UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported) May 19, 2010
OCCIDENTAL PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
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1-9210
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95-4035997
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(State or other jurisdiction
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(Commission
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(I.R.S. Employer
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of incorporation)
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File Number)
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Identification No.)
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10889 Wilshire Boulevard
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Los Angeles, California
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90024
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(Address of principal executive offices)
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(ZIP code)
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Registrant’s telephone number, including area code:
(310) 208-8800
Check the appropriate box below if the Form 8-K is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions (see General Instruction A.2. below):
[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Section 7 – Regulation FD
Item 7.01. Regulation FD Disclosure
Attached as Exhibit 99.1 is a presentation made on May 19, 2010, in connection with Occidental’s 2010 Analyst Meeting.
Section 9 - Financial Statements and Exhibits
Item 9.01. Financial Statements and Exhibits
(d) Exhibits
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99.1
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Presentation dated May 19, 2010.
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1
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
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OCCIDENTAL PETROLEUM CORPORATION
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(Registrant)
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DATE: May 19, 2010
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/s/ ROY PINECI
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Roy Pineci, Vice President, Controller
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and Principal Accounting Officer
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EXHIBIT INDEX
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99.1
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Presentation dated May 19, 2010.
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EXHIBIT 99.1
Occidental Petroleum Corporation
Dr. Ray R. Irani
Chairman and Chief Executive Officer
May 19, 2010
1
2
Top quartile total shareholder
return as compared to peers
return as compared to peers
Oxy Goal
2
3
• Grow production 5-8% compounded over a multi-year
period
period
• Maintain return-based focus
– 15+% after tax for U.S. assets
– 20+% after tax for foreign assets
• Increase dividend payout annually
• Low level of financial risk
Key Elements to Achieve Goal
3
4
• Strong Health, Environment and Safety performance
• Bulk of the assets in the United States
• Maintain oil focus with significant natural gas exposure
• Capture new projects in the Middle East
• Make property acquisitions in the U.S. for growth
Additional Elements to Achieve Goal
4
5
Thousand BOE/Day
519
601
633
675
Notes: 1) From continuing operations; 2) This schedule reflects what production volumes
would have been for the past 5 years if all production had been represented on a pre-tax basis.
would have been for the past 5 years if all production had been represented on a pre-tax basis.
714
7.9%
CAGR
CAGR
Actual Worldwide Production
5
6
519
601
633
675
714
756
837
946
1,033
1,118
6.2%
Base
CAGR
Base
CAGR
Worldwide Production Outlook
6
7
• Abu Dhabi
• Oman
• Iraq
Additional Middle East Opportunities
7
8
• Sandy Lowe, President, Oxy Oil & Gas -
International Production
International Production
– Latin America
– Bahrain
– Oman
– Iraq
• Bill Albrecht, President, Oxy Oil & Gas - USA
– Permian CO2 Growth
– Deep Inventory of Drilling Projects
Today’s Focus
8
9
• Anita Powers, EVP Worldwide Exploration
– California Conventional Exploration
• Todd Stevens, VP - California Operations
– California Unconventional Plays
Today’s Focus
9
10
• Steve Chazen, President & Chief Financial Officer
– Midstream & Chemicals
– Production Forecast
– Capital Forecast
– Acquisition Strategy
– Cash Flow Priorities
– Investment Attributes
• Questions & Answers
Today’s Focus
10
International Oil & Gas
Sandy Lowe
President, Oxy Oil & Gas - International Production
May 19, 2010
2
Colombia
Libya
Oman
UAE
Yemen
Argentina
Bolivia
Qatar
Iraq
Bahrain
Focus Areas
International Producing Areas
3
• 2010 Outlook 79
• 2014 Outlook 95 - 105
$75 WTI
Latin America Net Production
Mboepd
4
Llanos Basin - 3 B boe Remaining Oil In
Place (ROIP)
Place (ROIP)
• Cano Limon - 15 infill wells in 2010
• New Fields on trend with Cano Limon
– Some stratigraphic reserves upside
– 2 exploration wells this year
• 2010 Gross 80 Mbopd, Net 23 Mbopd
• 2014 expected gross 33 Mbopd,
Net 10 Mbopd
Net 10 Mbopd
La Cira Infantas - 800 MM boe ROIP
• Gross raised from 4 Mbopd to 26
Mbopd in 4 years
Mbopd in 4 years
– 150 new wells per year
– Increasing water injection facilities
• 2010 Gross 28 Mbopd, Net 9 Mbopd
• 2014 expected Gross 50 Mbopd,
Net 18 Mbopd
Net 18 Mbopd
• Total Colombia 2014 Net expected to
be 28 Mbopd
be 28 Mbopd
!
(
!
!
Covenas
Ayacucho
La Cira
Infantas
Infantas
Cano
Limon
Limon
Venezuela
Colombia
LLN-COV pipeline
Vasconia
Oleoducto de
Colombia
Pipeline Source: Ecopetrol
Colombia BU Highlights
5
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Oxy Argentina Concessions
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Province |
Concessions |
Proved Reserves (MMboe)
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Current Net Production
(Mboepd)
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Santa Cruz
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15
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118
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39
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Chubut
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1
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3
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2
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Mendoza
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7
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9
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4
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TOTAL
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23
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130
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45
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Argentina
Cuyo Basin
Cuyo Basin
Neuquen Basin
Neuquen Basin
San Jorge Basin
San Jorge Basin
Atlantic
Ocean
Ocean
Chubut
Santa Cruz
Argentina Asset - Overview
6
• 6 B boe ROIP
• Oxy Argentina currently operates
– 2,200 active wells
– 85% oil
– 26 waterflood projects, 13 gas plants
• 2010 plan
– Sign 10 year contract extension, adding over 72
MMboe of proven reserves
MMboe of proven reserves
– Production growth of 8% over 2009
– Drill 140 wells and perform 100 workovers
– Continue to add waterflood facilities
• 2010 Gross production 50 Mboepd, Net 45 Mbopd
Argentina - 2010
7
• Contract extension increases the term to 2025
• Opportunity to fully develop and exploit these prolific
reservoirs
reservoirs
• Continue production growth at 9% per year through 2014
• Perform near field, low risk exploration - 10 wells per year
• Drill 140 development wells per year
• Focus on waterflood development
• 2014 Gross production expected to be 74 to 85 Mboepd,
Net production expected to be 65 to 75 Mboepd
Net production expected to be 65 to 75 Mboepd
Argentina - Future Plans
8
• 2010 Outlook 286
• 2014 Outlook 358 - 381
$75 WTI
Middle East/North Africa Net Production
Mboepd
9
• 7 B boe ROIP
• Nafoora Augila Field
– 255 new wells and 32 workovers
– Install 1 MMBD processing & water
injection facilities and 100 MW
power
injection facilities and 100 MW
power
• Blocks 103 and 74/29 Fields
– 96 new wells
– Install 500 MBD processing & water
injection facilities and 50 MW power
injection facilities and 50 MW power
• 22 Exploration wells 2011 to 2013
• 2010 Gross production 98 Mbopd,
Net 15 Mbopd
Net 15 Mbopd
• 2014 expected Gross production 160
to 172 Mbopd, Net 28 to 33 Mbopd
to 172 Mbopd, Net 28 to 33 Mbopd
Libya Re-Development Plan
Gulf of Sidra
Mediterranean Sea
Benghazi
Sirte
74A
29B
74F
103
102
51A
NAU-NNU
74B
29C
NC145
NC144
NC150
Tripoli
NC143
Area 103
Zueitina EPSA
NAU - NNU
-
Exploration Blocks
Bid Round 4
10
• 2 B bo ROIP
• Block S-1 producing 9 Mbopd
gross
gross
• East Shabwa producing 60 Mbopd
gross
gross
• Masila producing 71 Mbopd gross
– Contract expires 12/2011
– Extension being negotiated
• 2010 program
– 31 development wells
– 3 exploration wells
• 2010 Net production 30 Mbopd
• 2014 Expected Gross production
75 to 110 Mbopd, Net 16 to 24
Mbopd
75 to 110 Mbopd, Net 16 to 24
Mbopd
!
(
!
(
!
(
Aden
Shibam
OXY Exploration
OXY Non Operated Production
OXY Operated Production
Oil Fields / Gas Fields
Pipeline
Red
Sea
Red
Sea
!
San’a
As Salif
Block 14
Masila
Block 10
East Shabwa
Saudi Arabia
Yemen
Gulf of Aden
Block S-1
Damis
Oil Fields / Gas Fields
Pipeline
Yemen
10
11
Qatar - Oil & Gas Fields
• Idd El Shargi North Dome
(ISND) - 4 B bo ROIP
(ISND) - 4 B bo ROIP
• Idd El Shargi South Dome
(ISSD) - 800 MM bo ROIP
(ISSD) - 800 MM bo ROIP
• Al Rayyan - 300 MM bo ROIP
• 2010 Gross Production 118
Mbopd, Net 76 Mbopd
Mbopd, Net 76 Mbopd
• Priorities:
– Maintain production from
existing fields
existing fields
– Additional activity to
increase production later
in the 2010 - 2014 period
increase production later
in the 2010 - 2014 period
Qatar
Qatar
Al Rayyan
Gas Project
Idd El Shargi
North Dome (ISND)
North Dome (ISND)
Idd El Shargi
South Dome (ISSD)
Saudi Arabia
Saudi Arabia
Bahrain
Doha
Umm Sa’id
12
• ISND - applying modern
technology
technology
– Gross Production -
105 Mbopd
105 Mbopd
– Extensive Horizontal Drilling
– Tight matrix waterflood
– Multi-lateral production
– Early use of multi-lateral
source water to injection
completions
source water to injection
completions
Qatar - ISND - Enhancing Production
Qatar
Qatar
Idd El Shargi
North Dome (ISND)
North Dome (ISND)
Saudi Arabia
Saudi Arabia
Bahrain
Bahrain
Doha
Umm Sa’id
13
• Phase 1 1994 - 2001
– Drilled 77 Wells
– Added gas lift and water injection facilities
– Multi-lateral production and injection
• Phase 2 2002 - 2005
– Drilled 50 Wells
– Added power, gas compression and water injection facilities
• Phase 3 2007 - 2010
– Drilled 70 wells
– Minor facilities additions
• 2010-2012 Projects for all three assets
– Drill 55 additional development wells
– Install additional facilities
§ 2 new platforms
§ Power generator
§ Additional processing equipment
– Develop 70 MMBO of gross reserves
• 2014 Gross production expected to be 100 to 110 Mboepd,
Net 65 to 70 Mbopd
Net 65 to 70 Mbopd
Qatar Projects
14
15
Oxy operated since 1994
previous operators
Oxy Qatar Gross Oil Production
15
16
• Delivering 2.0 Bcfd to UAE
and 200 MMcfd to Oman
markets
and 200 MMcfd to Oman
markets
• Gross Production over
530 Mboepd
530 Mboepd
• Consistently above
anticipated gas / liquids
production
anticipated gas / liquids
production
• Additional third party gas
volumes being shipped
volumes being shipped
• On time and budget during
period of rapidly increasing
costs
period of rapidly increasing
costs
• Exceptional returns
Dubai
Taweelah
Jebel Ali
Abu Dhabi
Al Ain
Fujayrah
Umm Sa’id
Doha
Al Hawailah
Dolphin
ISND
ISSD
Block 12
Al Rayyan
Qatar
Saudi Arabia
United Arab Emirates
Oman
Iran
48” Export Pipeline
Jarn
Yaphour
Dolphin Project
17
• Oxy share 24.5%
• 2010 Gross production
537 Mboepd, Net
production 64 Mboepd
537 Mboepd, Net
production 64 Mboepd
• Fee income for UAE
distribution and 3rd party
sales increasing
distribution and 3rd party
sales increasing
• 2014 expected Gross
production 535 Mboepd,
Net 39 Mboepd
production 535 Mboepd,
Net 39 Mboepd
Ras Laffan Plant
Dolphin Gas Project - Oxy Metrics
17
18
Dolphin Fee Income
18
19
Oxy Oman History
• Oxy commenced operation of the
Safah field in 1984
Safah field in 1984
• Over 500 wells drilled and 30 fields
discovered in Blocks 9 and 27
discovered in Blocks 9 and 27
• Mukhaizna acquired in 2005
• Block 62 acquired in 2008
• 1,300 total wells drilled in Oman
• 2010 Gross production 190
Mboepd, Net production 70
Mboepd
Mboepd, Net production 70
Mboepd
• 2014 expected Gross production
220 to 240 Mboepd, Net production
70 to 80 Mboepd
220 to 240 Mboepd, Net production
70 to 80 Mboepd
9
27
62
54
53
Safah
Mukhaizna
Block 62
!
Muscat
Gulf of Oman
Arabian Sea
Oman
Oman
Saudi
Saudi
Arabia
Arabia
UAE
UAE
19
20
Mboepd
Oman Gross Production Growth
1984 - 2010
1984 - 2010
21
Block 9
Block 27
Safah Field
3D Seismic Coverage
• 2.1 B boe ROIP
• Gross Production
currently at record 91
Mboepd
currently at record 91
Mboepd
• Exploration
– Near field, low risk
– Added ~50Mmboe
over last five years
over last five years
– Multi-year inventory
– Expect to discover
~10 Mmboe gross
per year
~10 Mmboe gross
per year
Oil Discovery or Producing Field
Gas Discovery or Producing Field
Example Oxy Discovery
Oman Blocks 9 & 27
22
• Oxy is partnered with Oman
Oil Company and Mubadala
Oil Company and Mubadala
• Develop Maradi Huraymah
Field
Field
• Appraise 3 gas discoveries
– 5 wells
– 2 drilled at Habiba
– Encouraging logs and
cores, testing in June
cores, testing in June
• 2011+ Exploration Program
– 2 shallow wells
– 3 to 4 deep wells, 15,000 to
20,000 ft
20,000 ft
– Deep potential of 1 to 2 TCF
Oman Block 62
KM
-
1H1
Oman Block 62
Maradi Huraymah Field
Rasafah Discovery
Habiba Discovery
Fushaigah Discovery
23
• World Class Steam flood
• 2 B bo ROIP
• Discovered in 1975 in South
Central Oman
Central Oman
• Cold production commenced 1992
• Oxy assumed operation
September 1, 2005 at 8,500 Bopd
September 1, 2005 at 8,500 Bopd
• Steam flood commenced May 2007
• Current Gross Production: 100,000
Bopd
Bopd
• Target Gross Production: 150,000
Bopd
Bopd
9
27
62
54
53
Safah
Mukhaizna
Block 62
!
Muscat
Gulf of Oman
Arabian Sea
Oman
Oman
Saudi
Saudi
Arabia
Arabia
UAE
UAE
Oman - Mukhaizna
24
MECHANICAL VAPOR COMPRESSORS
• 7 TRAINS - LARGEST EVER BUILT
• CONDITION WATER FOR BOILER FEED
• 43 MBWPD PER TRAIN
Water Treatment Plant - 2010
24
25
• Increase long term gross oil production from 30,000
to over 100,000 Bopd
to over 100,000 Bopd
• Increase total sales gas rate from 1.1 Bcfd to
over 2 Bcfd
over 2 Bcfd
• Gross oil production expected to be 70,000 to 75,000 Bopd
by 2014
by 2014
• Gross gas production expected to be 1.6 Bcfd by 2014
Bahrain Field Development Plan
25
26
• 7 B bo ROIP
• 17 TCF remaining gas in place (RGIP)
• JV with OXY, Mubadala & Nogaholding
• 19 Reservoirs
• Development includes several new
reservoirs including steam flood of heavy
oil
reservoirs including steam flood of heavy
oil
1.5 B bbl heavy oil
28 TCF gas
6.8 B bbl light oil
Bahrain Field Development
26
27
• Drilling over 2,500 wells
– Increase the rig fleet - building up to 6 drilling rigs and 6
workover rigs
workover rigs
• Implement new recovery processes
– Waterfloods
– Steam injection
• Increase fluid and gas handling capacity
– Expanding and adding new tank batteries and manifolds
– Add new steam and water injection facilities
– Expand gas processing capacity
Bahrain Work Activities
27
28
• Agreement Signed January 2010 allows Oxy
to:
to:
– Produce oil
– Take payment in kind
– Book reserves
• Over 20 B bo ROIP
• Gross production of 200 Mbopd by year end,
1.2 MMbopd in 7 years
1.2 MMbopd in 7 years
• Base Rate - 182 Mbopd
• Rehabilitation Plan of activities submitted
April 16, 2010
(period 2011 - 2013)
April 16, 2010
(period 2011 - 2013)
Iran
Iran
Kuwait
Kuwait
Basra
Iraq
Iraq
OXY Production
Oil & Gas Fields
Majnoon
(Shell, Petronas)
Rumaila
(BP & CNPC)
West Qurna-2
(Lukoil & Statoil)
West Qurna-1
(ExxonMobil & Shell)
Halfaya
(CNPC, Total, & Petronas)
Zubair Field
(OXY, ENI, KoGas)
Iraq - Zubair Field
29
Iraq - Contract Features
• Contract allows for quick cost recovery
• At current prices, payback occurs in 4
years, sooner if prices rise
years, sooner if prices rise
• Maximum cash outlay at risk is $800 million
• Ultimate recovery net to Oxy is 210 MMBO
at current prices
at current prices
30
• Consortium presence of 40 personnel currently
in Zubair increasing to 150 by year end
in Zubair increasing to 150 by year end
• Consortium working with the Iraqi South Operating
Company (SOC) to form the Zubair Field Operating
Division (ZFOD)
Company (SOC) to form the Zubair Field Operating
Division (ZFOD)
• Anticipate Zubair 10% gross production increase and
Rehabilitation Plan approval by the end of the year
Rehabilitation Plan approval by the end of the year
• 2014 Gross production expected to be 840 to 880
Mbopd, Net production expected to be 65 to 75
Mbopd
Mbopd, Net production expected to be 65 to 75
Mbopd
Iraq - Current Activities
31
Middle East / Africa 286 358-381
Latin America 79 95-105
TOTAL 365 453-486
2010 2014
Outlook Estimate
Outlook Estimate
MBOEPD
International Net Production
32
Grow:
• Oman gross production from 190 to 240 Mboepd
• Bahrain gross oil production from 30 to 75 Mbopd
• Bahrain gross gas production from 1.1 to 1.6 Bcfd
• Argentina gross production from 50 to 85 Mboepd
• Iraq gross production from 182 to 880 Mbopd
Continue generating substantial free cash flow
from:
from:
• Qatar
• Dolphin
• Colombia
• Yemen
International Summary - 5 years
United States Production Operations
Bill Albrecht
President, Oxy Oil & Gas - USA
May 19, 2010
1
2
Overview
• Permian
– Primary Development
– CO2 Growth Opportunities
• California
– Elk Hills Development
– Other California
• Mid-Continent
– Piceance Overview
– Hugoton Overview
• Domestic Summary
2
3
PERMIAN
3
4
• Oxy’s largest business unit
• 180,000 BOEPD
• Largest oil producer in Texas
• Largest oil producer in Permian
(20% of total)
(20% of total)
• Largest operator in Permian
(of 1,500+ operators)
(of 1,500+ operators)
• 10,000+ interest owners
• 100,000 square mile area
• Acreage
– 3,600,000 gross
– 2,200,000 net
• 1.1 BBOE of net proved
reserves (34% of Oxy total)
reserves (34% of Oxy total)
• 1.7 BCFPD (0.5 TCF/YR) of CO2
Permian Overview
4
5
Permian Basin
Permian Basin
• Primary Development (1,000+
locations)
locations)
– Plan a 6-7 rig program
– Dora Roberts Wolfberry
– Continued southeast New
Mexico exploitation
Mexico exploitation
– Deeper added plays
• CO2 Growth
– Existing flood expansions
(including residual oil zone
deepenings)
(including residual oil zone
deepenings)
– New CO2 projects
– Infill drilling/pattern flooding
– New Century plant online 4Q
2010 for additional CO2
supply
2010 for additional CO2
supply
Lubbock
Texas
New Mexico
Oklahoma
Bravo Dome CO2
Source
Source
Midland
Wolfberry
Delaware Sands
Permian Growth Opportunities
5
6
Shallow (4,000-10,000 feet)
• Non-traditional pays, e.g.,
“Wolfberry” play at Dora
Roberts (250 well program)
“Wolfberry” play at Dora
Roberts (250 well program)
• Historically uneconomic
pays with horizontal drilling
applications, e.g., Delaware
and Bone Springs sands
pays with horizontal drilling
applications, e.g., Delaware
and Bone Springs sands
Delaware Sands
“Wolfberry”
Permian Primary Development
Delaware Sands (Oil)
200+ locations; 20+ mmboe
“Wolfberry” (Oil)
550+ locations; 70+ mmboe
6
7
Deep (10,000-15,000 feet)
• Horizontal Devonian
opportunities
opportunities
• Ellenburger oil and deeper
Ellenburger gas
Ellenburger gas
• Morrow sand opportunities
on southeast New Mexico
acreage
on southeast New Mexico
acreage
• These deeper plays are on
acreage Oxy already owns
acreage Oxy already owns
Delaware Sands
Fusselman
Ellenburger
“Wolfberry”
Devonian
Potential Added Plays
Devonian (Oil)
375+ locations; 30+ mmboe
Fusselman (Oil)
75+ locations; 15+ mmboe
Ellenburger (Oil)
125+ locations; 25+ mmboe
7
8
Permian Added Plays
• Added plays inventory
– ~1,000 locations and 90-100 MMBOE net risked reserves
• Infill drilling inventory
– ~1,100+ locations, greater than a 10-year inventory at
existing drilling pace
existing drilling pace
• Higher oil prices bringing new opportunities (1,100
additional locations, 25-40 MMBOE) which are
economic at current oil prices
additional locations, 25-40 MMBOE) which are
economic at current oil prices
8
9
Note: Based on data obtained from the O&GJ 2010 Biannual EOR Survey
22% of Permian Basin’s Oil Production
Permian Basin CO2 Floods
EOR Production is Growing
EOR Production is Growing
9
10
14 other companies
• Permian Basin CO2 Floods
• First floods initiated 35 years ago
• Over 50 CO2 floods in Permian Basin
Note: Based on data obtained from the O&GJ 2010 Biannual EOR Survey
Permian Basin CO2 Floods
Number of Active Operated CO2 Projects
Number of Active Operated CO2 Projects
10
11
14 other companies
• Permian Basin CO2 Floods
• First floods initiated 35 years ago
• Over 50 CO2 floods in Permian Basin
Note: Based on data obtained from the O&GJ 2010 Biannual EOR Survey
Permian Basin CO2 Floods
Operated CO2 Projects EOR Production, BOPD
Operated CO2 Projects EOR Production, BOPD
11
12
CO2 Flood
Waterflood
Primary
60%
30%
10%
Permian Oil Production
12
13
1-2 yrs. avg.
response time
response time
Examples of CO2 Flood Response
13
14
1-2 yrs. avg.
response time
response time
Examples of CO2 Flood Response
14
15
1-2 yrs. avg.
response time
response time
Examples of CO2 Flood Response
15
16
1-2 yrs. avg.
response time
response time
Examples of CO2 Flood Response
16
17
1-2 yrs. avg.
response time
response time
Examples of CO2 Flood Response
17
18
Pattern Layout
Evaluated more
than 50 parameters
for each pattern
than 50 parameters
for each pattern
Facilitated by new
generation of tools
generation of tools
Traditional Process
New Process
Typical pattern =
One injector and
four producers
four producers
1800 CO2 Patterns
Applied at Pattern Level
CO2 Surveillance - Step Change
• Flood specific tools
• Only applied to largest
projects
projects
• Limited to senior
engineers
engineers
• Manual process
• Annual frequency
• Standardized approach
• Applied to all CO2 floods
• Visualization software
• Monthly updates
• Readily taught
• Improved accuracy
• Frequent flood
improvements
improvements
18
19
Permian CO2 Surveillance
Results of Surveillance Effort
• Constructed new tools to enable review of 1,600
patterns in two months
patterns in two months
• Re-allocated CO2 to better performing patterns
• Defined 3,000+ BOPD improvement with equal volume
of CO2 injected
of CO2 injected
• Developed skills to maintain efficiency
19
20
4.6 BBO
3P Reserves
EOR Likely
EOR Potential
0.8 BBO
1.4 BBO
1.0 BBO
Residual
7.8 BBO Net Remaining
EOR Opportunities
• 4.1 BBO have been
produced,
produced,
• leaving 7.8 BBO net
remaining
remaining
20
21
|
|
Net
Reserves* (MMBOE) |
Net CO2
Required (TCF) |
|
Developed
|
570
|
2.8
|
|
Undeveloped
TOTAL
|
430
1,000
|
2.2
5.0
|
“The next billion barrels”
Reserves and CO2 Requirements
* 3P Reserves
21
22
CO2 Growth Opportunities
• Currently produce 1.7 BCF/day (0.5 TCF/year)
• Short term CO2 purchase opportunities (1.1TCF)
– More opportunity to purchase additional CO2 volumes
– Recently contracted for additional 100 MMCFD
• Oxy produced CO2 (1.6 TCF)
– Can add CO2 by drilling more wells
• Additional CO2 supply (3.5 TCF)
– From methane/CO2 fields (e.g., Piñon field)
• Enables Occidental to accelerate development of
projects that are in hand
projects that are in hand
22
23
Additional CO2 Supply vs. Demand
• Should Piñon development cease, currently developed
CO2 would continue to be available to Oxy at similar
rates
CO2 would continue to be available to Oxy at similar
rates
• If Century Plant CO2 delivery schedule not met,
adequate CO2 supply exists today on the market to
cover the shortfall
adequate CO2 supply exists today on the market to
cover the shortfall
• Penalties paid for non-delivery of CO2 would
effectively reduce the cost of make-up CO2
effectively reduce the cost of make-up CO2
• Oxy expects to be able to secure such supply if
necessary
necessary
23
24
• Plant design
– Inlet = 675 MMCFD
– Train I = 260 MMCFD CO2
– Train II = 180 MMCFD CO2
• Expected start up:
– Train I - 4th Quarter 2010
– Train II - Early 2012
Permian - Century CO2 Plant Project
24
25
• Flood Expansions:
Slaughter (in 6 Units)
Levelland (3 Units)
Wasson (ROZ, 3 Units)
Seminole (ROZ, Hess)
South Hobbs
North Cowden
ROZ Expansions (numerous
projects)
projects)
• New CO2 Floods:
West Seminole
Sharon Ridge
Clearfork Reservoirs
• Slug Size Increases
Nearly all existing projects
Permian CO2 Floods (with additional CO2)
25
26
* $75 / Bbl Marker Price
Typical CO2 Project Cost Structure
26
27
Permian - Summary
• Primary development
– Deep inventory of 2,000+ drilling locations, mostly oil,
with 150+ MMBOE risked reserve exposure
with 150+ MMBOE risked reserve exposure
– Locations on acreage Oxy already owns
• CO2 growth
– 1-3 billion BBLS net of enhanced recovery reserves
expected from Oxy Operated CO2 floods
expected from Oxy Operated CO2 floods
– Significant inventory of CO2 flood opportunities
§ Expansions, new floods, residual oil zone
development, slug size increases
development, slug size increases
– Ample CO2 supply accelerates implementation
• Production
– Expect to grow production from 180 MBOEPD in 2010 to
220-230 MBOEPD in 2014
220-230 MBOEPD in 2014
– Assumes no additional acquisitions
27
28
CALIFORNIA
28
29
• 143,000 BOEPD
• 780 MMBOE net proved reserves
(24% of Oxy total)
(24% of Oxy total)
• Main producing assets are Elk Hills,
Wilmington, and other assets in the
San Joaquin, Ventura, Sacramento
and LA basins
Wilmington, and other assets in the
San Joaquin, Ventura, Sacramento
and LA basins
• #1 natural gas producer and #2 oil
producer in the state
producer in the state
• Largest fee mineral owner in the
state with more than one million
net acres
state with more than one million
net acres
• 90 producing fields, spanning
more than 600 miles
more than 600 miles
• 7,500 active wells
California Overview
29
30
• Took over operations in February 1998
• Approximately 78% ownership
• 538 million BOE proved reserves (70% of CA total)
• Produced 400 million BOE (1998-2009)
• ~125% production replacement
• Largest CA gas & NGL producer
• 5th largest CA oil producer
• Largest gas plant in CA
Elk Hills Key Facts
30
31
Elk Hills
• Development Drilling
– Continued focus on
Stevens sands and shales
(60+ wells in 2010)
Stevens sands and shales
(60+ wells in 2010)
– Re-focused effort on
eastern shallow oil zone
development (129 wells and
57 workovers)
eastern shallow oil zone
development (129 wells and
57 workovers)
– Maintain a 7-rig program
California Development
31
32
Drilling
Inventory
Shallow Oil 1,060
Stevens Sands & Shales 700
Total 1,760
Elk Hills Drilling Location Inventory
32
33
Gas Plant
Capacity MMCFD
Current 420
Late 2Q 2010 Skid Plant 90
Q1 2012 Cryo Plant 200
Total 710
• 200 MMCFD plant-largest that could be built in 20-24 months
• Awarded contract for the plant, and work has begun
• Deeper NGL recovery, high sales gas quality
• Largest, most efficient plant in the area (regional gas hub)
• By year-end 2010, additional capacity will be ordered
(at capacity)
(will be at capacity)
Elk Hills Gas Plant Expansions
33
34
California Development -
Kern County Discovery
Kern County Discovery
• Currently have 24 wells capable
of producing ~45 MBOEPD
of producing ~45 MBOEPD
– Currently gas plant
constrained
constrained
– When 90 MMCFPD skid
mounted facility is brought
online, it will be filled
mounted facility is brought
online, it will be filled
• Planning to drill an additional
20 wells in 2010 (oil focused)
20 wells in 2010 (oil focused)
• Extension opportunities to the
North, South, and West
North, South, and West
• At least 30 additional locations
beyond 2010
beyond 2010
34
35
California Development -
North Shafter
North Shafter
• North Shafter Field
– Acquired 58% in 2004, and
the remainder in 2009
the remainder in 2009
– Now 100% Oxy
– 140+ MMBOEIP
– 7.3% current Recovery Factor
– 44 active wells
– Potential to reduce 80 acre
well spacing to 40 acres
well spacing to 40 acres
• New Concept
– California’s first cemented
liner, plug & perf, fracture
stimulation
liner, plug & perf, fracture
stimulation
– Completed March, 2010
– IP 350 BOPD
– Up to 40 additional locations
using this new completion
method and 40 acre spacing
using this new completion
method and 40 acre spacing
35
36
• Producing:
– 580 Wells, 22 MMbo Net
• Undeveloped:
– 720 Wells, 42 MMbo Net
Historical Steam
Development
Development
Proved
Undeveloped
Undeveloped
Probable
Undeveloped
Undeveloped
California Development - Heavy Oil
36
37
Oxy Long Beach Overview
Wilmington Field
• Among Top 10 largest
oilfields in North America
oilfields in North America
– 6-8 Billion barrels in place
– 2+ Billion recovered
to date
to date
• Significant redevelopment
upside
upside
• Oxy partnering with State,
City of Long Beach, and
the Port of Long Beach
City of Long Beach, and
the Port of Long Beach
37
38
Oxy Long Beach Development
• Steadily growing field
ownership
ownership
– Current stake in over
80% of properties
80% of properties
• Tidelands is a service
contract; THUMS Long
Beach is a PSC
contract; THUMS Long
Beach is a PSC
• Converted a portion of
Tidelands contract to a
PSC through deal with
Port of Long Beach
Tidelands contract to a
PSC through deal with
Port of Long Beach
• Currently negotiating with
the State to do the same
the State to do the same
• Opportunity to grow
production over a 5 year
period with additional
investment
production over a 5 year
period with additional
investment
38
39
California - Summary
• Primary development
– Current inventory of 3,700+ drilling locations
– Locations on HBP or Oxy owned fee minerals
– Recent Kern county discovery does not materially change
gas/oil production mix
gas/oil production mix
– Long Beach is a growth opportunity with recent increases
in equity ownership
in equity ownership
• Infrastructure
– Aging gas plant infrastructure constraining production
– 200 MMCFPD gas plant to be built in 20-24 months
– Additional gas plant capacity will be necessary
• Production
– Expect to grow production from 151 MBOEPD in 2010 to
212-222 MBOEPD in 2014
212-222 MBOEPD in 2014
– Assumes no exploration success or acquisitions
39
40
MID-CONTINENT
40
41
Mid-Continent Gas Business Unit
42
42
Cascade Creek
Collbran Valley
Oxy Acreage
Legend
65 Miles
Piceance Position Overview
• ~120,000 net acres
• ~ 640 mmboe total resource base (> 3.8 TCFE)
• ~ 6,000 undrilled locations
42
43
Piceance Development
• Prudent development approach short term, because of
low current gas prices
low current gas prices
– One rig program currently
• Excellent acreage
– Own legacy fee acreage with low royalty (15,000 acres
<1% royalty)
<1% royalty)
• Focused operations
– Reduced unit operating costs by 40+% in 2009
– Specialized Piceance fit-for-purpose drilling rigs in
inventory
inventory
– Reduced drilling time to < 10 days/well from 15+ days/well
in 2008
in 2008
– Improved time to market through simultaneous drilling &
completions operations
completions operations
• Growth
– Resource play where we can readily add production
43
44
|
NYMEX Price |
Realized
Price ($/MMBTU) |
Capital ($MM) |
Reserves/Well (BCFE) |
ROR |
|
$4.00/MMBTU
|
$3.62
|
$2.1
|
1.6
|
19%
|
|
$6.00/MMBTU
|
$5.36
|
$2.1
|
1.6
|
40%
|
Piceance Development Economics
44
45
Legacy Acreage
Recently Acquired Acreage
Chase
Council Grove
Wabaunsee
Shawnee
Lansing
Kansas City
Marmaton
Cherokee
Atoka
Morrow
Chester
St. Genevieve
Summer
Heebner
Shallow
Formations
Formations
Gas
Lower
Formations
Formations
Oil + Gas
2500’
4000’
6000’
Hugoton - Oil Drilling Opportunities
• 185 miles long by 45 miles wide
• 2,500 active Oxy wells & 500 miles of pipeline
• ~25,000 boepd (100 mmcfpd, 5,500 bopd, 3,000 bcpd)
• Oxy operated since 1940’s
• Recently doubled acreage from 700,000 to 1,400,000 acres
• 2010 capital program targeting high ROR oil opportunities
– Primary & secondary recovery opportunities
(waterfloods)
(waterfloods)
– 35+ wells planned (90+% oil)
45
46
Mid-Continent Gas - Summary
• Primary development
– Prudent approach to gas drilling
– 3.8 TCFE Resource
– 6,000+ drilling locations
– Low royalty burden enhances economics
– Recent Hugoton acquisition doubles acreage position
and adds significant oil location inventory
and adds significant oil location inventory
• Production
– Expect to grow production from 60 MBOEPD in 2010 to
80-100 MBOEPD in 2014
80-100 MBOEPD in 2014
– Assumes no additional acquisitions
46
47
DOMESTIC SUMMARY
47
48
|
|
Drilling Inventory
|
|
Mid-Continent
|
6,500
|
|
Other California
|
1,870
|
|
Permian Primary
|
1,350
|
|
Elk Hills Shallow Oil
|
1,060
|
|
Permian ROZ deepenings
|
800
|
|
Elk Hills Stevens
|
700
|
|
Kern County discovery
|
50
|
|
TOTAL
|
12,330
|
Domestic Drilling Location Inventory
48
49
Domestic Net Production
Permian 184 185 180 220-230
California 128 134 151 212-222
Mid-Continent 49 57 60 80-100
TOTAL 361 376 391 512-552
CAGR, % 6.4 - 8.0
2010 2014
2008 2009 Outlook Estimate
2008 2009 Outlook Estimate
MBOEPD
49
50
Domestic Summary
• Stable, low decline base production
• Deep inventory of drilling projects, mostly oil, across
all domestic business units (12,000+ locations)
all domestic business units (12,000+ locations)
• Large inventory of existing and new CO2 floods
with adequate CO2 supplies secured
with adequate CO2 supplies secured
• California continues to be a major production growth
driver in the U.S.
driver in the U.S.
• Expect to generate 6-8% growth per year over the next
five years (excludes exploration success and
acquisitions)
five years (excludes exploration success and
acquisitions)
• U.S. business is 70% liquids, and we expect this
percentage to stay the same, or grow in the future
percentage to stay the same, or grow in the future
50
California Conventional Exploration
Anita Powers
EVP Worldwide Exploration
May 19, 2010
1
2
Source: Modified from Schlumberger
Conventional Reservoirs
These are the reservoirs that are capable of
natural flow and will produce economic
volumes of oil and gas without special recovery
techniques.
natural flow and will produce economic
volumes of oil and gas without special recovery
techniques.
2
3
Occidental Petroleum
• Why California
– High potential, underexplored
– Dominant position
– Favorable geology, many plays
– Kern County Discovery
– Just started, multi year inventory
3
4
Sources:
California Division of Oil, Gas & Geothermal Resources
Gibson Consulting
Oxy Fee/Lease
2 Billion BOE
20 Billion BOE
3 Billion BOE
10 Billion BOE
Major Producing
Basins
Sacramento
Sacramento
San
Francisco
Francisco
San
Francisco
Francisco
Los Angeles
Los Angeles
Bakersfield
Bakersfield
California Oil and Gas Overview
• World Class Province
– 35+ Billion BOE discovered
– 5 of top 12 U.S. oil fields
• Significant Remaining Potential
– Large undiscovered resources
– Multiple play and trap types
• Underexplored
• Oxy
– Major producer
– Largest land holder
– Successful explorer
– Multi-year prospect inventory
4
5
Discovery Year
Drill Oil and
Gas Seeps
Gas Seeps
Drill Surface
Features
Features
2D
Seismic
Seismic
Small
Discoveries
Discoveries
Since mid 1970’s
• Little exploration activity
• Few discoveries
Why?
• Super major focus?
• Shift to EOR?
• Limited potential?
• Too little exploration?
Sources:
California Division of Oil, Gas & Geothermal Resources
2008-2009 Occidental Upside Estimates
California Exploration History
5
6
USGS National Assessment of Oil and Gas Update (2008)
* Excludes Federal Waters
* Excludes Federal Waters
Total US Onshore 90 BBOE
California Only 11 BBOE (12%)
Conventional Oil and Gas - L/48
USGS Undiscovered Upside Resources
6
7
Sources:
EIA, IHS wells with recorded spud dates and Oxy estimated spud
EIA, IHS wells with recorded spud dates and Oxy estimated spud
California Exploration Drilling
As a percentage of the Total U.S. Exploration
7
8
Occidental Petroleum
• Why California
– High potential, underexplored
– Dominant position
– Favorable geology, many plays
– Kern County Discovery
– Just started, multi year inventory
8
9
Competitor data estimated by Oxy
4Q 2009 Oxy 1.3
Competitor A 0.4
Competitor B 0.3
Competitor C 0.3
Competitor D 0.1
California Net Acreage
Million Acres
Sacramento
Sacramento
Los Angeles
Los Angeles
Bakersfield
Bakersfield
South San
Joaquin Valley
Joaquin Valley
Oxy Fee/Lease
Oxy Land Position Today
9
10
1998 Fee Holdings
• Elk Hills Acquisition in 1998
Elk Hills Field
Kern Front Field
Bakersfield
Taft
1998
10
11
1998 Fee Holdings
1999-2005 Lease/Fee Additions
1998-2005 3D Seismic
1998-2005 Exploration Wells
• Elk Hills Acquisition in 1998
• Learn, build, explore close-in
Elk Hills Field
Kern Front Field
Bakersfield
Taft
1998 - 2005
11
12
Bakersfield
Taft
Elk Hills Field
Kern Front Field
1998 Fee Holdings
1999-2005 Lease/Fee Additions
2005-2010 Lease/Fee Additions
1998-2005 3D Seismic
2005-2010 3D Seismic
1998-2005 Exploration Wells
2005-2010 Exploration Wells*
• Elk Hills Acquisition in 1998
• Learn, build, explore close-in
• Dominant player, expand
*Excludes certain wells currently in confidentiality period
1998 - 2010
12
13
Occidental Petroleum
• Why California
– High potential, underexplored
– Dominant position
– Favorable geology, many plays
– Kern County Discovery
– Just started, multi year inventory
13
14
Oxy Fee/Lease
San
Francisco
Francisco
San
Francisco
Francisco
Los Angeles
Los Angeles
Major Producing
Basins
Sacramento
Sacramento
Bakersfield
Bakersfield
Favorable Geology
Multiple Reservoirs
Rich Marine Oil and Gas
Source Rocks
Source Rocks
Tectonics Form Variety of
Trap Types
Trap Types
14
15
Producing Intervals
AGE
PLEISTOCENE
PLIOCENE
MIOCENE
OLIGOCENE
EOCENE
CRETACEOUS
UPPER
25
35
60
MyBP
Reservoir
Source
2
5
Anticlines
Simple
Complex
Normal
Faulted Closures
Stratigraphic
Reverse
Pinch-out
Facies Change
Conventional Exploration Plays
15
16
• Targeting Oil Prone Plays and Areas
• Integrate Well, Seismic, Outcrop and Analog Data
• Forensic geology - not all information resides on a workstation
• Challenge what is known
• No magic bullets - Just good solid geoscience
47 Plays Identified
San
Joaquin
Ventura
L.A.
Sac.
Valley
Valley
10 Plays Selected
Focus
Plays
Emerging
All Others
Oxy California Play Focus
16
17
Prospect Size
Limited Potential
Limited Potential
One-Offs
One-Offs
Ideal
Ideal
Traditional
Traditional
Bread &
Butter
Butter
Bread &
Butter
Butter
High
Potential
Potential
High
Potential
Potential
?
Emerging
Emerging
?
Emerging
Emerging
Discovery
Discovery
Play
Play
Oxy Play Grouping
17
18
Field Size (MMBOE)
Oxy Play Type and Prospect Exposure
Sources:
California Division of Oil, Gas & Geothermal Resources
Occidental Estimates
California Division of Oil, Gas & Geothermal Resources
Occidental Estimates
California Field Sizes
18
19
Occidental Petroleum
• Why California
– High potential, underexplored
– Dominant position
– Favorable geology, many plays
– Kern County Discovery
– Just started, multi year inventory
19
20
Mix of Sand and Silts
Gross: 1,500 ft.
Net Pay: 600-1000 ft.
Upper Reservoirs
IP ~ 10-30 MMCF/d
36 bc/MMcf, 1,100 BTU
Lower Reservoirs
IP ~ 100-2000 BO/d
1-3 MMCF/d
Clastic Zone
SP Log
Rock
Fluid
Gross: 2,300 ft.
Net Pay: 1,000 ft.
IP ~ 100-500 BO/d
0.3 - 2 MMCF/d
SP Log
Rock
Fluid
“Shale” Zone
Discovery Play
2008: 1st discovery: Proved play concept
2009: 2nd discovery: Major Kern County find
20
21
Gas
Condensate
Zone
Condensate
Zone
Oil Zone
Kern County Discovery
• 24 wells drilled to date
• Observed tighter intervals on edges
of field
of field
– Modified completions of 6 wells
• Increased flow rates
• Ex: Low flow to >1,000+ BOEPD
– 2 horizontal wells planned 2010
• Exploit thick laminated pay intervals
• Field limits not yet defined
– Continue step-out drilling along strike
– Appraise down-dip limits for fluid contacts
21
22
Gross Production
Actual
Forecast
Discovery Volumes
(Net MMBOE)
Results after 24 Wells:
Produced + Proved 88
Probable 47
Possible 40 - 115
End 1Q ‘10 175 - 250
2010 Step-Out Plan 100 - 150
Total Net Potential 275 - 400
Gross Potential 350 - 500
Kern County Discovery
22
23
Occidental Petroleum
• Why California
– High potential, underexplored
– Dominant position
– Favorable geology, many plays
– Kern County Discovery
– Just started, multi year inventory
23
24
* Includes recompletions and deepenings
California Exploration Program
24
25
* includes Deepenings and Recompletions
14-20 Wells
3-5 Wells
3-5 Wells
San
Francisco
Francisco
San
Francisco
Francisco
Los Angeles
Los Angeles
Sacramento
Sacramento
Bakersfield
Bakersfield
Major Producing
Basins
Oxy Fee/Lease
2011 - 14 Annual Program
# Wells*
3D Seismic - 200-400 km2 per year
- San Joaquin - Infill and Expand
- Ventura/LA - Combined exploration
and development
Exploration Going Forward
Discovery Play 7-10
High Potential 5-10
Bread & Butter 5-6
Emerging 3-4
Total per year 20 - 30
25
26
California Conventional Exploration
• Tremendous potential
– Attractive risk profile (Oxy 1 in 3 success rate)
• Dominant land position
• Kern County Discovery
– 175 - 250 MMBOE net discovered with significant upside
• Discovery Play
– 7-10 prospects/year
– Each prospect
• 100 - 125 MMBOE, average
• 500 MMBOE, high-side
• Program will evolve
– Targeting areas more oil prone than Kern County Discovery
– Multi-year inventory: 50 prospects and leads (and growing)
– Learn as we go, prioritize and drill
26
California Unconventional
Todd Stevens
VP - California Operations
May 19, 2010
1
2
“These are the reservoirs that cannot be produced at
economic flow rates or that do not produce economic
volumes of oil and gas without assistance from
massive stimulation treatments or special recovery
processes and technologies.”
economic flow rates or that do not produce economic
volumes of oil and gas without assistance from
massive stimulation treatments or special recovery
processes and technologies.”
Source: Schlumberger Presentation
Unconventional Reservoirs
2
3
• California “Shale” Background
• Oxy’s “Shale” Program
• California “Shale” Technical Attributes
• California “Shale” Analogs
• Summary
Agenda
3
4
“Shale”
Production
Production
“Shale”
Production
Production
Los Angeles
Los Angeles
Bakersfield
Bakersfield
Oxy Acreage
Locator Map
4
5
BASIN:
SACRAMENTO
LOS ANGELES
AGE
FORMATION
MEMBER / ZONE
MEMBER / ZONE
MEMBER / ZONE
PLEISTOCENE
PLIOCENE
MIOCENE
OLIGOCENE
EOCENE
CRETACEOUS
UPPER
TEMBLOR
MONTEREY
2
5
60
myBP
JURASSIC
30
20
10
140
GAS SANDS
FORBES
PHACOIDES / VEDDER
CARNEROS / OLCESE
SAN JOAQUIN
MEMBER / ZONE
STEVENS
SANDS
OCEANIC
VAQUEROS
SISQUOC
GAVIOTA
RINCON
SESPE
VENTURA
PICO
PICO
MOHNIAN
SANDS
TERMINAL
FORD
RANGER
SACRAMENTO
SHALE
LOWER MONTEREY
ANTELOPE
SHALE
SANTOS
MORENO SHALE
SALT CREEK / CYMRIC
TUMEY
REEF RIDGE
LOWER MONTEREY
MOHNIAN
SHALES
237 / LOWER MONTEREY
Sandstone Reservoirs / Conventional Plays
Source Rocks and “Shales” / Unconventional Plays
KREYENHAGEN
POINT OF ROCKS
AGUA
ETCHEGOIN
TULARE
Stratigraphic Column - Major Producing Basins
5
6
Antelope
Santos/Salt Creek
Kreyenhagen
Sacramento
Santos
Sandstone Reservoirs / Conventional Plays
Source Rocks and “Shales” / Unconventional Plays
California “Shales” - Target Zones
6
7
• Oil and gas companies in California, in particular Oxy,
have been producing from unconventional plays for a
number of years
have been producing from unconventional plays for a
number of years
• California “shales” compare very favorably with some
of the higher profile plays in other states
of the higher profile plays in other states
• Since acquiring Elk Hills, Oxy has been building its
shale expertise
shale expertise
• Oxy has maintained a low profile to acquire the
California acreage and assets it covets at reasonable
prices
California acreage and assets it covets at reasonable
prices
California “Shales” - “Under the Radar”
Unconventional Play
Unconventional Play
7
8
San Joaquin Basin: Breaking the Paradigm
• Unlock the potential:
– Tight Sands (w/shows)
– Oxy’s “Shale” Successes
– Carbonates (lower Monterey /
Santos?)
Santos?)
– Encouraging results
– Kern County discovery
• Historical view of California
reservoirs:
reservoirs:
– Permeable Sands
– Shales (biosiliceous rocks -
diatomite, porcelanite and cherts)
diatomite, porcelanite and cherts)
– No carbonates (except sporadic
dolomites)
dolomites)
– “The Lower Monterey is a source
rock with good shows but no
production potential.”
rock with good shows but no
production potential.”
– Very small new discoveries - not
material to large operators
material to large operators
8
9
After : Brown (2001)
Petroleum Resource Generation by Zone
9
10
Thermal Regime - Source Rock Kitchens
10
11
Thermal Regime - San Joaquin Basin
11
12
Thermal Regime - Los Angeles and Ventura Basins
12
13
60º
70º
80º
90º
50º
40º
30º
20º
10º
Opal A
Opal CT
Quartz
30
70
40
60
50
50
60
40
70
30
80
20
90
10
100
0
Biogenic Silica in wt %
Detritus in wt %
Siliceous
Mudstone
Porcelanite
Chert
Silica Phase Diagram
Modified after Behl & Garrison, 1994
Antelope Shale Facies
Thermal Regime - Silica Phases
13
14
• California “Shale” Background
• Oxy’s “Shale” Program
• California “Shale” Technical Attributes
• California “Shale” Analogs
• Summary
Agenda
14
15
• “Shale” drilling program really started in 1998 at Elk Hills
• Currently, over 1/4th of Oxy’s production in California
comes from “shales”
comes from “shales”
– Have successfully tested concept in eight more fields
• Undertaking 4 year development program
– Appraising 20+ BBOE in place from “most likely” areas
– 10 to 15 test wells/ year in different areas
– Largest 3D seismic program in the history of the state
– Identify “sweet” spots
– Determine pay thickness, fracture distribution,
fault zones, etc.
fault zones, etc.
Occidental “Shale” Production
15
16
• Oxy has over
1.3 MM net acres
in California
1.3 MM net acres
in California
• Largest acreage
position in the
state
position in the
state
• Oxy “shale”
production spans
multiple basins
production spans
multiple basins
Occidental Acreage - Southern California
16
17
Occidental “Shale” Production
17
18
Sample of “Shale” Producing Fields
18
19
• Stimulation recipe innovation
– Large acid treatments key to unlocking potential in
some areas
some areas
• Interval production testing
– Distinguish between oil-producing, wet and other zones
– Determine hydrocarbon properties and quality
• Reservoir characterization
– Better understanding of hydrocarbons in place and their
distribution
distribution
– Fracture reservoir modeling
• Reservoir Management
– Individual zone completions
– Optimizing lateral length and frac stages leads to better
economics
economics
Drivers for Success - California “Shales”
19
20
Representative “Shale” Type Curves
20
21
Vertical “Shale” Type Curve
21
22
Horizontal “Shale” Type Curve
22
23
• California “Shale” Background
• Oxy’s “Shale” Program
• California “Shale” Technical Attributes
• California “Shale” Analogs
• Summary
Agenda
23
24
Comparison of Major California “Shales”
24
25
• Organic Rich “Shales”
– Good TOC
– Thermal Maturity
– Source and Reservoir Rock
• Gross Thickness
– Active Margin Basins
• Unique Depositional Environment
– Deep vs. Shallow water
– Diatom & Foram Rich
CA “Shales” - Critical Technical Aspects
25
26
• California “Shale” Background
• Oxy’s “Shale” Program
• California “Shale” Technical Attributes
• California “Shale” Analogs
• Summary
Agenda
26
27
• California oil “shales” compare very favorably to
developed unconventional oil plays
developed unconventional oil plays
• Bakken and Eagle Ford are best analogs
– Large amounts of hydrocarbons generated and in place
– Reservoir parameters are similar
– Predominantly oil/liquids plays
– Significant learning curves with pay-off - the more these
plays are understood the more prospective they become
plays are understood the more prospective they become
California “Shale” Analogs
27
28
Side by Side Play Comparison
28
29
• California “Shale” Background
• Oxy’s “Shale” Program
• California “Shale” Technical Attributes
• California “Shale” Analogs
• Summary
Agenda
29
30
• ~870,000 acres are within most prospective “shale” plays
• Oxy’s average NRI ~95%
• Multiple potentially productive “shale” zones in each well
• Oxy’s acreage encompasses favorable thermal regime
• Identified 15 areas to appraise over the next 4 years
(5-10% of total acreage)
(5-10% of total acreage)
– Initially target 1-2 areas including Kern County discovery
– Average IP 400-800 boepd
– Production range from 100 to 1,000 boepd
– Average EUR 400-700 Mboe
– 10-acre spacing
• 10 years from now California “shale” could become Oxy’s
largest business unit
largest business unit
Summary
30
Occidental Petroleum Corporation
Stephen I. Chazen
President and Chief Financial Officer
May 19, 2010
1
2
• Midstream & Chemicals
• Production Forecast
• Capital Forecast
• Acquisition Strategy
• Asset Return Results
• Cash Flow Priorities
• Investment Attributes
Agenda
2
3
Midstream Overview
• 3-Year Average EBIT
was $374 Million
was $374 Million
• 2009 EBIT was $235
Million
Million
• $3.8 Billion net PP&E
and investments
and investments
• Significant and growing
fee income
fee income
Midstream 3-Year Average EBIT
3
4
Gas Processing
• Located near our domestic producing operations
• Processes both Oxy and third-party gas
• Spread between natural gas and NGL prices drives
business
business
Marketing & Trading
• Maximizes value of company’s production
– Spread in pricing between various grades of crude
oil drives business
oil drives business
• Gas storage arbitrage
• Gas storage capacity of 30.5 BCF
• Phibro is long a basket of commodities
Midstream Lines of Business
4
5
Pipelines
• Oxy owns 2,760 miles of oil pipeline in Permian Basin
and Oklahoma
and Oklahoma
• 22% ownership of Plains All American Pipeline, G.P.
• 24.5% ownership of Dolphin Pipeline
• Fee-based business
Power Generation
• Oxy power and steam generation facilities at our
Louisiana and Texas chemical sites
Louisiana and Texas chemical sites
• 50% ownership in a power generation facility at Elk Hills
• Spread between natural gas price and electricity price
drives business
drives business
Midstream Lines of Business
5
6
EBIT Growth to $1 Billion Annually by 2014
• Increased pipeline fees
• Addition of Phibro
• Increased gas and CO2 plant capacity
• Bolt-on acquisitions likely
Midstream 5-Year Outlook
6
7
• 5-Year Average EBIT was $688 Million
• $ 389 Million EBIT in 2009
• $ 2.6 Billion Net PP&E
• Focus on Chlorovinyls
• Major Factor in its Industry
• Earnings are Volatile
Chemicals Overview
See attached for GAAP reconciliation
7
8
* Other Products Accounted for 12% of Sales & 16% of Earnings in 2009
Major Market End Uses for OxyChem Products
Chlorovinyls
• Building Materials / Automotive Products
• Pulp & Paper / Aluminum Production
• Water Treatment / Disinfection
• Medical Products
• Fertilizers / Ag Feed
Other Products *
• Soaps / Detergents / Paint Pigments
• Ice Melting / Dust Control / Oil Field Services
8
9
Chemical Companies Comparison
See attached for GAAP reconciliation
9
10
• Expect average annual EBIT of $700 Million
over next five years
over next five years
• Opportunity for small bolt-on acquisitions
Chemicals 5-Year Outlook
10
11
• Volume Growth
• Capital Expenditures
• Acquisitions
• Return Targets
E&P Business Drivers
11
12
• Base 5 - 8% Growth
– CO2 in Permian
– Current California risked prospects
– Rockies gas
– Bahrain
– Oman
– Iraq
• Upside from Existing Holdings
– New California conventional and unconventional prospects
– Permian exploration
– Rockies gas
– Argentina
• Additional opportunities from balance sheet and cash
generation
generation
– Domestic properties acquisitions
– New Middle East projects
Volume Growth Drivers
12
13
Major Potential Drivers
of Production and Profitability
of Production and Profitability
• California Non-conventional
– 870,000 potential acres with virtually no royalties
– EUR of 400 - 700 MBOE per well
– Modest F&D
– Modest success built into production wedge
• California Conventional
– 50 prospect inventory and growing
– Low F&D
– Considerable success so far
– Only two or three moderate exploration successes built
into production wedge
into production wedge
13
14
Major Potential Drivers
of Production and Profitability
of Production and Profitability
• Rockies Gas
– 3.8 TCFE potential
– Base uses $6.00 gas in 2014
– Upside case is $7.00 gas in 2014
• Permian CO2
– 3 billion net barrels in resource from Oxy operated only
– Possibly more CO2 available over the 5-year period
– Probable better response by 2013-14
14
15
Thousand BOE/Day
U.S. Production Outlook
376
391
417
494
557
632
6.4% Base
CAGR
CAGR
10.9% Total
CAGR
CAGR
15
16
Major Potential Drivers
of Production and Profitability
of Production and Profitability
• Bahrain
– Base case shows steady but not aggressive progress
– Possible better oil results by 2014
• Oman
– Base shows only modest growth of Oman gas markets
– Likely better growth by 2014
• Libya
– Little progress assumed
– Possible need by the government for better production
growth by end of the period
growth by end of the period
16
17
Major Potential Drivers
of Production and Profitability
of Production and Profitability
• Argentina
– Modest base case shown
– Potential is very high
• Iraq
– Field is capable of outperforming our estimates
17
18
Thousand BOE/Day
(Assumes $75 WTI Price)
International Production Outlook
338
365
420
452
476
486
6.0% Base
CAGR
CAGR
7.5% Total
CAGR
CAGR
18
19
Worldwide Production Outlook
Thousand BOE/Day
(Assumes $75 WTI Price)
714
756
837
946
1,033
1,118
6.2% Base
CAGR
CAGR
9.4% Total
CAGR
CAGR
19
20
2010 - 2014 Capital - $27.5 Billion
International share will remain at 45% of Capital Program
Capital
20
21
• Company’s core business is acquiring assets that can
provide future growth through improved recovery
provide future growth through improved recovery
– Foreign contracts
– Domestic add-ons
– Small incremental additions to production in
short term
short term
• Generate returns of at least 15% in the U.S. and
20% internationally
20% internationally
• Overall average finding & development costs of
less than 25% of selling price
less than 25% of selling price
• Even with the additional capital shown, program will
generate a significant amount of free cash flow
generate a significant amount of free cash flow
• Large number of opportunities over 5-year period
Acquisition Strategy
21
22
• Permian
– 1,500+ Operators; 75,000+ Royalty owners
• California
– Large acreage holders
• Other U.S.
– Small investments in emerging plays
• Foreign
– Additional foreign contracts
Sources of Acquisitions
22
23
2005 128 139 104 371 220% 169
2006 137 325 51 513 259% 198
2007 254 60 (72) 242 116% 208
2008 247 210 (121) 336 153% 220
2009 173 160 150 483 206% 235
3-Year Avg. 225 143 (14) 354 160% 221
5-Year Avg. 188 179 22 389 189% 206
Improved Reserve Worldwide
Recovery Acquisitions Others Total Replace % Production
Recovery Acquisitions Others Total Replace % Production
Million BOE
Reserves Replacement
23
24
2005 $ 1,807 139 128
2006 $ 4,463 325 137
2007 $ 1,103 60 254
2008 $ 3,202 210 247
2009 $ 703 160 173
Investment in Reserves Immediately Improved
Acquisitions Added from Acquisition Recovery
($ Million) (MMBOE) (MMBOE)
Acquisitions Added from Acquisition Recovery
($ Million) (MMBOE) (MMBOE)
Acquisitions
See attached for GAAP reconciliation
24
25
Net Income Return on Assets
U.S. 19%
International 24%
Total E&P 21%
Cash Flow* Return on Assets
U.S. 27%
International 41%
Total E&P 31%
* Net Income + DD&A
5 Year Average
5 Year Average
Return on Assets
See attached for GAAP reconciliation
25
26
F&D Costs
Actual as a % of
6:1 * Prices ** WTI Price
Actual as a % of
6:1 * Prices ** WTI Price
* Oil / Gas Energy Content (Industry convention)
** Gas converted to BOE @ WTI Oil Price / NYMEX Gas Price
** Gas converted to BOE @ WTI Oil Price / NYMEX Gas Price
Finding & Development Costs per Barrel
See attached for GAAP reconciliation
2009 $ 7.90 $ 9.64 16%
3-Year Average $15.04 $18.40 24%
(2007 - 2009)
(2007 - 2009)
5-Year Average $14.77 $16.84 24%
(2005 - 2009)
(2005 - 2009)
10-Year Average $ 9.15 $ 9.82 19%
(2000 - 2009)
(2000 - 2009)
26
27
1. Base/Maintenance Capital
2. Dividends
3. Growth Capital
4. Acquisitions
5. Share Repurchase
Cash Flow Priorities
27
28
Growth Capital $ 1.8 $ 11.2
Base Capital 2.5 15.0
Total Oil & Gas
and Midstream Capital $ 4.3 $ 26.2
and Midstream Capital $ 4.3 $ 26.2
($ in Billions)
2010-2014
Oil & Gas and Midstream Capital 2010 Cumulative
Oil & Gas and Midstream Capital 2010 Cumulative
• Base Oil & Gas capital historically running at $2.5 billion
• As production increases, the base capital will grow
Capital Spending Program
28
29
Dividends
29
30
Proved Unproved Properties
Developed plus Goodwill /
Developed plus Goodwill /
Reserves / Total Net Capitalized Costs
Company Proved Reserves plus Goodwill
Company Proved Reserves plus Goodwill
OXY 77.3% 6.7%
A 54.4% 10.0%
B 59.2% 21.6%
C 69.1% 8.2%
D 70.5% 39.3%
E 70.3% 40.5%
F 61.4% 13.6%
G 70.7% 21.9%
H 70.1% 22.6%
I 67.3% 3.4%
J 56.6% 21.0%
Conservative Accounting
30
31
Five years Ten Years
Company ended 12/31/09 ended 12/31/09
Company ended 12/31/09 ended 12/31/09
OXY $2.67 $2.57
A $2.28 $2.53
B $1.67 $1.31
C $1.38 $1.63
D $1.38 $1.29
E $1.06 $1.13
F $0.75 $1.28
G $0.60 $0.83
H $0.25 $0.66
I ($0.60) $0.87
J ($1.15) ($0.24 )
* Impairments greater than 5% of Shareholders’ Equity have been added back to Shareholders’ Equity.
(Equity Market Value Created per $1 Change in Shareholders’ Equity*)
Capital Program Effectiveness
31
32
• 5 - 8% base annual production growth
• Opportunity for additional volume growth
• Annual increases in dividends
• Significant financial flexibility for opportunities in
distressed periods
distressed periods
• Conservative financial statements
• Returns on invested capital significantly in excess of
Company’s cost of capital
Company’s cost of capital
• Committed to generating stock market value which is
greater than earnings retained
greater than earnings retained
• We believe this will generate top quartile returns for
our shareholders
our shareholders
Investment Attributes
32
Statements in this release that contain words such as “will,” “expect” or “estimate,” or otherwise relate to
the future, are forward-looking and involve risks and uncertainties that could significantly affect expected
results. Factors that could cause actual results to differ materially include, but are not limited to: global
commodity price fluctuations and supply/demand considerations for oil, gas and chemicals; not
successfully completing (or any material delay in) any expansions, field development, capital projects,
acquisitions, or dispositions; higher-than-expected costs; political risk; operational interruptions; changes
in tax rates; exploration risks, such as drilling of unsuccessful wells; and commodity trading risks. You
should not place undue reliance on these forward-looking statements which speak only as of the date of
this release. Unless legally required, Occidental does not undertake any obligation to update any forward-
looking statements as a result of new information, future events or otherwise. The United States Securities
and Exchange Commission (SEC) permits oil and natural gas companies, in their filings with the SEC, to
disclose only reserves anticipated to be economically producible, as of a given date, by application of
development projects to known accumulations. We use certain terms in this presentation, such as
reported reserves, EUR, expected ultimate recovery, potential reserves, volumes in resource, net risked
reserves, enhanced recovery reserves, expected recovery, discovery volumes, recoverable reserves and
oil in place, that the SEC’s guidelines strictly prohibit us from using in filings with the SEC. See our 2010
Form 10-K and February 3, 2010 8-K for information on calculation methodology for our reserves
replacement ratio and F&D costs. U.S. investors are urged to consider carefully the disclosures in our
2010 Form 10-K, available through the following toll-free telephone number, 1-888-OXYPETE (1-888-699-
7383) or on the Internet at http://www.oxy.com. You also can obtain a copy from the SEC by calling 1-800
- -SEC-0330. We post or provide links to important information on its website including investor and analyst
presentations, certain board committee charters and information the SEC requires companies and certain
of its officers and directors to file or furnish. Such information may be found in the “Investor Relations”
and “Social Responsibility” portions of the website.
the future, are forward-looking and involve risks and uncertainties that could significantly affect expected
results. Factors that could cause actual results to differ materially include, but are not limited to: global
commodity price fluctuations and supply/demand considerations for oil, gas and chemicals; not
successfully completing (or any material delay in) any expansions, field development, capital projects,
acquisitions, or dispositions; higher-than-expected costs; political risk; operational interruptions; changes
in tax rates; exploration risks, such as drilling of unsuccessful wells; and commodity trading risks. You
should not place undue reliance on these forward-looking statements which speak only as of the date of
this release. Unless legally required, Occidental does not undertake any obligation to update any forward-
looking statements as a result of new information, future events or otherwise. The United States Securities
and Exchange Commission (SEC) permits oil and natural gas companies, in their filings with the SEC, to
disclose only reserves anticipated to be economically producible, as of a given date, by application of
development projects to known accumulations. We use certain terms in this presentation, such as
reported reserves, EUR, expected ultimate recovery, potential reserves, volumes in resource, net risked
reserves, enhanced recovery reserves, expected recovery, discovery volumes, recoverable reserves and
oil in place, that the SEC’s guidelines strictly prohibit us from using in filings with the SEC. See our 2010
Form 10-K and February 3, 2010 8-K for information on calculation methodology for our reserves
replacement ratio and F&D costs. U.S. investors are urged to consider carefully the disclosures in our
2010 Form 10-K, available through the following toll-free telephone number, 1-888-OXYPETE (1-888-699-
7383) or on the Internet at http://www.oxy.com. You also can obtain a copy from the SEC by calling 1-800
- -SEC-0330. We post or provide links to important information on its website including investor and analyst
presentations, certain board committee charters and information the SEC requires companies and certain
of its officers and directors to file or furnish. Such information may be found in the “Investor Relations”
and “Social Responsibility” portions of the website.
Forward-Looking Statements
1
Anadarko
Apache
BP
Chevron
ConocoPhillips
Devon
EOG
ExxonMobil
Hess
Marathon
Companies Included
in Equity Market Comparison
in Equity Market Comparison
2
| Occidental Petroleum Corporation | |||||||||||||
| Chemicals | |||||||||||||
| EBIT | |||||||||||||
| Reconciliation to Generally Accepted Accounting Principles (GAAP) | |||||||||||||
| ($ Millions) | |||||||||||||
|
5-Year
|
|||||||||||||
|
2005
|
2006
|
2007
|
2008
|
2009
|
Average
|
||||||||
|
Segment income
|
614
|
906
|
601
|
669
|
389
|
636
|
|||||||
|
Add: significant items affecting earnings
|
|||||||||||||
|
Plant closure and impairments
|
-
|
-
|
-
|
90
|
-
|
18
|
|||||||
|
Hurricane insurance charges
|
11
|
-
|
-
|
-
|
-
|
2
|
|||||||
|
Write-off of plants
|
159
|
-
|
-
|
-
|
-
|
32
|
|||||||
|
Core results - EBIT
|
784
|
906
|
601
|
759
|
389
|
688
|
|||||||
|
Occidental Petroleum Corporation
|
|||||||||
|
Chemicals
|
|||||||||
|
EBITDA as a Percentage of Sales
|
|||||||||
|
Reconciliation to Generally Accepted Accounting Principles (GAAP)
|
|||||||||
|
($ Millions)
|
|||||||||
|
3-Year
|
|||||||||
|
2007
|
2008
|
2009
|
Average
|
||||||
|
Net Sales
|
4,664
|
5,112
|
3,225
|
4,334
|
|||||
|
Segment income
|
601
|
669
|
389
|
553
|
|||||
|
Add: significant items affecting earnings
|
|||||||||
|
Plant closure and impairments
|
-
|
90
|
-
|
30
|
|||||
|
Core results - EBIT
|
601
|
759
|
389
|
583
|
|||||
|
DD&A Expense
|
304
|
311
|
298
|
304
|
|||||
|
EBITDA
|
905
|
1,070
|
687
|
887
|
|||||
|
EBITDA as a % of Sales
|
19.4%
|
20.9%
|
21.3%
|
20.5%
|
|||||
|
Occidental Petroleum Corporation
|
|||||||||||
|
Oil & Gas
|
|||||||||||
|
Acquisitions
|
|||||||||||
|
Reconciliation to Generally Accepted Accounting Principles (GAAP)
|
|||||||||||
|
($ Millions)
|
|||||||||||
|
2005
|
2006
|
2007
|
2008
|
2009
|
|||||||
|
Property Acquisition Costs
|
|||||||||||
|
Proved Properties
|
1,768
|
4,888
|
926
|
1,830
|
727
|
||||||
|
Unproved Properties
|
398
|
1,142
|
119
|
1,711
|
103
|
||||||
|
Acquisitions - per costs incurred
|
2,166
|
6,030
|
1,045
|
3,541
|
830
|
||||||
|
Contract extensions and bonuses
|
(359
|
)
|
(225
|
)
|
58
|
(339
|
)
|
(127
|
)
|
||
|
Vintage acquisition deferred tax gross-up
|
-
|
(1,342
|
)
|
-
|
-
|
-
|
|||||
|
1,807
|
4,463
|
1,103
|
3,202
|
703
|
|||||||
|
Occidental Petroleum Corporation
|
|||||||||||||
|
Oil & Gas
|
|||||||||||||
|
Return on Assets
|
|||||||||||||
|
Reconciliation to Generally Accepted Accounting Principles (GAAP)
|
|||||||||||||
|
($ Millions)
|
|||||||||||||
|
5-Year
|
|||||||||||||
|
2005
|
2006
|
2007
|
2008
|
2009
|
Average
|
||||||||
|
Revenues
|
9,038
|
11,448
|
13,039
|
17,877
|
11,565
|
12,593
|
|||||||
|
Production costs
|
1,290
|
1,836
|
2,167
|
2,684
|
2,462
|
2,088
|
|||||||
|
Other operating expense
|
408
|
506
|
567
|
553
|
713
|
549
|
|||||||
|
Depreciation, depletion and amortization
|
1,082
|
1,672
|
1,992
|
2,307
|
2,688
|
1,948
|
|||||||
|
Taxes other than income
|
289
|
388
|
411
|
580
|
421
|
418
|
|||||||
|
Charges for impairments
|
-
|
-
|
58
|
557
|
170
|
157
|
|||||||
|
Exploration expenses
|
309
|
296
|
364
|
327
|
267
|
313
|
|||||||
|
Pretax income
|
5,660
|
6,750
|
7,480
|
10,869
|
4,844
|
7,121
|
|||||||
|
Income tax expense
|
2,162
|
2,755
|
3,119
|
4,178
|
1,827
|
2,808
|
|||||||
|
Results of operations
|
3,498
|
3,995
|
4,361
|
6,691
|
3,017
|
4,312
|
|||||||
|
Depreciation, depletion and amortization
|
1,082
|
1,672
|
1,992
|
2,307
|
2,688
|
1,948
|
|||||||
|
Charges for impairments
|
-
|
-
|
58
|
557
|
170
|
157
|
|||||||
|
Gross Cash
|
4,580
|
5,667
|
6,411
|
9,555
|
5,875
|
6,418
|
|||||||
|
Capitalized costs
|
|||||||||||||
|
Current year
|
14,008
|
20,369
|
22,167
|
26,981
|
27,735
|
22,252
|
|||||||
|
Prior year
|
11,554
|
14,008
|
20,369
|
22,167
|
26,981
|
19,016
|
|||||||
|
Average capitalized costs
|
12,781
|
17,189
|
21,268
|
24,574
|
27,358
|
20,634
|
|||||||
|
5-Year Average
|
U.S.
|
International
|
Total
|
||||||||||
|
Results of operations
|
2,653
|
1,659
|
4,312
|
(a)
|
|||||||||
|
Depreciation, depletion and amortization
|
984
|
964
|
1,984
|
||||||||||
|
Charges for impairments
|
12
|
145
|
157
|
||||||||||
|
Gross Cash
|
3,649
|
2,768
|
6,417
|
(b)
|
|||||||||
|
Average capitalized costs
|
13,653
|
6,981
|
20,634
|
(c)
|
|||||||||
|
Net income return on assets (a) / (c)
|
19%
|
24%
|
21%
|
||||||||||
|
Cash flow return on assets (b) / (c)
|
27%
|
41%
|
31%
|
||||||||||
|
Occidental Petroleum Corporation
|
||||||||||||||||||||||||||||||||||||||||
|
Oil & Gas
|
||||||||||||||||||||||||||||||||||||||||
|
Finding and Development Costs - Using Industry Convention of 6:1
|
||||||||||||||||||||||||||||||||||||||||
|
Reconciliation to Generally Accepted Accounting Principles (GAAP)
|
||||||||||||||||||||||||||||||||||||||||
|
($ Millions except for F&D Costs)
|
||||||||||||||||||||||||||||||||||||||||
|
Averages
|
||||||||||||||||||||||||||||||||||||||||
|
2000
|
2001
|
2002
|
2003
|
2004
|
2005
|
2006
|
2007
|
2008
|
2009
|
3-Year
|
5-Year
|
10-Year
|
||||||||||||||||||||||||||||
|
Property Acquisition Costs
|
||||||||||||||||||||||||||||||||||||||||
|
Proved Properties
|
3,753
|
25
|
163
|
357
|
146
|
1,768
|
4,888
|
926
|
1,830
|
727
|
1,161
|
2,028
|
1,458
|
|||||||||||||||||||||||||||
|
Unproved Properties
|
8
|
56
|
29
|
4
|
8
|
398
|
1,142
|
119
|
1,710
|
103
|
644
|
694
|
358
|
|||||||||||||||||||||||||||
|
Acquisitions
|
3,761
|
81
|
192
|
361
|
154
|
2,166
|
6,030
|
1,045
|
3,540
|
830
|
1,805
|
2,722
|
1,816
|
|||||||||||||||||||||||||||
|
Exploration Costs
|
134
|
171
|
134
|
97
|
158
|
255
|
316
|
327
|
334
|
207
|
289
|
288
|
213
|
|||||||||||||||||||||||||||
|
Development Costs
|
579
|
918
|
897
|
1,080
|
1,435
|
1,844
|
2,426
|
2,740
|
4,112
|
2,779
|
3,210
|
2,780
|
1,881
|
|||||||||||||||||||||||||||
|
713
|
1,089
|
1,031
|
1,177
|
1,593
|
2,099
|
2,742
|
3,067
|
4,446
|
2,986
|
3,500
|
3,068
|
2,094
|
||||||||||||||||||||||||||||
|
Costs Incurred
|
4,474
|
1,170
|
1,223
|
1,538
|
1,747
|
4,265
|
8,772
|
4,112
|
7,986
|
3,816
|
5,305
|
5,790
|
3,910
|
|||||||||||||||||||||||||||
|
Reserve replacements
|
||||||||||||||||||||||||||||||||||||||||
|
Improved recovery
|
46
|
143
|
142
|
102
|
120
|
139
|
140
|
254
|
247
|
173
|
225
|
190
|
151
|
|||||||||||||||||||||||||||
|
Purchases of proved reserves
|
970
|
4
|
68
|
107
|
36
|
139
|
327
|
60
|
210
|
160
|
143
|
179
|
208
|
|||||||||||||||||||||||||||
|
Others
|
||||||||||||||||||||||||||||||||||||||||
|
Revisions of previous estimates
|
100
|
21
|
3
|
12
|
49
|
(12
|
)
|
12
|
(95
|
)
|
(145
|
)
|
58
|
(61
|
)
|
(37
|
)
|
0
|
||||||||||||||||||||||
|
Extensions & discoveries
|
55
|
76
|
50
|
147
|
64
|
124
|
34
|
23
|
24
|
92
|
46
|
59
|
69
|
|||||||||||||||||||||||||||
|
Total Others
|
155
|
97
|
53
|
159
|
113
|
112
|
46
|
(72
|
)
|
(122
|
)
|
149
|
(15
|
)
|
23
|
69
|
||||||||||||||||||||||||
|
1,171
|
244
|
263
|
368
|
269
|
390
|
512
|
241
|
335
|
483
|
353
|
392
|
427
|
||||||||||||||||||||||||||||
|
F&D Costs
|
$
|
3.82
|
$
|
4.80
|
$
|
4.65
|
$
|
4.18
|
$
|
6.51
|
$
|
10.93
|
$
|
17.14
|
$
|
17.04
|
$
|
23.84
|
$
|
7.90
|
$
|
15.04
|
$
|
14.77
|
$
|
9.15
|
||||||||||||||
|
Occidental Petroleum Corporation
|
||||||||||||||||||||||||||||||||||||||||
|
Oil & Gas
|
||||||||||||||||||||||||||||||||||||||||
|
Finding and Development Costs - Using Average Commodity Prices
|
||||||||||||||||||||||||||||||||||||||||
|
Reconciliation to Generally Accepted Accounting Principles (GAAP)
|
||||||||||||||||||||||||||||||||||||||||
|
($ Millions except for F&D Costs)
|
||||||||||||||||||||||||||||||||||||||||
|
Averages
|
||||||||||||||||||||||||||||||||||||||||
|
2000
|
2001
|
2002
|
2003
|
2004
|
2005
|
2006
|
2007
|
2008
|
2009
|
3-Year
|
5-Year
|
10-Year
|
||||||||||||||||||||||||||||
|
Property Acquisition Costs
|
||||||||||||||||||||||||||||||||||||||||
|
Proved Properties
|
3,753
|
25
|
163
|
357
|
146
|
1,768
|
4,888
|
926
|
1,830
|
727
|
1,161
|
2,028
|
1,458
|
|||||||||||||||||||||||||||
|
Unproved Properties
|
8
|
56
|
29
|
4
|
8
|
398
|
1,142
|
119
|
1,710
|
103
|
644
|
694
|
358
|
|||||||||||||||||||||||||||
|
Acquisitions
|
3,761
|
81
|
192
|
361
|
154
|
2,166
|
6,030
|
1,045
|
3,540
|
830
|
1,805
|
2,722
|
1,816
|
|||||||||||||||||||||||||||
|
Exploration Costs
|
134
|
171
|
134
|
97
|
158
|
255
|
316
|
327
|
334
|
207
|
289
|
288
|
213
|
|||||||||||||||||||||||||||
|
Development Costs
|
579
|
918
|
897
|
1,080
|
1,435
|
1,844
|
2,426
|
2,740
|
4,112
|
2,779
|
3,210
|
2,780
|
1,881
|
|||||||||||||||||||||||||||
|
713
|
1,089
|
1,031
|
1,177
|
1,593
|
2,099
|
2,742
|
3,067
|
4,446
|
2,986
|
3,500
|
3,068
|
2,094
|
||||||||||||||||||||||||||||
|
Costs Incurred
|
4,474
|
1,170
|
1,223
|
1,538
|
1,747
|
4,265
|
8,772
|
4,112
|
7,986
|
3,816
|
5,305
|
5,790
|
3,910
|
|||||||||||||||||||||||||||
|
Reserve replacements
|
||||||||||||||||||||||||||||||||||||||||
|
Improved recovery
|
45
|
143
|
135
|
102
|
115
|
136
|
133
|
225
|
220
|
156
|
200
|
174
|
141
|
|||||||||||||||||||||||||||
|
Purchases of proved reserves
|
952
|
4
|
65
|
107
|
36
|
136
|
305
|
59
|
146
|
81
|
95
|
145
|
189
|
|||||||||||||||||||||||||||
|
Others
|
||||||||||||||||||||||||||||||||||||||||
|
Revisions of previous estimates
|
91
|
20
|
6
|
12
|
43
|
(13
|
)
|
13
|
(89
|
)
|
(131
|
)
|
104
|
(39
|
)
|
(23
|
)
|
6
|
||||||||||||||||||||||
|
Extensions & discoveries
|
50
|
78
|
47
|
148
|
59
|
114
|
31
|
20
|
18
|
56
|
31
|
48
|
62
|
|||||||||||||||||||||||||||
|
Total Others
|
141
|
98
|
53
|
161
|
102
|
101
|
44
|
(68
|
)
|
(113
|
)
|
159
|
(7
|
)
|
25
|
68
|
||||||||||||||||||||||||
|
1,139
|
245
|
252
|
370
|
254
|
373
|
482
|
215
|
254
|
396
|
288
|
344
|
398
|
||||||||||||||||||||||||||||
|
F&D Costs
|
$
|
3.93
|
$
|
4.77
|
$
|
4.84
|
$
|
4.15
|
$
|
6.88
|
$
|
11.44
|
$
|
18.20
|
$
|
19.09
|
$
|
31.49
|
$
|
9.64
|
$
|
18.40
|
$
|
16.84
|
$
|
9.82
|
||||||||||||||
|
WTI
|
$
|
30.20
|
$
|
25.97
|
$
|
26.08
|
$
|
31.03
|
$
|
41.40
|
$
|
56.56
|
$
|
66.23
|
$
|
72.32
|
$
|
99.65
|
$
|
61.80
|
$
|
77.92
|
$
|
71.31
|
$
|
51.12
|
||||||||||||||
|
F&D Costs as a % of WTI
|
13%
|
18%
|
19%
|
13%
|
17%
|
20%
|
27%
|
26%
|
32%
|
16%
|
24%
|
24%
|
19%
|
|||||||||||||||||||||||||||