting Continued Cost Reductions
(1) Completion Cost per Stage is for horizontal wells completed utilizing a standard completion design, not a Reduced Cluster Spacing (RCS) completion design. 

March 2013
Utility
46

March 2013
Rate Mechanisms
New York & Pennsylvania
Low Income Rates
Choice Program/POR
Merchant Function Charge
New York only
Revenue Decoupling
90/10 Sharing
Weather Normalization
Utility
47
Providing Financial Stability

March 2013
Utility
48
Continued Cost Control Helps Provide Earnings Stability

March 2013
Utility
49
Strong Commitment to Safety
The anticipated increase in 2013
capital expenditures is largely due
to the implementation of a new
Customer Information System
The Utility remains
focused on consistent
spending to maintain
the ongoing safety and
reliability of its system

March 2013
National Fuel Gas Company
50
Comparable GAAP Financial Measure Slides and Reconciliations
This
presentation
contains
certain
non-GAAP
financial
measures.
For
pages
that
contain
non-GAAP
financial
measures,
pages
containing
the
most
directly
comparable
GAAP
financial
measures
and
reconciliations
are
provided
in
the
slides
that
follow.
The
Company
believes
that
its
non-GAAP
financial
measures
are
useful
to
investors
because
they
provide
an
alternative
method
for
assessing
the
Company’s
operating
results
in
a
manner
that
is
focused
on
the
performance
of
the
Company’s
ongoing
operations,
or
on
earnings
absent
the
effect
of
certain
credits
and
charges,
including
interest,
taxes,
and
depreciation,
depletion
and
amortization.
The
Company’s
management
uses
these
non-
GAAP
financial
measures
for
the
same
purpose,
and
for
planning
and
forecasting
purposes.
The
presentation
of
non-GAAP
financial
measures
is
not
meant
to
be
a
substitute
for
financial
measures
prepared
in
accordance
with
GAAP. 

March 2013
51
Reconciliation of Exploration & Production West Division Adjusted EBITDA
to Exploration & Production Segment Net Income
($ Thousands)
12 Months Ended
December 31, 2012
Exploration & Production - West Division Adjusted EBITDA
224,201
$                           
Exploration & Production - All Other Divisions Adjusted EBITDA
180,063
                             
Total Exploration & Production Adjusted EBITDA
404,264
$                           
Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years
(6,206)
                                
Minus: Exploration & Production Net Interest Expense
(31,020)
                              
Minus: Exploration & Production Income Tax Expense
(76,111)
                              
Minus: Exploration & Production Depreciation, Depletion & Amortization
(198,064)
                            
Exploration & Production Net Income
92,863
$                             
Exploration & Production Net Income
92,863
$                             
Pipeline & Storage Net Income
67,500
                               
Utility Net Income
62,115
                       
Energy Marketing Net Income
4,235
                         
Corporate & All Other Net Income
609
                            
Consolidated Net Income
227,322
$                    

March 2013
52
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
$           
224,201
$              
Exploration & Production - All Other Divisions Adjusted EBITDA
108,139
             
139,624
             
189,854
             
170,232
             
180,063
                
Total Exploration & Production Adjusted EBITDA
279,711
$           
327,462
$           
377,457
$           
397,129
$           
404,264
$              
Total Adjusted EBITDA
Exploration & Production Adjusted EBITDA
279,711
$           
327,462
$           
377,457
$           
397,129
$           
404,264
$              
Utility Adjusted EBITDA
164,443
             
167,328
             
168,540
             
159,986
             
164,386
                
Pipeline & Storage Adjusted EBITDA
130,857
             
120,858
             
111,474
             
136,914
             
146,147
                
Energy Marketing Adjusted EBITDA
11,589
                
13,573
                
13,178
                
5,945
                   
6,065
                      
Corporate & All Other Adjusted EBITDA
(5,575)
                 
2,429
                   
(2,960)
                 
4,140
                   
5,849
                      
Total Adjusted EBITDA
581,025
$           
631,650
$           
667,689
$           
704,114
$           
726,711
$              
Total Adjusted EBITDA
581,025
$           
631,650
$           
667,689
$           
704,114
$           
726,711
$              
Minus: Net Interest Expense
(81,013)
              
(90,217)
              
(75,205)
              
(82,551)
              
(85,375)
                 
Plus:  Other Income
9,762
                   
6,126
                   
5,947
                   
5,133
                   
5,212
                      
Minus: Income Tax Expense
(52,859)
              
(137,227)
            
(164,381)
            
(150,554)
            
(153,379)
               
Minus: Depreciation, Depletion & Amortization
(170,620)
            
(191,199)
            
(226,527)
            
(271,530)
            
(281,314)
               
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
                
21,672
                   
Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P)
-
                       
-
                       
-
                       
(6,206)
                 
(6,206)
                    
Rounding
-
                       
-
                       
-
                       
(1)
                          
2
                              
Consolidated Net Income
100,708
$           
225,913
$           
258,402
$           
220,077
$           
227,322
$              
12-Months Ended
12/31/12

March 2013
53
Reconciliation of Segment Capital Expenditures to
Consolidated Capital Expenditures
($ Thousands)
FY 2013
FY 2009
FY 2010
FY 2011
FY 2012
Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures
188,290
$ 
398,174
$       
648,815
$       
693,810
$       
$480,000-560,000
Pipeline & Storage Capital Expenditures -
Expansion
52,504
37,894
129,206
144,167
$70,000-90,000
Utility Capital Expenditures
56,178
57,973
58,398
58,284
$65,000-70,000
Marketing, Corporate & All Other Capital Expenditures
9,829
7,311
17,767
81,133
$50,000-75,000
Total Capital Expenditures from Continuing Operations
306,801
$ 
501,352
$       
854,186
$       
977,394
$       
$665,000-795,000
Capital Expenditures from Discountinued Operations
All Other Capital Expenditures
216
150
$                
-
$                 
-
$                 
-
Plus (Minus) Accrued Capital Expenditures
Exploration & Production FY 2012 Accrued Capital Expenditures
-
-
$                 
(38,861)
$        
-
Exploration & Production FY 2011 Accrued Capital Expenditures
-
-
(103,287)
103,287
-
Exploration & Production FY 2010 Accrued Capital Expenditures
-
(78,633)
78,633
-
-
Exploration & Production FY 2009 Accrued Capital Expenditures
(9,093)
19,517
-
-
-
Pipeline & Storage FY 2012 Accrued Capital Expenditures
-
-
-
(2,696)
-
Pipeline & Storage FY 2011 Accrued Capital Expenditures
-
-
(7,271)
7,271
-
Pipeline & Storage FY 2008 Accrued Capital Expenditures
16,768
-
-
-
-
All Other FY 2012 Accrued Capital Expenditures
-
-
-
(11,000)
-
All Other FY 2011 Accrued Capital Expenditures
-
-
(1,389)
1,389
-
All Other FY 2009 Accrued Capital Expenditures
(715)
715
-
-
-
Total Accrued Capital Expenditures
6,960
$      
(58,401)
$        
(33,314)
$        
59,390
$         
-
Eliminations
(344)
$        
-
-
-
$                 
-
Total Capital Expenditures per Statement of Cash Flows
313,633
$ 
443,101
$       
820,872
$       
1,036,784
$   
$665,000-795,000
-
$          
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