 National Fuel Gas Company
Investor Presentation
March 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,
target
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)
$207
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 Over 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
included
in
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
(1) As of March 18, 2014
Current
Dividend Yield
(1)
2.0%
Annual Rate at Fiscal Year End |
 8
Exploration & Production
Overview |
 Seneca Resources
Proven Record of Growth
9
(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 Seneca
expects to convert its long-term firm transport (FT) contracts into firm sales (FS)
agreements, with the cost reflected in price
realization. As such, it is not included in LOE. |
 Marcellus Shale
Prolific Pennsylvania Acreage
13 |
 Marcellus Shale
EDA Delivering Significant Growth
14
(1)
One well included in this total is producing from the Geneseo Shale
|
 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)
5
wells
currently
producing
in
Tract
100
in
Lycoming
County,0
Pa.
Have
limited
production
history
and
have
been
excluded
from
this
table. |
 Marcellus Shale
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 |
 Marcellus Shale
Huge Position –
Varies in Understanding
17
Understanding Seneca’s
780,000 Net Acres |
 Marcellus Shale
2013 & 2014 WDA Delineation Program
18 |
 Marcellus Shale
Strong Wells Across WDA Acreage
19
(1)
RCS –
Reduced Cluster Spacing
Well Name
Completion
Design
Treatable
Lateral
Length
Stages
Peak
24-Hour
Rate
(MMcfd)
Peak
7-Day
Rate
(MMcfd)
EUR
(Bcf)
Status
Clermont 9H
RCS1
5,500’
37
11.4
10.0
8.6
Producing
Clermont 10H
Non-RCS
5,565’
23
8.1
7.3
6.6
Producing
Rich Valley 27H
RCS
6,372’
42
8.1
7.8
7.4
Producing
Rich Valley 25H
RCS
4,492’
30
5.0
4.5
4.5
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
4.5-5.5
Producing
Owl’s Nest 54H
RCS
6,139’
41
6.1
5.8
4-7
Flowback
Test |
 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’
Larger 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
Clermont
Rich Valley
Rich Valley 2
Well
7-day IP: 4.5 MMcf/d
Lateral Length: 4,492’
Marcellus Faults
Marcellus & Basement Faults
200-250 Horizontal Locations
Pad N: Spacing Test
9 of 9 Wells Drilled
JV Wells
Pad D
Pad E
Pad O
Clermont
RCS: 9H 7-day IP: 10.0 MMcf/d (EUR: 8.6 Bcf)
Non-RCS: 10H 7-day IP: 7.3 MMcf/d
Rich Valley
7-day IP: 7.8 MMcf/d
EUR: 7.4 BCF
Lateral Length: 6,372’
SRC Lease Acreage
SRC Fee Acreage
Pad H
6 of 6 Wells Drilled
nd |
 Marcellus Shale
200,000 Acres With 6-8 Bcfe EUR Wells
22
Note: Assumes 6,000’
treated lateral length |
 Marcellus Shale
~2,000 Economic Locations at $2.00 to $3.80/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
34
11.5-12.5
1,030
90%
$1.92
Gamble
Lycoming
Dry Gas
29
10-11
1,030
77%
$2.05
Tract 595
Tioga
Dry Gas
20
8.1
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
5.8
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 |
 Natural Gas Marketing
How Does Seneca Sell its Production?
24 |
 Natural Gas Marketing
Adding Long-Term Firm Transport to the Portfolio
25
Project
Volume
(Dth/d)
In-Service
Date
Comments
Northeast Supply
Diversification Project (TGP)
50,000
2012
Executed firm sales agreements for entire
capacity over 15 years
Niagara Expansion (TGP/NFG)
170,000
November
2015
Executed firm sales agreements for 140,000
Dth/d for the entire 15 years
Atlantic Sunrise (Transco)
189,405
2017
Evaluating marketing opportunities
Agreements Executed
Project
Volume
(Dth/d)
Target In-
Service
Date
Comments
Northern Access 2016 (NFG)/
TransCanada Open Season
350,000
2016
Evaluating market potential for transportation
path from WDA into Canada
Under Evaluation
Additional current and future Appalachian marketing
opportunities are continuously under evaluation |
 Natural Gas Marketing
Firm Sales Provide a Market for Appalachian Production
26
(1)
Long-term firm sales represent gross volumes
26 |
 Natural Gas Marketing
Current Natural Gas Hedge Positions
27
(1)
2014 hedge positions are for the remaining nine months of the fiscal year
|
 Natural Gas Marketing
Current Hedge Book has Seneca Positioned Very Well
28
(1)
2014 hedge positions are for the remaining nine months of the fiscal year
Note: 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
$4.29/Mcf
$4.33/Mcf
$4.44/Mcf
$4.81/Mcf
Crude Oil
$100.22/Bbl
$95.27/Bbl
$92.97/Bbl
$92.30/Bbl
$91.00/Bbl |
 Natural Gas Marketing
FY 2014 Production –
Firm Sales & Hedge Composition
29 |
 Geneseo Shale
Path to Geneseo Development –
2018/2019 Start
30
1
st
Well (Tract 100 –
Pad N)
Peak IP: 14.1 MMcf per day
30-Day Average Rate: 8.6 MMcf per day
Estimated EUR: 7.0 Bcf
Lateral Length: 4,920’
Frac Stages: 33 stages
Current developed infrastructure from DCNR
100 & Gamble:
14 well pads
3 compressor pads
3 water impoundments
Gathering infrastructure
Savings estimate of ~$300,000 per well from
shared infrastructure
•
>125 Wells
•
Water Infrastructure = $13MM
•
Usable Pads = $16MM
•
Road Infrastructure = $16MM
Tract 100/Gamble (Lycoming County) |
 Point Pleasant & Utica Shale
Industry Activity & 2014 Appraisal Program
31 |
 California
Stable Production Fields; Modest Growth Potential
32 |
 California
East Coalinga Summary
33
Production has increased from 214 BOPD to
559 BOPD
•
Highest on leases since 2000
Drilled 12 evaluation wells in 2013
•
9 of 12 new wells are on line and making ~200
BOPD
Plan to drill 28 new producers and 2 water
disposal wells in 2014 |
 California
South Midway Sunset Has Delivered Significant Growth
34
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
252 Pool
97X Pool
SE Pool
251 Pool
B Pool
A Pool
Extended Pool Boundary
Original Pool Boundary
Existing Wells
1000’
16X Pool |
 California
Evaluating the Monterey Shale at South Lost Hills
35 |
 California
Limited Growth Opportunities, But Strong Economics
36
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 –
Coldwater
$2,800,000
180
35%
4 |
 California
Modest Growth Anticipated in 2014 and 2015
37 |
 California
Outstanding Cash Flow
(1)
38
(1)
Adjusted EBITDA and Capital Expenditures represent Seneca Resources Corporation’s West
Division, which includes its activity in Kansas |
 California
Looking Forward
39
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 |
 Mississippian Lime
Commenced Evaluation Program in Fiscal 2014
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
-
Mississippian Rocks Absent
Drilled and completed first two
horizontal appraisal wells and two
salt water disposal (SWD) wells
Monitoring significant industry
activity
40 |
 Seneca Resources
What Will Seneca Look Like Moving Forward?
41
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
|
 42
Midstream Businesses
Overview |
 Midstream Businesses
Positioned to Serve Seneca’s Rapidly Growing Production
43 |
 Gathering
Gathering is the First Step to Reaching a Market
44 |
 Gathering
Existing Systems Supporting Seneca’s Near-Term Growth
45
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
Interconnects |
 Gathering
Clermont Gathering System has Large Expandability
46
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
47
Revenue Growth (2013 to 2015): ~60%
CAGR
Capital Investment (2013 to 2015): ~60%
CAGR |
 Pipeline & Storage
Project Opportunities to Support WDA Growth
48
Develop multiple outlets
to high-value markets |
 Pipeline & Storage
Northeast PA Spot Markets are Heavily Discounted
49 |
 Pipeline & Storage
Expansions to Move Gas from the WDA are Significant
50
Projects to Support WDA Growth
Project
Capacity (Dth/day)
Northern Access 2015
140,000
Northern Access 2016
1
350,000
Total New Capacity
490,000
Project
Capital Cost
Northern Access 2015
$67 million
Northern Access 2016
1
$360 million
Total Capital
Expenditures
$427 million
Northern
Access 2015
(November 2015)
Northern
Access 2016
(2016)
Clermont
(1)
Previously referred to as the Clermont to Chippawa expansion project
|
 Pipeline & Storage
Major Expansion Designed for Canadian Deliveries
51
In-Service: November 2015
System: NFG Supply Corp.
Capacity: 140,000 Dth per day
Lease to TGP (Kinder) as part of
their Niagara Expansion project
Interconnect
Niagara (TransCanada)
Total Cost: $67 Million
Major Facilities
23,000 HP Compressor
Northern Access 2015
Northern
Access 2015
(November 2015)
Clermont |
 Pipeline & Storage
Northern Access 2016 Provides Additional Access to Canada
52
In-Service: 2016
System: NFG Supply Corp. &
Empire Pipeline, Inc.
Capacity
350,000 Dth per day
Interconnect
Chippawa (TransCanada)
Total Cost: ~$360 Million
Northern
Access 2016
(2016)
Clermont
Northern Access 2016
(1)
(1)
Previously referred to as the Clermont to Chippawa expansion project
|
 Pipeline & Storage
Recent 3
rd
Party Expansions Have Been Highly Successful
53
Completed Expansions
for 3
rd
Parties
Project
Capacity
(Dth/day)
Northern Access 2012
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 2012
$72 million
Tioga County Extension
$58 million
Line N (2011, 2012 & 2013)
$104 million
Total Capital Expenditures
$234 million
Northern
Access 2012
Tioga County
Extension
Line N Projects |
 Pipeline & Storage
Additional Line N Expansions Planned for the Future
54
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
55
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
56
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)
Retained Storage: 3.3 Bcf
New Incremental Transportation
Capacity of 64,000 Dth per day
Precedent agreements executed with
RG&E and NYSEG
Interconnect
Tuscarora (NFG/Supply)
Total Cost: $45 Million
Major Facilities
1,500 HP Compressor
17 miles –
12”
Pipeline
Tuscarora Lateral
Tuscarora
Lateral |
 Pipeline & Storage
Significant Expansions Are Driving Growth
57
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 2012
Northern Access 2015
Northern Access 2016
(1)
Total Capacity
1,160 MDth/d
Other Projects
Lamont Compressor
Tuscarora Lateral
Total Capacity
154 MDth/d
Planned Projects (2014 -2015)
Precedent Agreements Executed
Planned Capacity Additions
484,000
Dth/day
Potential Projects (2016+)
Currently Evaluating
Potential Capacity Additions
350,000
Dth/day
Total (2009-2016+)
Capacity Additions
1,947,000
Dth/day
(1)
Previously referred to as the Clermont to Chippawa expansion project
|
 Pipeline & Storage
Expansion Project Revenue Growth
58
Larger projects under consideration
for fiscal 2016 and 2017 will drive
significant revenue growth |
 59
Utility
Overview |
 Utility
New York & Pennsylvania Service Territories
60
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
Target 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
61
(1)
Weighted Average of New York and Pennsylvania service territories (assumes normal
weather) |
 Utility
Continued Cost Control Helps Provide Earnings Stability
62 |
 Utility
Capital Spending Largely Focused on Maintenance
63 |
 Utility
Achieved a Settlement in New York
64
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
likely consider the Joint
Proposal in 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
65
30% CAGR
Since 2009
Adjusted
EBITDA
Growth
Production
Growth
Midstream
Businesses
Adjusted
EBITDA
10-15% CAGR
2014 to 2018
Adjusted
EBITDA
Growth
15-25% CAGR
2014 to 2018
Production
Growth
10-15% CAGR
2014 to 2018
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. A
Future of Opportunity |
 66
Appendix |
 National Fuel Gas Company
Current Hedge Positions
67
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
63.2
$4.35
17.8
$4.07
1.1
$4.57
82.1
$4.29
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
0.26
$92.10
0.90
$98.42
0.40
$90.14
1.56
$95.27
2016
0.04
$92.10
0.93
$95.18
0.30
$86.09
1.27
$92.95
2017
-
-
0.38
$92.30
-
-
0.38
$92.30
2018
-
-
0.08
$91.00
-
-
0.08
$91.00
Crude Oil Hedges
(1)
2014 hedge positions are for the remaining nine months of the fiscal year
|
 National Fuel Gas Company
Comparable GAAP Financial Measure Slides and Reconciliations
68
This
presentation
contains
certain
non-GAAP
financial
measures.
For
pages
that
contain
non-GAAP
financial
measures,
pages
containing
the
most
directly
comparable
GAAP
financial
measures
and
reconciliations
are
provided
in
the
slides that follow.
The
Company
believes
that
its
non-GAAP
financial
measures
are
useful
to
investors
because
they
provide
an
alternative
method
for
assessing
the
Company’s
ongoing
operating
results,
for
measuring
the
Company’s
cash
flow
and
liquidity,
and
for
comparing
the
Company’s
financial
performance
to
other
companies.
The
Company’s
management
uses
these
non-GAAP
financial
measures
for
the
same
purpose,
and
for
planning
and
forecasting
purposes.
The
presentation
of
non-GAAP
financial
measures
is
not
meant
to
be
a
substitute for financial measures prepared in accordance with GAAP.
The
Company
defines
Adjusted
EBITDA
as
reported
GAAP
earnings
before
the
following
items:
interest
expense,
depreciation,
depletion
and
amortization,
interest
and
other
income,
impairments,
items
impacting
comparability
and
income taxes. |
 69
Reconciliation of Adjusted EBITDA to Consolidated Net Income
($ 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 |
 70
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 |