Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - PLAINS EXPLORATION & PRODUCTION CO | d8k.htm |
 UBS
Global Oil and Gas Conference
May 2010
Exhibit 99.1 |
 2
Corporate Headquarters
Contacts
Plains Exploration & Production Company
700 Milam, Suite 3100
Houston, Texas 77002
Forward-Looking Statements
This presentation is not for reproduction or distribution to others without
PXP’s consent. Corporate Information
James C. Flores –
Chairman, President & CEO
Winston M. Talbert –
Exec. Vice President & CFO
Hance V. Myers –
Vice President Investor Relations
Joanna Pankey –
Manager, Investor
Relations
& Shareholder Services
Phone: 713-579-6000
Toll Free: 800-934-6083
Email: investor@pxp.com
Web Site: www.pxp.com
Except for the historical information contained herein, the
matters discussed in this presentation are “forward-looking
statements”
as defined by the Securities and Exchange
Commission. These statements involve certain assumptions PXP
made based on its experience and perception of historical trends,
current conditions, expected future developments and other
factors it believes are appropriate under the circumstances.
The forward-looking statements are subject to a number of
known and unknown risks, uncertainties and other factors that
could cause our actual results to differ materially. These risks
and uncertainties include, among other things, uncertainties
inherent in the exploration for and development and production
of oil and gas and in estimating reserves, unexpected future
capital expenditures, general economic conditions, oil and gas
price volatility, the success of our risk management activities,
competition, regulatory changes and other factors discussed in
PXP’s filings with the Securities and Exchange Commission.
References to quantities of oil or natural gas may include
amounts that the Company believes will ultimately be produced,
but that are not yet classified as "proved reserves" under SEC
definitions. |
 3
PXP
WTI NYMEX Historical Prices and
Forward Curves ($/bbl)
Source: Goldman Sachs, NYMEX |
 4
PXP
PXP Today
•
~$7 billion enterprise value
(1)
•
360 MMBOE proved reserves YE 2009
•
85,100 BOE per day production
(2)
•
+2.0 billion BOE resource potential
•
140 million shares outstanding
(3)
•
45% debt-to-total capitalization
(3)
(1) Reflects stock price as of March 31, 2010 and total debt.
(2) Reported average production for 1Q 2010.
(3) As of March 31, 2010. |
 5
PXP
Revenue Per MCFE
Revenue Per MCFE
(3)
$5.77/
MCFE
$8.35/
MCFE
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
PXP
Gas Peer Group Avg.
(1)(2)
1Q 2010
(1) Revenues for non oil and gas producing operations servicing third parties not
included. (2) Peer group average includes the following peers: COG, HK, RRC,
SD, UPL. Source: Company filings. (3) Excludes the impact of
derivatives. |
 6
PXP
$565
$300
$500
$400
$600
$400
$0
$500
$1,000
$1,500
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Strong Liquidity With No Near Term Debt Maturities
Revolver Availability Senior
Notes Millions
$1.3B
Available
Liquidity |
 7
PXP
$3.96
$1.78
$1.99
$0.00
$5.00
$10.00
$15.00
$20.00
$25.00
2008
2009
2010
Total Lease Expense Targeted Reduction
$9.06
Natural Gas
$14.05
$3.97
Natural Gas
$14.49
$4.00
Natural Gas
$18.90
Total Lease Expense per BOE Steam Costs per
BOE |
 8
PXP
Debt-Adjusted Cash Operating Margin
(1)(8)
(1) Debt-Adjusted Cash Operating Margin calculated as revenue (excluding
hedging), less production expenses, less cash G&A (excluding capitalized G&A and noncash compensation),
less interest (excluding capitalized interest).
(2) Revenues and expenses for non oil and gas producing operations servicing third
parties not included. (3) Peer group average includes the following peers:
COG, HK, RRC, SD, UPL. Source: Company filings. (4)
Net
of
$0.21
per
Mcfe
loss
on
mark-to-market
derivative
contracts.
(5) Includes transportation, gathering, production & ad valorem taxes and steam
& electricity costs. (6) Excludes noncash compensation expense and
capitalized G&A. (7) Excludes capitalized interest.
(8) A reconciliation schedule for PXP is included in the Addendum. PXP does not make
any representations as to the accuracy of the information used to make the calculations or the conformity of these measures with
those which may be prepared by the respective companies, and does not undertake to
provide a GAAP reconciliation with respect to any non-GAAP financial measure which may be included in such information.
Production Costs
G&A
Interest
Margin (Excl. Derivatives)
Derivatives
(5)
(6)
(7)
$2.40
$1.26
$0.44
$0.49
$0.46
$1.00
$3.01
$0.65
$4.84
(4)
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
PXP
Gas Peer Group Avg.
(2)(3)
$3.66
$4.84
1Q 2010 |
 9
PXP
95
87
85.5
85.1
0
20
40
60
80
100
120
140
1Q10
2Q10e
3Q10e
4Q10e
Production Target Growth Rate 15%
(1) Represents corporate targets.
2010 Production
Guidance 88-92 MBOEPD
88
100
(1)
120
(1)
0
20
40
60
80
100
120
140
2010e
2011e
2012e
2010-2012
Annual Production |
 10
PXP
209
230
250
264
83
130
176
253
0
100
200
300
400
500
600
700
800
2008
2009
2010
2011
Proved Developed
Proved Undeveloped
Proved Reserves Target Growth
292
360
426
(1)
72%
72%
64%
64%
51%
51%
(1) Illustrates estimated reserves using NYMEX pricing.
59%
59%
517
(1) |
 11
PXP
Capital Allocation
2010E
$1.1 billion
2011E
Targeting $1 billion
28%
72%
Development
Capital Program
Exploration
27%
64%
9%
Development capital includes exploitation, real estate, capitalized interest and
G&A costs but does not include additional capital for exploratory
successes. Exploration capital is defined as discovery and dry hole
costs. Development-Haynesville |
 12
PXP
PXP Operating Strategy Detail
Operationally Balanced
•
Expand development of Diatomite, Non-Diatomite and
Miocene projects to maintain oil production volumes
•
Accelerate Granite Wash potential in the Texas
Panhandle
•
Continue Haynesville Shale development to increase
natural gas production
•
Develop high impact Gulf of Mexico deep shelf
discoveries
•
Optimize high potential deepwater Gulf of Mexico
discoveries |
   13
PXP
Texas/Louisiana
Haynesville Shale
•
107,800 net acres
•
1,400 potential net locations
•
53 rigs operating (34 CHK, 19 other)
(1)
•
Current production +100 MMcfe/d net
(1)
Texas Panhandle
•
383,300 gross acres
•
715 square miles 3D
seismic
•
Horizontal Granite
Wash potential
•
Current
Production
~25 MMcfe/d net
(1)
South Texas
•
90,400 gross acres
•
321 square miles 3D seismic
•
Current production ~50 MMcfe/d net
(1)
Big Mac
•
28,200 gross acres
•
275 square
miles
3D seismic
(1)
As of March 31, 2010.
The shaded areas are for illustrative purposes only and do not reflect actual leasehold
acreage. South Texas
South Texas
Haynesville
Panhandle
Big Mac
Big Mac
Flatrock Area
•
54,000 gross acres offshore Louisiana
•
215 square miles 3D seismic
•
Will include production from Blueberry
Hill and Hurricane Deep
•
Current production ~50 MMcfe/d net
(1) |
 14
PXP
Legend
PRODUCING
AWAITING COMPLETION
2010 DRILL LOCATIONS
ACTIVE DRILLING
Location Map
Haynesville Shale
Activity Map
TEXAS
LOUISIANA |
 15
PXP
0
400
800
1,200
1,600
2,000
2009
2010
2011
2012
2013
2014
0
60
120
180
240
300
Haynesville Shale
Economics
$1.37/Mcfe or $8.24/BOE
(2)
January 1, 2010 Project Cost Forward F&D:
(1) Assumes D&C costs for first 4 years = $7.5 MM per well, after 4 years = $6
MM per well. (2) Assumes flat NYMEX natural gas pricing of $5.50 per
MMBtu. 6.5 Bcfe
Est. Median Gross EUR per Well:
$7.5 MM
(1)
Est. Median Gross Well Cost:
6.8 Tcfe
Est. Net Resource
Potential:
1,400
Potential Net
Locations:
107,800
Net Acreage:
20% WI/15% NRI
PXP
Interest:
Wells
Producing H'Ville CAPEX Avg. Yearly Production
MMcf/d
PXP Projected Net Production
$652
MM
$293
MM
$291
MM
$308
MM
$312
MM
$302
MM |
 16
PXP
Granite Wash Horizontal Play
Recent High-Rate Completions
NW. Mendota Area
Buffalo
Wallow Area
Projection: NAD 1927 OK North
PXP LEASES
Horizontal Well
Drilled/Permitted
Legend
Custer
Washita
21 MMCFD / 570 BPD
8.6 MMCFD/1400 BPD
21 MMCFD
20 MMCFD
25 MMCFD / 1900 BPD
21 MMCFD / 1230 BPD
10 MMCFD/3300 BPD
15 MMCFD/3600 BPD
16 MMCFD/3500 BPD
PXP Hanson #40-4H
TD: 15,681’
WOC
PXP Thomas #903H
TD 16,389’
WOC
PXP Britt Caldwell #5015H
TD 18,000’
Drilling
PXP Hanson #29-2H
TD: 15,500’
Drilling
18 MMCFD / 400 BPD
11 MMCFD / 608 BPD
15 MMCFED
20.1 MMCFD
•
PXP acreage position
–
19,100 net acres
•
Two rigs currently operating
with a third rig arriving in June
•
58 Primary Granite Wash
Locations (PXP WI 86%)
•
50+ Additional Granite Wash
Locations
•
Industry ROI 35% @
$5.00/MMBtu & $70/bbl
•
2010 Plan
-
16 wells planned
-
$104 MM Capex |
     17
PXP
California
Onshore/Offshore
Los
Angeles
Basin
Los
Angeles
Basin
San Joaquin
Valley
San Joaquin
Valley
Arroyo
Grande
Arroyo
Grande
Pt Pedernales
Pt Arguello
•
215 MMBOE Net Proved Reserves
•
275 MMBOE Net Development Resource
Potential
•
68% Proved Developed
•
2009 Capex $92 MM; 2010E Capex
$200 MM
•
14 yr R/P
•
2,500+ future well locations
•
Price differentials protected by contract
Expected CA Oil Production by Year
42.6
40.6
48.1
45.5
0
10
20
30
40
50
60
2009
2010e
2011e
2012e |
 18
PXP
Projection: NAD 1927 CAL VII
T:\California\Regional_CA\Graphics\ppt\\CA_Relief_maps.ppt
Midway Sunset
Cymric
South Belridge
McKittrick
Legend
PXP LEASES
Diatomite/Non-Diatomite
•
Steam recovery
•
Development Resource
~ 180 MMBOE
•
Diatomite ~ 59 MMBOE
•
Non-Diatomite ~ 121
MMBOE
•
2010E Capital ~$100 MM
Diatomite/Non-Diatomite
Onshore California –
Bakersfield
Arroyo Grande
Bakersfield |
       19
PXP
Miocene Sands
Onshore California -
LA Basin
Location Map
LA Basin
Projection: NAD 1927 CAL VII
Legend
PXP LEASES
T:\California\Regional_CA\Graphics\ppt\\CA_Relief_maps.ppt
Miocene/Pliocene Sands
•
Waterflood recovery
•
Development Resource
~ 83 MMBOE
•
2010E Capital ~$75 MM
Los Angeles
Montebello
Inglewood
Urban Area
Las Cienegas |
 20
PXP
Davy Jones
Gulf of Mexico -
Shallow Water
Subsalt Wilcox & Miocene
Discoveries and Current Operations
Discoveries
2010-2012 Drilling
New Orleans
Flatrock Field
Blueberry Hill
Blackbeard West
John Paul Jones
Blackbeard East
Davy Jones 2
Lafitte |
 21
PXP
Subsalt Wilcox Prospects
Davy Jones & John Paul Jones
John Paul Jones Prospect
Flatrock (Rob L. Operc)
Structure Map
Top Wilcox
Davy Jones Discovery
Davy Jones 2 |
 22
PXP
Regional Cross Section –
Subsalt Miocene Play
Eugene Island to South Timbalier
A
A’
Subsalt Miocene Prospects
Blackbeard & Lafitte Regional Cross Section
LAFITTE
EI 223
BLACKBEARD WEST
ST 168 #1 BP2
TD 32,997'
BLACKBEARD EAST
ST 144
PTD 29,950'
W
E |
 23
PXP
Davy Jones
Gulf of Mexico
Subsalt Wilcox, Miocene & Pliocene
Discoveries and Current Operations
Discoveries
2010-2012 Drilling
New Orleans
Flatrock Field
Blueberry Hill
Blackbeard West
Friesian
Lucius
John Paul Jones
Phobos
Blackbeard East
Davy Jones 2
Lafitte |
   24
PXP
Lucius/Phobos Projects
Keathley Canyon Area, GOM
LOUISIANA
LOUISIANA
1007
1008
Keathley Canyon
875
874
963
964
919
876
877
920
921
965
1009
918
HADRIAN
962
1006
38
41
84
83
82
85
40
39
PHOBOS
Prospect
Miles
0
3 Existing Leases
Lucius
Discovery
PXP WI 33% |
 25
PXP
Friesian Project
Green Canyon Area, GOM
Gross Reserve Potential Approx. 125-150 MMBOE
“Holstein”
Miocene Type Log
Friesian 2
Friesian 1
Potential
Production
Hub
Friesian
Tahiti
Front Runner
~ 22 Miles |
 26
PXP
Gulf of Mexico
Discoveries, Current Operations and Prospects
Discoveries
2010-2012 Drilling
New Orleans
Davy Jones
Flatrock Field
Blueberry Hill
Blackbeard West
Friesian
Lucius
John Paul Jones
Phobos
Davy Jones 2
Blackbeard East
Lafitte
Prospects
Calico Jack
Drake
Barataria
Flying Dutchman
Hook
Bonnet
England
Captain Blood
Blood & Guts
Calico Jack
Drake
Barataria
Flying Dutchman
Hook
Bonnet
Captain Blood
Blood & Guts
Elba
Salus
Rex
Brutus
Augustus
Dutch
Corsica
Capri
Elba
Salus
Rex
Brutus
Augustus
Dutch
Calico Jack
Drake
Barataria
Flying Dutchman
Hook
Bonnet
Captain Blood
Silver Fox
Blood & Guts |
 27
PXP
+2.0 Billion BOE Resource Potential
Potential Reserves
950 MMBOE
275 MMBOE
100 MMBOE
110 MMBOE
10 MMBOE
~1.4 Billion BOE
Development Resource Potential
Region
Haynesville
California
Panhandle/S. TX
Gulf of Mexico
Rockies
~600 Million BOE
Exploration Resource Potential
Potential Reserves
600 MMBOE
Region
Gulf of Mexico |
 28
PXP
PXP Targets Over Next 3 Years
•
Grow reserves 15% to 20% per year over the
next 3 years
•
Grow production 10% to 15% per year over the
next 3 years
•
Efficiently manage business focusing on cost
reduction and profitability
•
Maintain conservative balance sheet with active
hedging program |
 29
PXP
Addendum |
 30
PXP
Commodity Price Protection
Oil and Natural Gas Derivative Positions
(1)
All of our derivative instruments are settled monthly.
(2)
In addition to the deferred premium, an upfront payment of $3.86 per barrel was
paid upon entering into these derivative contracts. (3)
PXP receives difference between floor of $80.00 less the Index price up to a
maximum of $20.00 per barrel. (4)
PXP
receives
difference
between
floor
of
$80.00
less
the
Index
price
up
to
a
maximum
of
$20.00
per
barrel.
PXP
pays
if
Index
>
$110.00
ceiling.
(5)
PXP receives difference between floor of $6.12 less the Index price up to a maximum
of $1.48 per MMBtu. PXP pays if Index > $8.00 ceiling. 2010
2010
Sales of Natural Gas Production
Henry Hub
$0.034
per MMBtu
$6.12 Floor with a
$4.64 Limit
$8.00 Ceiling
85,000 MMBtu
Three-way
Collars
(5)
Apr –
Dec 2010
WTI
$6.087 per Bbl
$80.00 Floor with a
$60.00 Limit
40,000 Bbls
Put Options
(3)
Jan –
Dec
2012
WTI
$1.00 per Bbl
$80.00 Floor with a
$60.00 Limit
$110.00 Ceiling
9,000 Bbls
Three-way Collars
(4)
Jan –
Dec
WTI
$5.023 per Bbl
$80.00 Floor with a
$60.00 Limit
31,000 Bbls
Put Options
(3)
Jan –
Dec
2011
$5.00 per Bbl
(2)
AVERAGE
DEFERRED
PREMIUM
INDEX
AVERAGE
PRICE
DAILY
VOLUME
INSTRUMENT
TYPE
PERIOD
(1)
Sales of Crude Oil Production
WTI
$55.00 Strike Price
40,000 Bbls
Put Options
Apr –
Dec |
 31
PXP
Reconciliation of Debt-Adjusted Cash Operating Margin
(Non-GAAP) to Net Cash Provided by Operating Activities (GAAP)
The following table reconciles the debt-adjusted operating margin (non-GAAP)
to the net cash provided by operating activities (GAAP) for the three months
ended March 31, 2010. Management believes this presentation may be useful to
investors. PXP management uses this information for comparative purposes
within the industry and as a means to measure cash generated by our oil and gas
production and the ability to fund, among other things, capital expenditures
and acquisitions. This measure is not intended to replace the GAAP statistic
but rather to provide additional information that may be helpful in evaluating the
Company's operational trends and performance.
Debt-adjusted operating margin is calculated by adjusting gross margin to
include general & administrative expenses, interest expense and realized
losses on mark-to-market derivative contracts and to exclude
depreciation, depletion, and amortization expense (DD&A) and noncash
compensation expense.
Per MCFE
Three Months
Ended
March 31,
2010
$
4.84
$ 222.5
Debt adjusted cash operating margin (Non-GAAP)
0.10
4.7
Current income taxes attributable to derivative contracts
(0.21)
(9.5)
Realized loss on mark-to-market derivative contracts
(0.26)
(12.1)
Noncash
and other income items
0.38
17.6
Changes in operating assets & liabilities
$
4.83
$ 221.8
Net cash provided by operating activites
(GAAP)
$
4.84
$ 222.5
Debt adjusted cash operating margin (Non-GAAP)
(0.21)
(9.5)
Realized loss on mark-to-market derivative contracts
(0.46)
(21.1)
Interest expense, net of capitalized interest
0.37
16.9
Noncash
compensation
(0.81)
(37.4)
General & administrative
2.55
118.6
Oil and Gas related DD&A
3.40
155.0
Gross margin (GAAP)
(2.55)
(118.6)
Oil and Gas related DD&A
(2.40)
(110.1)
Production expenses
$
8.35
$ 383.7
Oil and gas revenues
(In Millions) |
 UBS
Global Oil and Gas Conference
May 2010 |