Attached files
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| 8-K - FORM 8-K - NATIONAL FUEL GAS CO | d893922d8k.htm |
 National Fuel Gas
Company Investor Presentation
Scotia Howard Weil 43
rd
Annual
Energy Conference -
March 2015
1
Exhibit
99 |
 Corporate
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;
the
cost
and
effects
of
legal
and
administrative
claims
against
the
Company
or
activist
shareholder
campaigns
to
effect
changes
at
the
Company;
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;
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;
changes
in
demographic
patterns
and
weather
conditions;
changes
in
the
availability,
price
or
accounting
treatment
of
derivative
financial
instruments;
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;
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,
2014
and
the
Form
10-Q
for
the
quarter
ended
December
31,
2014.
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.
Safe Harbor For Forward Looking Statements
2 |
 Corporate
3 Million BBls of Crude Oil Production
$260 Million of Midstream Adjusted EBITDA
800,000 Net Acres in Pennsylvania
1.914 Tcfe of Proved Reserves
Quality Assets, Exceptional Location, Unique Integration
3 |
 Corporate
Unique Integrated Business Model Provides Competitive Advantage
The National Fuel Value Proposition
4
800,000
net
acres
in
Pennsylvania
–
2
nd
largest
acreage
position
in
Marcellus
Shale
(1)
WDA mineral ownership = no royalty or drilling commitments
Stacked pay potential in Marcellus, Utica and Geneseo shales
Coordinated midstream infrastructure build-out
Opportunity for further pipeline expansion to accommodate Appalachian supply growth
Creating sustainable value for shareholders remains our #1 priority
Considerable Upstream and Midstream Growth Opportunities in Appalachia
Integration significantly reduces operational and financing costs
Diversified cash flows provide stability in challenging commodity price environment
Strong Balance Sheet and History of Disciplined Financial Management
Investment grade credit rating and liquidity to support Appalachian growth strategy
Disciplined capital investment focused on economic returns
112-year commitment to the dividend
(1) Per NGI’s Shale Daily
(January 5, 2015). 780,000 acres prospective in Marcellus Shale.
|
   Corporate
Upstream & Midstream –
Common Vision For Growth
5
Western Development Area
Tier I Acreage: 200,000 Acres
Clermont Gathering System
NFG Supply & Other Interconnects
High quality
Marcellus acreage
Connected to our
interstate pipeline
network
Pipeline capacity to premium
and alternate markets
Northern Access Projects
490 MMcf/d to Canada by 2016 |
 Corporate
EBITDA Growth by Segment
6
Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated
Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. |
 Corporate
Adjusting Capex to Capitalize on Opportunities
7
Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of
Cash Flows is included at the end of this presentation. |
 Corporate
Maintaining a Strong Balance Sheet
8
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 and short-term debt of $172.9 million.
Total Debt
(1)
41%
$4.4 Billion
As of December 31, 2014
Debt/Adjusted EBITDA
Capitalization |
 Corporate
Dividend Track Record
9
(1) As of March 18, 2015.
Current
Dividend Yield
(1)
2.5%
Dividend Consistency
Consecutive Dividend Payments
112 Years
Consecutive Dividend Increases
44 Years
Current Annualized Dividend Rate
$1.54 per Share |
 Upstream
Overview Exploration & Production
10 |
 Upstream
Proven Record of Reserve Growth
11
(1) Represents a three-year average U.S. finding and development cost.
Fiscal
Years
3-Year
F&D Cost
(1)
($/Mcfe)
2007-2009
$5.35
2008-2010
$2.37
2009-2011
$2.09
2010-2012
$1.87
2011-2013
$1.67
2012-2014
$1.38
•
2014 F&D Cost = $1.15
•
Marcellus F&D: $1.00
•
327% Reserve
Replacement Rate
•
73% Proved Developed |
 Upstream
Delivering Tremendous Production Growth
12 |
 Upstream
Disciplined Capital Spending
13 |
 Upstream
Highly Competitive Cost Structure
14
(1)
Represents the midpoint of current General & Administrative Expense guidance of $0.40 to
$0.45 per Mcfe for fiscal 2015. (2)
The total of the two LOE components represents the midpoint of current LOE guidance of $1.00
to $1.10 per Mcfe for fiscal 2015. (3)
The cost of firm transportation is reflected in price realizations (a deduction to gross
revenues). As such, it is not included in LOE. (1)
(2)
(2)
(3) |
       Upstream
Marcellus Shale: Prolific Pennsylvania Acreage
15
Eastern Development Area (EDA)
•
Mostly leased (16-18% royalty)
•
No near-term lease expiration
•
Limited development drilling until firm
transportation capacity on Atlantic
Sunrise becomes available in late 2017
o
Drilling activity will HBP key acreage
Western Development Area (WDA)
•
Average
net
revenue
interest
(NRI):
98%
o
No
lease
expiration
o
No
royalty
on
most
acreage
•
Highly
contiguous
o
Significant
economies
of
scale
•
1,700
to
2,000
locations
de-risked
Seneca Lease
Seneca Fee
720,000 Acres
60,000 Acres |
 Upstream
Marcellus Well Results
16
(1)
Does
not
include
a
well
drilled
into
and
producing
from
the
Geneseo
Shale.
Area
Producing Well
Count
Peak 24-Hour
Rate (MMcfd)
Average
7-Day (MMcf/d)
Average Treatable
Lateral Length (ft)
Clermont / Rich Valley
(CRV)
Elk, Cameron &
McKean counties
19
8.1
7.2
5,710’
WDA Development Wells:
EDA Development Wells:
Area
Producing Well
Count
Peak 24-Hour
Rate (MMcfd)
Average
7-Day (MMcf/d)
Average Treatable
Lateral Length (ft)
Covington
Tioga
County
47
5.2
4.7
4,023’
Tract 595
Tioga
County
43
(1)
7.4
6.1
4,765’
Tract 100
Lycoming
County
57
(1)
16.8
14.8
5,270’ |
 Upstream
EDA Delivering Significant Growth
17
(1)
One
well
included
in
this
total
is
drilled
into
and
producing
from
the
Geneseo
Shale. |
               Upstream
Focusing on WDA Development
18
Note:
Assumes
6,000’
treated
lateral
length.
4 -
6 BCF/well
4 -
6 BCF/well
6 -
8 BCF/well
2-4 BCF/well
SRC Lease Acreage
SRC Fee Acreage
EOG Earned JV Acreage
Seneca’s Tier I Acreage:
•
200,000 Acres
•
6-8 Bcfe EUR Wells
•
Economic at $2.60 to $4.00/MMbtu
CRV
Hemlock
Ridgeway
2-4 BCF/well |
 Upstream
Clermont/Rich Valley (CRV) Area
19 |
   Upstream
~2,000 Economic WDA Locations Below $4/MMBtu
20
(1)
Internal
Rate
of
Return
(IRR)
includes
estimated
well
costs
under
current
cost
structure,
LOE,
and
Gathering
tariffs
anticipated
for
each
prospect.
Prospect
Product
Locations
Remaining to
Be Drilled
Completed
Lateral Length
(ft)
EUR
Assumption
(MMcf)
BTU
$4.50
Dawn/Nymex
(% IRR)
$4.00
Dawn/Nymex
(% IRR)
15% IRR
Realized Price
DCNR 100
Dry Gas
13
5,582
13,540
1030
>100%
74%
$1.84
Gamble
Dry Gas
28
4,605
11,240
1030
72%
50%
$2.08
DCNR 595
Dry Gas
8
4,475
6,890
1030
46%
33%
$2.28
Clermont - Rich Valley
Dry Gas
148
7,000
7,817
1050
42%
28%
$2.60
Hemlock
Dry Gas
157
7,000
7,000
1050
35%
24%
$2.78
Ridgway
Dry Gas
564
7,000
6,300
1111
31%
21%
$2.90
Remaining Tier 1
Dry Gas
1,020
7,000
6,000
1030 - 1100
$3.00 -
$4.00
Future Resource
Dry & Wet
Gas
1,620
7,000
6,000
1030 - 1350
>$4.00
Additional Delineation Required
(1) |
 Upstream
WDA Mineral Interests Significantly Enhance Returns
21
(1)
Internal
Rate
of
Return
(IRR)
includes
estimated
well
costs
under
current
cost
structure,
LOE,
and
Gathering
tariffs
anticipated
for
each
prospect.
($/Mcf)
The Seneca
Advantage
0% Royalty
Realized Price
$ 2.60
Less: Royalty Payment
(0.00)
Less: Cash Operating Expenses
(0.65)
Cash Margin
$ 1.95
Before Tax IRR
(1)
15%
A producer burdened by a 15% royalty would
require a $0.46 higher realized price to achieve
same level of economics as Seneca Resources
Producer
Paying
15% Royalty
$ 2.60
(0.39)
(0.65)
$ 1.56
8%
Clermont/Rich Valley Example |
 Upstream
How Does Seneca Sell its Production?
22
Well Head
Interconnection
with Interstate
Pipeline Network
Gathering
System
3rd Party
Marketer
(or spot market)
Firm Transport
Demand Center
(firm sales or
spot market)
Contracted Basis
Differential
FT Rate
Spot Market
Breakeven economics based on a
realized price after gathering |
 Upstream
Adding Long-Term Firm Transport to the Portfolio
23
(1) A large majority of the executed firm sales agreements continue for the
remainder of the firm transportation contract term. Project
(Counterparty)
In-
Service
Date
Contract
Term
Delivery
Market
FT Capacity (Dth/day)
Matched Firm
Sales Contracts
Fiscal
2015
Fiscal
2016
Fiscal
2017
Fiscal
2018
Northeast Supply
Diversification
Project (TGP)
Nov.
2012
15 years
Canada
50,000
50,000
50,000
50,000
Executed Contracts
50,000 Dth/d
for 10 years
Niagara
Expansion/
TETCO
(TGP
&
NFG)
Nov.
2015
15 years
Canada
---
158,000
158,000
158,000
Executed Contracts
140,000 Dth/d
for 15 years
TETCO
---
12,000
12,000
12,000
Northern Access
2016 (NFG/
TransCanada/
Union)
Nov.
2016
15 years
Canada
---
---
350,000
350,000
Evaluating
marketing
opportunities
TGP 200
(NY)
---
---
140,000
140,000
Atlantic Sunrise
(Transco)
Nov.
2017
15 years
Mid-
Atlantic/
Southeast
---
---
---
189,405
Executed Contracts
189,405 Dth/d
for first 5 years
(1)
Total Firm Transportation Capacity
50,000
220,000
710,000
899,405 |
 Upstream
Significant Base of Long-Term Firm Contracts
24
(1) Includes base firm sales contracts not tied to firm transportation capacity.
Atlantic Sunrise
Williams Co. (Transco)
189,405 Dth/d
Northern Access 2016
NFG & TransCanada
490,000 Dth/d
Niagara Expansion
TGP & NFG
170,000 Dth/d
Current Firm Sales & FT
(1)
914,405 Dth per day
(1)
Total Firm Contracts by FY 2018 |
   Upstream
Reaching High Value Markets
25
Seneca FT Capacity by Fiscal 2018
(Dth per day)
Canadian Markets
558,000
Mid-Atlantic, Southeast & Other
+ 341,405
Total Firm Transport Capacity
899,405
To Mid-Atlantic
& Southeast
Markets
To Canadian
Markets |
 Upstream
Firm Sales Provide Market for Appalachian Production
26
(1)
EDA
and
WDA
carry
an
average
net
revenue
interest
(NRI)
of
82%
-
84%
and
98%,
respectively.
Values
shown
represent
the
price
or
differential
to
a
reference
price
(netback
price)
at
the
first
non-affiliated
interstate
pipeline,
including
the
cost
of
all
related
downstream
transportation
EDA
(1)
320,098 Dth/d
280,036 Dth/d
280,036 Dth/d
WDA
(1)
61,427 Dth/d
60,000 Dth/d
60,000 Dth/d
50,000
Fixed $3.77
50,000
Fixed $3.77
50,000
Fixed $3.77
Dominion
95,327
Less: $0.42
Dominion
85,000
Less: $0.47
Dominion
85,000
Less: $0.47
NYMEX
236,198
Less: $0.51
NYMEX
205,036
Less: $0.59
NYMEX
205,036
Less: $0.59
381,525
340,036
340,036 |
 Upstream
Current Natural Gas Hedge Positions
27
(1) For the remaining nine months of fiscal 2015. |
 Upstream
FY 2015 Production –
Firm Sales & Spot Exposure
28
(1)
Spot price assumptions reflected in fiscal 2015 earnings guidance range.
(2)
Indicates firm sales not backed by financial hedges. Non-hedged DOM firm sales include 5.6
Bcf of non-operated production volumes. Firm Sales with Price Certainty
76.5 Bcf at ~$3.70/Mcf
Spot Price Exposure
27 Bcf at $2.00-$2.25/Mcf
(1)
2.7 Bcf
(2)
7.3 Bcf
(2) |
 Upstream
FY
2016
Productive
Capacity
(1)
29
(1)
Productive capacity reflects firm sales commitments and assumes no price-related
curtailments on projected production exposed to local Appalachian spot pricing. Productive capacity is not
intended to reflect production guidance for fiscal 2016.
(2)
Unhedged firm sales includes non-operated production volumes.
FY 2016 Productive Capacity Summary
Hedged Firm Sales / FT
78 Bcf
Unhedged Firm Sales / FT
(2)
36 Bcf
Productive Capacity Exposed to Spot
66 -
74 Bcf
Total East Div. Productive Capacity
180 -
188 Bcf
West Division (California)
20 -
22 Bcfe
Total SRC Productive Capacity
200 -
210 Bcfe
Total
East Division
Productive Capacity
Price Certainty
at ~$3.75 /Mcf
(2) |
 Upstream
Utica/Point Pleasant: Industry Activity
30
Range
59 Mmcf/d
Rice
42
Mmcf/d
Shell
26.5
Mmcf/d
PGE
PGE
Permitted
Permitted
Drilling
Drilling
Completed
Completed
Production
Production
Seneca Vert.
Seneca Vert.
Seneca Horiz.
Seneca Horiz.
MHR
46 Mmcf/d
Color-filled contours are Trenton TVDSS; CI = 1000’
Seneca -
DCNR 007
IP: 22.7 MMcfd
Seneca –
Mt. Jewett
IP: 8.9 MMcfd |
 Upstream
Utica/Point
Pleasant Shale: EDA Opportunities
31 |
 Upstream
California: Stable Production; Modest Growth
32 |
   Upstream
South Midway Sunset Development
33
252 Pool
97X Pool
SE Pool
251 Pool
B Pool
A Pool
Extended Pool Boundary
Original Pool Boundary
Existing Wells
1000’
16X Pool
Seneca Acquired
in June 2009
Highlights Since Acquisition
•
Significantly increased daily production
•
Drilled 114 new producers
•
Added 3.3 MMBO of proven reserves
•
Increased steam capacity by 420%
•
Identified opportunities for additional
pool development |
   Upstream
California: East Coalinga Summary
34
•
Production has increased from 214 BOPD to
750 BOPD
•
Drilled 31 new producers and 1 water disposal
well in 2014
•
Plan to drill 5 wells in 2015
•
Evaluating potential of undeveloped Upper
Temblor heavy oil reservoir in Section 28
Seneca Acquired
in January 2013 |
 Upstream
Focused on High Return Opportunities
35
CALIFORNIA
Field
Average
Well Cost
Average
EUR
(MBO)
Estimated
IRR
@$55/Bbl
Fiscal 2015
Locations
South Midway Sunset
$250,000
39
57%
36
North Midway Sunset
$300,000
30
25%
15
East Coalinga
$420,000
29
15%
5 |
 Upstream
California: Modest Growth Anticipated in 2015
36 |
 Upstream
Strong Margins Support Significant Free Cash Flow
37
Average Revenue
for Q1 FY2015
(1)
$74.26 per BOE
(1)
Includes impact of hedging. |
 Midstream
Overview Pipeline & Storage
Gathering
38 |
 Midstream
Gathering is the First Step to Reaching a Market
39
(1)
Fiscal
2015
estimated
revenue
reflects
projected
throughput
based
on
the
range
of
Seneca’s
Fiscal
2015
production
guidance
(155-190
Bcfe).
TGP 300
Transco
TGP 200
Covington
Gathering System
(In-Service)
Gathering Interconnects
Clermont
Gathering System
(In-Service)
Trout Run
Gathering System
(In-Service)
(1) |
 Midstream
Gathering Supporting Seneca’s EDA Production
40
(1) Fiscal 2015 estimated throughput reflects the midpoint of Seneca’s Fiscal
2015 production guidance range (155-190 Bcfe). •
In-Service Date: November 2009
•
Capacity: 220,000 Dth per day
•
Interconnect: TGP 300
•
Capital Expenditures (to date): $32 Million
Interconnects
(1)
•
In-Service Date: May 2012
•
Capacity: 466,000 to 585,000 Dth per day
•
Interconnect: Transco –
Leidy Lateral
•
Capital Expenditures (to date): $162 Million
Covington Gathering System
Trout Run Gathering System |
 Midstream
•
In-Service: July 2014
•
Ultimate Trunkline Capacity:
1+ Bcf per day
•
Interconnects
o
TGP 300 (current)
o
NFG Supply Corporation
(Northern Access 2016)
•
Capital Expenditures:
o
To date: $115 Million
o
2015
(1)
: $95 -
$135 Million
Clermont Gathering System has Large Expandability
41
(1) For the remaining nine months of fiscal 2015.
Clermont Gathering System |
 Midstream
Positioned to Serve Growing Production in Appalachia
42
NFG is focused on expanding our pipeline
systems to support the growing needs of
Appalachian producers and shippers |
 Midstream
Major Expansion Designed for Canadian Deliveries
43
•
Customer: Seneca Resources
•
In-Service: November 2015
•
System: NFG Supply Corp.
•
Capacity: 140,000 Dth per day
o
Lease to TGP as part of their
Niagara Expansion project
•
Interconnect
o
Niagara (TransCanada)
•
Total Cost: $66 Million
•
Major Facilities
o
23,000 HP Compression
Northern Access 2015 |
 Midstream
Northern Access 2016 Provides Access to Canada
44
•
Customer: Seneca Resources
•
In-Service: November 2016 target
•
Capacity: 490,000 Dth/d
•
Interconnects:
o
TransCanada –
Chippawa
(350,000 Dth/d)
o
TGP 200 –
East Aurora
(140,000 Dth/d)
•
Total Cost: ~$451 Million
•
FERC Timing
o
Pre-filing: July 2014
o
Certificate filing: March 2015
Northern Access 2016 |
 Midstream
Recent
3
rd
Party
Expansions
Highly
Successful
45
Completed Expansions
Capacity (Dth/day)
Northern Access 2012
320,000
Tioga County Ext. & Lamont
440,000
Line N & Mercer Expansion
458,000
Total New Capacity
1,218,000
Capital Cost ($Millions)
Northern Access 2012
$72
Tioga County Ext. & Lamont
$72
Line N & Mercer Expansion
$138
Total Capital Expenditures
$282
Northern
Access 2012
Tioga County
Extension
Line N Projects
Annual Revenues ($Millions)
Northern Access 2012
$16.1
Tioga County Ext. & Lamont
$33.4
Line N & Mercer Expansion
$23.1
Total Reservation Charges
$72.6 |
 Midstream
Mercer
(TGP Station 219)
Pairing Line N Expansions with System Modernization
46
•
In-Service: November 2015
•
System: NFG Supply Corp.
•
Capacity: 175,000 Dth per day
o
Range Resources (145,000 Dth/d)
o
Seneca Resources (30,000 Dth/d)
•
Interconnect
o
Mercer (TGP Station 219)
o
Holbrook (TETCO)
•
Total Cost: $86 Million
o
Expansion: $45 Million
o
Modernization: $41 Million
•
Major Facilities
o
3,550 HP Compressor
o
23.3 miles –
24”
Replacement Pipe
Westside Expansion &
Modernization
Holbrook (TETCO)
Westside
Expansion &
Modernization |
 Midstream
Developing Unique Solutions for Shippers
47
•
In-Service: November 2015
•
System: NFG Supply & Empire Pipeline
•
New No-Notice Services
o
Precedent agreements executed with
RG&E, NYSEG & NFG Utility
o
Preserving 172,500 Dth per day (RG&E)
o
Preserving 20,000 Dth per day (NYSEG)
o
Retained Storage: 3.3 Bcf
o
New incremental transportation
capacity of 49,000 Dth per day
•
Interconnect
o
Tuscarora (NFG/Supply)
•
Total Cost: $58.5 Million
•
Major Facilities
o
1,384 HP Compressor
o
17 miles –
12”/16”
Pipeline
Tuscarora Lateral
Tuscarora
Lateral |
 Midstream
Recent Capacity
Additions
1,218,000 Dth/day
Significant Expansions Are Driving Growth
48
Completed Projects (Since 2009)
Total Expansion (2009-2016+)
Capacity
Additions
2,072,000 Dth/day
In-Service 2015
364,000 Dth/day
In-Service 2016+
490,000 Dth/day
Planned Projects (2015+)
Precedent Agreements Executed |
 Downstream
Overview Utility
Energy Marketing
49 |
 Downstream
New York & Pennsylvania Service Territories
50
Total
Customers:
524,300
Rate Mechanisms:
o
Revenue Decoupling
o
Weather Normalization
o
Low Income Rates
o
Merchant Function Charge (Uncollectibles Adj.)
o
90/10 Sharing (Large Customers)
NY PSC Rate Case Settlement, May 2014
o
Rates Unchanged
o
9.1% ROE Confirmed
o
2-Tier Earnings Sharing Mechanism
o
9.5% to 10.5% -
Share 50%
o
10.5% > -
Share 80%
o
$8.2 MM CapEx -
system replacement
o
$8.0 MM incremental O&M (post-retirement benefits)
Total
Customers:
213,500
Rate Mechanisms:
o
Low Income Rates
o
Merchant Function Charge
ROE:
Black
Box
Settlement
(2007)
New York
Pennsylvania |
 Downstream
Utility: Shifting Trends in Customer Usage
51
(1) Weighted Average of New York and Pennsylvania service territories (assumes normal
weather). Residential Usage
Industrial Usage |
 Downstream
A Proven History of Controlling Costs
52 |
 Downstream
Utility: Strong Commitment to Safety
53
The Utility remains focused on maintaining the
ongoing safety and reliability of its system
Near-term increase due
to ~$60MM upgrade of
the Utility’s Customer
Information System and
~$25MM NRG Dunkirk
power plant project |
 Appendix
54 |
 Appendix
Natural Gas Hedge Positions
55
(1) For the remaining nine months of fiscal 2015.
(Volumes in thousands Mmbtu; Prices in $/Mmbtu)
Fiscal 2015
(1)
Fiscal 2016
Fiscal 2017
Fiscal 2018
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
NYMEX Swaps
49,130
$4.18
32,350
$4.24
23,130
$4.50
5,550
$4.59
Dominion
Swaps
18,630
$3.74
18,840
$3.78
12,720
$3.87
-
-
SoCal Swaps
900
$4.35
-
-
-
-
-
-
MichCon
Swaps
-
-
9,000
$4.10
3,000
$4.10
-
-
Dawn Swaps
-
-
5,490
$4.36
7,950
$4.14
-
-
Fixed Price
Physical Sales
13,650
$3.77
18,300
$3.77
18,250
$3.77
1,550
$3.77
Total
82,310
$4.01
83,980
$4.03
65,050
$4.11
7,100
$4.41 |
 Appendix
Crude Oil Hedge Positions
56
(1) For the remaining nine months of fiscal 2015.
Fiscal 2015
(1)
Fiscal 2016
Fiscal 2017
Fiscal 2018
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
Midway
Sunset
(MWSS)
Swaps
108,000
$92.10
36,000
$92.10
-
-
-
-
Brent
Swaps
765,000
$98.32
933,000
$95.18
384,000
$92.30
75,000
$91.00
NYMEX
Swaps
297,000
$90.14
300,000
$86.09
-
-
-
-
Total
1,170,000
$95.67
1,269,000
$92.95
384,000
$92.30
75,000
$91.00
(Volumes & Prices in Bbl) |
 Appendix
WDA Delineation Well Results
57
Area
Producing
Well Count
Peak 24-Hour
Rate (MMcfd)
Average
7-Day (MMcf/d)
Average Treatable
Lateral Length (ft)
Ridgway
Elk County
1
7.1
6.4
5,537’
Church Run
Elk & Jefferson
counties
2
4.8
4.5
4,690’
Hemlock
Elk County
2
5.4
5.2
7,067’
Owl’s Nest
Elk & Forest counties
1
6.1
5.8
6,137’
Sulger Farms
Jefferson County
1
6.1
5.6
5,778’ |
 Appendix
Comparable GAAP Financial Measure Slides & Reconciliations
58
This
presentation
contains
certain
non-GAAP
financial
measures.
For
pages
that
contain
non-GAAP
financial
measures,
pages
containing
the
most
directly
comparable
GAAP
financial
measures
and
reconciliations
are
provided
in
the
slides
that
follow.
The
Company
believes
that
its
non-GAAP
financial
measures
are
useful
to
investors
because
they
provide
an
alternative
method
for
assessing
the
Company’s
ongoing
operating
results,
for
measuring
the
Company’s
cash
flow
and
liquidity,
and
for
comparing
the
Company’s
financial
performance
to
other
companies.
The
Company’s
management
uses
these
non-GAAP
financial
measures
for
the
same
purpose,
and
for
planning
and
forecasting
purposes.
The
presentation
of
non-GAAP
financial
measures
is
not
meant
to
be
a
substitute
for
financial
measures
prepared
in
accordance
with
GAAP.
The
Company
defines
Adjusted
EBITDA
as
reported
GAAP
earnings
before
the
following
items:
interest
expense,
depreciation,
depletion
and
amortization,
interest
and
other
income,
impairments,
items
impacting
comparability
and
income
taxes. |
 Appendix
National Fuel Gas Company
59
Reconciliation of Adjusted EBITDA to Consolidated Net Income
($ Thousands)
FY 2010
FY 2011
FY 2012
Exploration & Production - West Division Adjusted EBITDA
187,838
$
187,603
$
226,897
$
215,042
$
217,150
$
206,875
$
Exploration & Production - All Other Divisions Adjusted EBITDA
139,624
189,854
170,232
277,341
322,322
332,332
Total Exploration & Production Adjusted EBITDA
327,462
$
377,457
$
397,129
$
492,383
$
539,472
$
539,207
$
Total Adjusted EBITDA
Exploration & Production Adjusted EBITDA
327,462
$
377,457
$
397,129
$
492,383
$
539,472
$
539,207
$
Pipeline & Storage Adjusted EBITDA
120,858
111,474
136,914
161,226
186,022
186,799
Gathering Adjusted EBITDA
2,021
9,386
14,814
29,777
64,060
73,437
Utility Adjusted EBITDA
167,328
168,540
159,986
171,669
164,643
162,779
Energy Marketing Adjusted EBITDA
13,573
13,178
5,945
6,963
10,335
12,359
Corporate & All Other Adjusted EBITDA
408
(12,346)
(10,674)
(9,920)
(11,078)
(11,515)
Total Adjusted EBITDA
631,650
$
667,689
$
704,114
$
852,098
$
953,454
$
963,066
$
Total Adjusted EBITDA
631,650
$
667,689
$
704,114
$
852,098
$
953,454
$
963,066
$
Minus: Net Interest Expense
(90,217)
(75,205)
(82,551)
(89,776)
(90,107)
(88,818)
Plus: Other Income
6,126
5,947
5,133
4,697
9,461
10,416
Minus: Income Tax Expense
(137,227)
(164,381)
(150,554)
(172,758)
(189,614)
(189,349)
Minus: Depreciation, Depletion & Amortization
(191,199)
(226,527)
(271,530)
(326,760)
(383,781)
(393,414)
Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax (Corp. & All Other)
6,780
-
-
-
-
-
Plus: Gain on Sale of Unconsolidated Subsidiaries (Corp. & All
Other) -
50,879
-
-
-
-
Plus: Elimination of Other Post-Retirement Regulatory Liability
(P&S) -
-
21,672
-
-
-
Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P)
-
-
(6,206)
-
-
-
Minus: New York Regulatory Adjustment (Utility)
-
-
-
(7,500)
-
-
Rounding
-
-
(1)
-
-
-
Consolidated Net Income
225,913
$
258,402
$
220,077
$
260,001
$
299,413
$
301,901
$
Consolidated Debt to Total Adjusted EBITDA
Long-Term Debt, Net of Current Portion (End of Period)
1,049,000
$
899,000
$
1,149,000
$
1,649,000
$
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
-
85,600
172,900
Total Debt (End of Period)
1,249,000
$
1,089,000
$
1,570,000
$
1,649,000
$
1,734,600
$
1,821,900
$
Long-Term Debt, Net of Current Portion (Start 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 (Start of Period)
-
200,000
150,000
250,000
-
-
Notes Payable to Banks and Commercial Paper (Start of Period)
-
-
40,000
171,000
-
-
Total Debt (Start of Period)
1,249,000
$
1,249,000
$
1,089,000
$
1,570,000
$
1,649,000
$
1,649,000
$
Average Total Debt
1,249,000
$
1,169,000
$
1,329,500
$
1,609,500
$
1,691,800
$
1,735,450
$
Average Total Debt to Total Adjusted EBITDA
1.98 x
1.75 x
1.89 x
1.89 x
1.77 x
1.80 x
FY 2013
12-Months
Ended 12/31/14
FY 2014 |
 Appendix
National Fuel Gas Company
Reconciliation of Segment Capital Expenditures to
Consolidated Capital Expenditures
($ Thousands)
FY 2015
FY 2010
FY 2011
FY 2012
FY 2013
FY 2014
Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures
398,174
$
648,815
$
693,810
$
533,129
$
602,705
$
$525,000-575,000
Pipeline & Storage Capital Expenditures
37,894
129,206
144,167
56,144
$
139,821
$
$225,000-275,000
Gathering Segment Capital Expenditures
6,538
17,021
80,012
54,792
$
137,799
$
$125,000-175,000
Utility Capital Expenditures
57,973
58,398
58,284
71,970
$
88,810
$
$115,000-130,000
Energy Marketing, Corporate & All Other Capital Expenditures
773
746
1,121
1,062
$
772
$
-
Total
Capital Expenditures from Continuing Operations 501,352
$
854,186
$
977,394
$
717,097
$
969,907
$
$990,000-1,155,000
Capital Expenditures from Discountinued Operations
All Other Capital Expenditures
150
$
-
$
-
$
-
$
-
$
-
$
Plus (Minus)
Accrued Capital Expenditures Exploration & Production FY 2014 Accrued Capital
Expenditures -
$
-
$
-
$
-
$
(80,108)
$
Exploration & Production FY 2013 Accrued Capital Expenditures
-
-
-
(58,478)
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
19,517
-
-
-
-
-
Pipeline & Storage FY 2014 Accrued Capital Expenditures
-
-
-
-
(28,122)
Pipeline & Storage FY 2013 Accrued Capital Expenditures
-
-
-
(5,633)
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
-
-
-
-
-
-
Gathering FY 2014 Accrued Capital Expenditures
-
-
-
-
(20,084)
Gathering FY 2013 Accrued Capital Expenditures
-
-
-
(6,700)
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
-
-
-
-
-
Utility FY 2014 Accrued Capital Expenditures
-
-
-
-
(8,315)
Utility FY 2013 Accrued Capital Expenditures
-
-
-
(10,328)
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 (58,401)
$
(39,908)
$
57,613
$
(13,636)
$
(55,490)
$
-
$
Eliminations
-
$
-
$
-
$
-
$
-
$
-
$
Total
Capital Expenditures per Statement of Cash Flows 443,101
$
814,278
$
1,035,007
$
703,461
$
914,417
$
$990,000-1,155,000
60 |