 National Fuel Gas Company
Investor Presentation
August 2013
Exhibit 99 |
 August
2013 National Fuel Gas Company
2
Safe Harbor For Forward Looking Statements
This
presentation
may
contain
“forward-looking
statements”
as
defined
by
the
Private
Securities
Litigation
Reform
Act
of
1995,
including
statements
regarding
future
prospects,
plans,
performance
and
capital
structure,
anticipated
capital
expenditures
and
completion
of
construction
projects,
aswell
as
statements
that
are
identified
by
the
use
of
the
words
“anticipates,”
“estimates,”
“expects,”
“forecasts,”
“intends,”
“plans,”
“predicts,”
“projects,”
“believes,”
“seeks,”
“will,”
“may,”
and
similar
expressions.
Forward-looking
statements
involve
risks
and
uncertainties,which
could
cause
actual
results
or
outcomes
to
differ
materially
from
those
expressed
in
the
forward-looking
statements.
The
Company’s
expectations,
beliefs
and
projections
contained
herein
are
expressed
in
good
faith
and
are
believed
to
have
a
reasonable
basis,
but
there
can
be
no
assurance
that
such
expectations,
beliefs
or
projectionswill
result
or
be
achieved or
accomplished.
In addition to other factors, the following are important factors that could cause
actual results to differ materially from results referred to in the forward-looking statements: factors affecting the
Company’s ability to successfully identify, drill for and produce economically
viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather
conditions,
shortages,
delays
or
unavailability
of
equipment
and
services
required
in
drilling
operations,
insufficient
gathering,
processing
and
transportation
capacity,
the
need
to
obtain
governmental
approvals
and
permits,
and
compliance
with
environmental
laws
and
regulations;
changes
in
laws,
regulations
or
judicial
interpretations
towhich
the
Company
is
subject,
including
those
involving
derivatives,
taxes,
safety,
employment,
climate
change,
other
environmental
matters,
real
property,
and
exploration
and
production
activities
such
as
hydraulic
fracturing;
changes
in
the
price
of
natural
gas
or
oil;
impairments
under
the
SEC’s
full
cost
ceiling
test
for
natural
gas
and
oil
reserves;
uncertainty
of
oil
and
gas
reserve
estimates;
significant
differences
between
the
Company’s
projected
and
actual
production
levels
for
natural
gas
or
oil;
changes
in
demographic
patterns
andweather
conditions;
changes
in
the
availability,
price
or
accounting
treatment
of
derivative
financial
instruments;
governmental/regulatory
actions,
initiatives
and
proceedings,
including
those
involving
rate
cases
(which
address,
among
other
things,
allowed
rates
of
return,
rate
design
and
retained
natural
gas),
environmental/safety
requirements,
affiliate
relationships,
industry
structure,
and
franchise
renewal;
delays
or
changes
in
costs
or
plans
with
respect
to
Company
projects
or
related
projects
of
other
companies,
including
difficulties
or
delays
in
obtaining
necessary
governmental
approvals,
permits
or
orders
or
in
obtaining
the
cooperation
of
interconnecting
facility
operators;
financial
and
economic
conditions,
including
the
availability
of
credit,
and
occurrences
affecting
the
Company’s
ability
to
obtain
financing
on
acceptable
terms
for
working
capital,
capital
expenditures
and
other
investments,
including
any
downgrades
in
the
Company’s
credit
ratings
and
changes
in
interest
rates
and
other
capital
market
conditions;
changes
in
economic
conditions,
including
global,
national
or
regional
recessions,
and
their
effect
on
the
demand
for,
and
customers’
ability
to
pay
for,
the
Company’s
products
and
services;
the
creditworthiness
or
performance
of
the
Company’s
key
suppliers,
customers
and
counterparties;
economic
disruptions
or
uninsured
losses
resulting
from
major
accidents,
fires,
severe
weather,
natural
disasters,
terrorist
activities,
acts
of
war,
cyber
attacks
or
pest
infestation;
changes
in
price
differential
between
similar
quantities
of
natural
gas
at
different
geographic
locations,
and
the
effect
of
such
changes
on
the
demand
for
pipeline
transportation
capacity
to
or
from
such
locations;
other
changes
in
price
differentials
between
similar
quantities
of
oil
or
natural
gas
having
different
quality,
heating
value,
geographic
location
or
delivery
date;
significant
differences
between
the
Company’s
projected
and
actual
capital
expenditures
and
operating
expenses;
changes
in
laws,
actuarial
assumptions,
the
interest
rate
environment
and
the
return
on
plan/trust
assets
related
to
the
Company’s
pension
and
other post-
retirement
benefits,which
can
affect
future
funding
obligations
and
costs
and
plan
liabilities;
the
cost
and
effects
of
legal
and
administrative
claims
against
the
Company
or
activist
shareholder
campaigns
to
effect
changes
at
the
Company;
increasing
health
care
costs
and
the
resulting
effect
on
health
insurance
premiums
and
on
the
obligation
to
provide
other
post-
retirement
benefits;
or
increasing
costs
of
insurance,
changes
in
coverage
and
the
ability
to
obtain
insurance.
Forward-looking
statements
include
estimates
of
oil
and
gas
quantities.
Proved
oil
and
gas
reserves
are
those
quantities
of
oil
and
gaswhich,
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,
2012
and
Forms
10-Q
for
the
periods
ended
December
31,
2012,
March
31,
2013
and
June
30,
2013.
The
Company
disclaims
any
obligation
to
update
any
forward-looking
statements
to
reflect
events
or
circumstances
after
the
date
thereof
or
to
reflect
the
occurrence
of
unanticipated
events. |
 August
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) |
 August
2013 National Fuel Gas Company
4
Integrated Businesses with Significant Marcellus Exposure… |
 August
2013 National Fuel Gas Company
5
…And Exposure to Growth from the Utica Shale |
 August
2013 National Fuel Gas Company
6
EBITDA Growth Driven by Stability and Ongoing 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. |
 August
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)
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 |
 August
2013 Total Debt
(1)
44%
National Fuel Gas Company
8
Strong Balance Sheet and Liquidity Position
$3.786 Billion
As of June 30, 2013
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
Debt / Adjusted EBITDA
Capitalization
The Company has a total short-term debt capacity of
$1.085 billion of which all remains available |
 August
2013 National Fuel Gas Company
9
Dividend Track Record
Current
Dividend Yield
(1)
2.2%
(1) As of August 5, 2013
Dividend Consistency
Consecutive Dividend Payments
111 Years
Consecutive Dividend Increases
43 Years
Current
Annualized Dividend Rate
$1.50
per Share |
 August
2013 Exploration & Production
10 |
 August
2013 Seneca Resources
11
Disciplined Capital 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
|
 August
2013 Seneca Resources
12
Production Continues to Grow |
 August
2013 Seneca Resources
13
Driving Down Costs
(1)
Represents the midpoint of current General & Administrative Expense guidance of $0.50 to
$0.55 per Mcfe for fiscal 2013 and $0.45 to $0.50 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 $0.95 to $1.05 per Mcfe for fiscal 2013 and
$0.90 to $1.10 per Mcfe for fiscal 2014 |
 August
2013 Seneca Resources
14
California: Seventh Largest Producer in the State
Net Acreage: 18,418 Acres
Net Wells: 1,485
Oil Gravity: 12 –
37°
Api
NRI: 87.64
Rank
Company
California
2012
BOEPD
(1)
1
Occidental
187,376
2
Chevron
160,611
3
Aera (Shell/Exxon)
143,983
4
Plains Exploration
36,365
5
Berry Petroleum
19,589
6
Macpherson Oil
10,416
7
Seneca Resources
10,154
8
Venoco Inc
6,113
9
E&B Natural Resources
6,042
10
ExxonMobil
3,664
(1)
Gross operated production (Source: California Division of Oil, Gas, & Geothermal
Resources) |
 August
2013 Seneca Resources
15
California: Stable Production Fields
East Coalinga
~120 BOEPD
Temblor Formation
Primary
South Lost Hills
~1,500 BOEPD
Monterey Shale
Primary
222 Active Wells
Sespe
~1,100 BOEPD
Sespe Formation
Primary
172 Active Wells
South Midway Sunset
~1,200 BOEPD
Antelope Formation
Steamflood
120 Active Wells
North Midway Sunset
~4,000 BOEPD
Potter & Tulare Formation
Steamflood
728 Active Wells
North Lost Hills
~1,100 BOEPD
Tulare & Etchegoin Formation
Primary & Steamflood
175 Active Wells |
 August
2013 Seneca Resources
16
California: Strong Margins Provide Significant Free Cash Flow
Average Revenue
(12 Months Ended 6/30/13)
$87.51 per BOE
(1) Total production from the Exploration & Production segment’s properties in
California was 3,308 Mboe for the 12 months ended June 30, 2013. Note:
A
reconciliation
of
Exploration&
Production
WestDivision
Adjusted
EBITDA
to
Exploration&
Production
Segment
Net
Income
is
includedat
theend
of
this
presentation. |
 August
2013 Seneca Resources
17
California: Midway-Sunset South Activity Update |
 August
2013 18
WS 48-33
IP: 80 BOEPD
1st
Oil 09/12
“X”
SANDS ISOCHORE (Thickness)
Seneca Resources
California: Sespe Field –
Drilling Programs and Results
1 Mile
Oak Flat 1-31
IP: 110 BOEPD
1st
Oil 08/12
FA 502-33
IP: 75 BOEPD
1st
Oil 1/13
FA 501-33
IP: 100 BOEPD
1st
Oil 1/13
Oak Flat 2-31
IP: 100 BOEPD
1st
Oil 08/12
TG 562-29
IP: 190 BOEPD
1st
Oil 2/13
TG 53-29
IP: 90 BOEPD
1st
Oil 3/13
2011 Sespe Wells (5)
2012 Sespe Wells (6)
2013 Sespe Wells (6)
2014 Sespe Wells (4) |
 August
2013 Seneca Resources
19
California: East Coalinga Overview
Seneca became operator on January 30, 2013
Previous Operator: Chevron
7,764 net acres
90 active wells
~380 BOPD (Up from 230 BOPD on 1/30/13)
$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 (9 of 12 drilled to date)
Place ~50% of currently idled wells back on
production
Have put 40 on since 1/30/13
Upgrade surface facilities |
 August
2013 Seneca Resources
20
California: Delivering Steady Results
Key Areas of Focus in 2014
1.East Coalinga Evaluation
2.South Midway Sunset Extensions
3.Sespe Coldwater Evaluation |
 August
2013 Seneca Resources
21
Expansive Pennsylvania Acreage Position
SRC Lease Acreage
SRC Fee Acreage
Eastern Development Area
Net Acreage: 55,000 acres
Mostly leased (16-18% royalty)
No near-term lease expiration
First large expiration: 2018
Ongoing development drilling in
Tioga and Lycoming Counties
Western Development Area
Net acreage:
~720,000 acres
Own most mineral rights
Minimal
royalty obligation
Minimal
lease expiration
Evaluating rich-gas potential and
initiating dry gas development
NFG Storage Acreage |
 August
2013 Seneca Resources
Firm Sales in Place for Appalachian Production
22
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 |
 August
2013 Seneca Resources
23
Eastern Development Area (EDA)
SRC Lease Acreage
SRC Fee Acreage
DCNR Tract 595
Gross Production: ~75 MMcf per Day
34 Wells Drilled
26 Wells Producing
Covington –
Fully Developed
Gross Production: ~60 MMcf per Day
47 Wells Drilled and Producing
DCNR Tract 100
Gross Production: ~165 MMcf per Day
40 Wells Drilled
25 Wells Producing |
 August
2013 Seneca Resources
24
Strong Results in Lycoming and Tioga Counties
Development Area
Producing
Well
Count
Average
IP Rate
(MMcf/d)
Average
7-Day
(MMcf/d)
Average
30-Day
(MMcf/d)
Average
EUR
per Well
(Bcf)
Average
Lateral
Length
EUR per
1,000’
of
Lateral
(Bcfe)
Covington
Tioga
County
47
5.2
4.7
4.1
5.7
4,023’
1.42
Tract 595
Tioga
County
26
7.1
6.0
5.1
8.2
4,629’
1.77
Tract 100
Lycoming
County
25
15.4
13.5
11.1
11.0
5,008’
2.20 |
 August
2013 Seneca Resources
25
Successful Delineation Across a Large Acreage Position
Owl’s Nest
2 Wells Drilled
Testing: August 2013
Church Run (1 Well)
IP : 4.8 MMcfd
SRC Lease Acreage
SRC Fee Acreage
Horizontal Well
Ridgway (1 Well)
IP: 7.1 MMcfd
Rich Valley (1 Well)
Peak 7-Day IP: 7.8 MMcfd
30-Day Rate: 6.7MMcfd
Estimated EUR: 7.4 Bcf
BTU
Contours
Clermont (2 Wells)
9H (RCS) IP: 8.9 MMcfd
10H (Non-RCS) IP: 6.6 MMcfd
Tionesta
1 Well Drilled |
 August
2013 Seneca Resources
26
Delineation Well Test Data Provides Positive Data Points
Completion Design
Initial Test Data
Sales Data
Well Name
RCS
(1)
/
Non-RCS
Treatable
Lateral
Length
Stages
Peak
IP Rate
(MMcfd)
7-Day
Rate
(MMcfd)
Normalized
7-Day Rate
(MMcfd per
1,000’)
7-Day
Rate
(MMcfd)
30-Day
Rate
(MMcfd)
EUR
(Bcf)
Rich Valley
27H
RCS
6,372’
42
6.4
5.4
0.8
7.8
6.7
7.4
Clermont 9H
RCS
5,500’
37
8.9
8.6
1.6
Clermont 10H
Non-RCS
5,565’
23
6.6
6.3
1.1
Ridgway 19H
RCS
5,537’
37
7.1
6.4
1.2
Church Run 2H
RCS
4,435’
29
4.8
4.5
1.0
Wells tested during
the 3
rd
quarter of
fiscal 2013
Initial well test data in the Western Development Area furthers our
confidence in a long-term Marcellus development program
(1)
RCS –
Reduced Cluster Spacing |
 August
2013 Seneca Resources
27
Rich Valley/Clermont: Moving Forward with Full Development
Clermont
Rich Valley
Rich Valley
7-day IP: 7.8 MMcf/d
EUR: 7.4 BCF
Rich Valley 2nd
Well
Currently Drilling
Marcellus Faults
Marcellus & Basement Faults
Drilled Well
Planned Well
Rich
Valley/Clermont
Program
150-200 horizontal locations
SRC Lease Acreage
SRC Fee Acreage
Pad N (9 Wells)
Spud Q4 FY2013
Clermont
9H 7-day Flow back: 8.6 MMcf/d
10H 7-day Flow back: 6.3 MMcf/d |
 August
2013 Seneca Resources
28
Ongoing Production Growth in the East Division |
 August
2013 Seneca Resources
29
Utica Shale –
Activity Summary
Permitted
Drilled/Drilling
Completed
Producing
Mt. Jewett
Tested 3 Frac Stages at 1.6 MMcfd
(Typical Well: 17 Frac Stages)
2nd
Horizontal: Completed (Soaking)
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” |
 August
2013 Seneca Resources
30
Initial Entry into the Mississippian Lime Play in Kansas
Total Net Acres: 13,615
Negotiated an increase in Seneca’s
working interest and have taken over
as operator
Will drill up to 5 evaluation wells in
2014
The initial entry into the Mississippian Lime play furthers the Company’s goal
of maintaining a significant contribution from oil-producing properties
Unit
30-day IP:
352 BOED
(92% Oil/NGLs)
100% working interest in 4,400 gross
acres
55% net working interest in 17,365
gross acres
Spud first horizontal well in the first
quarter of fiscal 2014 |
 August
2013 Midstream Businesses
31
Pipeline & Storage/NFG Midstream |
 August
2013 Midstream Businesses
32
Pipeline Expansions to Transport Appalachian Production
Gathering
Marcellus
Production
Shipping Gas
to Canada &
Northeast
Line N
Corridor
Expansions |
 August
2013 Midstream Businesses
33
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
(2016)
LINE “N”
2012
EXPANSION
(In-Service)
MERCER
EXPANSION
PROJECT
(Nov. 2014)
LINE “N”
2013
EXPANSION
(Nov. 2013)
WEST SIDE
EXPANSION
(Nov. 2015)
TIONESTA
GATHERING SYSTEM
(In-Service)
MT. JEWETT
GATHERING SYSTEM
(Under
Construction)
CLERMONT
GATHERING SYSTEM
(IQ4 FY2014) |
 August
2013 Midstream Businesses
34
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 |
 August
2013 Utility
35 |
 August
2013 Total Customers: 520,000
Rate Mechanisms:
Revenue Decoupling
Weather Normalization
Low Income Rates
Choice Program/Purchase of
Receivables (POR)
Merchant Function Charge
(Uncollectibles Adjustment)
90/10 Sharing (Large Customers)
Natural Gas Vehicle Pilot Program
Allowed ROE: 9.1%
Utility
36
New York Service Territory |
 August
2013 Utility
37
New York -
Earnings Sharing Proposal and Show Cause Order
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
Further proceedings would follow to establish
permanent rates
Most recent NY PSC multi-year plan include:
ROE: 9.4%
Equity Ratio: 48%
National Fuel continues to maintain a dialogue
with regulators
May 8, 2013
Company responds to
OTSC
June 14, 2013
“Temporary rates”
become effective
July 26, 2013
Settlement discussions
commence for
permanent rates |
 August
2013 Utility
38
Pennsylvania Service Territory
Total Customers: 213,000
Rate Mechanisms:
Low Income Rates
Choice Program/Purchase of
Receivables (POR)
Merchant Function Charge
Allowed ROE: N/A
(1)
(1)
Black Box Settlement |
 August
2013 Utility
39
Continued Cost Control Helps Provide Earnings Stability
Low natural gas prices,
combined with a focus
on cost control, continue
to help reduce expenses |
 August
2013 Utility
40
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 |
 August
2013 National Fuel Gas Company
41
Appendix |
 August
2013 National Fuel Gas Company
42
No Debt Maturities Until Fiscal 2018
In February, the Company
Issued $500 million in
10-year notes at 3.75% |
 August
2013 Midstream Businesses
43
Appendix |
 August
2013 Midstream Businesses
44
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
$61 MM
(1)
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
$39 MM
(2)
11/2012
Fully Subscribed
Completed
Line “N”
2013 Expansion
30,000
$4 MM
11/2013
Fully Subscribed
Under Construction
Mercer Expansion Project
105,000
$30 MM
(3)
11/2014
Fully Subscribed
Executed Precedent Agreement
West Side Expansion and
Modernization Project
95,000+
$66 MM
(4)
2015
OS Concluded
Executed one of two Precedent
Agreements
Central Tioga County
Extension
260,000
~$150 MM
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: ~$789 MM
(1)
The Line “N”
Expansion Project consists of $22 million in expansion capital expenditures and $39 million in
replacement capital expenditures (2)
The Line “N”
2012 Expansion Project consists of $32 million in expansion capital expenditures and $7
million in replacement capital expenditures (3)
The Mercer
Expansion Project consists of $27 million in expansion capital expenditures and $3 million in
replacement capital expenditures (4)
The
Westside
Expansion
and
Modernization
Project
consists
of
$31
million
in
expansion
capital
expenditures
and
$35
million
in
replacement
capital
expenditures |
 August
2013 Midstream Businesses
45
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
April 2012
Fully Subscribed
Completed
–
Flowing into TGP 300
Line
Mt. Jewett Gathering System
10,000
$3.9 MM
FY2013
Q4
Fully Subscribed
Under Construction
Clermont Gathering System
500,000+
~$25 MM
(FY2014)
FY2014
Q4
Evaluating
Fiscal 2014 capital spending on the
Clermont Gathering System is
primarily for the trunkline
Total Firm Capacity: ~1,206,000 Mcf/D
Capital Investment: ~$256 MM |
 August
2013 Exploration & Production
46
Appendix |
 August
2013 Seneca Resources
47
Another Strong Year of Reserve Growth
Fiscal
Years
3-Year
F&D Cost
(1)
($/Mcfe)
2006-2008
$7.63
2007-2009
$5.35
2008-2010
$2.37
2009-2011
$2.09
2010-2012
$1.87
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
|
 August
2013 Seneca Resources
48
Hedge Positions and Strategy
Natural Gas
Swaps
Volume
(Bcf)
Average
Hedge Price
Fiscal 2013
19.4
$4.49 / Mcf
Fiscal 2014
63.8
$4.28 / Mcf
Fiscal 2015
42.5
$4.29 / Mcf
Fiscal 2016
38.2
$4.35 / Mcf
Fiscal 2017
38.8
$4.45 / Mcf
Fiscal 2018
5.3
$4.81 / Mcf
Oil Swaps
Volume
(MMBbl)
Average
Hedge Price
Fiscal 2013
0.4
$94.92 / Bbl
Fiscal 2014
2.0
$100.22 / Bbl
Fiscal 2015
1.1
$94.95 / Bbl
Fiscal 2016
0.8
$91.60 / Bbl
Fiscal 2017
0.2
$91.50 / Bbl
Fiscal 2018
0.05
$91.00 / Bbl
Most hedges executed at sales point to eliminate basis risk
Seneca has hedged approximately 54% of its
forecasted production for Fiscal 2014
Note: Fiscal 2013 hedge positions are for the remaining three months of the fiscal year
|
 August
2013 Seneca Resources
49
Operational Efficiencies Continue to Drive Production Growth
Ongoing efficiency allows for more activity with a flat rig count
(1)
RCS
–
Reduced
Cluster
Spacing
(2)
Drilling pace represents the average feet drilled per day from the time the well is spud
until it reaches total depth (TD) |
 August
2013 Marcellus Shale
50
Targeting Continued Cost Reductions
(1) Completion Cost per Stage is for horizontal wells completed utilizing a standard
completion design, not a Reduced Cluster Spacing (RCS) completion design. |
 August
2013 National Fuel Gas Company
51
Comparable GAAP Financial Measure Slides and Reconciliations
This
presentation
contains
certain
non-GAAP
financial
measures.
For
pages
that
contain
non-GAAP
financial
measures,
pages
containing
the
most
directly
comparable
GAAP
financial
measures
and
reconciliations
are
provided
in
the
slides
that
follow.
The
Company
believes
that
its
non-GAAP
financial
measures
are
useful
to
investors
because
they
provide
an
alternative
method
for
assessing
the
Company’s
operating
results
in
a
manner
that
is
focused
on
the
performance
of
the
Company’s
ongoing
operations,
or
on
earnings
absent
the
effect
of
certain
credits
and
charges,
including
interest,
taxes,
and
depreciation,
depletion
and
amortization.
The
Company’s
management
uses
these
non-
GAAP
financial
measures
for
the
same
purpose,
and
for
planning
and
forecasting
purposes.
The
presentation
of
non-GAAP
financial
measures
is
not
meant
to
be
a
substitute
for
financial
measures
prepared
in
accordance
with
GAAP. |
 August
2013 52
Reconciliation of Exploration & Production West Division Adjusted EBITDA
to Exploration & Production Segment Net Income
($ Thousands)
12 Months Ended
June 30, 2013
Exploration & Production - West Division Adjusted EBITDA
215,766
$
Exploration & Production -
All Other Divisions Adjusted EBITDA 251,623
Total Exploration &
Production Adjusted EBITDA 467,389
$
Minus: Exploration & Production Net
Interest Expense (35,947)
Minus: Exploration
& Production Income Tax Expense (93,596)
Minus: Exploration
& Production Depreciation, Depletion & Amortization (229,645)
Exploration & Production Net
Income 108,201
$
Exploration & Production Net
Income 108,201
$
Pipeline & Storage Net
Income 72,903
Utility Net
Income 70,890
Energy Marketing Net Income
5,248
Corporate & All Other
Net Income 3,719
Consolidated Net Income
260,961
$
|
 August
2013 53
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
$
215,766
$
Exploration & Production - All Other Divisions Adjusted EBITDA
108,139
139,624
189,854
170,232
251,623
Total Exploration & Production Adjusted EBITDA
279,711
$
327,462
$
377,457
$
397,129
$
467,389
$
Total Adjusted EBITDA
Exploration & Production Adjusted EBITDA
279,711
$
327,462
$
377,457
$
397,129
$
467,389
$
Utility Adjusted EBITDA
164,443
167,328
168,540
159,986
172,898
Pipeline & Storage Adjusted EBITDA
130,857
120,858
111,474
136,914
156,803
Energy Marketing Adjusted EBITDA
11,589
13,573
13,178
5,945
7,694
Corporate & All Other Adjusted EBITDA
(5,575)
2,429
(2,960)
4,140
14,120
Total Adjusted EBITDA
581,025
$
631,650
$
667,689
$
704,114
$
818,904
$
Total Adjusted EBITDA
581,025
$
631,650
$
667,689
$
704,114
$
818,904
$
Minus: Net Interest Expense
(81,013)
(90,217)
(75,205)
(82,551)
(89,078)
Plus: Other Income
9,762
6,126
5,947
5,133
4,723
Minus: Income Tax Expense
(52,859)
(137,227)
(164,381)
(150,554)
(183,151)
Minus: Depreciation, Depletion & Amortization
(170,620)
(191,199)
(226,527)
(271,530)
(312,109)
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)
-
Rounding
-
-
-
(1)
-
Consolidated Net Income
100,708
$
225,913
$
258,402
$
220,077
$
260,961
$
Consolidated Debt to Total Adjusted EBITDA
Long-Term Debt, Net of Current Portion (End of Period)
1,249,000
$
1,049,000
$
899,000
$
1,149,000
$
1,649,000
$
Current Portion of Long-Term Debt (End of Period)
-
200,000
150,000
250,000
-
Notes Payable to Banks and Commercial Paper
(End of Period) -
-
40,000
171,000
-
Total Debt (End of Period)
1,249,000
$
1,249,000
$
1,089,000
$
1,570,000
$
1,649,000
$
Long-Term Debt, Net of Current Portion (Start of Period)
999,000
1,249,000
1,049,000
899,000
1,149,000
Current Portion of Long-Term Debt (Start of Period)
100,000
-
200,000
150,000
250,000
Notes Payable to Banks and Commercial Paper (Start of Period)
-
-
-
40,000
70,200
Total Debt (Start of Period)
1,099,000
$
1,249,000
$
1,249,000
$
1,089,000
$
1,469,200
$
Average Total Debt
1,174,000
$
1,249,000
$
1,169,000
$
1,329,500
$
1,559,100
$
Average Total Debt to Total Adjusted EBITDA
2.02
1.98
1.75
1.89
1.90
12-Months Ended
6/30/13 |
 August
2013 54
Reconciliation of Segment Capital Expenditures to
Consolidated Capital Expenditures
($ Thousands)
FY 2013
FY 2014
FY 2009
FY 2010
FY 2011
FY 2012
Forecast
Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures
188,290
$
398,174
$
648,815
$
693,810
$
$525,000-585,000
$550,000-650,000
Pipeline & Storage Capital Expenditures - Expansion
52,504
37,894
129,206
144,167
$70,000-90,000
$80,000-100,000
Utility Capital Expenditures
56,178
57,973
58,398
58,284
$65,000-70,000
$80,000-90,000
Marketing, Corporate & All Other Capital Expenditures
9,829
7,311
17,767
81,133
$50,000-75,000
$80,000-100,000
Total Capital Expenditures from Continuing Operations
306,801
$
501,352
$
854,186
$
977,394
$
$710,000-820,000
$790,000-940,000
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
$
$710,000-820,000
$790,000-940,000 |