Attached files
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| 8-K - FORM 8-K - NATIONAL FUEL GAS CO | d770571d8k.htm |
 National Fuel Gas Company
Investor Presentation
August 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 Forms
10-Q for the quarters ended December 31, 2013, March 31, 2014 and June 30, 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. |
 National Fuel Gas Company
Exceptional Assets, Focused on Execution
3
1.549
Tcfe
of
Proved
Reserves
(1)
800,000 Net Acres in Pennsylvania
3.0
MMBbl
of
Crude
Oil
Production
(2)
$235
Million
of
Midstream
Adjusted
EBITDA
(2)
(3)
(1)
As of September 30, 2013
(2)
12 months ended June 30, 2014. Midstream includes the Pipeline & Storage segment and
Gathering segment (3)
A reconciliation of Adjusted EBITDA to Net Income is included at the end of this
presentation |
 National Fuel Gas Company
Targeting Sustained EBITDA Growth Over the Next Five Years
4
2014 –
2018
10-15%
Forecasted
Adjusted EBITDA
CAGR
$164
$167
$169
$160
$172
$174
$131
$121
$111
$137
$161
$181
$53
$280
$327
$377
$397
$492
$531
$581
$632
$668
$704
$852
$939
$0
$250
$500
$750
$1,000
$1,250
2009
2010
2011
2012
2013
12-Months
Ended
6/30/14
2014
Forecast
2015
Forecast
Fiscal Year
Exploration & Production Segment
Gathering Segment
Pipeline & Storage Segment
Utility Segment
Energy Marketing & Other
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. |
 National Fuel Gas Company
Capital Spending Adjusts to Capitalize on Opportunities
5
$56
$58
$58
$58
$72
$85-$90
$95-$105
$53
$38
$129
$144
$56
$130-
$140
$200-
$250
$80
$55
$135-
$145
$125-
$175
$188
$398
$649
$694
$533
$575-
$625
$650-
$750
$307
(1)
$501
$854
$977
$717
$925-
$1,000
$1,070-
$1,280
$0
$250
$500
$750
$1,000
$1,250
$1,500
2009
2010
2011
2012
2013
2014
Forecast
2015
Forecast
Fiscal Year
Exploration & Production Segment
Gathering Segment
Pipeline & Storage Segment
Utility Segment
Energy Marketing & Other
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)
41%
$3.990 Billion
As of June 30, 2014
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
Shareholders’
Equity
59%
2.02 x
1.98 x
1.75 x
1.89 x
1.89 x
1.76 x
0.0
0.5
1.0
1.5
2.0
2.5
2009
2010
2011
2012
2013
12-Months
Ended
6/30/14
Fiscal Year |
 National Fuel Gas Company
Dividend Track Record
7
Current
Dividend Yield
(1)
2.2%
Dividend Consistency
Consecutive Dividend Payments
112 Years
Consecutive Dividend Increases
44 Years
Current Annualized Dividend Rate
$1.54 per Share
(1) As of August 6, 2014
$0.00
$0.50
$1.00
$1.50
$2.00
Annual Rate at Fiscal Year End |
 8
Exploration & Production
Overview |
 Seneca Resources
Proven Record of Growth
9
Fiscal
Years
3-Year
F&D Cost
(1)
($/Mcfe)
2006-2008
$7.63
2007-2009
$5.35
2008-2010
$2.37
2009-2011
$2.09
2010-2012
$1.87
2011-2013
$1.67
(1)
Represents a three-year average U.S. finding and development cost
2000
1500
1000
500
0
Natural Gas (Bcf)
Crude Oil (MMbbl)
503
528
700
935
1,246
1,549
1,300
988
675
428
249
226
46.2
46.6
45.2
43.3
42.9
41.6
2008
2009
2010
2011
2012
2013
At September 30
2013 F&D Cost = $1.31
Marcellus F&D: $0.99
Doubled Proved Reserves
71% Proved Developed
Since 2010 |
 Seneca Resources
Delivering Tremendous Production Growth
10
19.8
19.2
20.5
20.0
21
21-23
16.5
43.2
62.9
100.7
139-147
159-197
13.3
49.7
67.6
83.4
120.7
160-168
180-220
0
75
150
225
2010
2011
2012
2013
2014
Forecast
2015
Forecast
Fiscal Year
Gulf of Mexico (Divested in 2011)
East Division (Appalachia)
West Division (California) |
 Seneca Resources
Disciplined Capital Spending
11
$31
$28
$47
$63
$105
$70-$90
$65-$95
$139
$356
$596
$631
$428
$505-
$535
$585-
$655
$188
(1)
$398
$649
$694
$533
$575-$625
$650-$750
$0
$200
$400
$600
$800
$1,000
2009
2010
2011
2012
2013
2014
Forecast
2015
Forecast
Fiscal Year
Gulf of Mexico (Divested in 2011)
East Division (Appalachia)
West Division (California)
(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 |
 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 and $0.35 to $0.40 per Mcfe for fiscal 2015, respectively
(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 2014 and fiscal 2015, respectively
Seneca expects to match its long-term firm
transport (FT) contracts with firm sales (FS)
agreements, with the cost of transportation
reflected in price realization. As such, it is
not included in LOE.
$4.50
$3.00
$1.50
$0.00
2008
2009
2010
2011
2012
2013
2014
2015
Forecast
Forecast
Fiscal Year
Property, Franchise & Other Taxes
Other O&M Expense
General & Administrative Expense
Lease Operating & Transportation Expense (Gathering Only)
Lease Operating & Transportation Expense (Excl. Gathering)
$2.56
$2.42
$2.23
$2.09
$2.01
$1.74
$1.65
$1.55
$1.35
$1.26
$1.17
$0.91
$0.76
$0.65
$0.52
(2)
$0.50
(2)
$0.60
$0.69
$0.64
$0.73
$0.65
$0.52
$0.43
(1)
$0.38
(1)
$0.28
$0.20
$0.21
$0.18
$0.28
$0.14
$0.15
$0.10
$0.17
$0.24
$0.34
$0.48
(2)
$0.50
(2) |
 Marcellus Shale
Prolific Pennsylvania Acreage
13
Eastern
Development
Area
(EDA)
Western
Development
Area
(WDA)
Seneca Lease
Seneca Fee
720,000 Acres
60,000 Acres
Average net revenue interest (NRI): 98%
No lease expiration
No royalty on most acreage
Significant economies of scale
Highly contiguous
1,700 to 2,000 locations de-risked
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
Drilling activity will HBP key acreage |
 Marcellus Shale
EDA Delivering Significant Growth
14
Covington –
Fully Developed
Gross Production: ~50 MMcf per Day
47 Wells Drilled and Producing
DCNR Tract 595
Gross Production: ~80 MMcf per Day
45 Wells Drilled
(1)
(52 Total Locations)
32 Wells Producing
DCNR Tract 100
Gross Production: ~300 MMcf per Day
58 Wells Drilled
(2)
(70 Total Locations)
53 Wells Producing
(2)
Gamble
(1)
One well included in this total is drilled into the Geneseo Shale
(2)
One well included in this total is drilled into and producing from the Geneseo Shale
Recently, 30 to 50 future locations
were added in Lycoming County
3 Wells Drilled; 1 Well Producing |
 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
6.2
5.2
8.1
4,736’
1.72
Tract 100
Lycoming
County
42
(1)
16.4
14.4
12.2
12.2
5,152’
2.37
(1)
Does not include a Geneseo well and ten new Marcellus Shale wells with less than 30 days of
production history. |
 Marcellus Shale
Huge High Quality Position
16
Tier I
~200,000 Acres
Northeast Core
~30,000 acres in NE Core
Tier I Acres
~200,000 acres
Economic at $2.80 to $3.80/Mcfe
Longer-Term Evaluation
~250,000 acres
(Minimal Lease Expiration)
Requires Gas Price Above $4/Mcf
~300,000 acres
Understanding Seneca’s
780,000 Net Acres
Seneca Fee
Seneca Lease Size of combined
EDA current development areas
|
 Marcellus Shale
2014 & 2015 WDA Delineation Program
17
Heath
Utica Core
Marcellus Horizontal
1 Well Completed
Sulger Farms
Marcellus Horizontal
1 Well Completed
Hemlock
2 Marcellus Horizontals
Beechwood
Marcellus Horizontal
1 Well Drilled
West Branch
Marcellus Horizontal
Beechwood
Marcellus Horizontal
SRC Fee Acreage
SRC Lease Acreage EOG Earned JV
Acreage
2013 Appraisal
2014 Appraisal 2015
Appraisal |
 Marcellus Shale
Strong Wells Across WDA Acreage
18
Area
Producing
Well Count
Peak
24-Hour Rate
(MMcfd)
Average
7-Day (MMcf/d)
Average Treatable
Lateral Length
Clermont/Rich Valley
Elk, Cameron & McKean
counties
13
8.0
7.0
5,364’
WDA Development Areas:
WDA Delineation Areas:
Area
Producing
Well Count
Peak
24-Hour Rate
(MMcfd)
Average
7-Day (MMcf/d)
Treatable
Lateral Length
Ridgway
Elk County
1
7.1
6.4
5,537’
Church Run
Elk County
1
4.8
4.5
4,435’
Owl’s Nest
Elk & Forest counties
1
6.1
5.8
6,137’
Sulger Farms
Jefferson County
1
6.1
5.6
5,778’ |
 Marcellus Shale
Clermont Wells Improved from Early Non-Op JV Wells
19
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
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
0
5
10
15
20
25
30
Days On
9H
10H
COP 2316 5H
COP 2316 6H
SRC Clermont vs. Non-Op JV Clermont
9H: RCS Completion (150’
stage spacing)
10H: Standard Completion (240’
stage spacing)
Non-Op JV Wells (5H, 6H) |
 Marcellus Shale
Clermont/Rich Valley RCS Wells Outperforming Typecurve
20
Rich Valley 27H -
6,372 FT -
RCS
Clermont 9H -
5,500 FT -
RCS
Clermont 10H -
5,565 FT -
non RCS
Typecurve -
6,000 FT -
6.9 Bcf
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
0
6
12
18
24
30
36
Months |
 Marcellus Shale
CRV is in Full Development Mode
21
Marcellus Faults
Marcellus & Basement Faults
SRC Lease Acreage
SRC Fee Acreage
Pad D08-N:
Spacing Test
Pad
E09-E
Pad
C08-G
Rich Valley 2
nd
Well
7-day IP: 4.5 MMcf/d
Lateral Length: 4,492’
Rich Valley
7-day IP: 7.8 MMcf/d
EUR: 7.4 BCF
Lateral Length: 6,372’
Clermont
RCS: 9H 7-day IP:
10.0 MMcf/d
(EUR: 8.6 Bcf)
Non-RCS: 10H 7-day IP:
7.4 MMcf/d
Pad
D08-G
Planned Wells
Drilled Wells
Producing Wells
Pad
C08-F
Pad
D09-D
JV Wells
Pad
C08-D
200-250 Horizontal Locations
Pad
E09-H |
 Marcellus Shale
200,000 Acres With 6-8 Bcfe EUR Wells
22
SRC Lease Acreage
SRC Fee Acreage
EOG Earned JV Acreage
2014 Appraisal Program
2015+ Locations
4 -
6 BCF/well
6 -
8 BCF/well
2-4 BCF/well
2-4 BCF/well
Note: Assumes 6,000’
treated lateral length
4 -
6 BCF/well |
 Marcellus Shale
Position Offers Attractive Economics 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)
EASTERN DEVELOPMENT AREA (EDA)
Tract 100
Lycoming
Dry Gas
18
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
Covington
Tioga
Dry Gas
Developed
5.8
1,030
22%
$3.49
WESTERN DEVELOPMENT AREA (WDA)
Clermont/Rich Valley
Elk/Cameron
Dry Gas
219
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
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
(1)
Internal Rate of Return (IRR) includes estimated well costs under current cost structure, LOE,
and Gathering tariffs anticipated for each prospect |
 Natural Gas Marketing
How Does Seneca Sell its Production?
24
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
Breakeven economics based on a
realized price after gathering
Spot Market |
 Natural Gas Marketing
Adding Long-Term Firm Transport to the Portfolio
25
Project
(Counterparty)
In-
Service
Date
Contract
Term
Delivery
Market
FT Capacity (Dth/day)
Matched Firm Sales
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/ TETCO)
Nov.
2015
15 years
Canada/
TETCO
---
170,000
170,000
170,000
Executed Contracts
140,000 Dth/d
for 15 years
Northern Access
2016 (NFG/
TransCanada/
Union)
Nov.
2016
15 years
Canada
---
---
350,000
350,000
Evaluating marketing
opportunities
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
570,000
759,405
(1)
A large majority of the executed firm sales agreements continue for the remainder of the
firm transportation contract term. |
 Natural Gas Marketing
Significant Base of Long-Term Firm Contracts
26
Over
time,
Seneca
plans
to
enter
into
firm
sales
agreements
to support all of its firm transportation capacity
Atlantic Sunrise
Northern Access 2016
Niagara Expansion/
Northern Access 2015
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
Base Firm Sales Contracts
Firm Sales Matched to Firm Transport Capacity
Additional Firm Transport Capacity
250
500
750
1,000
- |
 Natural Gas Marketing
Firm Sales Provide a Market for Appalachian Production
27
27
EDA
336,532 Dth/d
318,032 Dth/d
320,036 Dth/d
280,036 Dth/d
280,036 Dth/d
WDA
51,353 Dth/d
44,470 Dth/d
41,100 Dth/d
20,000 Dth/d
20,000 Dth/d
(1)
Fixed price sales contracts totaling 50,000 Dth/day at an average fixed price of $3.77
starting November 2014 through October 2017 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.
Dominion
145,000
Less: $0.44
NYMEX
242,885
Less: $0.72
387,885
362,502
361,136
300,036
300,036
Q4
FY 2014
Q1
FY 2015
Q2
FY 2015
Q3
FY 2015
Q4
FY 2015
Dominion
111,848
Less: $0.43
NYMEX
217,502
Less: $0.47
33,152
Fixed $3.77
(1)
Dominion
95,000
Less: $0.43
NYMEX
216,136
Less: $0.42
50,000
Fixed $3.77
Dominion
85,000
Less: $0.47
NYMEX
165,036
Less: $0.34
50,000
Fixed $3.77
Dominion
85,000
Less: $0.47
NYMEX
165,036
Less: $0.34
50,000
Fixed $3.77
100,000
200,000
300,000
400,000
500,000
Fixed Price
NYMEX
Dominion South Point
0 |
 Natural Gas Marketing
Current Natural Gas Hedge Positions
28
(1)
2014 hedge positions are for the remaining three months of the fiscal year. Full details
can be found in the appendix. (1)
7.2
18.7
18.8
18.8
22.3
70.7
37.8
25.0
9.0
3.0
29.8
90.6
65.7
46.8
5.6
0
25
50
75
100
125
2014
2015
2016
2017
2018
Fiscal Year
Dominion
NYMEX
Other |
 Natural Gas Marketing
Current Hedge Book has Seneca Positioned Very Well
29
(1)
2014 hedge positions are for the remaining three 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
$4.07/MMBtu
$4.10/MMBtu
$4.12/MMBtu
$4.22/MMBtu
$4.59/MMBtu
Crude Oil
$100.22/Bbl
$95.27/Bbl
$92.95/Bbl
$92.30/Bbl
$91.00/Bbl
(1)
63%
50%
34%
9%
1%
64%
48%
29%
17%
2%
0%
20%
40%
60%
80%
100%
Fiscal
2014
Fiscal
2015
Fiscal
2016
Fiscal
2017
Fiscal
2018
Hedging Policy Range
Oil Hedges
Natural Gas Hedges |
 Natural Gas Marketing
FY 2014 Production –
Firm Sales & Hedge Composition
30
Price Certainty
Price Certainty
98.8 Bcf
18.3
Bcf
7.0 Bcf
9.5 Bcf
5.5 Bcf
3.9 Bcf
139-147
0
30
60
90
120
150
Q1 -
Q3
DOM
East Division
Production
NYMEX
Firm Sales
Firm Sales
Fixed Price
Sales
EDA
Spot Sales
WDA
Total Spot Sales
East Division
Production |
 Natural Gas Marketing
FY 2015 Production –
Firm Sales & Hedge Composition
31
Price Certainty
Seneca will continue to pursue firm
sales agreements to mitigate spot
market exposure during the year
Price Certainty
58.2 Bcf
18.0 Bcf
13.6 Bcf
41.4 Bcf
36.8 Bcf
10.0 Bcf
159-197
0
50
100
150
200
NYMEX
Firm Sales
DOM
Firm Sales
Fixed Price Sales
EDA
Spot Sales
WDA
Spot Sales
Total
East Division
Production |
 Geneseo Shale
Path to Geneseo Development –
2018/2019 Start
32
Tract
100/Gamble
(Lycoming
County)
Geneseo Well
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:
13 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 |
 Point Pleasant & Utica Shale
Industry Activity & 2014 Appraisal Program
33
Heath
Cored
May 2014
RANGE RESOUCES
1.4 MMcf/d
“Not Effectively
Stimulated”
HALCON
2.5 MMcf/d,
360 Bbls/d
HALCON
4.5 MMcf/d,
860 Bbls/d
HALCON
6.6 MMcf/d,
750 Bbls/d
CHESAPEAKE
6.4 MMcf/d
RANGE
4.4 MMcf/d
REX
9.2 MMcf/d
TIONESTA
Horizontal: Completed Fall 2012
Peak 24-Hour Rate: 3.9 MMcf/d
MT JEWETT
Horizontal: Completed September 2013
Peak 24-Hour Rate: 8.5 MMcf/d
DCNR 007
Core & Drill
August 2014 |
 California
Stable Production Fields; Modest Growth Potential
34
East Coalinga
Temblor Formation
Primary
North Lost Hills
Tulare & Etchegoin Formation
Primary/Steamflood
South Lost Hills
Monterey Shale
Primary
North Midway Sunset
Tulare & Potter Formation
Steamflood
South Midway Sunset
Antelope Formation
Steamflood
Sespe
Sespe Formation
Primary
Key Areas of Focus in 2015
0
1,500
3,000
4,500
6,000
North
Midway
Sunset
South
Midway
Sunset
South
Lost Hills
North
Lost Hills
Sespe
East
Coalinga
2010
Q3 2014
1.
East
Coalinga
Evaluation
2.
South
Midway
Sunset
Extensions
3.
South
Lost
Hills
Monterey
Evaluation |
 California
East Coalinga Summary
35
Production has increased from 214 BOPD to
749 BOPD
•
Highest on leases since 2000
Drilled 12 evaluation wells in 2013
•
Producing ~150 BOPD
Currently drilling 31 new producers and 2
water disposal wells in 2014
2014 Location
2013 Well
Active Well
Idle Well
P&A
Seneca Lease
Field Boundary
0
100
200
300
400
500
600
700
800
900
1000
East Coalinga Daily Oil Production |
 California
South Midway Sunset Has Delivered Significant Growth
36
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
Increased daily production 310% to
approximately 1,700 BOPD
Drilled 102 new producers
Added 3.3 MMBO of proven reserves
Increased steam capacity by 280%
Identified opportunities for additional
pool development |
 California
Evaluating the Monterey Shale at South Lost Hills
37
Citrus 11
Upper Antelope A
Upper Antelope B
McDonald
Truman 1H
2013
190 BOEPD
Citrus 2H
Waiting on
Completion
Truman 2H
Waiting on
Completion
GR
SP
ResD
Brittleness
Gas
Oil
18 potential locations in
each of the three
horizons (concept)
Seneca Lease
Lower Reef Ridge
1000’ |
 California
Modest Growth Opportunities, But Strong Economics
38
Field
Average
Well Cost
Average
EUR
(MBO)
Estimated
IRR
@$100/Bbl
Fiscal 2015
Locations
South Midway Sunset
$250,000
30
75%
42
East Coalinga
$400,000
40
50%
25
Sespe –
Coldwater
$2,800,000
180
35%
4 |
 California
Modest Growth Anticipated in 2014 and 2015
39
Forecast
9,056
8,773
9,322
9,078
6,000
7,000
8,000
9,000
10,000
11,000
2010
2011
2012
2013
2014
(Est.)
2015
(Est.)
Fiscal Year |
 California
Outstanding Cash Flow
(1)
40
(1)
Adjusted EBITDA and Capital Expenditures represent Seneca Resources Corporation’s West
Division, which includes its activity in Kansas. A reconciliation of Adjusted EBITDA
to Net Income is included at the end of this presentation.
$31.4
$27.6
$47.4
$62.9
$104.6
$171.6
$187.8
$187.6
$226.9
$215.0
$0
$50
$100
$150
$200
$250
2009
2010
2011
2012
2013
Fiscal Year
Capital Expenditures
Adjusted EBITDA |
 California
Looking Forward
41
1.
Manage decline of base
production
2.
Pursue and develop opportunities
for growth from current assets
East Coalinga
Sespe
South Midway Sunset
3.
Continue to pursue additional
acquisition and farm-in
opportunities |
 Seneca Resources
What Will Seneca Look Like Moving Forward?
42
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
|
 43
Midstream Businesses
Overview |
 Midstream Businesses
Positioned to Serve Seneca’s Rapidly Growing Production
44 |
 Gathering
Gathering is the First Step to Reaching a Market
45
Trout Run
Gathering System
(In-Service)
Covington
Gathering System
(In-Service)
Clermont
Gathering System
(In-Service)
$17.5
$34.8
$72 -
$74
$90-
$110
$0
$30
$60
$90
$120
2009
2010
2011
2012
2013
2014E
2015E
Fiscal Year
Gathering Segment Revenue
Gathering Interconnects
TGP 300
Transco |
 Gathering
Gathering Systems Supporting Seneca’s EDA Production
46
Covington Gathering System
In-service date: November 2009
Capacity: 220,000 Dth per day
Interconnect: TGP 300
Capital expenditures (to date): $31.3 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): $154 million
Capital expenditures (future): $50 to $80 million
Fiscal Year Throughput by Project
(Covington & Trout Run Systems) |
 Compressor
Station Interconnect
Gathering
Clermont Gathering System has Large Expandability
47
Clermont Gathering
System
In-Service: July 2014
Ultimate
Trunkline
Capacity:
1+ Bcf per day
Interconnects
TGP 300 and National Fuel
Gas Supply Corporation
(anticipated Nov. 2015)
Capital:
2014: $75 -
$100 million
2015: $115 -
$160 million
Seneca Pads Connected
SRC Pad N (9 wells)
connected July 2014
6 additional wells to be
connected in FY14
Up to 25 pads connected
following the 2015
expansion |
 Gathering
Capital Deployment Will Deliver Long-Term Growth
48
Revenue Growth (2013 to 2015): ~70%
CAGR
Capital Investment (2013 to 2015): ~65%
CAGR |
 Pipeline & Storage
Project Opportunities to Support WDA Growth
49
Develop multiple outlets
to high-value markets |
 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
$66 million
Northern Access 2016
(1)
$410 million
Total Capital
Expenditures
$476 million
Northern
Access 2015
(November 2015)
Northern
Access 2016
(Late 2016)
(1)
Previously referred to as the Clermont to Chippawa expansion project
Clermont |
 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: $66 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: Late 2016
System: NFG Supply Corp. &
Empire Pipeline, Inc.
Capacity
350,000 Dth per day
Interconnect
Chippawa (TransCanada)
Total Cost: ~$410 Million
Northern
Access 2016
(Late 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
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 49,000 Dth per day
Precedent agreements executed with
RG&E, NYSEG & NFG Distribution Corp.
Interconnect
Tuscarora (NFG/Supply)
Total Cost: $45 Million
Major Facilities
1,500 HP Compressor
17 miles –
12”/16”
Pipeline
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
139 MDth/d
Planned Projects (2014+)
Precedent Agreements Executed
Total Expansion (2009-2016+)
Capacity
Additions
1,932,000 Dth/day
(1)
Previously referred to as the Clermont to Chippawa expansion project
In-Service 2014
105,000 Dth/day
In-Service 2015
364,000 Dth /day
In-Service 2016+
350,000 Dth/day |
 58
Utility
Overview |
 Utility
New York & Pennsylvania Service Territories
59
Total Customers: 522,000
Rate Mechanisms:
Revenue Decoupling
Weather Normalization
Low Income Rates
Merchant Function Charge
90/10 Sharing (Large Customers)
NY PSC Rate Case Settlement, May 2014
Rates Unchanged
9.1% ROE Confirmed
2-Tier Earnings Sharing Mechanism
9.5% to 10.5% -
Share 50%
10.5% > -
Share 80%
$8.2 MM CapEx -
system replacement
$8.0 MM incremental O&M
Natural Gas Vehicle Pilot Program
Total Customers: 213,000
Rate Mechanisms:
Low Income Rates
Merchant Function Charge
ROE: Black Box Settlement (2007)
(post-retirement benefits)
(Uncollectibles Adjustment)
New York
Pennsylvania |
 Utility
Shifting Trends in Customer Usage
60
Residential Usage
Industrial Usage
(1)
Weighted Average of New York and Pennsylvania service territories (assumes normal
weather) |
 Utility
A Proven History of Controlling Costs
61 |
 Utility
Capital Spending Largely Focused on Maintenance
62
The Utility remains focused on maintaining the
ongoing safety and reliability of its system
Near-term increase in capital
expenditures is due to the
approx. $60MM upgrade of
the Utility’s Customer
Information System (CIS) |
 National Fuel Gas Company
A History of Success & A Future of Opportunity
63
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 |
 64
Appendix |
 National Fuel Gas Company
Current Hedge Positions
65
Fiscal
Year
NYMEX
Volume
(MMBtu)
Avg
Price
Dominion
Volume
(MMBtu)
Avg
Price
SoCal
Volume
(MMBtu)
Avg
Price
MichCon
Volume
(MMBtu)
Avg
Price
Total
Volume
(MMBtu)
Avg
Price
2014
(1)
22,260,000
$4.07
7,200,000
$4.06
300,000
$4.35
-
-
29,760,000
$4.07
2015
70,690,000
$4.16
18,720,000
$3.88
1,200,000
$4.35
-
-
90,610,000
$4.10
2016
37,840,000
$4.25
18,840,000
$3.88
-
-
9,000,000
$4.10
65,680,000
$4.12
2017
24,960,000
$4.49
18,840,000
$3.88
-
-
3,000,000
$4.10
46,800,000
$4.22
2018
5,550,000
$4.59
-
-
-
-
-
-
5,550,000
$4.59
Natural Gas Hedges ($/MMBtu)
Fiscal
Year
MWSS
Volume
(Bbl)
Average
Price
Brent
Volume
(Bbl)
Average
Price
NYMEX
Volume
(Bbl)
Average
Price
Total
Volume
(Bbl)
Average
Price
2014
(1)
156,000
$95.68
336,000
$102.32
-
-
492,000
$100.22
2015
258,000
$92.10
903,000
$98.42
396,000
$90.14
1,557,000
$95.27
2016
36,000
$92.10
933,000
$95.18
300,000
$86.09
1,269,000
$92.95
2017
-
-
384,000
$92.30
-
-
384,000
$92.30
2018
-
-
75,000
$91.00
-
-
75,000
$91.00
Crude Oil Hedges ($/Bbl)
(1)
2014 hedge positions are for the remaining three months of the fiscal year
|
 National Fuel Gas Company
Comparable GAAP Financial Measure Slides and Reconciliations
66
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. |
 67
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
$
212,822
$
Exploration & Production - All Other Divisions Adjusted EBITDA
108,139
139,624
189,854
170,232
277,341
318,100
Total Exploration & Production Adjusted EBITDA
279,711
$
327,462
$
377,457
$
397,129
$
492,383
$
530,922
$
Total Adjusted EBITDA
Exploration & Production Adjusted EBITDA
279,711
$
327,462
$
377,457
$
397,129
$
492,383
$
530,922
$
Pipeline & Storage Adjusted EBITDA
130,857
120,858
111,474
136,914
161,226
181,333
Gathering Adjusted EBITDA
(141)
2,021
9,386
14,814
29,777
53,391
Utility Adjusted EBITDA
164,443
167,328
168,540
159,986
171,669
173,947
Energy Marketing Adjusted EBITDA
11,589
13,573
13,178
5,945
6,963
7,415
Corporate & All Other Adjusted EBITDA
(5,434)
408
(12,346)
(10,674)
(9,920)
(8,508)
Total Adjusted EBITDA
581,025
$
631,650
$
667,689
$
704,114
$
852,098
$
938,500
$
Total Adjusted EBITDA
581,025
$
631,650
$
667,689
$
704,114
$
852,098
$
938,500
$
Minus: Net Interest Expense
(81,013)
(90,217)
(75,205)
(82,551)
(89,776)
(91,396)
Plus: Other Income
9,762
6,126
5,947
5,133
4,697
7,878
Minus: Income Tax Expense
(52,859)
(137,227)
(164,381)
(150,554)
(172,758)
(190,962)
Minus: Depreciation, Depletion & Amortization
(170,620)
(191,199)
(226,527)
(271,530)
(326,760)
(366,133)
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)
(7,200)
Minus: Plugging and Abandonment Accrual (E&P)
-
-
-
-
-
(862)
Rounding
-
-
-
(1)
-
-
Consolidated Net Income
100,708
$
225,913
$
258,402
$
220,077
$
260,001
$
289,825
$
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
1,649,000
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
171,000
-
Total Debt (Start of Period)
1,099,000
$
1,249,000
$
1,249,000
$
1,089,000
$
1,570,000
$
1,649,000
$
Average Total Debt
1,174,000
$
1,249,000
$
1,169,000
$
1,329,500
$
1,609,500
$
1,649,000
$
Average Total Debt to Total Adjusted EBITDA
2.02 x
1.98 x
1.75 x
1.89 x
1.89 x
1.76 x
FY 2013
12-Months
Ended 6/30/14 |
 68
Reconciliation of Segment Capital Expenditures to
Consolidated Capital Expenditures
($ Thousands)
FY 2014
FY 2015
FY 2009
FY 2010
FY 2011
FY 2012
FY 2013
Forecast
Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures
188,290
$
398,174
$
648,815
$
693,810
$
533,129
$
$575,000-625,000
$650,000-750,000
Pipeline & Storage Capital Expenditures
52,504
37,894
129,206
144,167
56,144
$
$130,000-140,000
$200,000-250,000
Gathering Segment Capital Expenditures
9,433
6,538
17,021
80,012
54,792
$
$135,000-145,000
$125,000-175,000
Utility Capital Expenditures
56,178
57,973
58,398
58,284
71,970
$
$85,000-90,000
$95,000-105,000
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
$
$925,000-1,000,000
$1,070,000-1,280,000
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
$
$925,000-1,000,000
$1,070,000-1,280,000 |