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8-K - FORM 8-K - PLAINS EXPLORATION & PRODUCTION COd8k.htm
Barclays Energy-Power Conference
September 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, the timing and closing
of acquisitions and divestments, 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
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
England
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
England
Captain Blood
Silver Fox
Blood & Guts


4
PXP
Gulf of Mexico Divestiture
Distributed overview materials and confidentiality
agreements to select group of companies
Data room process underway
Offers due late October to mid November
Effective date September 1, 2010
PXP will work very closely with successful bidders
in order to close by year-end 2010


5
PXP
$400
$600
$400
$500
$300
$565
$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
$1.4B
(1)
Available Liquidity
(1) As of August 3, 2010 upon closing of Amended and Restated Revolving Credit Facility.


6
PXP
WTI NYMEX Historical Prices and
Forward Curves ($/bbl)
Source: Goldman Sachs, NYMEX


7
PXP
PXP Today
$5.6
billion
enterprise
value
(1)
360 MMBOE proved reserves YE 2009
85.1 MBOE per day production for 1H 2010
+1.4
billion
BOE
resource
potential
(2)
140.1
million
shares
outstanding
(3)
45%
net
debt-to-total
capitalization
(3)
(1) Reflects stock price and total debt as of June 30, 2010.
(2) Excludes Gulf of Mexico assets.
(3) As of June 30, 2010.


8
PXP
PXP
Operational Plan
$1040 MM
$920 MM
$1077 MM
$1093 MM
$1078 MM
$904 MM
0
25
50
75
100
125
150
175
200
2010
2011
2012
2013
2014
2015
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
PXP Net
Production
PXP Net
Cash
Flow
(1)
Capital -
After Divest
Cash Flow -
After Divest
Production -
After Divest
(1) Net revenue minus net expenses.
Assumes Strip pricing in 2010, $85/Bbl of oil and natural gas pricing of $5.00/MMBtu in 2011, $85/Bbl of oil and natural gas pricing of $5.50/MMBtu in 2012, and $86/Bbl of oil
and natural gas pricing of $6.00/MMBtu 2013 and beyond.
Excludes Gulf of Mexico assets.


9
PXP
209
230
234
253
83
130
178
245
0
100
200
300
400
500
600
700
800
2008
2009
2010
2011
Proved Developed
Proved Undeveloped
Proved Reserves Target Growth
292
360
412
(1)
72%
72%
64%
64%
51%
51%
(1) Illustrates estimated reserves using NYMEX pricing.
57%
57%
498
(1)


10
PXP
Capex Profile
Oil vs. Gas
Operated vs. Non-Operated
21%
79%
Oil
Gas + Exploration
75%
25%
2009
2011
2010
2009
2011
2010
39%
61%
Operated
Non-Operated
33%
67%
37%
63%
7%
93%


11
PXP
Capital Allocation
2010E
$1.1 billion
2011E
Targeting $1 billion
22%
27%
21%
30%
Haynesville
California
Granite Wash
Other Capital
Capital Program
27%
64%
9%
Haynesville
Development
Exploration
(1) Includes
development,
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.
(1)
(1)


12
PXP
Operational Strategy
Focused Oil Growth Strategy
Operate substantially all oil assets
Maintain total company liquids volumes between 50% and 60%
of total production
Hedging strategy protects high oil margins that preserve
excellent returns
Targeted High Liquids/Natural Gas Strategy
Granite Wash development focusing on high liquids and highest
rate of return wells
Haynesville Shale development drilling continues for our Held By
Production (HBP) program


13
PXP
Oil Assets
88%
1%
PXP
Monterey Shale
75%
2%
PXP
Mowry Shale
88%
27%
PXP
California
$% of
NYMEX Oil
Est. % of
2011 Capital
Operator
Asset


14
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
$190 MM
14 yr R/P
2,500+ future well locations
Price differentials protected by
contract
The shaded areas are for illustrative purposes only and do not reflect actual leasehold acreage.


15
PXP
California
Operational Plan
$349 MM
$367 MM
$190 MM
$323 MM
$272 MM
$374 MM
0
15
30
45
60
75
90
2010
2011
2012
2013
2014
2015
$0
$200
$400
$600
$800
$1,000
$1,200
PXP Net
Production
PXP Net
Cash
Flow
(1)
$9.87/BOE
(2)
January 1, 2010 Project Cost Forward F&D:
135 MBOE
Average Gross EUR per Well:
$1.2 MM
Average Gross Well Cost:
275 MMBOE
Net Development Resource Potential:                            
215 MMBOE
Proved Net Reserves:                                            
2,500+
Potential Net Locations:
98% WI / 86% NRI
PXP Interest:                                                   
CAPEX                
(1) Net revenue minus net expenses.
(2)
Assumes
Strip
pricing
in
2010,
$85/Bbl
of
oil
and
natural
gas
pricing
of
$5.00/MMBtu
in
2011,
$85/Bbl
of
oil
and
natural
gas
pricing
of
$5.50/MMBtu
in
2012,
and
$86/Bbl
of
oil
and natural gas pricing of $6.00/MMBtu 2013 and beyond.


16
PXP
Mowry Shale Horizontal Oil Play
Big Horn Basin, Wyoming
PXP acreage position
54,000 net acres
Proven Source Rock
Petrophysical characteristics of
successful oil shale plays
Depth Range
~6,000' to 10,000'
Shale Thickness Range
~250' to 400'
Expected first drilling late 2010
Legend
PXP ACREAGE
USGS OIL
FAIRWAY
Location Map
Mowry Gas
Production
Mowry Oil
Production
USGS Oil Fairway


17
PXP
Legend
PXP ACREAGE
Los Angeles Basin
Los Angeles Basin
PXP
MONTEREY
PRODUCTION
OXY DISCOVERY
VENOCO
ACTIVITY
*
PXP acreage position
86,000 net
Acquiring 3D seismic data
over key assets
Exploratory wells planned
in 2011
Point Pedernales
Point Arguello
Rocky Point
Arroyo Grande
Lompoc
Cymric
Belridge
McKittrick
Midway Sunset
Urban Area
Las Cienegas
Inglewood
Montebello
Pescado
Hondo
San Joaquin Basin
San Joaquin Basin
Santa Maria Basin
Santa Maria Basin
*
Monterey Shale Oil Play
Location Map
Jesus Maria


18
PXP
Natural Gas Assets
Dry Gas
1%
COP
Madden
Dry Gas
1%
PXP
South Texas
High Liquids
21%
PXP
Granite Wash
Dry Gas
22%
CHK
Haynesville
Production
Characteristics
Est. % of
2011Capital
Operator
Assets


19
PXP
PRODUCING
AWAITING COMPLETION
2010 DRILL LOCATIONS
ACTIVE DRILLING
Haynesville Shale
Activity Map
TEXAS
LOUISIANA
Location Map
Legend


20
PXP
$312 MM
$319 MM
$336 MM
$218 MM
$232 MM
$315 MM
0
15
30
45
60
2010
2011
2012
2013
2014
2015
$0
$200
$400
$600
$800
Haynesville Shale
Operational Plan
$8.24/BOE
(3)
or
$1.37/Mcfe
January 1, 2010 Project Cost Forward F&D:
(1) Net revenue minus net expenses.
(2) Assumes D&C costs for first 4 years = $7.5 MM per well, after 4 years = $6 MM per well.
(3)
Assumes
Strip
pricing
in
2010,
$85/Bbl
of
oil
and
natural
gas
pricing
of
$5.00/MMBtu
in
2011,
$85/Bbl
of
oil
and
natural
gas
pricing
of
$5.50/MMBtu
in
2012,
and
$86/Bbl
of
oil
and natural gas pricing of $6.00/MMBtu 2013 and beyond.
6.5 Bcfe
Average Gross EUR per Well:
$7.5 MM
(2)
Average Gross Well Cost:
6.8 Tcfe
Net Resource Potential:                                        
1,400
Potential Net Locations:                                       
105,000
Net Acreage:
20% WI / 15% NRI
PXP Interest:                                                   
CAPEX                
PXP Net
Production
PXP Net
Cash
Flow
(1)


21
PXP
Granite Wash Horizontal Play
Recent High-Rate Completions
NW. Mendota Area
Buffalo
Wallow Area
PXP LEASES
PXP WELLS
Producing
Horizontal Wells
Custer
Washita
PXP Hanson #29-2H 18MMCFED
10.4 MMCFD/344 BOPD/888NGL
PXP acreage position
19,100 net acres
Five rigs currently operating
152 Granite Wash Locations
(PXP WI 88%)
Industry ROI 39% @
$5.00/MMBtu & $75/bbl
2010 Plan
19 wells Spud
$105 MM Capex
Marvin
Lake Area
PXP Britt Caldwell #9026H
Drilling
PXP Thomas #1003H
PTD 18,300’
WOC
PXP Thomas #903H
28 MMCFED
12.2 MMCFD/1373 BOPD/1311 NGL
PXP Sanders #74-1H
PTD 15600’
md
WOC
Legend
Location Map
Thomas 1103H
Drilling
JO Well 96-6H
Drilling
PXP Hanson #40-4H
29 MMCFED
15.4 MMCFD/746 BOPD/1532 NGL
PXP Cook 39-2H
Drilling
PXP Hanson #29-3H
PTD 16000’
md
Drilling


22
PXP
CAPEX                
PXP Net
Production
PXP Net
Cash
Flow
(1)
$48 MM
$105 MM
$240 MM
$240 MM
$210 MM
$253 MM
0
6
12
18
24
30
2010
2011
2012
2013
2014
2015
$0
$100
$200
$300
$400
$500
Granite Wash Horizontal Potential
Operational Plan
(1) Net revenue minus net expenses.
(2)
Assumes
Strip
pricing
in
2010,
$85/Bbl
of
oil
and
natural
gas
pricing
of
$5.00/MMBtu
in
2011,
$85/Bbl
of
oil
and
natural
gas
pricing
of
$5.50/MMBtu
in
2012,
and
$86/Bbl
of
oil
and natural gas pricing of $6.00/MMBtu 2013 and beyond.
$9.79/BOE or $1.62/Mcfe
(2)
January 1, 2010 Project Cost Forward F&D:
1.1 MMBOE
Average Gross EUR per Well:
$8.2 MM
Average Gross Well Cost:
113.2 MMBOE
Net Resource Potential:                                        
152
Potential Locations:                                            
19,100
Net Acreage:
88% WI / 70% NRI
PXP Interest:                                                   


23
PXP
+1.4 Billion BOE Resource Potential
Potential Reserves
950 MMBOE
275 MMBOE
100 MMBOE
10 MMBOE
+1.3 Billion BOE
Development Resource Potential
Region
Haynesville
California
Granite Wash
Rockies
+100 Million BOE
Exploration Resource Potential
Potential Reserves
90 MMBOE
30 MMBOE
Region
Mowry Shale
Monterey Shale


24
PXP
Revenue Per MCFE 
Revenue Per MCFE
(3)
$4.58/
MCFE
$7.84/
MCFE
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
PXP
Gas
Peer
Group
Avg.
(1)(2)
2Q 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.


25
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 $0.14 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)
$2.22
$1.23
$0.47
$0.46
$0.60
$0.98
$1.92
$1.24
$4.40
(4)
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
PXP
Gas
Peer
Group
Avg.
(2)(3)
$3.16
$4.40
2Q 2010


26
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
Maintain oil production between 50% and 60% of
total production


27
PXP
Addendum


28
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.
PERIOD
(1)
INSTRUMENT
TYPE
DAILY
VOLUME
AVERAGE
PRICE
AVERAGE
DEFERRED
PREMIUM
INDEX
Sales of Crude Oil Production
2010
Sep –
Dec
Put  Options
40,000 Bbls
$55.00 Strike Price
$5.00
per
Bbl
(2)
WTI
2011
Jan –
Dec
Put
Options
(3)
31,000 Bbls
$80.00 Floor with a
$60.00 Limit
$5.023 per Bbl
WTI
Jan –
Dec
Three-way
Collars
(4)
9,000 Bbls
$80.00 Floor with a
$60.00 Limit
$110.00 Ceiling
$1.00 per Bbl
WTI
2012
Jan –
Dec
Put  Options
(3)
40,000 Bbls
$80.00 Floor with a
$60.00 Limit
$6.087 per Bbl
WTI
Sales of Natural Gas Production
2010
Sep –
Dec
Three-way
Collars
(5)
85,000 MMBtu
$6.12 Floor with a
$4.64 Limit
$8.00 Ceiling
$0.034
per MMBtu
Henry Hub


29
PXP
(Millions)
3 mo.
ended
6/30/10
3 mo.
ended
6/30/09
Revenues
$     364.6
$     278.7
Production Costs
(100.7)
(105.8)
General & Administrative Expenses
(30.3)
(37.6)
DD&A & Accretion Expense
(128.2)
(94.4)
Impairment of Oil & Gas Properties
(59.5)
-
Legal Recovery
-
87.3
Other Operating Income (Expense)
3.9
(1.5)
Income From Operations
$       49.8
$     126.7
Income Before Income Taxes
$       91.0
$       21.3
Net Income
(1)(2)
$       45.4
$       43.6
Earnings Per Share -
diluted
$       0.32
$       0.37
Income Statement Summary
(1) Includes an after-tax gain (loss) on mark-to-market derivative contracts of approximately $36.2 million and ($56.0) million for the three months
ended June 30, 2010 and 2009, respectively.
(2) Three months ended June 30, 2009 includes a beneficial income tax effect of $24 million from a change in the balance of unrecognized tax benefits.


30
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 June 30, 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.
Three Months
Ended
June 30,
2010
Per MCFE
(In Millions)
Oil and gas revenues
$            363.9
$                7.84
Production expenses
(103.0)
(2.22)
Oil and Gas related DD&A & impairments
(179.4)
(3.86)
Gross margin (GAAP)
81.5
1.76
Oil and Gas related DD&A & impairments
179.4
3.86
General & administrative
(30.3)
(0.65)
Noncash compensation
8.3
0.18
Interest expense, net of capitalized interest
(28.0)
(0.61)
Realized loss on mark-to-market derivative contracts
(6.7)
(0.14)
Debt adjusted cash operating margin (Non-GAAP)
$            204.2
$                4.40
Net cash provided by operating activities (GAAP)
$            252.6
$                5.44
Changes in operating assets & liabilities
(28.3)
(0.61)
Noncash and other income items
(16.1)
(0.35)
Realized loss on mark-to-market derivative contracts
(6.7)
(0.14)
Current income taxes attributable to derivative contracts
2.7
0.06
Debt adjusted cash operating margin (Non-GAAP)
$            204.2
$                4.40


31