Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - EXCO RESOURCES INC | d8k.htm |
 Investor Presentation
June 2010
Exhibit 99.1 |
 2
Company
Overview
(1)
Significant shale upside with a solid base of conventional assets
•
1.2 Tcfe
of Proved Reserves
–
300 Mmcfe/d
of
current
net
production,
reserve
life
of
9.1
years
and
–
255 Bcf
of shale assets
booked as proved with potential for
significant future reserve adds
•
Significant Unproved Upside
–
2.0 Tcfe
of probable and possible reserves
–
8.7 Tcfe
of contingent reserves
–
~0.6 million net acres
•
~68,500 net acres
in the Haynesville play
•
~93,000 net acres
in the Marcellus play
•
Pursuing
additional
acquisition
and
leasing
opportunities
(2)
•
Successfully shifted focus from acquisitions to
developing shale acreage
–
Gross operated
Haynesville
production
exceeds
500
Mmcf/d
(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
62%
Proved
Developed |
 Reserve Base
Concentrated portfolio focused on shale resources
Proved Reserves = 1.2 Tcfe
3P Reserves = 3.2 Tcfe
3P+ Reserves = 11.9 Tcfe
Current Net Production = 300 Mmcfe/d
Gross acreage: ~820,000
Net acreage: ~628,000
Proved: 0.2 Tcfe
3P: 0.2 Tcfe
3P+: 5.9 Tcfe
Production: 17 Mmcfe/d
Gross acreage: ~364,000
Net acreage: ~327,000
Permian
Proved: 0.1 Tcfe
3P: 0.1 Tcfe
3P+: 0.3 Tcfe
Production: 20 Mmcfe/d
Gross acreage: ~190,000
Net acreage: ~138,000
East Texas / North Louisiana
Proved: 0.9 Tcfe
3P: 2.9 Tcfe
3P+: 5.7 Tcfe
Production: 263 Mmcfe/d
Gross acreage: ~297,000
Net acreage: ~178,000
Appalachia
3 |
 4
Recent Events
(1)
Subject to normal post closing purchase price adjustments.
•
Significant
liquidity
created
through
2009
asset
sales
and
joint
venture
with
BG
Group
–
Reduced debt by $2.4 billion or 78% since YE 2008
–
Increased liquidity to over $1.1 billion
•
Continued success in the Haynesville
–
Completed 54 operated wells to date with average IP’s of 23.0 Mmcf/d
–
Closed
purchase
of
Common
Resources,
LLC
jointly
with
BG
Group
for
$442
(1)
million
($221
million
net to EXCO)
–
Adds ~29,200 net acres to the JV (14,600 net to EXCO) in the Shelby Trough in San
Augustine, Shelby and Nacogdoches Counties, TX; acquisition will create
second focus area –
Continue to look for bolt on acreage
•
Closed Appalachia Joint Venture with BG Group for $985 million
–
Received
$835
(1)
million
cash
proceeds
–
Additional $150 million deep drilling carry to be satisfied in 2011 or 2012
•
EXCO is positioned for unmatched organic growth within cash flow
–
Began 2010 with 234 Mmcfe/d, Q1 2010 average of 264 Mmcfe/d
–
Expect
Q4
2010
to
average
375
–
395
Mmcfe/d
resulting
in
~60%
growth
for
2010
–
Targeting
30
–
40%
growth
for
the
next
five
years |
 5
Liquidity and Financial Position
(1)
Includes $70.0
million of restricted cash at 3/31/10
(2)
Excludes unamortized bond premium of $3.1 million
(3)
Net of $15.2 million in letters of credit
•
Borrowing base reduced to $1.2 billion as a result of the JV transaction
–
Expected pro forma liquidity of $1.1 billion
•
Balance sheet right sized for opportunities in a low price environment
Common
Appalachian
Pro Forma
Consolidated ($ in thousands)
March 31, 2010
Acquisition
Joint Venture
March 31, 2010
Cash
(1)
117,792
$
-
-
$
117,792
$
Bank debt (L + 200 -
300bps)
762,543
220,800
(835,200)
148,143
Senior notes
(7
1/4%)
(2)
444,720
-
-
444,720
Total debt
1,207,263
$
220,800
$
(835,200)
$
592,863
$
Net debt
1,089,471
$
220,800
$
(835,200)
$
475,071
$
Borrowing base
1,300,000
$
-
$
(100,000)
$
1,200,000
$
Unused borrowing base
(3)
522,257
$
-
$
-
$
1,036,657
$
Unused borrowing base plus cash
(3)
640,049
$
-
$
-
$
1,154,449
$ |
  6
-
50
100
150
200
250
300
350
400
450
$-
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
Actual production
Production guidance midpoint
Outstanding net debt
Production Profile
Achieved our 2009 strategic plan; positioned for significant growth
(1)
Pro forma for Common Acquisition and Appalachia JV
•
Completed significant divestment program in 2009
•
Focused portfolio on Haynesville, Bossier and Marcellus shales
•
Prepared to deliver significant, sustained organic production growth of 50 – 60% during 2010
|
 7
Net Asset Value Summary
Pro forma for the Common acquisition and Appalachian JV
In millions, except per share and per unit
Low Case
High Case
E&P
Proved
Reserves
-
1.2
Tcfe
at
$2.00
&
$2.50
per
Mcfe
2,400
$
3,000
$
Unproved
Reserves
(Conventional)
-
0.9
Tcfe
at
$0.20
&
$0.40
per
Mcfe
180
360
Unproved
Reserves
(Haynesville)
-
3.3
Tcf
at
$0.30
&
$0.50
per
Mcf
990
1,650
Unproved
Reserves
(Bossier)
-
0.9
Tcf
at
$0.20
and
$0.40
per
Mcf
180
360
Unproved Reserves
(Marcellus/Huron)
-
5.6
Tcf
at
$0.15
&
$0.25
per
Mcf
833
1,388
BG Group Carry as of 3/31/10
464
464
E&P Assets
5,047
$
7,222
$
Midstream
TGGT -
8x and 10x 2011 EBITDA
720
900
Vernon Gathering
60
60
Midstream Assets
780
$
960
$
Hedges
Hedge Value
150
150
Total Asset Value
5,977
$
8,332
$
Less: Net Long-term Debt
512
512
Equity Value
5,465
$
7,820
$
Fully Diluted Shares
216
216
NAV per Share
25.30
$
36.20
$ |
 8
Unmatched NAV Growth
2010E
(1)
2014 Target
(2)
Production (Mmcfe/d)
319
900 - 1,000
Proved Reserves (Tcfe)
1.2
5.0 - 6.0
EBITDA (Millions)
$550
$1,250 - $1,600
Cash Flow (Millions)
$500
$1,200 - $1,550
Capital Expenditures (Millions)
$488
$1,100 - $1,300
50% of TGGT EBITDA (Millions)
$40
$160
Net Debt (Millions)
$550
$500 - $800
NAV per Share
$25 - $35
$50 - $60
(1)
Ranges based on the midpoint of 2010 guidance
(2)
2014
prices
based
on
$5.00
-
$6.00
natural
gas
and
range
of
production
volumes
•
Ability to grow NAV per share significantly even in a low commodity price
environment |
  9
Production
and
Cash
Flow
Growth
(1)
(dollars in millions)
2010
2011
2012
2013
2014
Average Rig Counts:
Haynesville/Bossier Area
17
22
27
27
27
Marcellus Area
2
5
10
14
16
Permian Area
2
2
3
2
-
Total
21
29
40
43
43
Production (Mmcfe/d)
319
500
650
800
950
Cash Flow
500
$
700
$
950
$
1,150
$
1,200
$
Total CAPEX
774
$
880
$
1,100
$
1,150
$
1,200
$
Less: Carry
(270)
(250)
-
-
-
Net CAPEX
504
$
630
$
1,100
$
1,150
$
1,200
$
•
Drilling carries fund capital spending growth during activity ramp up period
•
Cash flow grows as carries expire enabling self funding of capital spending
levels (1)
Based
on
midpoint
of
estimates
and
assumes
gas
prices
of
$5.25,
$5.50,
$5.75,
and
$6.00
and
oil
prices
of
$75.00,
$77.50,
$80.00
and
$80.00
for
2011
–
2014;
2010
prices
based
on
midpoint
of
guidance |
 10
Quarterly 2010 Guidance
(1)
Non-cash interest expense in Q2 includes write-off of deferred financing costs associated with
amended credit facility (2)
2010 estimates based on natural gas and oil NYMEX prices of $4.09 and $76.88 for Q2, $4.50 and $70.00
for Q3, and $5.00 and $72.50 for Q4 (3)
Includes $37.9 million of cash proceeds received Q1 2010 for early termination of hedges related to
dispositions, and excludes EXCO’s share of TGGT EBITDA Q1 2010
(dollars in thousands, except per unit amounts)
Actual
Low
High
Low
High
Low
High
Low
High
Production:
Oil -
Mbbls
159
130
141
128
138
127
139
544
576
Gas -
Mmcf
22,837
24,884
25,727
29,595
30,914
33,736
35,507
111,051
114,984
Mmcfe
23,791
25,662
26,572
30,360
31,740
34,500
36,340
114,313
118,443
Mmcfe/d
264
282
292
330
345
375
395
313
325
Differentials to NYMEX:
Oil per Bbl
(3.47)
$
(4.75)
$
(4.15)
$
(4.75)
$
(4.15)
$
(4.75)
$
(4.15)
$
(4.38)
$
(3.96)
$
Gas per Mcf
98.3%
97.0%
99.0%
97.0%
99.0%
96.0%
98.0%
97.0%
98.6%
Lease operating expense
18,843
$
19,300
$
22,300
$
17,600
$
20,600
$
18,000
$
21,000
$
73,740
$
82,740
$
Non-cash stock based compensation -
LOE
350
$
300
$
500
$
300
$
500
$
300
$
500
$
1,250
$
1,850
$
Gathering expense -
per Mcfe
0.47
$
0.52
$
0.55
$
0.52
$
0.56
$
0.52
$
0.57
$
0.49
$
0.52
$
Production tax rate
6.0%
6.0%
7.0%
6.0%
7.0%
6.0%
7.0%
6.0%
6.8%
Other income
467
$
250
$
500
$
250
$
500
$
250
$
500
$
1,220
$
1,970
$
Depletion rate per Mcfe
1.43
$
1.45
$
1.60
$
1.45
$
1.60
$
1.45
$
1.60
$
1.45
$
1.57
$
Depreciation rate per Mcfe
0.20
$
0.20
$
0.25
$
0.20
$
0.25
$
0.20
$
0.25
$
0.20
$
0.24
$
Asset retirement obligation
1,089
$
1,100
$
1,400
$
1,100
$
1,400
$
1,100
$
1,400
$
4,390
$
5,290
$
Cash G&A
22,160
$
20,700
$
22,700
$
18,600
$
20,600
$
19,000
$
21,000
$
80,460
$
86,460
$
Non-cash stock based compensation -
G&A
4,259
$
3,400
$
3,800
$
3,700
$
4,100
$
6,500
$
7,500
$
17,860
$
19,660
$
Interest expense -
cash
12,742
$
12,500
$
14,500
$
10,000
$
12,000
$
10,000
$
12,000
$
45,240
$
51,240
$
Interest expense -
non-cash
(1)
(90)
$
4,800
$
5,800
$
1,000
$
1,500
$
1,000
$
1,500
$
6,710
$
8,710
$
Equity method income in TGGT Holdings, LLC
89
$
5,000
$
6,000
$
8,000
$
9,000
$
12,000
$
13,000
$
25,090
$
28,090
$
Tax rate
40%
40%
40%
40%
40%
40%
40%
40%
40%
Cash tax rate
0%
0%
0%
0%
0%
0%
0%
0%
0%
CAPEX
130,491
$
115,700
$
135,700
$
111,000
$
131,000
$
116,800
$
136,800
$
473,990
$
533,990
$
Fully diluted shares outstanding
215,666
215,000
217,000
215,500
217,500
216,000
218,000
215,500
217,000
Adjusted EBITDA at midpoint
(2,3)
148,527
EXCO's
share of TGGT EBITDA
1,094
$
5,500
$
7,500
$
8,000
$
10,000
$
12,000
$
14,000
$
26,594
$
32,594
$
2010
$ 505,900
$ 94,600
$ 120,100
$ 142,700
Q2 2010E
Q3 2010E
Q4 2010E |
 11
Capital Spending Summary
Focus on the shales
$ in millions
2010E
Haynesville / Bossier
278
$
Marcellus
134
Conventional
64
Corporate
28
Total CAPEX
504
Investment in TGGT Holdings, LLC
80
Total CAPEX including TGGT
584
Less: BG Group reimbursments
(130)
Total Investing Activities
454
$
2010 Capital Spending
Marcellus
23%
Haynesville /
Bossier
47%
Conventional
11%
Corporate
5%
TGGT Holdings
14%
•
~85% of capital directed to shale activity |
 12
Current Derivatives Position
•
Cash settlements for Q1 2010 totaled $77.0 million
–
$39.1 million was received in the normal course of business
–
An additional $37.9 million was received in connection with early termination
of certain 2010 derivatives
•
Expect to add additional hedges for 2011 and 2012
NYMEX
Contract
Contract
Contract
% Hedged
natural gas
price per
NYMEX oil
price per
Equivalent
price per
proved
Mmcf
Mcf
Mbls
Bbl
Mmcfe
Equivalent
forecast
(1)
Q2 2010
13,803
7.17
$
111
114.96
$
14,471
7.72
$
55%
Q3 2010
13,940
7.16
113
114.96
14,616
7.72
47%
Q4 2010
13,940
7.21
113
114.96
14,616
7.76
41%
2011
27,375
6.68
548
111.32
30,660
7.95
5%
2012
12,810
6.11
92
109.30
13,359
6.61
2%
2013
5,475
5.99
-
-
5,475
5.99
1%
Total
87,343
6.79
$
976
112.39
$
93,198
7.54
$
(1)
Based on the midpoint of 2010 production guidance, Q4 2010 midpoint held flat for
2011-2013 |
 Haynesville Assets and Efforts
•
~68,500 net Haynesville acres with
significant held by production
position
•
Average IP rate from our operated
Haynesville horizontal wells in
DeSoto
Parish continues to be
approximately 23 Mmcf
per day
•
Currently testing various drilling and
completion methods to improve our
recoveries and reduce costs
–
Pad drilling and spacing tests;
completed 4 wells on 80-acre
spacing off of same pad in June
2010
–
Frac
sizes and cluster spacing
–
Frac
optimization through
different types and combinations
of proppant
EXCO / BG
JV Area
TX
LA
AR
Common Acquisition Area
13 |
 Shelby Area
Haynesville and Middle Bossier assets
•
Located in Shelby Trough in Shelby,
San Augustine & Nacogdoches
Counties, TX
•
Eight horizontal shale wells flowing to
sales (7 Haynesville, 1 Bossier)
•
Large acreage holdings in three areas
totaling 62,722 gross & 29,200 net
acres
•
Three acreage areas
–
North area
–
~11,250’
to Bossier
–
~11,500’
to Haynesville
–
Center area
–
~12,750’
to Bossier
–
~13,000’
to Haynesville
–
South area
–
~14,250’
to Bossier
–
~14,500’
to Haynesville
•
3 operated rigs currently running
•
First EXCO operated completion
flowing more than 23 Mmcf/d
Haynesville
31 Mmcf/d
IP
Haynesville
12 Mmcf/d
IP
Haynesville
3 wells > 15 Mmcf/d
IP
Bossier
12 Mmcf/d
IP
Bossier
9 Mmcf/d
IP
Bossier
20 Mmcf/d
IP
Bossier
21 Mmcf/d
IP
Prior Operator Results
Last three Haynesville wells
21.0, 18.1 and 22.1 Mmcf/d
IP’s;
First Middle Bossier well
11 Mmcf/d
IP
EXCO Lease Position
Haynesville Shale Area
Haynesville Shale Well
Bossier Shale Well
14 |
 15
Haynesville IP Rate Consistency
23 Mmcf/d
average IP in DeSoto
Parish
(1)
(1)
EXCO IP’s defined as highest 24 hour average flow rate to sales
Average Desoto Parish IP rate of
23 Mmcf/d
•
Excludes 4 wells in DeSoto Parish (2 testing restricted choke, and 2 outside of DeSoto core)
•
Now have 60 operated Haynesville horizontal wells to sales
•
Monitor pressure drawdown on every well; currently testing restricted choke on 2 wells
•
Initiated pad drilling operations; completed first 4 pad wells in June 2010
|
 b =
1.00 EUR = 6.6 Bcfe
b = 1.25
EUR = 7.6 Bcfe
b = 1.75
EUR = 9.6 Bcfe
EXCO’s
current
proved type curve
16
Haynesville Type Curve - DeSoto Parish, LA
Conservatively booked with significant upside based on actual decline
rates |
 17
EXCO Gross Operated Haynesville Shale Forecast
Poised to deliver significant growth in Haynesville production; plan to accelerate
drilling in 2010 and beyond
~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) |
 •
Drilling program underway
–
Plan at least 11 horizontals in 2010
–
Built-for-purpose drilling rig under long term
contract delivered February 2010
–
Contracted to add two additional rigs
•
Completed two horizontal wells
with IP’s of 2.9 and 2.2 Mmcf/d
from 8 stage fracs
–
One of these wells had 8 stages completed over
its planned 2,500’
lateral
–
The other well was drilled to a lateral length of
4,600’
but completed only over 2,500’
(casing
problem)
•
Opportunity to complete the remaining
seven stages at a later date
•
Solidify land position
–
Continue to build acreage position
–
Current net leasehold position is approximately
325,000 net acres with more than 93,000 net
acres in the over-pressured fairway
–
Focus
on adding contiguous acreage positions
which allow for multi-well pad operations
•
Identify and develop access to gas
markets
Marcellus Activity
18 |
 TGGT
Midstream Operations •
TGGT throughput currently totals approximately 1.1
Bcf/d
•
Construction of 36 inch, 29 mile Haynesville header
system completed
•
Throughput capacity in excess of 1.5 Bcf/d
with the
opportunity to increase throughput with compression
and system management
•
Continuing to add high pressure flow lines to gather
production
•
Will have amine and glycol facilities with capacity to
treat 1 Bcf/d
of natural gas to meet pipeline quality
requirements during 2010; now have capacity > 800
Mmcf/d
•
Interconnects to several major pipelines with access
to multiple markets
–
Regency
–
Crosstex
–
Centerpoint
–
Gulf South
–
ETC Tiger (Q1 2011)
–
Enterprise Acadian (Q3 2011)
TGGT Holly System
TGGT East TX / North LA System
19 |
 20
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 and the ability of financial institutions to honor
their commitments, such as the events which occurred during the third quarter of 2008 and
thereafter, for an extended period of time; •
estimates of reserves and economic assumptions used in connection with our acquisitions;
•
geological concentration of our reserves;
•
risks associated with drilling and operating wells;
•
exploratory risks, including our Marcellus and Huron shale plays in Appalachia and our
Haynesville/Bossier shale play 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; •
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
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 the 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 Annual Report on Form 10-K for the fiscal year ended December 31, 2009, which is available on our website at
www.excoresources.com under the Investor Relations tab or by calling us at 214-368-2084.
|