Attached files
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| 8-K - FORM 8-K - EXCO RESOURCES INC | d8k.htm |
 PPT-169 –
Barclay’s September 2010
Barclay’s Capital CEO Energy-Power Conference
September 15, 2010
Exhibit 99.1 |
 EXCO
Resources, Inc. 2
PPT-169 –
Barclay’s September 2010
Key Investment Highlights
•
EXCO is positioned for growth
–
Targeting 30% growth for the next five years
•
Strong position in Haynesville/Bossier and Marcellus shale plays
–
8,800 potential drilling locations
•
Joint Ventures with BG Group
–
Accelerates
development
of
Haynesville/Bossier
and
Marcellus
and
infrastructure
•
Operational and technical expertise
–
Technical headcount has increased more than 200% since January 2008
•
Significant held-by-production acreage
–
Development pace driven by returns, not lease expirations
•
Strong balance sheet
–
Target funding drilling program within cash flow
•
EXCO is poised to thrive in low price environment
–
Focused in core shale areas where a 20% pre-tax IRR can be achieved at current
prices •
Experienced management team with successful track record and significant inside
ownership
–
Officers and directors represent 32.8% of shares outstanding
|
 3
PPT-169 –
Barclay’s September 2010
Delivering What We Promise
Joint venture partner
–
Joint ventures with BG Group position EXCO for dramatic upstream
and midstream growth
–
Combined JV’s netted $1.8 billion of cash and $550 million carry on future
drilling through sale of 50% in all production, acreage and associated
midstream assets in JV areas Asset sales
–
Closed ~$1.1 billion in additional divestitures during 2009
Debt reduction
(1)
–
Reduced debt by approximately $2.1 billion or ~67%
–
Increased liquidity to ~$1.2 billion
Shifted strategy
–
Strategic
shift
from
acquisition
focus
to
organic
growth
through
development
of
existing assets
Focus on core areas of our shale plays
–
All drilling and acreage additions in specific areas of the plays
–
Since
late
2008,
we
have
spud
more
than
100
wells
and
produced
over
100
Bcf
of
gross
natural gas to sales in the Haynesville shale
–
Recently added 47,600 net acres (23,800 net to EXCO) in the Shelby Trough; we
believe a majority of the acreage is comparable to our DeSoto
Parish position
(1)
Pro forma for $750 million bond issuance |
 4
PPT-169 –
Barclay’s September 2010
Production Profile
Positioned for growth while exceeding our economic hurdles in low price
environment •
Focused portfolio on Haynesville, Bossier and Marcellus shales
•
On track to deliver significant organic production growth in 2010 and beyond
-
50
100
150
200
250
300
350
400
450
$-
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
$4,500
Actual production
Production guidance midpoint
Net debt outstanding |
 Company
Overview
and
Reserve
Base
(1)
High quality portfolio focused on shale resources
Texas
Texas
Louisiana
Louisiana
Pennsylvania
Pennsylvania
West
West
Virginia
Virginia
EXCO Operations Area
•
Reserve life of
10.3
years
and 62% Proved Developed
•
260 Bcf
of shale assets
booked as proved with
potential for significant
future reserve adds
•
Strong position in
Haynesville/Bossier and
Marcellus shale plays
–
8,800 potential drilling
locations
•
80,000
net
acres
in
the
Haynesville play and
pursuing additional leasing
opportunities
•
113,000
net
acres
in
the
Marcellus play and
pursuing additional leasing
opportunities
(1)
The reserve estimates provided throughout this document are pro forma for the Common
and Appalachia JV transactions and effective as of 3.31.10 with 3.31.10 NYMEX strip pricing, adjusted for differentials and excluding
hedge effects, unless otherwise noted
(2)
Haynesville
and
Marcellus
acreage
throughout
this
document
is
net
to
EXCO’s
interest
in
the
JVs;
assumes
BG
Group
exercises
their
option
to
purchase
50%
of
recently
acquired
acreage
Proved Reserves = 1.2 Tcfe
3P Reserves = 3.6 Tcfe
3P+ Reserves = 12.5 Tcfe
Current Net Production = 320 Mmcfe/d
Net
acreage
(2)
:
602,000
Proved Total: 0.1 Tcfe
3P Reserves = 0.1 Tcfe
3P+ Reserves = 0.3 Tcfe
Production: 20 Mmcfe/d
Net acreage: 98,000
Permian
Appalachia
Proved Total: 0.2 Tcfe
3P Reserves = 0.2 Tcfe
3P+ Reserves = 5.9 Tcfe
Production: 18 Mmcfe/d
Net acreage: 335,000
Proved Total: 0.9 Tcfe
3P Reserves = 3.3 Tcfe
3P+ Reserves = 6.3 Tcfe
Production: 262 Mmcfe/d
Net acreage: 169,000
East Texas / North Louisiana
PPT-169 –
Barclay’s September 2010
5 |
 6
PPT-169 –
Barclay’s September 2010
Liquidity and Financial Position
(1)
Includes $75.2
million of restricted cash at 6/30/10
(2)
Excludes bond premium or discount
(3)
Net of $15.2 million in letters of credit
(4)
LTM Adjusted EBITDA of $588.9 million pro forma for our joint venture transactions
with BG Group and 2009 divestitures as if each transaction occurred on June 30, 2009
•
Current liquidity of ~$1.2 billion pro forma for bond offering
Pro forma
Consolidated ($ in thousands)
June 30, 2010
June 30, 2010
Cash
(1)
173,273
$
173,273
$
Bank debt (L + 200 -
300bps)
477,500
197,870
7 1/4%
(2)
Senior notes due 2011
444,720
-
7 1/2%
(2)
Senior notes due 2018
-
750,000
Total debt
922,220
$
947,870
$
Net debt
748,947
$
774,597
$
Borrowing base
1,200,000
$
1,200,000
$
Unused borrowing base
(3)
707,300
$
986,930
Unused borrowing base plus cash
(3)
880,573
$
1,160,203
$
Credit statistics
Debt / PD reserves
1.27
$
Debt / proved reserves
0.79
$
Debt / Adjusted EBITDA (LTM)
(4)
1.6x |
 7
PPT-169 –
Barclay’s September 2010
Derivatives Position
As of June 30, 2010
•
Cash settlements for Q2 2010 totaled $46.5 million
•
Hedges added in Q2:
NG
Oil
2011
30 Mmcf/d
2012
20 Mmcf/d
250 Bbls/d
NYMEX
Contract
Contract
Contract
natural gas
price per
NYMEX oil
price per
Equivalent
price per
Mmcf
Mcf
Mbls
Bbl
Mmcfe
Equivalent
Q3 2010
13,940
7.16
$
113
114.96
$
14,616
7.72
$
Q4 2010
13,940
7.21
113
114.96
14,616
7.76
2011
31,025
6.54
548
111.32
34,310
7.69
2012
16,470
6.05
92
109.30
17,019
6.44
2013
5,475
5.99
-
-
5,475
5.99
Total
94,653
6.70
$
976
112.39
$
100,508
7.41
$ |
 8
PPT-169 –
Barclay’s September 2010
Capital Spending Summary
Approximately 75% of 2010 spending focused on shales
(1)
2010 budget excludes acquisitions. Leasing net of BG Group acreage
reimbursements. (2)
Related to acquisitions closed prior to June 30, 2010, of which $91 million has been
received as of June 30, 2010 •
Closed on $454 million of acquisitions
•
Expect to receive $131 million
(2)
of acquisition reimbursements from BG Group during 2010
$ in millions
Total 2010 Budget
(1)
Development capital expenditures
327
$
Leasing
62
Seismic
20
Gas gathering and water pipelines
23
Corporate and other
40
Capital expenditures before acquisitions
472
Investment in TGGT Holdings, LLC
75
Total investing activities before acquisitions
547
$
Corporate and other
8%
Gas gathering &
water pipelines
5%
Seismic
4%
Leasing
13%
Development capital
expenditures
70% |
 9
PPT-169 –
Barclay’s September 2010
Haynesville Overview
•
80,000 net Haynesville acres
with significant held by
production position
•
Optimizing drilling and
completion methods to improve
recoveries and reduce costs
•
Average IP rate from our
operated Haynesville horizontal
wells
in
our
core
DeSoto
Parish
area
continues
to
be
~23
Mmcf/d
•
Full scale development will
focus drilling in our core areas
with >20 Mmcf/d
IP’s
EXCO / BG
JV Area
Holly Field
Focus Area
Shelby Trough
Focus Area |
 Shelby
Trough
Focus
Area
Haynesville and Middle Bossier assets
•
Located in Shelby Trough
in Shelby, San Augustine
& Nacogdoches Counties,
TX
•
10
operated horizontal
shale wells flowing to
sales (9 Haynesville, 1
Bossier)
•
Large acreage holdings in
three areas totaling
approximately 60,800
gross & 47,600 net acres
(JV interest)
•
3 operated rigs currently
running
•
First EXCO operated
completion IP’d
at 22
Mmcf/d
EXCO Lease Position
Haynesville Shale Area
Haynesville Shale Well
Bossier Shale Well
10
PPT-169 –
Barclay’s September 2010
Prior Operator Results
•
Last 3 Haynesville wells:
–
21, 18 and 22 IP’s
•
First Middle Bossier well:
–
11 Mmcf/d
IP
Haynesville
3 wells > 15 Mmcf/d
IP
Bossier
21 Mmcf/d
IP
Shelby
Focus Area
Haynesville
32 Mmcf/d
IP
Haynesville
32 Mmcf/d
IP
Haynesville
30 Mmcf/d
IP
Haynesville
31 Mmcf/d
IP
EXCO’s
1
well
22 Mmcf/d
IP
Bossier
20 Mmcf/d
IP
Bossier
12 Mmcf/d
IP
Bossier
9 Mmcf/d
IP
Haynesville
12 Mmcf/d
IP
st |
 11
PPT-169 –
Barclay’s September 2010
EXCO Operated Haynesville IP's
DeSoto Parish, LA
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
IP, Mcf/d
Haynesville IP Rate Consistency
23 Mmcf/d average IP in DeSoto Parish
(1)
•
Since operations have commenced in Q3 2008, we have spud in excess of 100
Haynesville operated horizontal wells
•
Monitor and control pressure drawdown on every well
•
Initiated pad drilling operations; simultaneously completed first 4 wells on a
single pad in June 2010 with total IP of 92 Mmcf/d
(1)
EXCO IP’s defined as highest 24 hour average flow rate to sales
Average Core DeSoto Parish Area
IP rate of 23 Mmcf/d |
 12
PPT-169 –
Barclay’s September 2010
Pad Drilling
EXCO’s
first 4 well, 80 acre spacing super pad -
IP rate of 92 Mmcf/d
•
4 wells drilled with 2 rigs on a
9 acre pad in DeSoto
Parish
•
Completed with 2 frac
fleets
•
20 million pounds of proppant
–
400 truckloads or 100
railroad cars
•
23 million gallons of water
–
35 Olympic size pools
•
Currently utilizing surface
water; constructing pipeline
project for water sourced from
nearby industrial plant
•
Monitoring performance with
microseismic
and pressure
observation
2 well heads
2 well heads |
 13
PPT-169 –
Barclay’s September 2010
EXCO
Gross
Operated
Haynesville
Shale
Forecast
(1)
Poised to deliver significant growth in Haynesville production
~2,000 Mmcf/d
Production (High Case)
Currently ~
500 Mmcf/d
Gross
~ 939 Mmcf/d
Production
~1,600 Mmcf/d
Production
•
Have secured firm transportation to ensure takeaway; continuing to evaluate
additional takeaway opportunities as needed
Firm Transportation
~1,700 Mmcf/d
Production (Low Case)
(1)
Forecasted production growth through 2012 is primarily based on our current drilling program of 22 rigs
running at year end 2010 (18 rigs running as of June 30, 2010), 22 rigs running during 2011 and 27 rigs
running during 2012, our year end Haynesville type curve of 6.6 Bcfe EUR, and current drilling and
completion timing |
 14
PPT-169 –
Barclay’s September 2010
•
Further efficiencies expected to reduce average well cost by ~$0.5 million
•
Current fracture stimulation costs have remained at Q2 2010 levels
•
Drilling costs have decreased since 2H ’09; expect to increase as a result of
deeper targets in the Shelby Trough area and certain directional drilling
Haynesville Well Costs and Rate of Return
Haynesville Well Cost Break-Down
2.4
2.1
1.8
2.5
1.4
1.0
1.0
1.2
1.0
2.7
2.4
3.6
2.8
2.6
0.9
$9.9
$9.3
$10.2
0
2
4
6
8
10
12
2H '09 Avg. Cost
Q1 Avg. Cost
Q2 Avg. Cost
Fracture Stimulation
Completion Other
Drilling Special Services
Rig Costs
OCTG
(1)
XCO Core Desoto / Shelby Asset locations
(2)
Industry average of 800+ Haynesville wells
IP
(Mmcf/d)
Gas price required to
achieve 20% pre-tax IRR
(per Mcf)
XCO Core
(1)
20
$4.00 -
$4.25
Industry Avg
(2)
13
$6.00 -
$6.25
@ $10mm Well D&C Costs |
 PPT-169 –
Barclay’s September 2010
Haynesville Type Curve
Significant upside from potential shallower decline rates
EXCO’s
current
proved type
curve
b = 1.75
EUR = 9.6 Bcfe
b = 1.25
EUR = 7.6 Bcfe
b = 1.00
EUR = 6.6
Bcfe
Year:
1 2
3 4
5
6 7
8
9
20 Mmcf/d
10 Mmcf/d
1 Mmcf/d
100 Mcf/d
10 Mcf/d
Avg
Haynesville IP
EUR Booked
EXCO Resources
23 Mmcf/d
6.7
Competitor A
17 Mmcf/d
7.5
Competitor B
15 Mmcf/d
7.5
15 |
 PPT-169 –
Barclay’s September 2010
Marcellus Overview
Well positioned acreage
Northeast PA Area
Avg
IP’s 6-12 Mmcf/d
Major Operators:
Talisman, Cabot, Chesapeake, East
Central PA Area
Avg
IP’s 4-7 Mmcf/d
Major Operators:
EXCO, Anadarko, Rex, EOG
Southwest PA Area
Avg
IP’s 4-10 Mmcf/d
Major Operators:
Range, Atlas, Consol
Northern WV Area
Avg
IP’s 4-7 Mmcf/d
Major Operators:
Chesapeake, EQT, Antero
EXCO Marcellus Acreage
Marcellus Fairway
16 |
 PPT-169 –
Barclay’s September 2010
•
2010 Drilling program
–
12 horizontal wells in
2010
–
Exit year with 3 rigs
running
•
Completion activity
–
Last well IP’d
at 4.0
Mmcf/d
from a 4,500’
lateral
•
Current and 30 day
average production
rates of 3.9 Mmcf/d
–
Currently completing
three 5,000’+ horizontal
laterals
•
Solidifying land position
–
Hold 113,000 net
Marcellus acres
–
Continuing to block up
acreage
Central Pennsylvania Area
Current Marcellus activity
Planned Q3 Pad
Completions
17 |
 18
PPT-169 –
Barclay’s September 2010
Marcellus Type Curve and Economics
Year: 1
2 3 4 5
6
7 8 9 10
•
Expect
average
well
cost
to
decrease
from
current
costs
of
~$6.5
million
to
~$5.0
million
by
year end 2011 with further expected reductions as development continues
•
Expected
well
cost
reductions
from
improved
drilling,
completion
and
logistical
efficiencies
resulting from multi rig program
(1)
Based on forward natural gas strip prices of $4.50, $5.25, $5.50, $5.75 and $6.00 for
2011, 2012, 2013, 2014 and beyond 10 Mmcf/d
1 Mmcf/d
100 Mcf/d
Well Cost
($MM)
Gas price required to
achieve 20% pre tax
IRR (per Mcf)
IRR at
NYMEX strip
pricing
(1)
4.5
$
$3.75 -
$4.00
40%
5.5
$
$4.25 -
$4.50
25%
6.5
$
$5.00 -
$5.25
20%
Lateral = 4,500’
IP = 4,500 Mcf/d
b = 1.49
EUR = 4.5 Bcfe |
 PPT-169 –
Barclay’s September 2010
TGGT Midstream Operations
Additional expansion projects in Shelby Trough
•
TGGT throughput currently totals more than 1.1 Bcf/d
•
Throughput capacity growing to 2.0 Bcf/d
•
Will have amine and glycol facilities with capacity to
treat 1 Bcf/d
of natural gas to meet pipeline quality
requirements during 2010; evaluating additional
treating opportunities
•
Interconnects in Holly area to several major pipelines
with access to multiple markets
–
Regency
–
Crosstex
–
Centerpoint
–
Gulf South
–
ETC Tiger (Q1 2011)
–
Enterprise Acadian (Q3 2011)
•
Building midstream infrastructure in Shelby County
similar to TGG Holly system; multiple interconnects
available
–
Tenaska
–
ETC
–
NGPL
–
Enbridge
–
TETCO (now in service)
19
TGGT East TX / North LA System
TGGT Holly System |
 20
PPT-169 –
Barclay’s September 2010
Forward Looking Statements
This
presentation
contains
forward-looking
statements,
as
defined
in
Section
27A
of
the
Securities
Act
and
Section
21E
of
the
Securities
Exchange
Act
of
1934,
or
the
Exchange
Act.
These
forward-looking
statements relate to, among other things, the following:
•
our future financial and operating performance and results;
•
our business strategy;
•
market prices;
•
our future use of derivative financial instruments; and
•
our plans and forecasts.
We have based these forward-looking statements on our current assumptions,
expectations and projections about future events. We use the words
"may," "expect," "anticipate," "estimate," "believe," "continue," "intend," "plan," "budget" and other similar words to identify forward-looking statements. You should read
statements that contain these words carefully because they discuss future
expectations, contain projections of results of operations or of our financial condition and/or state other "forward-looking" information. We do not
undertake
any
obligation
to
update
or
revise
publicly
any
forward-looking
statements,
except
as
required
by
law.
These
statements
also
involve
risks
and
uncertainties
that
could
cause
our
actual
results
or
financial condition to materially differ from our expectations in this presentation,
including, but not limited to: •
fluctuations in prices of oil and natural gas;
•
imports of foreign oil and natural gas, including liquefied natural gas;
•
future capital requirements and availability of financing;
•
continued disruption of credit and capital markets;
•
estimates of reserves and economic assumptions;
•
geological concentration of our reserves;
•
risks associated with drilling and operating wells;
•
exploratory risks, including our Marcellus shale play in Appalachia and our
Haynesville and Bossier shale plays in East Texas/North Louisiana;
•
risks associated with operation of natural gas pipelines and gathering
systems; •
discovery, acquisition, development and replacement of oil and natural gas
reserves; •
cash flow and liquidity;
•
timing and amount of future production of oil and natural gas;
•
availability of drilling and production equipment;
•
marketing of oil and natural gas;
•
developments in oil-producing and natural gas-producing countries;
•
title to our properties;
•
competition;
•
litigation;
•
general economic conditions, including costs associated with drilling and operation
of our properties; •
environmental or other governmental regulations, including legislation to reduce
emissions of greenhouse gases, legislation of derivative financial instruments, regulation of hydraulic fracture
stimulation and elimination of income tax incentives available to our
industry; •
receipt and collectibility
of amounts owed to us by purchasers of our production and counterparties to our
derivative financial instruments; •
decisions whether or not to enter into derivative financial instruments;
•
potential acts of terrorism;
•
actions of third party co-owners of interests in properties in which we also
own an interest; •
fluctuations in interest rates; and
•
our ability to effectively integrate companies and properties that we
acquire.. |
 21
PPT-169 –
Barclay’s September 2010
Forward Looking Statements (continued)
We believe that it is important to communicate our expectations of future
performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no
control. You are cautioned not to place undue reliance on a
forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this
presentation, and the risk factors included in our Registration Statement on form
S-3 with respect to the senior notes, our Annual Reports on Form 10-K and our Quarterly Reports on Form 10-Q.
Our
revenues,
operating
results,
financial
condition
and
ability
to
borrow
funds
or
obtain
additional
capital
depend
substantially
on
prevailing
prices
for
oil
and
natural
gas,
the
availability
of
capital
from
our
revolving
credit
facilities
and
liquidity
from
capital
markets.
Declines
in
oil
or
natural
gas
prices
may
materially
adversely
affect
our
financial
condition,
liquidity,
ability
to
obtain
financing
and
operating
results.
Lower
oil
or
natural gas prices also may reduce the amount of oil or natural gas that we can
produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and
estimated
quantities
of
our
oil
and
natural
gas
reserves,
our
ability
to
fund
our
operations
and
our
financial
condition,
cash
flow,
results
of
operations
and
access
to
capital.
Historically,
oil
and
natural
gas
prices
and markets have been volatile, with prices fluctuating widely, and they are likely
to continue to be volatile. Effective January 1, 2010, the United States
Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil
and
gas
that
are
estimated
to
be
recoverable
with
a
high
degree
of
confidence),
but
also
"probable"
reserves
(i.e.,
quantities
of
oil
and
gas
that
are
as
likely
as
not
to
be
recovered)
as
well
as
"possible"
reserves
(i.e.,
additional
quantities
of
oil
and
gas
that
might
be
recovered,
but
with
a
lower
probability
than
probable
reserves).
As
noted
above,
statements
of
reserves
are
only
estimates
and
may
not
correspond
to
the
ultimate quantities of oil and gas recovered. Any reserve estimates provided in this
presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not
necessarily
calculated
in
accordance
with,
or
contemplated
by,
the
SEC's
latest
reserve
reporting
guidelines.
Investors
are
urged
to
consider
closely
the
disclosure
in
our
Registration
Statement
on
form
S-3
with
respect
to
the
senior
notes,
our
Annual
Report
on
Form
10-K
for
the
fiscal
year
ended
December
31,
2009,
and
our
Quarterly
Reports
on
Form
10-Q
which
are
available
on
our
website
at
www.excoresources.com
under the Investor Relations tab or by calling us at 214-368-2084.
|