Table of Contents
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
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported) February 23, 2006
OCCIDENTAL PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware (State or other jurisdiction of incorporation) |
1-9210 (Commission File Number) |
95-4035997 (I.R.S. Employer Identification No.) |
| 10889 Wilshire Boulevard Los Angeles, California |
90024 |
|
| (Address of principal executive offices) | (ZIP code) |
Registrant’s telephone number, including area code:
(310) 208-8800
(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):
o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR
240.14d-2(b))
o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR
240.13e-4(c))
TABLE OF CONTENTS
| Item 7.01. Regulation FD Disclosure | ||||||||
| Item 8.01. Other Events | ||||||||
| SIGNATURE | ||||||||
| EXHIBIT INDEX | ||||||||
| Exhibit 99.1 | ||||||||
| Exhibit 99.2 | ||||||||
| Exhibit 99.3 | ||||||||
Table of Contents
Section 7
— Regulation FD
Item 7.01. Regulation FD Disclosure
Attached
as Exhibit 99.1 is a presentation made by Dr. Ray R. Irani,
Occidental Petroleum Corporation’s Chairman,
President & Chief Executive Officer, Stephen I. Chazen, Occidental’s Senior Executive Vice
President and Chief Financial Officer, John W. Morgan, President of Oxy Oil and Gas – Western
Hemisphere, and R. Casey Olson, President of Oxy Oil and Gas –
Eastern Hemisphere, at an analyst conference on February 23, 2006, at the St. Regis Hotel in New York, New York.
Section 8 – Other Events
Item 8.01. Other Events
On February 23, 2006, Occidental issued a press release regarding the analyst conference and a
press release announcing that in 2005 its proved reserve additions exceeded production. The full
text of the each press release is attached to this report as Exhibit 99.2 and Exhibit 99.3,
respectively.
1
Table of Contents
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.
| OCCIDENTAL PETROLEUM CORPORATION | ||
| (Registrant) | ||
DATE: February 23, 2006
|
/s/ Jim A. Leonard | |
| (Principal Accounting and Duly Authorized Officer) |
Table of Contents
EXHIBIT INDEX
| 99.1 | Presentation dated February 23, 2006.* | |
| 99.2 | Press release dated February 23, 2006 regarding Analysts Conference. | |
| 99.3 | Press release dated February 23, 2006 regarding Reserves. |
| * | Includes additional GAAP reconciliation information. |
| February 23, 2006 2006 Analyst Meeting Part 1 Dr. Ray R. Irani Chairman of the Board, President & Chief Executive Officer |
| Sustainable Growth & Financial Returns Oil & gas production growth Large pipeline of projects High quality assets with good returns Volume growth of 5-7 percent Disciplined capital program Maintain top quartile financial returns Maintain "A" credit rating |
| Oxy Financial Returns (2001-2005) Amerada Hess Anadarko Apache BP Burlington Chevron ConocoPhillips Devon ExxonMobil Kerr-McGee Marathon Oxy Returns In Top Quartile Among Industry Peers ROE ................................ ROCE .............................. 5-Year Average 28% 19% See Appendix for GAAP reconciliation. |
| Total Returns (2001-2005) Oxy .................................................... S&P 500 Oil & Gas E&P Index ................. S&P 500 Oil & Gas Integrated Index .......... * Data Source: Bloomberg 279 166 59 Percent Primary Goal : Generate Top Quartile Total Returns |
| Current Projects in Pipeline Argentina Dolphin Mukhaizna California Permian Libya |
| Strategy Focus on core areas US - California & Permian Basin Middle East-North Africa Latin America Maintain strong balance sheet Maintain investment discipline Create value Acquire assets with upside potential Capture EOR projects with large volumes of oil in place Maximize free cash flow from chemicals |
| Competitive Advantages Economies of scale Infrastructure Operating experience Large technical data base Strong regional relations |
| Today's Program Company overview & chemicals outlook Steve Chazen Western Hemisphere - Oil & Gas John Morgan Eastern Hemisphere - Oil & Gas Casey Olson Financial outlook & worldwide production outlook Steve Chazen Wrap up Ray Irani |
| Key Points Project pipeline Deliver sustainable production growth of 5-7 percent through 2010 Additional high quality growth opportunities during the outlook period - and beyond Maintain top quartile financial returns |
| February 23, 2006 2006 Analyst Meeting Part 2 Stephen I. Chazen Senior Executive Vice President & Chief Financial Officer |
| Company Overview |
| Overview Returns are key Financial strength driven by domestic business Growth driven by international business Both sectors are highly profitable |
| Return on Equity 2001 20023 2003 2004 2005 5Yr. Aver. East 22.2 16.5 21.4 27.8 41.3 28 Percentage 2001 2002 2003 2004 5 Year Average 22 17 21 28 41 2005 28 See Appendix for GAAP reconciliation. |
| Return on Capital Employed 2001 20023 2003 2004 2005 5Yr. Aver. East 13 10.9 14.6 20.2 33.3 19.2 Percentage 2001 2002 2003 2004 5 Year Average 13 11 15 20 33 2005 19 See Appendix for GAAP reconciliation. |
| 2005 After-Tax Earnings Domestic International 2530 1435 $1,435 (36%) $2,530 (64%) $ Millions |
| 2005 Cash From Operations Domestic International 3275 2060 $2,060 (39%) $3,275 (61%) Before Capital ($ Millions) |
| Oil & Gas Chemicals Earnings 4138 855 2005 Cash Flow Sources Oil & Gas Chemicals Earnings 6347 1028 Chemicals Before Capital After Capital $ Millions $1,028 $6,374 (14%) Oil & Gas (86%) Oil & Gas (83%) Chemicals (17%) $4,138 $855 (12%) (88%) (87%) (13%) (2004) |
| Chemicals Overview Financial asset Consistently profitable business Generates free cash flow Domestic asset Not closely related to oil & gas business Economic growth drives demand Construction, automotive, consumer goods Margin business Natural gas is primary feedstock |
| Chemicals Overview Focus on single business Chloro-vinyls Major factor in industry Large, cost competitive assets |
| Chemicals - Core Earnings $ Millions 2001 2002 2003 2004 2005 3 Yr. Average 5-Yr. Average Earnings 55 175 225 415 780 475 330 2001 2002 2003 2004 2005 55 175 225 415 780 3-Yr Average 5-Yr Average 475 330 See Appendix for GAAP reconciliation. |
| Chemicals - Free Cash Flow $ Millions 2001 2002 2003 2004 2005 3-Yr. Average 5-Yr. Average Earnings 180 245 305 505 855 555 420 2001 2002 2003 2004 2005 180 245 305 505 855 3-Yr Average 5-Yr Average 555 420 See Appendix for GAAP reconciliation. |
| Chemical Sales' Components 54 19 13 7 7 100 2003 56 15 11 7 11 100 2004 Energy & Feedstock Plant Costs SG&A DD&A Segment Income 55 14 9 5 17 100 2005 Percentage of Total Sales |
| Key to Success - Quality Assets Size Location Technology Environmental stewardship |
| North American Chlor-Alkali Producers Dow ....................... OxyChem ................ PPG ....................... Olin ........................ Formosa .................. Pioneer ................... Georgia Gulf ............ Others ..................... 30 25 13 7 6 4 3 12 100 Market Share (%) |
| North American PVC Producers Shintech ................. OxyChem ................ Georgia Gulf ............ Formosa ................. Westlake ................ Others ..................... 28 23 14 14 8 13 100 Market Share (%) |
| Key Initiatives Vulcan acquisition Elimination of mercury technology Shutdown/consolidation of small plants Pasadena PVC modernization Emissions reduction |
| OxyChem - 16.7 Chemical Companies Comparisons Nova Lyondell Dow Westlake Olin Georgia Gulf Eastman Huntsman Celanese FMC Rohm & Haas Air Products OxyChem - 22.2 8.0 11.6 2.9 14.0 7.6 7.2 8.2 13.9 11.8 13.0 13.4 11.2 EBIT Percent of Sales EBITDA 12.0 8.1 11.9 10.6 9.9 20.7 19.4 19.4 15.7 15.5 17.3 18.4 Excludes special items. |
| Chemicals - 2006 Outlook Relatively stable margins Full year of Vulcan operations & realization of synergies |
| Worldwide Oil & Gas Operations Long Beach Permian Basin Horn Mountain Hugoton Elk Hills Colombia Ecuador Libya Russia Pakistan Oman U.A.E. Yemen Qatar .. .. .. Argentina Peru |
| 2005 Oil & Gas Results US Middle East & Other Latin America Earnings 971 1068 197 US Middle East & Other Latin America Earnings 3558 2024 753 US Middle East & Other Latin America Core Earnings Capital $971 (43%) $197 (9%) $1,068 (48%) $ Millions $753 (12%) $2,024 (32%) $3,558 (56%) See Appendix for GAAP reconciliation. |
| 2005 Oil & Gas Sales' Components $ Millions Operating Costs DD&A Division Income 2865 1215 6335 Segment Income Operating Costs DD&A 11% 61% 28% $1,215 $2,865 $6,335 (14%) (57%) (29%) (2004) |
| Reserve Factors to Consider Libya Costs incurred --- $257 million Booked only 2005 production No reserve carryover into 2006 Mukhaizna Costs incurred --- $137 million Booked minimal 2005 reserves Dolphin Unbooked reserves --- 50 million BOE Permian Basin acquisitions Significant probable reserves Reserve revisions Price impact --- 26 million BOE |
| Reserves Replacement 244 263 368 268 390 342 306 173 188 200 207 207 205 195 Worldwide Reserve Additions (Million BOE) Worldwide Production (Million BOE) 2001 2002 2003 2004 2005 3-Year Average 5-Year Average See Appendix for GAAP reconciliation. |
| Reserves Replacement 2005 2004 2003 2002 2001 3-Year Average 5-Year Average 251 231 261 195 240 248 236 139 37 107 68 4 94 70 390 268 368 263 244 342 306 64 86 71 74 98 72 77 Organic Growth Acquisitions Total Organic (% Total) Million BOE See Appendix for GAAP reconciliation. |
| Reserve Replacement Million BOE 2001 2002 2003 2004 2005 143 142 102 121 139 4 68 107 36 139 Acquisitions Improved Recovery See Appendix for GAAP reconciliation. |
| Finding & Development Costs 1,171 1,223 1,584 1,785 4,382 2,584 2,029 244 263 368 268 390 342 307 Costs Incurred ($ Millions) Reserve Additions (Million BOE) 2001 2002 2003 2004 2005 3-Year Average 5-Year Average See Appendix for GAAP reconciliation. |
| Finding & Development Costs 2005 2004 2003 2002 2001 3-Year Average 5-Year Average 2,202 1,631 1,216 1,031 1,089 1,683 1,434 2,180 154 368 192 82 901 595 4,382 1,785 1,584 1,223 1,171 2,584 2,029 50 91 77 84 93 65 71 Organic Growth Acquisitions Total Organic (% Total) Costs Incurred ($ Million) |
| Pro-forma Yearend 2005 Proved Reserves 2,127 303 (42) 2,388 Oil (Million BOE) BOE (Million BOE) Oxy Vintage Assets held for sale Total Oxy Proforma Gas (Billion CF) 3,478 678 (180) 3,976 2,707 416 (72) 3,051 See Appendix for GAAP reconciliation. |
| US Middle East/North Africa Latin America Other Reserves 2096 480 409 67 Pro-forma Yearend 2005 Proved Reserves Million BOE 2,095 480 409 67 United States Latin America Middle East/ North Africa Other Reserve Life = 13.1 years See Appendix for GAAP reconciliation. |
| U.S. Oil & Gas Operations Overview 2005 2004 2003 2002 2001 345 339 345 326 315 61 60 63 63 66 2,026 1,844 1,804 1,755 1,698 75 73 73 76 76 Production (MBOE/Day) Production (% Total) Reserves (MMBOE) Reserves (% Total) See Appendix for GAAP reconciliation. |
| International Oil & Gas Operations Overview 2005 2004 2003 2002 2001 223 227 202 189 161 39 40 37 37 34 681 688 667 556 543 25 27 27 24 24 Production (MBOE/Day) Production (% Total) Reserves (MMBOE) Reserves (% Total) See Appendix for GAAP reconciliation. |
| February 23, 2006 John Morgan President Oxy Oil & Gas - Western Hemisphere 2006 Analyst Meeting Part 3 |
| U.S. Operations Long Beach Hugoton Bravo Dome Oxy Permian Horn Mountain Houston Los Angeles Elk Hills & California Properties Bakersfield |
| 2005 U.S. Production Permian ................. California .............. Hugoton/Other........ Total .................... 189 116 40 345 Thousand BOE/Day |
| Permian Basin Large resource base Low decline rate & long-lived properties Significant cash generation Natural area for consolidation Area of Operations Dallas Houston Texas New Mexico |
| Permian - Oxy Reserves & Production Million BOE 2000 2001 2002 2003 2004 2005 968 955 1,013 1,078 1,083 1,211 855 43 102 162 224 288 357 Net Proved Reserves 89 |
| Permian - Production History Thousand BOE/Day 2000 2001 2002 2003 2004 2005 2005 Exit Rate Annual Rate 121 162 164 172 176 189 200 162 164 172 176 189 121 |
| Permian - Oxy Oil Infrastructure 1,300 miles long 3.3 million barrels storage 175,000 barrels/day capacity Lubbock Amarillo Bravo Dome Texas New Mexico Oklahoma Salt Creek Sharon Ridge Oxy Acreage Cogdell Indian Basin Area Hobbs Midland Denver City Unit Centurion Pipeline |
| Bravo Dome field Pipelines Gas processing plants Operating expertise Permian - Oxy CO2 Infrastructure Lubbock Amarillo Bravo Dome Texas New Mexico Oklahoma Salt Creek Sharon Ridge Oxy Acreage Cogdell Indian Basin Area Hobbs Midland Denver City Unit |
| Primary Waterflood CO2 East 10 30 60 Permian - World Class EOR Operator Recovery Methods |
| CO2 Flood Process Drive Water CO2 Water CO2 Miscible Zone Oil Bank Additional Oil Recovery |
| Permian - Oxy CO2/EOR Production Growth 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 1982 2 2.1 3.3 20.5 42.7 43.4 47.6 54.9 55.9 60 71 76 86.2 Thousand Barrels/Day |
| Permian - CO2 Development Projects New CO2 floods North Cowden West RKM Five major expansions Hobbs Wasson ODC Denver Cogdell Sharon Ridge 2006 Plan |
| Permian - CO2 Development Projects $100 million/year capital program ~50 projects New floods Expansions Five Year Plan |
| New Incremental CO2 Enhanced Oil Production 2006 2007 2008 2009 2010 2011 2012 2013 East 1.8 7.9 13.4 15.1 24.4 30.3 34.5 36.5 Thousand Barrels/Day |
| Improving lift systems Optimizing gathering system 2006 8 wells in current producing zones & deeper targets Permian - Adding Value to Acquired Assets Indian Basin Area Indian Basin Area Hobbs New Mexico Texas |
| Active workover program Improve Salt Creek injection performance CO2 flood expansion phases at Sharon Ridge identified Permian - Adding Value to Acquired Assets Cogdell Area KENT CO. SCURRY CO. 0 10 Miles Salt Creek Sharon Ridge Cogdell * Oxy Field Office Texas |
| Permian - 2006 Development Summary Drill ~320 wells Exit rate impact 16,000 - 18,000 barrels/day Lubbock Amarillo Bravo Dome Texas New Mexico Oklahoma Salt Creek Sharon Ridge Oxy Acreage Cogdell Indian Basin Area Hobbs Midland Denver City Unit |
| Permian - Production Outlook 2005 2006 2007 2008 2009 2010 Permian 189 200 200 200 200 200 California 116 125 130 130 130 130 Other US 40 45 35 35 30 30 Variance 5 10 15 20 25 Thousand Barrels/Day (Assumes $50 WTI Price) |
| California Operations Elk Hills Long Beach Vintage Assets Bakersfield Ventura Long Beach Elk Hills Existing Oxy Properties Vintage Property Additions San Francisco Sacramento NEVADA San Joaquin Valley |
| 2005 California Production Elk Hills ...................... Long Beach/Other......... Vintage Proforma ........ Total .......................... 90 26 10 126 Thousand BOE/Day |
| California - Elk Hills Profile Large resource Reserve growth EOR opportunities Bakersfield Ventura Long Beach Elk Hills Existing Oxy Properties Vintage Property Additions Kern Front Thums |
| Elk Hills - Oxy Reserves & Production Million BOE 96 235 26 61 132 169 203 268 1998 1999 2000 2001 2002 2003 2004 2005 399 410 439 437 462 444 441 505 |
| Elk Hills - Oxy Net Gas Production Million Cubic Feet/Day Original Forecast 0 50 100 150 200 250 300 1998 1999 2000 2001 2002 2003 2004 2005 |
| Elk Hills - 2006 Development Plan Drill 270 wells Shallow oil zone Shale development EOR Nitrogen flood CO2 pilots Bakersfield Ventura Long Beach Elk Hills Existing Oxy Properties Vintage Property Additions Kern Front Thums |
| Elk Hills - Historical Shale Development 98 99 00 01 02 03 04 05 BOE 6.5 5.8 7 12 20.2 24.8 25.8 27.2 Thousand BOE/Day Reservoir characterization Increasing target Stimulation Expanding development EOR evaluation Increasing recovery potential Recent Success |
| Elk Hills - Future Shale Development 06E 07E 08E 09E 10E 11E BOE 33.2 34.5 34.7 35 35.2 35.4 Drill 70+ wells Workover 180+ wells Pilot CO2 Thousand BOE/Day 2006 Plan |
| N2 Rejection Unit N2 Injection Gas and NGL Sales Elk Hills Nitrogen Injection Project Oil Sales Cryogenic Nitrogen Plant N2 Gas Natural Gas Additional Oil and Gas Recovery Compressor Air Intake Produced Gas Recycled Gas N2 Injection Pushes Extra Oil Out Of The Reservoir N2 Displaces High-Value Natural Gas NET OIL PRODUCTION M B O P D 2 4 6 8 0 N2 Gas 2006 2008 2010 2007 2009 |
| Elk Hills CO2 Pilots Engineering 2004 Core work Reservoir modeling Phase 1 (Q1 2005) Oil mobilized Phase 2 (Q2 2005) Expanded pilot Analysis ongoing Sourcing evaluations |
| California - Vintage Assets Bakersfield Ventura Long Beach Santa Barbara Elk Hills Existing Oxy Properties Vintage Property Additions Kern Front Thums Vintage Assets Ventura Basin Large resource 6 wells and technical work San Joaquin Basin Integration Exploration -- 4 wells Sacramento Valley Gas exploitation Base plus program adds 12,000 BOE/Day |
| California - Long Beach Large resource Unique operating environment Drill 55 wells in 2006 Stable production |
| California - Production Outlook 2005 2006 2007 2008 2009 2010 Permian 189 200 200 200 200 200 California 116 125 130 130 130 130 Other US 40 45 35 35 30 30 Variance 5 10 15 20 25 Thousand Barrels/Day (Assumes $50 WTI Price) |
| U.S. Proved Reserves 2001 2002 2003 2004 2005 Permian 955 1013 1078 1083 1211 California 437 441 444 462 505 Other 306 302 282 299 310 Million BOE 1,698 1,755 1,804 1,844 2,026 |
| U.S. Production Outlook 2005 2006 2007 2008 2009 2010 Permian 189 200 200 200 200 200 California 116 125 130 130 130 130 Other US 40 45 35 35 30 30 Variance 5 10 15 20 25 Thousand Barrels/Day (Assumes $50 WTI Price) |
| U.S. - 2006 Capital Outlook Projects Permian ................................... California ................................. Other ...................................... Total ............................................ 430 500 270 1,200 $ Millions |
| Latin America Operations Successful history Resource rich area Vintage assets Colombia Ecuador Peru Bolivia Argentina |
| 2005 Latin America Production Oxy Ecuador ....................... Colombia ..................... Vintage Proforma Argentina .................... Bolivia ........................ Total .............................. 2006 Outlook..................... 42 32 37 3 114 120+ Thousand BOE/Day |
| Colombia Operations Covenas Ayacucho Barranca Bucaramanga Arauca La Cira Infantas Cano Limon Venezuela Colombia CNA Pipeline Vasconia Oleoducto de Colombia Caricare |
| Colombia - La Cira Infantas Overview Colombia's largest oil field Remaining oil in place 3 billion+ barrels Current production 5,400 Barrels/Day (18% recovery rate) Phased EOR pilots Commerciality decision in 2008 Expected reserves 80 million barrels net @ full development Expected 2010 production impact 20,000 BOE/Day |
| Colombia - La Cira Infantas EOR Reactivation of idle wells & workovers Infill & horizontal drilling Waterflood redevelopment Gas & steam flooding Waterflood Redevelopment Steamflood Pilot Gas Injection & Horizontal Drilling |
| Ecuador Business as usual Meeting production targets Ongoing discussions with government OCP Pipeline Quito Eden Yuturi Ecuador Block 15 Peru Colombia |
| Ecuador Operations Net production 42,000 BOE/Day Development opportunities Exploration opportunities OCP Pipeline Quito Eden Yuturi Ecuador Block 15 Peru Colombia |
| Argentina - Vintage Properties Current production 37,000 BOE/Day San Jorge Basin 15 of 22 concessions 219 million BOE proved reserves (12/31/2005) Strong track record driven by 3D seismic Argentina Vintage Properties Buenos Aires |
| Argentina - Vintage Production 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006E 2007E 2008E 2009E 2010E 2011E Argentina 5.2 12 15 17 23 29.5 33 34 32.5 31 37.5 42 49.5 57.5 62 63 68 Thousand Barrels/Day 95 96 97 98 99 00 01 02 03 04 05 |
| Argentina - San Jorge Basin Comodoro Rivadavia Argentina Caleta Olivia Koluel Kayke Oxy Blocks Oil Gas Pipelines Proved Undeveloped Reserves |
| Argentina - Growth Inventory of 700 drilling locations 145 wells planned in 2006 Ramp up in future years Identified 28 waterflood projects Additional technology driven opportunities Exploration 2 exploration blocks Consolidation opportunities Mature areas ripe for consolidation |
| Argentina - Production Outlook 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006E 2007E 2008E 2009E 2010E 2011E Argentina 5.2 12 15 17 23 29.5 33 34 32.5 31 37.5 42 49.5 57.5 62 65 70 Thousand Barrels/Day 05 06E 07E 08E 09E 10E 11E |
| Latin America Production Outlook 2005 2006 2007 2008 2009 2010 Minimum 74 115 120 125 130 130 Variance 10 10 15 25 35 Thousand Barrels/Day (Assumes $50 WTI Price) |
| Latin America Colombia EOR/exploration 5,000 - 10,000 BOE/Day Argentina Development/consolidation 15,000 - 20,000 BOE/Day Additional Growth Opportunities |
| Latin America - 2006 Capital Outlook Major Projects Colombia .................................. Ecuador ................................... Argentina ................................. Total ............................................ 130 90 180 400 $ Millions |
| 2006 Goals Permian Increase production to 200,000 BOE/Day Execute development program for acquired assets Implement CO2 flood projects Elk Hills Maintain production @ 90,000 BOE/Day Increase liquid production to offset gas decline Continue shale drilling program for future growth Execute CO2 pilots Latin America Increase production with emphasis on Argentina |
| February 23, 2006 Casey Olson President Oxy Oil & Gas - Eastern Hemisphere 2006 Analyst Meeting Part 4 |
| Middle East / North Africa Operations Qatar Libya Yemen UAE Oman |
| Middle East / North Africa Production 2005 .................................. 2006 Outlook ....................... Full year of Libya production Yemen / Vintage 103 122 Thousand BOE/Day |
| Qatar - ISND / ISSD Operations ISND (North Dome) OXY - 1994 1994 gross production 19,000 Bbls/Day 1998 gross production 120,000 Bbls/Day ISSD (South Dome) OXY - 1998 Developed as ISND satellite Potential Projects ISND ISSD Arabian Gulf Doha Mesaieed Qatar Saudi Arabia UAE |
| Oman - Blocks 9 / 27 Arabian Gulf Arabian Sea Gulf of Oman UAE Saudi Arabia Oman Fujairah Sohar Al Ain Salalah PDO Block 6 9 27 Block 9 - 30 Years Block 27 OXY - 65% / Operator 2005 Gross Production Oil 67,000 Bbls/Day Gas 117,000 MCF/Day Recent discovery Drilling / development |
| 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 Oman Production 0.8 2 2.8 5.9 12.7 19.1 24.2 26.2 26.9 31.2 35.4 36 40.1 41.8 50.1 43.7 39.3 41.3 44.8 46.4 70.2 84.1 Oman Block 9 - Gross Operated Production Thousand Barrels/Day |
| Oxy Yemen Blocks Blocks 14 / 10 Masila - 38% E. Shabwa - 40.4% 2005 Gross Production 200,000 b/d Block: S1 - Vintage 75% / Operator Gross Production 2005 - 9,000 b/d 2006 - 12,000 b/d Exploration Success Blocks 20 / 75 80% / 85% - Operator Gulf of Aden Red Sea Sana'a Ras Isa Aden Masila Ash Shihr East Shabwa 20 OXY EXPLORATION OXY PRODUCTION OIL FIELD VINTAGE BLOCK PIPELINE 75 S1 |
| Current Growth Projects UAE / Qatar - Dolphin gas development and pipeline Oman - Mukhaizna enhanced oil recovery Libya - Enhanced oil recovery in existing assets |
| UAE / Qatar - Dolphin Project (Phase I) $4 billion gross capital Oxy share 24.5% First gas @ year-end 2006 Estimated Oxy reserves 300 million BOE Oxy net production 55-60,000 BOE/day |
| UAE Gas Supply/Demand Forecast 2006 2007 2008 2009 2010 2011 2012 2013 Total Demand (mmcf/day) 6.89 7.76 9.54 10.07 10.72 11.36 12.09 12.87 Supply 5.6 7.15 9.43 9.44 9.41 9.89 10.33 10.33 Demand Billion Cubic Feet/Day Supply (includes Dolphin's 3.2 BCF/Day |
| UAE / Qatar - Dolphin Project (Phase II) Offshore facilities Gas plant expansion 1.2 bcf / day Timeframe - 2010+ |
| Oman - Mukhaizna Project Overview Gross Capital - $ 3 Billion 1800+ wells Central processing facility Water treatment plant Steam generation facilities Pipelines 2006 Work Program & Budget $450-$500 MM (Gross) Drill 65 - 85 wells Initial steam injection Arabian Gulf Arabian Sea Gulf of Oman UAE Saudi Arabia Oman Fujairah Sohar Al Ain Salalah PDO Block 6 9 27 Mukhaizna |
| Steam Zone Production Well Oil & Water Injection Well Gravity Drainage of Hot Oil Steam Shale Shale Oil and Water Steam Flood Process |
| Oman - Mukhaizna Production Targets 2006 - 12,500 b/d 2008 - 50,000 b/d 2011 - 150,000 b/d 30,000 b/d net Arabian Gulf Arabian Sea Gulf of Oman UAE Saudi Arabia Oman Fujairah Sohar Al Ain Salalah PDO Block 6 9 27 Mukhaizna |
| Mukhaizna Today |
| Mukhaizna Tomorrow |
| Oxy Libya Holdings EPSA II NC143 EPSA II NC145 NC144 EPSA II NC150 NC74 NC29 36 53 35 52 163 131 59 124 106 New Exploration Acreage Original Exploration Acreage Original Producing Acreage Tunisia Algeria Niger Chad Egypt Tripoli Benghazi 103 102 Libya |
| Scope of Oxy Libya Projects EPSA II NC143 EPSA II NC145 NC144 EPSA NC150 NC74 NC29 36 53 35 52 163 131 59 124 106 Libya Tunisia Niger Chad Egypt Tripoli Benghazi 103 102 EPSA IV Exploration 19 Million Acres EPSA II/85 Exploration 11 Million Acres |
| Libya - 2005 Bid Rounds EPSA II NC143 EPSA II NC145 EPSA II NC144 EPSA 85 NC150 EPSA I NC74 EPSA I NC29 Concessions 102, 103 36 53 35 52 163 131 59 124 106 Libya Tunisia Algeria Niger Chad Egypt Tripoli Benghazi 44 94 171 186 42-1-3 40-3-4 17-4 82-3 81-2 42-2-4 17-3 82-4 2-1-2 161-2-4 102-3 123-1 176-3 176-4 146-1 81-1 102-4 123-2 121-2 123-3a 147-3-4 123-3b 161-1 Bid Round 2 Areas Bid Round 1 Areas Awarded EPSA 81/85 Blocks |
| Libya - 2005 Bid Round Comparison Round 1 15 blocks Round 2 26 blocks Round 1 blocks 4X larger than Round 2 blocks Minimum work programs equal for blocks in each Round Lowest production share Round 1 - 10.8% Round 2 - 6.8% 15 winning bids below 10.8% |
| Libya - 2006 Exploration Program EPSA II NC143 EPSA II NC145 NC144 EPSA II NC150 NC74 NC29 36 53 35 52 163 131 59 124 106 Tunisia Algeria Niger Chad Egypt Tripoli Benghazi 103 102 Libya New Exploration Acreage Original Exploration Acreage Original Producing Acreage Seismic 10,000 kms Drill 6 Wells 5 onshore 1 offshore |
| Planned 2006 Plan 2D Seismic 1,709km 3D Seismic 750km2 Drill 2-3 Wells in Q3 Existing Libya - Area 106 |
| Libya - Area 124 Planned 2006 Plan 2D Seismic 951km 3D Seismic 500km2 Drill 1-2 Wells in Q4 Existing |
| Middle East / North Africa Production Outlook 2005 2006 2007 2008 2009 2010 Minimum 103 120 155 175 175 180 Other 45 45 40 40 35 35 Variance 5 20 20 25 50 Thousand Barrels/Day (Assumes $50 WTI Price) |
| ME / NA - 2006 Capital Outlook ME / NA Projects Oman ....260 Dolphin...255 Qatar..... 250 Libya ..... 175 Yemen....160 Total ...............1,100 $ Millions |
| 2006 Goals Increase base production Dolphin "First Gas" Average 45-50,000+/- net BOE/Day in 2007 Mukhaizna development schedule Significant exploration success Libya Multiple new development projects |
| Middle East / North Africa Incremental growth opportunities Field Development (EOR - IOR) Libya Oman UAE Algeria Qatar Exploration - Libya New Project Profile (Not Included in 2006 - 2010 Production Outlook) |
| 2 - 4 significant new projects Target 20% ROR @ moderate oil prices Middle East / North Africa New Project Profile (Not Included in2006 - 2010 Production Outlook) |
| Middle East / North Africa Exposure to additional production Full field development 100, 000 - 125, 000 net BOE/Day ( 2010+) Net Oxy 2010 exit rate 50, 000 - 75, 000 net BOE/Day Exploration 20, 000 - 40,000 net BOE/Day New Project Profile (Not Included in 2006 - 2010 Production Outlook) |
| February 23, 2006 Stephen I. Chazen Senior Executive Vice President & Chief Financial Officer 2006 Analyst Meeting Part 5 |
| Focus on Top Quartile Returns Existing properties Acquisitions New projects Capital structure management Key Drivers |
| U.S. Oil & Gas Financial Overview 2005 2004 2003 2002 2001 10.64 8.88 8.91 8.71 8.71 2.58 1.80 1.40 ..83 1.45 Capital Employed ($ Billion) Net Income ($ Million) Return (%) 26 20 16 10 17 56.56 41.40 31.03 26.08 25.97 WTI ($/Barrel) |
| International Oil & Gas Financial Overview 2005 2004 2003 2002 2001 Capital Employed ($ Billion) Net Income ($ Million) Return (%) 56.56 41.40 31.03 26.08 25.97 WTI ($/Barrel) 3.93 2.96 2.34 1.98 1.52 1.38 0.98 0.65 0.62 0.35 40 37 30 35 23 |
| 2006-2010 Capital Program Based on current holdings only 2006 peak year Significant investment for growth during next 5 years |
| Capital Expenditures (2005-2010) US International Subtotal Exploration Total Oil & Gas Chemicals Total 957 1,131 2,088 160 2,248 175 2,423 1,200 1,400 2,600 300 2,900 215 3,115 1,200 1,200 2,400 300 2,700 250 2,950 1,100 1,100 2,200 300 2,500 225 2,725 1,000 900 1,900 300 2,200 200 2,400 1,000 900 1,900 300 2,100 170 2,270 2005 2006 2007 2008 2009 2010 $ Million |
| Oil & Gas Capital Expenditures (2006-2010) Base Growth Total 2,070 830 2,900 1, 950 750 2,700 1,765 735 2,500 1,460 740 2,200 1,465 635 2,100 2006 2007 2008 2009 2010 $ Million |
| Oil & Gas Growth Capital (2006-2010) Exploration Argentina Dolphin Mukhaizna Total 300 100 255 175 830 300 150 90 210 750 300 100 160 175 735 300 75 315 50 740 300 75 210 50 635 2006 2007 2008 2009 2010 $ Million |
| 2001-2004 Exploration Expense OXY Industry Average E & P Major Integrated $0.93 $1.26 $0.65 $/BOE |
| Exploration Expense 2005 2006 2007 2008 2009 2010 $1.63 $1.22 $1.14 $1.09 $1.08 $1.05 $/BOE |
| Worldwide Production Outlook Does not depend on exploration success Does not include future acquisitions Does not include new EOR/development projects Range reflects timing differences |
| Historic Worldwide Production 1997 1998 1999 2000 2001 2002 2003 2004 2005 US 395 438 425 461 476 515 547 566 568 Thousand Barrels/Day 5.3% CAGR |
| Worldwide Production Outlook 2005 2006 2007 2008 2009 2010 US 345 370 365 365 360 360 Eastern Hemisphere 150 165 195 210 210 210 Latin America 74 115 120 125 130 130 Variance 20 40 55 60 85 Thousand Barrels/Day (Assumes $50 WTI Price) |
| Worldwide Production Outlook 2005 2006 2007 2008 2009 2010 Minimum 568 650 680 700 700 700 Variance 20 45 55 60 85 Thousand Barrels/Day (Assumes $50 WTI Price) Variance = 7.6% Minimum = 4.6% 568 650 680 700 700 700 670 720 755 760 785 |
| Worldwide Production Outlook 2005 2006 2007 2008 2009 2010 US 334 360 355 365 360 360 Eastern Hemisphere 104 120 155 175 175 175 Latin America 73 115 120 125 130 130 Mature/Non-Operated 59 55 50 40 35 35 Variance 20 40 50 60 85 Thousand Barrels/Day (Assumes $50 WTI Price) |
| Oil Price Sensitivity $40 $60 WTI Price ($/Barrel) PSC Production Impact (Barrels/Day) + 10,000 - - 8,000 |
| Acquisitions Must Be Accretive To Value Acquire assets based on upside potential Permian (2001-2005) Acquired 1,163 MBOE proved reserves Extensions, discoveries & improved recovery Added 341 MBOE proved reserves Elk Hills (1998-2005) Acquired 425 MBOE proved reserves Extensions, discoveries & improved recovery Added 269 MBOE proved reserves |
| Reserve Additions Million BOE 2001 2002 2003 2004 2005 143 142 102 121 139 Improved Recovery See Appendix for GAAP reconciliation. |
| Future Acquisitions Expect to acquire additional reserves / production Permian California |
| Permian Opportunities 40,000 owners History of annual acquisitions |
| Top 10 Permian Oil Producers OXY CVX KMI APA AHC COP XTO PDX XOM DVN BOE/Day 195 74 56 30 30 26 25 24 19 17 195 74 56 30 30 26 25 24 19 17 2005 Gross Operated Production (Thousand BOE/Day) Source: 2005 IHS Energy Data. |
| California Operations Relatively concentrated Relatively few buyers |
| Aera Energy CVX OXY Plains E&P Berry Pet Seneca Res Rosetta Rec Venoco Breitburn Energy XOM Net Income 228.6 209.5 176.3 50.1 16.8 9.9 9.6 8.1 7 4.8 Aera OXY Seneca Venoco Berry Rosetta Breitburn XOM CVX 230 210 176 50 17 10 10 8 7 5 Plains California Operated Production 2004 (Thousand BOE/Day) |
| Return Targets* New Projects & Acquisitions Domestic ........................ International ................... 15+% 20+% * Assumes moderate product prices |
| 5-Year U.S. Acquisition Target 2001-2005 actual ............... 2006-2010 target ................ 52 35 - 50 Thousand BOE/Day |
| Vintage Status Assets held for sale 75 confidentiality agreements in place Production 19,000 BOE/Day Not included in production outlook Reserves 72 million BOE Second Quarter closing target |
| Financial Policy Priority cash flow uses Reinvestment Dividends & share repurchases Debt reduction |
| Gross Cash Flow Uses 43 26 19 12 100 2003 43 42 5 10 100 2004 Capital Debt Reduction & Cash Acquisitions Dividends 2005 Percentage of Total 42 30 20 8 100 |
| Why Debt Will Remain Low Taxes "A" Rating International Projects Flexibility Large projects are multi-year |
| Moody's Debt - Proved Reserves Ratio Aaa Aa A Baa <$1.00 $1.00 - $2.00 $2.00 - $3.00 $3.00 - $5.00 Moody's Rating Debt/ Proved Developed Reserves Pro-Forma Oxy (12/31/05) $1.62 See Appendix for GAAP reconciliation. |
| Annual payout rates/common share Dividend policy evaluated at least annually Reflects management's view of long-term free cash flow outlook at significantly lower oil prices Dividend Policy 2002 2003 2004 2005 2006 $1.00 $1.04 $1.10 $1.29 $1.44 |
| Share Repurchases Initial repurchase 10 million shares Additional repurchases after Vintage asset sales Additional repurchases possible from free cash flow Purpose of share repurchase Increase value for remaining shareholders Shares Outstanding Actual Year-end 2005 Pro-forma Vintage Acq. Target Millions 402 430 400 |
| February 23, 2006 Dr. Ray R. Irani Chairman of the Board, President & Chief Executive Officer 2006 Analyst Meeting Part 6 |
| Worldwide Production Outlook 2005 2006 2007 2008 2009 2010 Minimum 568 650 680 700 700 700 Variance 20 45 55 60 85 Thousand Barrels/Day (Assumes $50 WTI Price) Variance = 7.6% Minimum = 4.6% 568 650 680 700 700 700 670 720 755 760 785 |
| 2010 Production Range Future growth opportunities Libya EOR projects Exploration Other large international projects Permian Basin & California acquisitions Swap/sell mature non-operated properties |
| Additional Growth Opportunities Base Production .............................. New EOR/development projects Middle East/North Africa ................ Latin America................................. Exploration ..................................... Domestic acquisitions ....................... Mature non-operated ........................ Total ............................................. 700 - 785 50 - 75 20 - 30 20 - 40 35 - 50 (20 - 30) 805 - 950 Thousand BOE/Day |
| Creating Shareholder Value New projects must meet expectations for good returns Compare new projects & asset acquisitions with share repurchases Make decisions based on creating long-term value for shareholders |
| Focus on Key Metrics Focus on Top Quartile performance Continue to improve quality of assets Optimize profit/BOE Optimize free cash flow/BOE Maintain top quartile finding & development costs Grow reserves Maintain "A" credit rating Keep ROE & ROCE in top quartile Generate top quartile total returns |
| Occidental Petroleum Corporation Statements in this presentation 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 results to differ materially include, but are not limited to: exploration risks such as drilling of unsuccessful wells, global commodity pricing fluctuations and supply/demand considerations for oil, gas and chemicals; higher than expected costs; political risks; changes in tax rates; unrealized acquisition benefits or higher than expected integration costs; and not successfully completing (or any material delay in) any expansion, capital expenditure, acquisition or disposition. You should not place undue reliance on these forward-looking statements which speak only as of the date of this presentation. 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 proved reserves demonstrated by actual production or conclusive formation tests to be economically producible under existing economic and operating conditions. We use certain terms in this presentation, such as probable, possible and recoverable reserves and oil in place, that the SEC's guidelines strictly prohibit us from using in filings with the SEC. Additionally, the SEC requires oil and natural gas companies, in their filings, to disclose non-financial statistical information about their consolidated entities separately from such information about their equity holdings and not to show combined totals. Certain information in this presentation is shown on a combined basis; however, the information is disclosed separately in the Appendix. U.S investors are urged to consider carefully the disclosure in our Form 10-K, available through 1-888-699- 7383 or at www.oxy.com. You also can obtain a copy from the SEC by calling 1-800-SEC-0330. |
Statements in this presentation 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 results to differ materially
include, but are not limited to: exploration risks such as drilling of unsuccessful wells, global
commodity pricing fluctuations and supply/demand considerations for oil, gas and chemicals; higher
than expected costs; political risks; changes in tax rates; unrealized acquisition benefits or
higher than expected integration costs; and not successfully completing (or any material delay in)
any expansion, capital expenditure, acquisition or disposition. You should not place undue
reliance on these forward-looking statements which speak only as of the date of this presentation.
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 proved reserves demonstrated by actual production or conclusive
formation tests to be economically producible under existing economic and operating conditions. We
use certain terms in this presentation, such as probable, possible and recoverable reserves and oil
in place, that the SEC’s guidelines strictly prohibit us from using in filings with the SEC.
Additionally, the SEC requires oil and natural gas companies, in their filings, to disclose
non-financial statistical information about their consolidated entities separately from such
information about their equity holdings and not to show combined totals. Certain information in
this presentation is shown on a combined basis; however, the information is disclosed separately in
the Appendix. U.S investors are urged to consider carefully the disclosure in our Form 10-K,
available through 1-888-699-7383 or at www.oxy.com. You also can obtain a copy from the
SEC by calling 1-800-SEC-0330.
Return on Capital Employed (ROCE)
($ Millions)
($ Millions)
| Reconciliation to Generally Accepted Accounting Principles (GAAP) | 2001 | 2002 | 2003 | 2004 | 2005 | 5 Year Average |
||||||||||||||||||
GAAP measure — earnings applicable to common
shareholders |
1,154 | 989 | 1,527 | 2,568 | 5,281 | 2,304 | ||||||||||||||||||
Interest expense |
392 | 281 | 295 | 239 | 201 | 282 | ||||||||||||||||||
Tax effect of interest expense |
(137 | ) | (98 | ) | (103 | ) | (84 | ) | (70 | ) | (98 | ) | ||||||||||||
Earnings before tax-effected interest expense |
1,409 | 1,172 | 1,719 | 2,723 | 5,412 | 2,487 | ||||||||||||||||||
GAAP average stockholders’ equity |
5,634 | 6,318 | 7,929 | 10,550 | 15,032 | 8,373 | ||||||||||||||||||
Average Debt |
||||||||||||||||||||||||
GAAP debt |
||||||||||||||||||||||||
Notes payable |
54 | — | — | — | — | 9 | ||||||||||||||||||
Non-recourse debt |
— | — | — | — | — | 317 | ||||||||||||||||||
Debt, including current maturities |
4,065 | 4,203 | 4,016 | 3,804 | 2,919 | 3,758 | ||||||||||||||||||
Non-GAAP debt |
||||||||||||||||||||||||
Capital lease obligation |
26 | 26 | 26 | 26 | 25 | 26 | ||||||||||||||||||
Subsidiary preferred stock |
— | 75 | 75 | 75 | 75 | 50 | ||||||||||||||||||
Gas sales agreements |
282 | — | — | — | — | 116 | ||||||||||||||||||
Trust preferred securities |
463 | 455 | 453 | — | — | 307 | ||||||||||||||||||
Average total debt |
4,890 | 4,759 | 4,570 | 3,905 | 3,019 | 4,583 | ||||||||||||||||||
Total average capital employed |
10,524 | 11,077 | 12,499 | 14,455 | 18,051 | 12,956 | ||||||||||||||||||
ROCE |
13.0 | 10.9 | 14.6 | 20.2 | 33.3 | 19.2 | ||||||||||||||||||
Worldwide Production and Proved Reserve Additions
Million BOE
Reconciliation to Generally Accepted Accounting Principles (GAAP)
Million BOE
Reconciliation to Generally Accepted Accounting Principles (GAAP)
| Consolidated Subsidiaries | Other Interests | Worldwide | ||||||||||||||||||||||||||||||||||
| OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | ||||||||||||||||||||||||||||
PRODUCTION |
||||||||||||||||||||||||||||||||||||
2001 |
124 | 241 | 164 | 9 | — | 9 | 133 | 241 | 173 | |||||||||||||||||||||||||||
2002 |
142 | 229 | 180 | 8 | — | 8 | 150 | 229 | 188 | |||||||||||||||||||||||||||
2003 |
153 | 221 | 190 | 10 | — | 10 | 163 | 221 | 200 | |||||||||||||||||||||||||||
2004 |
159 | 233 | 198 | 9 | — | 9 | 168 | 233 | 207 | |||||||||||||||||||||||||||
2005 |
158 | 246 | 199 | 7 | 6 | 8 | 165 | 252 | 207 | |||||||||||||||||||||||||||
Five-Year Average |
147 | 234 | 186 | 9 | 1 | 9 | 156 | 235 | 195 | |||||||||||||||||||||||||||
Proved Reserve Additions |
||||||||||||||||||||||||||||||||||||
2001 |
219 | 100 | 236 | 8 | — | 8 | 227 | 100 | 244 | |||||||||||||||||||||||||||
2002 |
221 | 216 | 257 | 6 | — | 6 | 227 | 216 | 263 | |||||||||||||||||||||||||||
2003 |
223 | 766 | 351 | 16 | 9 | 18 | 239 | 775 | 368 | |||||||||||||||||||||||||||
2004 |
162 | 624 | 266 | 4 | (9 | ) | 2 | 166 | 615 | 268 | ||||||||||||||||||||||||||
2005 |
255 | 752 | 380 | 9 | 6 | 10 | 264 | 758 | 390 | |||||||||||||||||||||||||||
Five-Year Average |
216 | 492 | 298 | 9 | 1 | 9 | 225 | 493 | 306 | |||||||||||||||||||||||||||
Costs Incurred
$ Millions
Reconciliation to Generally Accepted Accounting Principles (GAAP)
$ Millions
Reconciliation to Generally Accepted Accounting Principles (GAAP)
| Consolidated | Other | |||||||||||
| Subsidiaries | Interests | Worldwide | ||||||||||
2001 |
||||||||||||
Property acquisition costs |
||||||||||||
Proved properties |
29 | — | 29 | |||||||||
Unproved properties |
53 | — | 53 | |||||||||
Exploration costs |
176 | (5 | ) | 171 | ||||||||
Development costs |
907 | 11 | 918 | |||||||||
Costs incurred |
1,165 | 6 | 1,171 | |||||||||
2002 |
||||||||||||
Property acquisition costs |
||||||||||||
Proved properties |
163 | — | 163 | |||||||||
Unproved properties |
29 | — | 29 | |||||||||
Exploration costs |
134 | — | 134 | |||||||||
Development costs |
890 | 7 | 897 | |||||||||
Costs incurred |
1,216 | 7 | 1,223 | |||||||||
2003 |
||||||||||||
Property acquisition costs |
||||||||||||
Proved properties |
364 | — | 364 | |||||||||
Unproved properties |
4 | — | 4 | |||||||||
Exploration costs |
98 | (1 | ) | 97 | ||||||||
Development costs |
1,109 | 10 | 1,119 | |||||||||
Costs incurred |
1,575 | 9 | 1,584 | |||||||||
2004 |
||||||||||||
Property acquisition costs |
||||||||||||
Proved properties |
158 | (12 | ) | 146 | ||||||||
Unproved properties |
8 | — | 8 | |||||||||
Exploration costs |
158 | — | 158 | |||||||||
Development costs |
1,463 | 10 | 1,473 | |||||||||
Costs incurred |
1,787 | (2 | ) | 1,785 | ||||||||
2005 |
||||||||||||
Property acquisition costs |
||||||||||||
Proved properties |
1,782 | — | 1,782 | |||||||||
Unproved properties |
398 | — | 398 | |||||||||
Exploration costs |
257 | (2 | ) | 255 | ||||||||
Development costs |
1,932 | 15 | 1,947 | |||||||||
Costs incurred |
4,369 | 13 | 4,382 | |||||||||
5 Year Average |
||||||||||||
Property acquisition costs |
||||||||||||
Proved properties |
499 | (2 | ) | 497 | ||||||||
Unproved properties |
98 | — | 98 | |||||||||
Exploration costs |
165 | (2 | ) | 163 | ||||||||
Development costs |
1,260 | 11 | 1,271 | |||||||||
Costs incurred |
2,022 | 7 | 2,029 | |||||||||
ProForma Yearend 2005 Proved Reserves
Million BOE
Reconciliation to Generally Accepted Accounting Principles (GAAP)
Million BOE
Reconciliation to Generally Accepted Accounting Principles (GAAP)
| Consolidated Subsidiaries | Other Interests | Worldwide | ||||||||||||||||||||||||||||||||||
| 2005 | OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Occidental |
||||||||||||||||||||||||||||||||||||
United States |
1,636 | 2,338 | 2,026 | — | — | — | 1,636 | 2,338 | 2,026 | |||||||||||||||||||||||||||
Qatar |
233 | 978 | 396 | — | — | — | 233 | 978 | 396 | |||||||||||||||||||||||||||
Ecuador |
96 | — | 96 | — | — | — | 96 | — | 96 | |||||||||||||||||||||||||||
Oman |
32 | 73 | 44 | — | — | — | 32 | 73 | 44 | |||||||||||||||||||||||||||
Colombia |
49 | — | 49 | (6 | ) | — | (6 | ) | 43 | — | 43 | |||||||||||||||||||||||||
Russia |
— | — | — | 48 | — | 48 | 48 | — | 48 | |||||||||||||||||||||||||||
Yemen |
32 | — | 32 | 3 | — | 3 | 35 | — | 35 | |||||||||||||||||||||||||||
Pakistan |
4 | 89 | 19 | — | — | — | 4 | 89 | 19 | |||||||||||||||||||||||||||
Occidental Totals |
2,082 | 3,478 | 2,662 | 45 | — | 45 | 2,127 | 3,478 | 2,707 | |||||||||||||||||||||||||||
Vintage |
||||||||||||||||||||||||||||||||||||
United States |
54 | 92 | 69 | — | — | — | 54 | 92 | 69 | |||||||||||||||||||||||||||
United States — held for sale |
42 | 180 | 72 | — | — | — | 42 | 180 | 72 | |||||||||||||||||||||||||||
Argentina |
198 | 125 | 219 | — | — | — | 198 | 125 | 219 | |||||||||||||||||||||||||||
Bolivia |
4 | 281 | 51 | — | — | — | 4 | 281 | 51 | |||||||||||||||||||||||||||
Yemen |
5 | — | 5 | — | — | — | 5 | — | 5 | |||||||||||||||||||||||||||
Vintage Totals |
303 | 678 | 344 | — | — | — | 303 | 678 | 416 | |||||||||||||||||||||||||||
Less — Assets held for sale |
(42 | ) | (180 | ) | (72 | ) | — | — | — | (42 | ) | (180 | ) | (72 | ) | |||||||||||||||||||||
ProForma Occidental and Vintage |
2,343 | 3,976 | 3,006 | 45 | — | 45 | 2,388 | 3,976 | 3,051 | |||||||||||||||||||||||||||
| Recap - Million BOE | OXY | Vintage | Total | |||||||||
US |
2,026 | 69 | 2,095 | |||||||||
Middle East / North Africa |
475 | 5 | 480 | |||||||||
Latin America |
139 | 270 | 409 | |||||||||
Other |
67 | — | 67 | |||||||||
| 2,707 | 344 | 3,051 | ||||||||||
Worldwide Production
Million BOE/D
Reconciliation to Generally Accepted Accounting Principles (GAAP)
Million BOE/D
Reconciliation to Generally Accepted Accounting Principles (GAAP)
| US | International | Worldwide | ||||||||||||||||||||||||||||||||||
| 2001 | OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Consolidated Subsidiaries |
213 | 610 | 315 | 129 | 50 | 137 | 342 | 660 | 452 | |||||||||||||||||||||||||||
Other Interests |
— | — | — | 24 | — | 24 | 24 | — | 24 | |||||||||||||||||||||||||||
Worldwide |
213 | 610 | 315 | 153 | 50 | 161 | 366 | 660 | 476 | |||||||||||||||||||||||||||
Percentage of total |
66 | % | 34 | % | 100 | % | ||||||||||||||||||||||||||||||
2002 |
OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Consolidated Subsidiaries |
232 | 564 | 326 | 155 | 63 | 166 | 387 | 627 | 492 | |||||||||||||||||||||||||||
Other Interests |
— | — | — | 23 | — | 23 | 23 | — | 23 | |||||||||||||||||||||||||||
Worldwide |
232 | 564 | 326 | 178 | 63 | 189 | 410 | 627 | 515 | |||||||||||||||||||||||||||
Percentage of total |
63 | % | 37 | % | 100 | % | ||||||||||||||||||||||||||||||
2003 |
OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Consolidated Subsidiaries |
256 | 532 | 345 | 163 | 74 | 174 | 419 | 606 | 519 | |||||||||||||||||||||||||||
Other Interests |
— | — | — | 27 | — | 27 | 27 | — | 27 | |||||||||||||||||||||||||||
Worldwide |
256 | 532 | 345 | 190 | 74 | 202 | 446 | 606 | 547 | |||||||||||||||||||||||||||
Percentage of total |
63 | % | 37 | % | 100 | % | ||||||||||||||||||||||||||||||
2004 |
OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Consolidated Subsidiaries |
254 | 507 | 339 | 180 | 130 | 201 | 434 | 637 | 540 | |||||||||||||||||||||||||||
Other Interests |
— | — | — | 26 | — | 26 | 26 | — | 26 | |||||||||||||||||||||||||||
Worldwide |
254 | 507 | 339 | 206 | 130 | 227 | 460 | 637 | 566 | |||||||||||||||||||||||||||
Percentage of total |
60 | % | 40 | % | 100 | % | ||||||||||||||||||||||||||||||
2005 |
OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Consolidated Subsidiaries |
253 | 553 | 345 | 178 | 121 | 198 | 431 | 674 | 543 | |||||||||||||||||||||||||||
Other Interests |
— | — | — | 22 | 15 | 25 | 22 | 15 | 25 | |||||||||||||||||||||||||||
Worldwide |
253 | 553 | 345 | 200 | 136 | 223 | 453 | 689 | 568 | |||||||||||||||||||||||||||
Percentage of total |
61 | % | 39 | % | 100 | % | ||||||||||||||||||||||||||||||
Worldwide
Proven Reserves
Million BOE
Reconciliation to Generally Accepted Accounting Principles (GAAP)
Million BOE
Reconciliation to Generally Accepted Accounting Principles (GAAP)
| US | International | Worldwide | ||||||||||||||||||||||||||||||||||
| 2001 | OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Consolidated Subsidiaries |
1,371 | 1,962 | 1,698 | 482 | 106 | 499 | 1,853 | 2,068 | 2,197 | |||||||||||||||||||||||||||
Other Interests |
— | — | — | 44 | — | 44 | 44 | — | 44 | |||||||||||||||||||||||||||
Worldwide |
1,371 | 1,962 | 1,698 | 526 | 106 | 543 | 1,897 | 2,068 | 2,241 | |||||||||||||||||||||||||||
Percentage of total |
76 | % | 24 | % | 100 | % | ||||||||||||||||||||||||||||||
2002 |
OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Consolidated Subsidiaries |
1,452 | 1,821 | 1,755 | 476 | 228 | 514 | 1,928 | 2,049 | 2,269 | |||||||||||||||||||||||||||
Other Interests |
— | — | — | 42 | — | 42 | 42 | — | 42 | |||||||||||||||||||||||||||
Worldwide |
1,452 | 1,821 | 1,755 | 518 | 228 | 556 | 1,970 | 2,049 | 2,311 | |||||||||||||||||||||||||||
Percentage of total |
76 | % | 24 | % | 100 | % | ||||||||||||||||||||||||||||||
2003 |
OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Consolidated Subsidiaries |
1,500 | 1,826 | 1,804 | 490 | 759 | 617 | 1,990 | 2,585 | 2,421 | |||||||||||||||||||||||||||
Other Interests |
— | — | — | 48 | 9 | 50 | 48 | 9 | 50 | |||||||||||||||||||||||||||
Worldwide |
1,500 | 1,826 | 1,804 | 538 | 768 | 667 | 2,038 | 2,594 | 2,471 | |||||||||||||||||||||||||||
Percentage of total |
73 | % | 27 | % | 100 | % | ||||||||||||||||||||||||||||||
2004 |
OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Consolidated Subsidiaries |
1,494 | 2,101 | 1,844 | 499 | 874 | 645 | 1,993 | 2,975 | 2,489 | |||||||||||||||||||||||||||
Other Interests |
— | — | — | 43 | — | 43 | 43 | — | 43 | |||||||||||||||||||||||||||
Worldwide |
1,494 | 2,101 | 1,844 | 542 | 874 | 688 | 2,036 | 2,975 | 2,532 | |||||||||||||||||||||||||||
Percentage of total |
73 | % | 27 | % | 100 | % | ||||||||||||||||||||||||||||||
2005 |
OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Consolidated Subsidiaries |
1,636 | 2,338 | 2,026 | 446 | 1,140 | 636 | 2,082 | 3,478 | 2,662 | |||||||||||||||||||||||||||
Other Interests |
— | — | — | 45 | — | 45 | 45 | — | 45 | |||||||||||||||||||||||||||
Worldwide |
1,636 | 2,338 | 2,026 | 491 | 1,140 | 681 | 2,127 | 3,478 | 2,707 | |||||||||||||||||||||||||||
Percentage of total |
75 | % | 25 | % | 100 | % | ||||||||||||||||||||||||||||||
Sources of Worldwide Proved Reserve Additions
Million BOE
Reconciliation to Generally Accepted Accounting Principles (GAAP)
Million BOE
Reconciliation to Generally Accepted Accounting Principles (GAAP)
| Consolidated Subsidiaries | Other Interests | Worldwide | ||||||||||||||||||||||||||||||||||
| 2001 | OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Revisions |
21 | (49 | ) | 13 | 8 | — | 8 | 29 | (49 | ) | 21 | |||||||||||||||||||||||||
Improved Recovery |
139 | 23 | 143 | — | — | — | 139 | 23 | 143 | |||||||||||||||||||||||||||
Extensions and Discoveries |
56 | 122 | 76 | — | — | — | 56 | 122 | 76 | |||||||||||||||||||||||||||
Purchases |
3 | 4 | 4 | — | — | — | 3 | 4 | 4 | |||||||||||||||||||||||||||
| 219 | 100 | 236 | 8 | — | 8 | 227 | 100 | 244 | ||||||||||||||||||||||||||||
2002 |
OIL |
GAS |
BOE |
OIL |
GAS |
BOE |
OIL |
GAS |
BOE |
|||||||||||||||||||||||||||
Revisions |
13 | (54 | ) | 4 | (1 | ) | — | (1 | ) | 12 | (54 | ) | 3 | |||||||||||||||||||||||
Improved Recovery |
112 | 151 | 137 | 5 | — | 5 | 117 | 151 | 142 | |||||||||||||||||||||||||||
Extensions and Discoveries |
40 | 60 | 50 | — | — | — | 40 | 60 | 50 | |||||||||||||||||||||||||||
Purchases |
56 | 59 | 66 | 2 | — | 2 | 58 | 59 | 68 | |||||||||||||||||||||||||||
| 221 | 216 | 257 | 6 | — | 6 | 227 | 216 | 263 | ||||||||||||||||||||||||||||
2003 |
OIL |
GAS |
BOE |
OIL |
GAS |
BOE |
OIL |
GAS |
BOE |
|||||||||||||||||||||||||||
Revisions |
(1 | ) | 44 | 6 | 6 | — | 6 | 5 | 44 | 12 | ||||||||||||||||||||||||||
Improved Recovery |
85 | 70 | 97 | 4 | 9 | 6 | 89 | 79 | 102 | |||||||||||||||||||||||||||
Extensions and Discoveries |
41 | 597 | 141 | 6 | — | 6 | 47 | 597 | 147 | |||||||||||||||||||||||||||
Purchases |
98 | 55 | 107 | — | — | — | 98 | 55 | 107 | |||||||||||||||||||||||||||
| 223 | 766 | 351 | 16 | 9 | 18 | 239 | 775 | 368 | ||||||||||||||||||||||||||||
2004 |
OIL |
GAS |
BOE |
OIL |
GAS |
BOE |
OIL |
GAS |
BOE |
|||||||||||||||||||||||||||
Revisions |
5 | 241 | 45 | 5 | (9 | ) | 3 | 10 | 232 | 48 | ||||||||||||||||||||||||||
Improved Recovery |
88 | 185 | 120 | 1 | — | 1 | 89 | 185 | 121 | |||||||||||||||||||||||||||
Extensions and Discoveries |
30 | 191 | 61 | 2 | — | 2 | 32 | 191 | 63 | |||||||||||||||||||||||||||
Purchases |
39 | 7 | 40 | (4 | ) | — | (4 | ) | 35 | 7 | 36 | |||||||||||||||||||||||||
| 162 | 624 | 266 | 4 | (9 | ) | 2 | 166 | 615 | 268 | |||||||||||||||||||||||||||
2005 |
OIL |
GAS |
BOE |
OIL |
GAS |
BOE |
OIL |
GAS |
BOE |
|||||||||||||||||||||||||||
Revisions |
(26 | ) | 30 | (21 | ) | 8 | 6 | 9 | (18 | ) | 36 | (12 | ) | |||||||||||||||||||||||
Improved Recovery |
117 | 131 | 139 | — | — | — | 117 | 131 | 139 | |||||||||||||||||||||||||||
Extensions and Discoveries |
52 | 427 | 123 | 1 | — | 1 | 53 | 427 | 124 | |||||||||||||||||||||||||||
Purchases |
112 | 164 | 139 | — | — | — | 112 | 164 | 139 | |||||||||||||||||||||||||||
| 255 | 752 | 380 | 9 | 6 | 10 | 264 | 758 | 390 | ||||||||||||||||||||||||||||
ProForma 2005 Debt / Proved Developed Reserves Ratio
Million BOE
Reconciliation to Generally Accepted Accounting Principles (GAAP)
Million BOE
Reconciliation to Generally Accepted Accounting Principles (GAAP)
| US | International | Worldwide | ||||||||||||||||||||||||||||||||||
| Proved Developed Reserves | OIL | GAS | BOE | OIL | GAS | BOE | OIL | GAS | BOE | |||||||||||||||||||||||||||
Consolidated Subsidiaries |
1,336 | 1,846 | 1,644 | 288 | 153 | 314 | 1,624 | 1,999 | 1,957 | |||||||||||||||||||||||||||
Other Interests |
— | — | — | 37 | — | 37 | 37 | — | 37 | |||||||||||||||||||||||||||
Occidental — Worldwide |
1,336 | 1,846 | 1,644 | 325 | 153 | 351 | 1,661 | 1,999 | 1,994 | |||||||||||||||||||||||||||
Vintage |
48 | 88 | 63 | 120 | 311 | 172 | 168 | 399 | 235 | |||||||||||||||||||||||||||
Total Occidental and Vintage |
1,384 | 1,934 | 1,706 | 445 | 464 | 522 | 1,829 | 2,398 | 2,229 | |||||||||||||||||||||||||||
| OXY | Vintage | Combined | ||||||||||
Debt |
$ | 3,019 | $ | 585 | $ | 3,604 | ||||||
Debt / Proved Developed Reserves Ratio |
$ | 1.62 | ||||||||||
Core Earnings
$ Millions
Reconciliation to Generally Accepted Accounting Principles (GAAP)
$ Millions
Reconciliation to Generally Accepted Accounting Principles (GAAP)
| CHEMICALS | 2001 | 2002 | 2003 | 2004 | 2005 | |||||||||||||||
Segment earnings |
$ | (437 | ) | $ | (99 | ) | $ | 223 | $ | 414 | $ | 607 | ||||||||
Reversal of Petrochemicals |
492 | 276 | — | — | — | |||||||||||||||
Write-off of plants |
— | — | — | — | 159 | |||||||||||||||
Hurricane related insurance charges |
— | — | — | — | 11 | |||||||||||||||
Others |
— | (2 | ) | 2 | 1 | (2 | ) | |||||||||||||
Core earnings |
$ | 55 | $ | 175 | $ | 225 | $ | 415 | $ | 775 | ||||||||||
| OIL & GAS | 2005 | |||
Segment earnings |
$ | 6,293 | ||
Hurricane related insurance charges |
18 | |||
Contract settlement |
26 | |||
Others |
(2 | ) | ||
Core earnings |
$ | 6,335 | ||
Chemicals Free Cash Flow
Reconciliation to Generally Accepted Accounting Principles (GAAP)
($ Millions)
Reconciliation to Generally Accepted Accounting Principles (GAAP)
($ Millions)
| 2001 | 2002 | 2003 | 2004 | 2005 | ||||||||||||||||
Occidental
Petroleum Consolidated Statement of Cash Flows |
||||||||||||||||||||
Cash flow from operating activities |
2,566 | 2,100 | 3,074 | 3,878 | 5,337 | |||||||||||||||
Cash flow from investing activities |
(651 | ) | (1,696 | ) | (2,131 | ) | (2,428 | ) | (3,161 | ) | ||||||||||
Cash flow from financing activities |
(1,814 | ) | (456 | ) | (516 | ) | (824 | ) | (1,186 | ) | ||||||||||
Change in cash |
101 | (52 | ) | 427 | 626 | 990 | ||||||||||||||
Chemicals Free Cash Flow |
||||||||||||||||||||
Core earnings |
55 | 175 | 225 | 415 | 775 | |||||||||||||||
Depreciation & amortization expense |
181 | 180 | 203 | 243 | 251 | |||||||||||||||
Working capital and other |
53 | (3 | ) | (3 | ) | 2 | 2 | |||||||||||||
Capital expenditures (excluding acquisitions) |
(109 | ) | (107 | ) | (120 | ) | (155 | ) | (173 | ) | ||||||||||
Free cash flow |
180 | 245 | 305 | 505 | 855 | |||||||||||||||
Geographical Core Earnings — After Tax
$ Millions
Reconciliation to Generally Accepted Accounting Principles (GAAP)
$ Millions
Reconciliation to Generally Accepted Accounting Principles (GAAP)
| Oil & Gas | Corporate and Other | |||||||||||||||||||||||||||||||||||
| Domestic | International | Total | Chemical | Pre-tax | Taxes | Others | Total | Total | ||||||||||||||||||||||||||||
Pretax operating profit (loss) |
3,540 | 2,753 | 6,293 | 607 | 392 | — | — | 392 | 7,292 | |||||||||||||||||||||||||||
Income taxes |
— | — | — | — | — | (2,020 | ) | — | (2,020 | ) | (2,020 | ) | ||||||||||||||||||||||||
Discontinued operations, net |
— | — | — | — | — | — | 6 | 6 | 6 | |||||||||||||||||||||||||||
Cumulative effect of changes
in accounting principles, net |
— | — | — | — | — | — | 3 | 3 | 3 | |||||||||||||||||||||||||||
Industry segments — net income (loss) |
3,540 | 2,753 | 6,293 | 607 | 392 | (2,020 | ) | 9 | (1,619 | ) | 5,281 | |||||||||||||||||||||||||
Less: significant items affecting income |
18 | 26 | 44 | 170 | (797 | ) | (725 | ) | (9 | ) | (1,531 | ) | (1,317 | ) | ||||||||||||||||||||||
Core earnings |
3,558 | 2,779 | 6,337 | 777 | (405 | ) | (2,745 | ) | — | (3,150 | ) | 3,964 | ||||||||||||||||||||||||
Pre-tax allocations |
— | 19 | 19 | — | (18 | ) | — | — | (18 | ) | 1 | |||||||||||||||||||||||||
Income tax allocations |
(982 | ) | (1,363 | ) | (2,345 | ) | (282 | ) | — | 2,627 | — | 2,627 | — | |||||||||||||||||||||||
2005 After-Tax Earnings |
2,576 | 1,435 | 4,011 | 495 | (423 | ) | (118 | ) | — | (541 | ) | 3,965 | ||||||||||||||||||||||||
| Domestic | International | Total | ||||||||||||||||||||||||||||||||||
Recap |
||||||||||||||||||||||||||||||||||||
Oil & Gas |
2,576 | 1,435 | 4,011 | |||||||||||||||||||||||||||||||||
Chemical |
495 | — | 495 | |||||||||||||||||||||||||||||||||
Corporate |
(541 | ) | — | (541 | ) | |||||||||||||||||||||||||||||||
Total |
2,530 | 1,435 | 3,965 | |||||||||||||||||||||||||||||||||
Percentage of total |
64 | % | 36 | % | 100 | % | ||||||||||||||||||||||||||||||
| Oil & Gas | Corporate and Other | |||||||||||||||||||||||||||||||||||
| Detail of significant items affecting income | Domestic | International | Total | Chemical | Pre-tax | Taxes | Others | Total | Total | |||||||||||||||||||||||||||
Contract settlement |
— | (26 | ) | (26 | ) | — | — | — | — | — | (26 | ) | ||||||||||||||||||||||||
Hurricane insurance charges |
(18 | ) | — | (18 | ) | (11 | ) | (12 | ) | 15 | — | 3 | (26 | ) | ||||||||||||||||||||||
Write-off of plants |
— | — | — | (159 | ) | — | 61 | — | 61 | (98 | ) | |||||||||||||||||||||||||
Debt purchase expense |
— | — | — | — | (42 | ) | 14 | — | (28 | ) | (28 | ) | ||||||||||||||||||||||||
Sale of Lyondell shares |
— | — | — | — | 140 | (51 | ) | — | 89 | 89 | ||||||||||||||||||||||||||
Sale of Premcor / Valero shares |
— | — | — | — | 726 | (263 | ) | — | 463 | 463 | ||||||||||||||||||||||||||
Equity investment impairment |
— | — | — | — | (15 | ) | 5 | — | (10 | ) | (10 | ) | ||||||||||||||||||||||||
Tax reserve reversal |
— | — | — | — | — | 335 | — | 335 | 335 | |||||||||||||||||||||||||||
Settlement of federal tax issue |
— | — | — | — | — | 619 | — | 619 | 619 | |||||||||||||||||||||||||||
State tax charge |
— | — | — | — | — | (10 | ) | — | (10 | ) | (10 | ) | ||||||||||||||||||||||||
Discontinued operations, net |
— | — | — | — | — | — | 6 | 6 | 6 | |||||||||||||||||||||||||||
Cumulative effect of changes
in accounting principles, net |
— | — | — | — | — | — | 3 | 3 | 3 | |||||||||||||||||||||||||||
| (18 | ) | (26 | ) | (44 | ) | (170 | ) | 797 | 725 | 9 | 1,531 | 1,317 | ||||||||||||||||||||||||
Chemical — Percent of Sales
Reconciliation to Generally Accepted Accounting Principles (GAAP)
For the Year Ended December 31, 2005
Reconciliation to Generally Accepted Accounting Principles (GAAP)
For the Year Ended December 31, 2005
| Sales | ||||||||
Oil and Gas |
10,416 | |||||||
Chemical |
4,641 | |||||||
Other |
151 | |||||||
| 15,208 | ||||||||
| $ AMT | % of Sales | |||||||
Chemicals |
||||||||
Segment income |
607 | |||||||
Less: significant items affecting earnings
|
||||||||
Hurricane insurance charges |
11 | |||||||
Write-off of plants |
159 | |||||||
Core earnings — EBIT |
777 | 16.7 | % | |||||
DD&A expense |
251 | |||||||
EBITDA |
1,028 | 22.2 | % | |||||
PRELIMINARY
Note 16 Costs and Results of Oil and Gas Producing
Activities
Capitalized costs relating to oil and gas producing activities and related accumulated
DD&A were as follows:
| Consolidated Subsidiaries | ||||||||||||||||||||||||
| Middle | Other | |||||||||||||||||||||||
| United | Latin | East/ | Eastern | Other | ||||||||||||||||||||
| In millions | States | America | North Africa | Hemisphere | Total | Interests (c) | ||||||||||||||||||
december 31, 2005 |
||||||||||||||||||||||||
Proved properties |
$ | 13,756 | $ | 1,453 | $ | 4,923 | $ | 247 | $ | 20,379 | $ | 47 | ||||||||||||
Unproved properties (a) |
475 | — | 385 | 36 | 896 | — | ||||||||||||||||||
Total property costs |
14,231 | 1,453 | 5,308 | 283 | 21,275 | 47 | ||||||||||||||||||
Support facilities |
700 | 51 | 109 | 103 | 963 | 17 | ||||||||||||||||||
Total capitalized costs (b) |
14,931 | 1,504 | 5,417 | 386 | 22,238 | 64 | ||||||||||||||||||
Accumulated depreciation, depletion
and amortization (d) |
(4,292 | ) | (927 | ) | (2,189 | ) | (259 | ) | (7,667 | ) | (26 | ) | ||||||||||||
Net capitalized costs |
$ | 10,639 | $ | 577 | $ | 3,228 | $ | 127 | $ | 14,571 | $ | 38 | ||||||||||||
december 31, 2004 |
||||||||||||||||||||||||
Proved properties |
$ | 11,480 | $ | 1,238 | $ | 4,048 | $ | 256 | $ | 17,022 | $ | 32 | ||||||||||||
Unproved properties (a) |
457 | 20 | 18 | — | 495 | — | ||||||||||||||||||
Total property costs |
11,937 | 1,258 | 4,066 | 256 | 17,517 | 32 | ||||||||||||||||||
Support facilities |
500 | 56 | 100 | 86 | 742 | 15 | ||||||||||||||||||
Total capitalized costs (b) |
12,437 | 1,314 | 4,166 | 342 | 18,259 | 47 | ||||||||||||||||||
Accumulated depreciation, depletion
and amortization (d) |
(3,553 | ) | (816 | ) | (1,829 | ) | (217 | ) | (6,415 | ) | (13 | ) | ||||||||||||
Net capitalized costs |
$ | 8,884 | $ | 498 | $ | 2,337 | $ | 125 | $ | 11,844 | $ | 34 | ||||||||||||
december 31, 2003 |
||||||||||||||||||||||||
Proved properties |
$ | 10,547 | $ | 978 | $ | 3,298 | $ | 246 | $ | 15,069 | $ | 34 | ||||||||||||
Unproved properties (a) |
867 | 10 | 20 | — | 897 | 1 | ||||||||||||||||||
Total property costs |
11,414 | 988 | 3,318 | 246 | 15,966 | 35 | ||||||||||||||||||
Support facilities |
443 | 57 | 97 | 81 | 678 | — | ||||||||||||||||||
Total capitalized costs (b) |
11,857 | 1,045 | 3,415 | 327 | 16,644 | 35 | ||||||||||||||||||
Accumulated depreciation, depletion
and amortization (d) |
(2,949 | ) | (720 | ) | (1,557 | ) | (171 | ) | (5,397 | ) | (1 | ) | ||||||||||||
Net capitalized costs |
$ | 8,908 | $ | 325 | $ | 1,858 | $ | 156 | $ | 11,247 | $ | 34 | ||||||||||||
| (a) | Primarily consists of California, Libya and Oman. | |
| (b) | Includes costs related to leases, exploration costs, lease and well equipment, pipelines and terminals, gas plant, other equipment and capitalized interest. | |
| (c) | Includes capitalized costs for equity investees in Russia and Yemen, partially offset by minority interests in a Colombian affiliate. | |
| (d) | Includes accumulated valuation allowance for unproved properties of $108 million in 2005, $28 million in 2004 and $22 million in 2003. |
PRELIMINARY
Costs incurred in oil and gas property acquisition, exploration and development
activities, whether capitalized or expensed, were as follows:
| Consolidated Subsidiaries | ||||||||||||||||||||||||
| Middle | Other | |||||||||||||||||||||||
| United | Latin | East/ | Eastern | Other | ||||||||||||||||||||
| In millions | States | America | North Africa | Hemisphere | Total | Interests(a) | ||||||||||||||||||
for the year ended
december 31, 2005 |
||||||||||||||||||||||||
Property Acquisition Costs |
||||||||||||||||||||||||
Proved Properties |
$ | 1,744 | $ | — | $ | 38 | $ | — | $ | 1,782 | $ | — | ||||||||||||
Unproved Properties |
51 | — | 343 | 4 | 398 | — | ||||||||||||||||||
Exploration costs |
39 | 69 | 47 | 102 | 257 | (2 | ) | |||||||||||||||||
Development costs (b) |
942 | 142 | 834 | 14 | 1,932 | 15 | ||||||||||||||||||
Costs Incurred (a, c) |
$ | 2,776 | $ | 211 | $ | 1,262 | $ | 120 | $ | 4,369 | $ | 13 | ||||||||||||
for the year ended
december 31, 2004 |
||||||||||||||||||||||||
Property Acquisition Costs |
||||||||||||||||||||||||
Proved Properties |
$ | 43 | $ | 94 | $ | 21 | $ | — | $ | 158 | $ | (12 | ) | |||||||||||
Unproved Properties |
4 | — | — | 4 | 8 | — | ||||||||||||||||||
Exploration costs |
31 | 47 | 28 | 52 | 158 | — | ||||||||||||||||||
Development costs (b) |
581 | 156 | 715 | 11 | 1,463 | 10 | ||||||||||||||||||
Costs Incurred (a, c) |
$ | 659 | $ | 297 | $ | 764 | $ | 67 | $ | 1,787 | $ | (2 | ) | |||||||||||
for the year ended
december 31, 2003 |
||||||||||||||||||||||||
Property Acquisition Costs |
||||||||||||||||||||||||
Proved Properties |
$ | 345 | $ | — | $ | 19 | $ | — | $ | 364 | $ | — | ||||||||||||
Unproved Properties |
4 | — | — | — | 4 | — | ||||||||||||||||||
Exploration costs |
27 | 30 | 17 | 24 | 98 | (1 | ) | |||||||||||||||||
Development costs (b) |
477 | 98 | 516 | 18 | 1,109 | 10 | ||||||||||||||||||
Costs Incurred (a, c) |
$ | 853 | $ | 128 | $ | 552 | $ | 42 | $ | 1,575 | $ | 9 | ||||||||||||
| (a) | Includes equity investees’ costs in Russia and Yemen, partially offset by minority interests in a Colombian affiliate. | |
| (b) | Includes asset retirement costs of $12 million in 2005, $25 million in 2004 and $12 million in 2003. | |
| (c) | Excludes capitalized CO2 of $59 million in 2005, $54 million in 2004 and $48 million in 2003. |
PRELIMINARY
The results of operations of Occidental’s oil and gas producing activities, which exclude
oil and gas trading activities and items such as asset dispositions, corporate overhead, interest
and royalties, were as follows:
| Consolidated Subsidiaries | ||||||||||||||||||||||||
| Middle | Other | |||||||||||||||||||||||
| United | Latin | East/ | Eastern | Other | ||||||||||||||||||||
| In millions | States | America | North Africa | Hemisphere | Total | Interests(a) | ||||||||||||||||||
for the year ended
december 31, 2005 |
||||||||||||||||||||||||
Revenues (b) |
$ | 6,000 | $ | 1,277 | $ | 2,633 | (d) | $ | 159 | $ | 10,069 | $ | 286 | |||||||||||
Production costs |
1,311 | 191 | 207 | 15 | 1,724 | 203 | ||||||||||||||||||
Exploration expenses |
132 | 77 | 56 | 72 | 337 | (2 | ) | |||||||||||||||||
Other operating expenses |
291 | 79 | 112 | 13 | 495 | 7 | ||||||||||||||||||
Depreciation, depletion and
amortization |
706 | 118 | 347 | 42 | 1,213 | 11 | ||||||||||||||||||
Pretax income |
3,560 | 812 | 1,911 | 17 | 6,300 | 67 | ||||||||||||||||||
Income tax expense(c) |
982 | 312 | 1,028 | (d) | 16 | 2,338 | 3 | |||||||||||||||||
Results of operations |
$ | 2,578 | $ | 500 | $ | 883 | $ | 1 | $ | 3,962 | $ | 64 | ||||||||||||
for the year ended
december 31, 2004 |
||||||||||||||||||||||||
Revenues (b) |
$ | 4,467 | $ | 994 | $ | 1,690 | (d) | $ | 149 | $ | 7,300 | $ | 200 | |||||||||||
Production costs |
1,016 | 168 | 175 | 16 | 1,375 | 122 | ||||||||||||||||||
Exploration expenses |
117 | 28 | 20 | 49 | 214 | 1 | ||||||||||||||||||
Other operating expenses |
226 | 73 | 77 | 16 | 392 | 6 | ||||||||||||||||||
Depreciation, depletion and
amortization |
622 | 96 | 276 | 46 | 1,040 | 12 | ||||||||||||||||||
Pretax income |
2,486 | 629 | 1,142 | 22 | 4,279 | 59 | ||||||||||||||||||
Income tax expense(c) |
689 | 270 | 525 | (d) | 14 | 1,498 | 9 | |||||||||||||||||
Results of operations |
$ | 1,797 | $ | 359 | $ | 617 | $ | 8 | $ | 2,781 | $ | 50 | ||||||||||||
for the year ended
december 31, 2003 |
||||||||||||||||||||||||
Revenues (b) |
$ | 3,637 | $ | 612 | $ | 1,341 | (d) | $ | 147 | $ | 5,737 | $ | 138 | |||||||||||
Production costs |
813 | 122 | 183 | 16 | 1,134 | 91 | ||||||||||||||||||
Exploration expenses |
79 | 20 | 17 | 23 | 139 | (1 | ) | |||||||||||||||||
Other operating expenses |
207 | 41 | 76 | 13 | 337 | 7 | ||||||||||||||||||
Depreciation, depletion and
amortization |
637 | 60 | 209 | 48 | 954 | 17 | ||||||||||||||||||
Pretax income |
1,901 | 369 | 856 | 47 | 3,173 | 24 | ||||||||||||||||||
Income tax expense(c) |
500 | 179 | 415 | (d) | 26 | 1,120 | 9 | |||||||||||||||||
Results of operations |
$ | 1,401 | $ | 190 | $ | 441 | $ | 21 | $ | 2,053 | $ | 15 | ||||||||||||
| (a) | Includes results of operations for equity investees in Russia and Yemen, partially offset by minority interests in a Colombian affiliate. | |
| (b) | Revenues from net production exclude royalty payments and other adjustments. | |
| (c) | United States federal income taxes reflect certain expenses related to oil and gas activities allocated for United States income tax purposes only, including allocated interest and corporate overhead. Foreign income taxes were included in geographic areas on the basis of operating results. | |
| (d) | Revenues and income tax expense include taxes owed by Occidental but paid by governmental entities on its behalf. |
PRELIMINARY
Results per Unit of Production (Unaudited)
| Consolidated Subsidiaries | ||||||||||||||||||||||||
| Middle | Other | |||||||||||||||||||||||
| United | Latin | East/ | Eastern | Other | ||||||||||||||||||||
| States | America | North Africa | Hemisphere | Total | Interests(a) | |||||||||||||||||||
for the year ended
december 31, 2005 |
||||||||||||||||||||||||
Revenues from net production Oil ($/bbl.) |
$ | 50.80 | $ | 44.79 | $ | 75.43 | (b) | $ | 46.75 | $ | 55.46 | $ | 34.12 | |||||||||||
Natural gas ($/Mcf) |
$ | 7.11 | $ | — | $ | 1.52 | $ | 2.44 | $ | 6.21 | $ | — | ||||||||||||
Barrel of oil equivalent
($/bbl.)(c,d) |
$ | 47.80 | $ | 44.79 | $ | 70.53 | (b) | $ | 24.04 | $ | 50.86 | $ | 34.12 | |||||||||||
Production costs |
10.44 | 6.70 | 5.54 | 2.27 | 8.71 | 19.76 | ||||||||||||||||||
Exploration expenses |
1.05 | 2.70 | 1.50 | 10.89 | 1.70 | — | ||||||||||||||||||
Other operating expenses |
2.32 | 2.77 | 3.00 | 1.97 | 2.50 | 0.75 | ||||||||||||||||||
Depreciation, depletion and
amortization |
5.62 | 4.14 | 9.30 | 6.35 | 6.13 | 1.77 | ||||||||||||||||||
Pretax income |
28.37 | 28.48 | 51.19 | 2.56 | 31.82 | 11.84 | ||||||||||||||||||
Income tax expense (e) |
7.82 | 10.94 | 27.54 | (b) | 2.42 | 11.81 | 2.70 | |||||||||||||||||
Results of operations |
$ | 20.55 | $ | 17.54 | $ | 23.65 | $ | 0.14 | $ | 20.01 | $ | 9.14 | ||||||||||||
for the year ended
december 31, 2004 |
||||||||||||||||||||||||
Revenues from net production Oil ($/bbl.) |
$ | 37.72 | $ | 32.75 | $ | 50.85 | (b) | $ | 33.13 | $ | 39.56 | $ | 24.31 | |||||||||||
Natural gas ($/Mcf) |
$ | 5.35 | $ | — | $ | 0.97 | $ | 2.25 | $ | 4.60 | $ | — | ||||||||||||
Barrel of oil equivalent
($/bbl.)(c,d) |
$ | 35.97 | $ | 32.75 | $ | 46.65 | (b) | $ | 20.63 | $ | 36.87 | $ | 24.31 | |||||||||||
Production costs |
8.18 | 5.54 | 4.83 | 2.21 | 6.95 | 12.11 | ||||||||||||||||||
Exploration expenses |
0.94 | 0.92 | 0.55 | 6.78 | 1.08 | 0.09 | ||||||||||||||||||
Other operating expenses |
1.82 | 2.41 | 2.13 | 2.21 | 1.98 | 0.83 | ||||||||||||||||||
Depreciation, depletion and
amortization |
5.01 | 3.16 | 7.62 | 6.37 | 5.25 | 1.66 | ||||||||||||||||||
Pretax income |
20.02 | 20.72 | 31.52 | 3.06 | 21.61 | 9.62 | ||||||||||||||||||
Income tax expense (e) |
5.55 | 8.90 | 14.49 | (b) | 1.94 | 7.57 | 2.77 | |||||||||||||||||
Results of operations |
$ | 14.47 | $ | 11.82 | $ | 17.03 | $ | 1.12 | $ | 14.04 | $ | 6.85 | ||||||||||||
for the year ended
december 31, 2003 |
||||||||||||||||||||||||
Revenues from net production Oil ($/bbl.) |
$ | 28.74 | $ | 26.98 | $ | 39.49 | (b) | $ | 26.68 | $ | 31.02 | $ | 16.30 | |||||||||||
Natural gas ($/Mcf) |
$ | 4.81 | $ | — | $ | — | $ | 2.04 | $ | 4.49 | $ | — | ||||||||||||
Barrel of oil equivalent
($/bbl.)(c,d) |
$ | 28.57 | $ | 26.98 | $ | 39.49 | (b) | $ | 18.52 | $ | 29.90 | $ | 16.30 | |||||||||||
Production costs |
6.39 | 5.38 | 5.39 | 2.02 | 5.91 | 8.50 | ||||||||||||||||||
Exploration expenses |
0.62 | 0.88 | 0.50 | 2.90 | 0.72 | — | ||||||||||||||||||
Other operating expenses |
1.63 | 1.81 | 2.24 | 1.64 | 1.76 | 0.79 | ||||||||||||||||||
Depreciation, depletion and
amortization |
5.00 | 2.64 | 6.15 | 6.05 | 4.97 | 1.93 | ||||||||||||||||||
Pretax income |
14.93 | 16.27 | 25.21 | 5.91 | 16.54 | 5.08 | ||||||||||||||||||
Income tax expense (e) |
3.93 | 7.89 | 12.22 | (b) | 3.27 | 5.84 | 2.19 | |||||||||||||||||
Results of operations |
$ | 11.00 | (f) | $ | 8.38 | $ | 12.99 | $ | 2.64 | $ | 10.70 | $ | 2.89 | |||||||||||
| (a) | Includes results of operations for equity investees in Russia and Yemen. | |
| (b) | Revenues and income tax expense include taxes owed by Occidental but paid by governmental entities on its behalf. | |
| (c) | Natural gas volumes have been converted to equivalent barrels based on energy content of six Mcf of gas to one barrel of oil. | |
| (d) | Revenues from net production exclude royalty payments and other adjustments. | |
| (e) | United States federal income taxes reflect certain expenses related to oil and gas activities allocated for United States income tax purposes only, including allocated interest and corporate overhead. Foreign income taxes were included in geographic areas on the basis of operating results. | |
| (f) | The denominator in the computation of results per unit of production includes 2.1 mmboe that were subject to volumetric production payments for 2003. |
PRELIMINARY
Supplemental Oil and Gas Information (Unaudited)
The following tables set forth Occidental’s net interests in quantities of proved developed
and undeveloped reserves of crude oil, condensate and natural gas and changes in such quantities.
Crude oil reserves (in millions of barrels) include condensate. The reserves are stated after
applicable royalties. These estimates include reserves in which Occidental holds an economic
interest under PSCs and other economic arrangements.
The reserve estimation process involves reservoir engineers, geoscientists, planning engineers
and financial analysts. As part of this process, all reserve volumes are estimated by a forecast
of production rates, operating costs and capital expenditures. Price differentials between
benchmark prices and prices realized and specifics of each operating agreement are then used to
estimate the net reserves. Production rate forecasts are derived by a number of methods, including
estimates from decline curve analyses, material balance calculations that take into account the
volume of substances replacing the volumes produced and associated reservoir pressure changes, or
computer simulation of the reservoir performance. Operating costs and capital costs are forecast
based on past experience combined with expectations of future cost for the specific reservoirs. In
many cases, activity-based cost models for a reservoir are utilized to project operating costs as
production rates and the number of wells for production and injection vary.
A senior corporate officer of Occidental is responsible for the internal audit and review of
its oil and gas reserves data. In addition, a Corporate Reserves Review Committee (the Reserves
Committee) has been established, consisting of senior corporate officers, to monitor and review
Occidental’s oil and gas reserves. The Reserves Committee reports to the Audit Committee of
Occidental’s Board of Directors periodically throughout the year. Occidental retained Ryder Scott
Company, L.P. (Ryder Scott), independent petroleum engineering consultants, to review its oil and
gas estimation processes for 2004 and 2005.
Ryder Scott has compared Occidental’s methods and procedures for estimating oil and gas
reserves to generally accepted industry standards and has reviewed certain data, methods and
procedures used in estimating reserve volumes, economic evaluations and reserve classifications.
Ryder Scott then reviewed the specific application of such methods and procedures for a selection
of oil and gas fields considered to be a valid representation of Occidental’s total reserves
portfolio.
Based on this review, including the data, technical processes and interpretations presented by
Occidental, Ryder Scott has concluded that the methodologies used by Occidental in preparing the
relevant estimates generally comply with current Securities and Exchange Commission standards.
Ryder Scott has not been engaged to render an opinion as to the reserves volumes presented by
Occidental.
Estimates of proven reserves are collected in a database and changes in this database are
reviewed by engineering personnel to ensure accuracy. Finally, reserve volumes and changes are
reviewed and approved by Occidental’s senior management.
PRELIMINARY
Oil Reserves
In millions of barrels
In millions of barrels
| Consolidated Subsidiaries | ||||||||||||||||||||||||
| Middle | Other | |||||||||||||||||||||||
| United | Latin | East/ | Eastern | Other | ||||||||||||||||||||
| States | America | North Africa | Hemisphere | Total | Interests(b) | |||||||||||||||||||
proved developed and undeveloped reserves |
||||||||||||||||||||||||
Balance at December 31, 2002 |
1,452 | 158 | 304 | (a) | 14 | 1,928 | 42 | |||||||||||||||||
Revisions of previous estimates |
(11 | ) | — | 10 | — | (1 | ) | 6 | ||||||||||||||||
Improved recovery |
58 | 6 | 21 | — | 85 | 4 | ||||||||||||||||||
Extensions and discoveries |
4 | 11 | 25 | 1 | 41 | 6 | ||||||||||||||||||
Purchases of proved reserves |
98 | — | — | — | 98 | — | ||||||||||||||||||
Sales of proved reserves |
(8 | ) | — | — | — | (8 | ) | — | ||||||||||||||||
Production |
(93 | ) | (23 | ) | (34 | ) | (3 | ) | (153 | ) | (10 | ) | ||||||||||||
Balance at December 31, 2003 |
1,500 | 152 | 326 | (a) | 12 | 1,990 | 48 | |||||||||||||||||
Revisions of previous estimates |
(4 | ) | (4 | ) | 16 | (3 | ) | 5 | 5 | |||||||||||||||
Improved recovery |
72 | 6 | 10 | — | 88 | 1 | ||||||||||||||||||
Extensions and discoveries |
9 | 18 | 3 | — | 30 | 2 | ||||||||||||||||||
Purchases of proved reserves |
10 | 29 | — | — | 39 | (4 | ) | |||||||||||||||||
Production |
(93 | ) | (30 | ) | (33 | ) | (3 | ) | (159 | ) | (9 | ) | ||||||||||||
Balance at December 31, 2004 |
1,494 | 171 | 322 | (a) | 6 | 1,993 | 43 | |||||||||||||||||
Revisions of previous estimates |
29 | (21 | ) | (34 | ) | — | (26 | ) | 8 | |||||||||||||||
Improved recovery |
98 | 16 | 3 | — | 117 | — | ||||||||||||||||||
Extensions and discoveries |
7 | 9 | 36 | — | 52 | 1 | ||||||||||||||||||
Purchases of proved reserves |
108 | — | 4 | — | 112 | — | ||||||||||||||||||
Sales of proved reserves |
(8 | ) | — | — | — | (8 | ) | — | ||||||||||||||||
Production |
(92 | ) | (29 | ) | (35 | ) | (2 | ) | (158 | ) | (7 | ) | ||||||||||||
Balance at December 31, 2005 |
1,636 | 146 | 296 | (a) | 4 | 2,082 | 45 | |||||||||||||||||
proved developed reserves (c) |
||||||||||||||||||||||||
December 31, 2002 |
1,183 | 85 | 228 | 12 | 1,508 | 34 | ||||||||||||||||||
December 31, 2003 |
1,262 | 116 | 227 | 11 | 1,616 | 35 | ||||||||||||||||||
December 31, 2004 |
1,260 | 151 | 208 | 6 | 1,625 | 37 | ||||||||||||||||||
December 31, 2005 |
1,336 | 110 | 174 | 4 | 1,624 | 37 | ||||||||||||||||||
| (a) | All Middle East/North Africa reserves are related to PSCs. | |
| (b) | Includes reserves applicable to equity investees in Russia and Yemen, partially offset by minority interests in a Colombian affiliate. | |
| (c) | Approximately one percent of the proved developed reserves at December 31, 2005 are nonproducing. Over half of these reserves are located in Latin America and the remainder is in the United States and Middle East/North Africa. Plans are to begin producing these reserves in 2006. |
PRELIMINARY
Gas Reserves
In billions of cubic feet
In billions of cubic feet
| Consolidated Subsidiaries | ||||||||||||||||||||||||
| Middle | Other | |||||||||||||||||||||||
| United | Latin | East/ | Eastern | Other | ||||||||||||||||||||
| States | America | North Africa | Hemisphere | Total | Interests | |||||||||||||||||||
proved developed and undeveloped reserves |
||||||||||||||||||||||||
Balance at December 31, 2002 |
1,821 | — | 106 | (a) | 122 | 2,049 | — | |||||||||||||||||
Revisions of previous estimates |
47 | — | (10 | ) | 7 | 44 | — | |||||||||||||||||
Improved recovery |
68 | — | — | 2 | 70 | 9 | ||||||||||||||||||
Extensions and discoveries |
38 | — | 558 | 1 | 597 | — | ||||||||||||||||||
Purchases of proved reserves |
55 | — | — | — | 55 | — | ||||||||||||||||||
Sales of proved reserves |
(9 | ) | — | — | — | (9 | ) | — | ||||||||||||||||
Production (b) |
(194 | ) | — | — | (27 | ) | (221 | ) | — | |||||||||||||||
Balance at December 31, 2003 |
1,826 | — | 654 | (a) | 105 | 2,585 | 9 | |||||||||||||||||
Revisions of previous estimates |
94 | — | 134 | 13 | 241 | (9 | ) | |||||||||||||||||
Improved recovery |
180 | — | — | 5 | 185 | — | ||||||||||||||||||
Extensions and discoveries |
181 | — | — | 10 | 191 | — | ||||||||||||||||||
Purchases of proved reserves |
7 | — | — | — | 7 | — | ||||||||||||||||||
Sales of proved reserves |
(1 | ) | — | — | — | (1 | ) | — | ||||||||||||||||
Production |
(186 | ) | — | (20 | ) | (27 | ) | (233 | ) | — | ||||||||||||||
Balance at December 31, 2004 |
2,101 | — | 768 | (a) | 106 | 2,975 | — | |||||||||||||||||
Revisions of previous estimates |
53 | — | (32 | ) | 9 | 30 | 6 | |||||||||||||||||
Improved recovery |
129 | — | — | 2 | 131 | — | ||||||||||||||||||
Extensions and discoveries |
96 | — | 331 | — | 427 | — | ||||||||||||||||||
Purchases of proved reserves |
164 | — | — | — | 164 | — | ||||||||||||||||||
Sales of proved reserves |
(3 | ) | — | — | — | (3 | ) | — | ||||||||||||||||
Production |
(202 | ) | — | (16 | ) | (28 | ) | (246 | ) | (6 | ) | |||||||||||||
Balance at December 31, 2005 |
2,338 | — | 1,051 | (a) | 89 | 3,478 | — | |||||||||||||||||
proved developed reserves (c) |
||||||||||||||||||||||||
December 31, 2002 |
1,630 | — | — | 110 | 1,740 | — | ||||||||||||||||||
December 31, 2003 |
1,618 | — | 91 | 94 | 1,803 | 9 | ||||||||||||||||||
December 31, 2004 |
1,644 | — | 100 | 95 | 1,839 | — | ||||||||||||||||||
December 31, 2005 |
1,846 | — | 73 | 80 | 1,999 | — | ||||||||||||||||||
(a) All Middle East/North Africa reserves are related to PSCs.
(b) Production excludes 12.7 bcf subject to volumetric production payments for 2003.
(c) Approximately two percent of the proved developed reserves at December 31, 2005 are
nonproducing. Plans are to begin producing these reserves in
2006.
PRELIMINARY
Standardized Measure, Including Year-to-Year Changes Therein, of Discounted Future Net
Cash Flows
For purposes of the following disclosures, estimates were made of quantities of proved
reserves and the periods during which they are expected to be produced. Future cash flows were
computed by applying year-end prices to Occidental’s share of estimated annual future production
from proved oil and gas reserves, net of royalties. Future development and production costs were
computed by applying year-end costs to be incurred in producing and further developing the proved
reserves. Future income tax expenses were computed by applying, generally, year-end statutory tax
rates (adjusted for permanent differences, tax credits, allowances and foreign income repatriation
considerations) to the estimated net future pre-tax cash flows. The discount was computed by
application of a 10 percent discount factor. The calculations assumed the continuation of existing
economic, operating and contractual conditions at each of December 31, 2005, 2004 and 2003.
However, such arbitrary assumptions have not necessarily proven to be the case in the past. Other
assumptions of equal validity would give rise to substantially different results.
The year-end prices used to calculate future cash flows vary by producing area and market
conditions. For the 2005, 2004 and 2003 disclosures, the West Texas Intermediate oil prices used
were $61.04 per barrel, $43.45 per barrel and $32.52 per barrel, respectively. The Henry Hub gas
prices used for the 2005, 2004 and 2003 disclosures were $10.08/MMBtu, $6.03/MMBtu and $5.79/MMBtu,
respectively.
Standardized Measure of Discounted Future Net Cash Flows
In millions
In millions
| Consolidated Subsidiaries | ||||||||||||||||||||||||
| Middle | Other | |||||||||||||||||||||||
| United | Latin | East/ | Eastern | Other | ||||||||||||||||||||
| States | America | North Africa | Hemisphere | Total | Interests(a) | |||||||||||||||||||
at december 31, 2005 |
||||||||||||||||||||||||
Future cash flows |
$ | 105,307 | $ | 6,515 | $ | 15,574 | $ | 441 | $ | 127,837 | $ | 1,695 | ||||||||||||
Future costs |
||||||||||||||||||||||||
Production costs and other operating
expenses |
(43,772 | ) | (2,063 | ) | (3,559 | ) | (112 | ) | (49,506 | ) | (1,318 | ) | ||||||||||||
Development costs (b) |
(3,207 | ) | (247 | ) | (1,096 | ) | (22 | ) | (4,572 | ) | (115 | ) | ||||||||||||
Future net cash flows before income taxes |
58,328 | 4,205 | 10,919 | 307 | 73,758 | 262 | ||||||||||||||||||
Future income tax expense |
(20,081 | ) | (1,748 | ) | — | (102 | ) | (21,931 | ) | (8 | ) | |||||||||||||
Future net cash flows |
38,246 | 2,457 | 10,919 | 205 | 51,829 | 254 | ||||||||||||||||||
Ten percent discount factor |
(21,258 | ) | (681 | ) | (4,463 | ) | (36 | ) | (26,438 | ) | (54 | ) | ||||||||||||
Standardized measure |
$ | 16,988 | $ | 1,776 | $ | 6,456 | $ | 169 | $ | 25,389 | $ | 200 | ||||||||||||
at december 31, 2004 |
||||||||||||||||||||||||
Future cash flows |
$ | 67,273 | $ | 5,161 | $ | 12,042 | $ | 438 | $ | 84,914 | $ | 959 | ||||||||||||
Future costs |
||||||||||||||||||||||||
Production costs and other operating
expenses |
(28,518 | ) | (2,334 | ) | (3,236 | ) | (147 | ) | (34,235 | ) | (633 | ) | ||||||||||||
Development costs (b) |
(2,214 | ) | (185 | ) | (1,421 | ) | (30 | ) | (3,850 | ) | (55 | ) | ||||||||||||
Future net cash flows before income taxes |
36,541 | 2,642 | 7,385 | 261 | 46,829 | 271 | ||||||||||||||||||
Future income tax expense |
(11,751 | ) | (986 | ) | — | (89 | ) | (12,826 | ) | 40 | ||||||||||||||
Future net cash flows |
24,790 | 1,656 | 7,385 | 172 | 34,003 | 311 | ||||||||||||||||||
Ten percent discount factor |
(14,104 | ) | (443 | ) | (3,389 | ) | (27 | ) | (17,963 | ) | (59 | ) | ||||||||||||
Standardized measure |
$ | 10,686 | $ | 1,213 | $ | 3,996 | $ | 145 | $ | 16,040 | $ | 252 | ||||||||||||
at december 31, 2003 |
||||||||||||||||||||||||
Future cash flows |
$ | 53,939 | $ | 3,977 | $ | 10,232 | $ | 556 | $ | 68,704 | $ | 987 | ||||||||||||
Future costs |
||||||||||||||||||||||||
Production costs and other operating
expenses |
(22,584 | ) | (1,404 | ) | (2,945 | ) | (112 | ) | (27,045 | ) | (434 | ) | ||||||||||||
Development costs (b) |
(1,931 | ) | (129 | ) | (1,382 | ) | (39 | ) | (3,481 | ) | (87 | ) | ||||||||||||
Future net cash flows before income taxes |
29,424 | 2,444 | 5,905 | 405 | 38,178 | 466 | ||||||||||||||||||
Future income tax expense |
(9,090 | ) | (1,070 | ) | (626 | ) | (169 | ) | (10,955 | ) | (141 | ) | ||||||||||||
Future net cash flows |
20,334 | 1,374 | 5,279 | 236 | 27,223 | 325 | ||||||||||||||||||
Ten percent discount factor |
(11,644 | ) | (355 | ) | (2,390 | ) | (47 | ) | (14,436 | ) | (81 | ) | ||||||||||||
Standardized measure |
$ | 8,690 | $ | 1,019 | $ | 2,889 | $ | 189 | $ | 12,787 | $ | 244 | ||||||||||||
PRELIMINARY
| (a) | Includes future net cash flows applicable to equity investees in Russia and Yemen, partially offset by minority interests in a Colombian affiliate. | |
| (b) | Includes dismantlement and abandonment costs. |
Changes in the Standardized Measure of Discounted Future
Net Cash Flows From Proved Reserve Quantities
In millions
Net Cash Flows From Proved Reserve Quantities
In millions
| For the years ended December 31, | 2005 | 2004 | 2003 | |||||||||
Beginning of year |
$ | 16,040 | $ | 12,787 | $ | 12,429 | ||||||
Sales and transfers of oil and gas produced, net of production costs and other operating
expenses |
(7,298 | ) | (5,397 | ) | (4,162 | ) | ||||||
Net change in prices received per barrel, net of production costs and other operating expenses |
14,475 | 5,868 | 1,874 | |||||||||
Extensions, discoveries and improved recovery, net of future production and development costs |
3,354 | 1,929 | 1,287 | |||||||||
Change in estimated future development costs |
(1,662 | ) | (1,058 | ) | (833 | ) | ||||||
Revisions of quantity estimates |
(1,302 | ) | 115 | 133 | ||||||||
Development costs incurred during the period |
1,911 | 1,434 | 1,078 | |||||||||
Accretion of discount |
2,041 | 1,641 | 1,545 | |||||||||
Net change in income taxes (a) |
(4,418 | ) | (712 | ) | (638 | ) | ||||||
Purchases and sales of reserves in place, net |
2,041 | 565 | 637 | |||||||||
Changes in production rates and other |
207 | (1,132 | ) | (563 | ) | |||||||
Net change |
9,349 | 3,253 | 358 | |||||||||
End of year |
$ | 25,389 | $ | 16,040 | $ | 12,787 | ||||||
| (a) | Income taxes were reduced due to the ability to credit foreign taxes in the United States. United States tax on foreign entities was zero for 2004 and 2005 and $486 million for 2003. |
Average Sales Prices and Average Production Costs of Oil and Gas
The following table sets forth, for each of the three years in the period ended December
31, 2005, Occidental’s approximate average sales prices and average production costs of oil and
gas. Production costs are the costs incurred in lifting the oil and gas to the surface and include
gathering, treating, primary processing, field storage, property taxes and insurance on proved
properties, but do not include depreciation, depletion and amortization, royalties, income taxes,
interest, general and administrative and other expenses.
| Consolidated Subsidiaries | ||||||||||||||||||||||||
| Middle | Other | |||||||||||||||||||||||
| United | Latin | East/ | Eastern | Other | ||||||||||||||||||||
| States | America(a) | North Africa | Hemisphere(a) | Total | Interests(c) | |||||||||||||||||||
2005 |
||||||||||||||||||||||||
Oil — Average sales price
($/bbl.) |
$ | 50.21 | $ | 45.43 | $ | 49.88 | (d) | $ | 46.84 | $ | 49.05 | $ | 36.16 | |||||||||||
Gas — Average sales price
($/Mcf) |
$ | 7.11 | $ | — | $ | 0.96 | $ | 2.44 | $ | 6.11 | $ | 0.16 | ||||||||||||
Average oil and gas production
cost ($/bbl.)
(b) |
$ | 10.44 | $ | 6.70 | $ | 5.54 | $ | 2.27 | $ | 8.71 | $ | 19.76 | ||||||||||||
2004 |
||||||||||||||||||||||||
Oil — Average sales price
($/bbl.) |
$ | 37.72 | $ | 33.09 | $ | 34.88 | (d) | $ | 33.13 | $ | 35.95 | $ | 23.83 | |||||||||||
Gas — Average sales price
($/Mcf) |
$ | 5.35 | $ | — | $ | 0.97 | $ | 2.25 | $ | 4.56 | $ | — | ||||||||||||
Average oil and gas production
cost ($/bbl.)
(b) |
$ | 8.18 | $ | 5.54 | $ | 4.83 | $ | 2.21 | $ | 6.95 | $ | 12.11 | ||||||||||||
2003 |
||||||||||||||||||||||||
Oil — Average sales price
($/bbl.) |
$ | 28.74 | $ | 27.21 | $ | 27.81 | (d) | $ | 26.61 | $ | 28.18 | $ | 15.95 | |||||||||||
Gas — Average sales price
($/Mcf) |
$ | 4.81 | $ | — | $ | — | $ | 2.04 | $ | 4.45 | $ | — | ||||||||||||
Average oil and gas production
cost ($/bbl.)
(b) |
$ | 6.39 | $ | 5.38 | $ | 5.39 | $ | 2.02 | $ | 5.91 | $ | 8.50 | ||||||||||||
| (a) | Sales prices include royalties with respect to certain of Occidental’s interests. | |
| (b) | Natural gas volumes have been converted to equivalent barrels based on energy content of six Mcf of gas to one barrel of oil. | |
| (c) | Includes prices and costs applicable to equity investees in Russia and Yemen. | |
| (d) | Excludes taxes owed by Occidental but paid by governmental entities on its behalf. |
EXHIBIT 99.2
For Immediate Release: February 23, 2006
Occidental to Grow Production by 5-7% Per Year Over Five Years
LOS ANGELES –- Occidental Petroleum Corporation (NYSE: OXY) today announced its 2006-2010
growth plan at a meeting with financial analysts in New York.
Occidental’s Chairman, President and Chief Executive Officer, Dr. Ray R. Irani, told the
analysts, “We have an attractive pipeline of short-term and medium-term projects with a portfolio
of high quality assets that will keep our combined oil and gas production growing at a sustainable
annual rate of at least 5 percent, and possibly 7 percent. Equally important, we are committed to
maintaining the disciplined execution of our capital program in funding these projects in order to
keep our financial returns solidly in the top quartile among our industry peers and retain our “A”
credit rating.”
Occidental emphasized that the company’s base production outlook for 2010 of at least 700,000,
and possibly 785,000, equivalent barrels of oil per day, was based on projects already in hand and
did not depend on new exploration success, new enhanced oil recovery (EOR) projects or new
acquisitions. Growth will come from the company’s Argentina assets that were recently acquired
from Vintage Petroleum, the giant Dolphin gas project in Qatar and the United Arab Emirates, the
Mukhaizna EOR project in Oman, and Libya. The company also expects to grow its California
production through a combination of the primary drilling and EOR projects at its Elk Hills
operation and by increasing production from former Vintage properties in southern California. The
company also has a large inventory of EOR projects in the Permian Basin of Texas and New Mexico
where it expects to offset moderate decline rates and keep production stable.
In addition, Occidental discussed a number of new growth opportunities in its core operating areas
that could increase production in 2010 to between 805,000 and 950,000 equivalent
barrels per day, for a potential annual growth rate at midpoint of approximately 10 percent over
five years.
Occidental also reaffirmed its plan to repurchase 10 million shares. The company also said it
expects to buy back an additional 20 million shares over the intermediate term from free cash flow
and the proceeds from Vintage asset sales.
“If oil prices remain above $50 per barrel, we will generate significant free cash flow in
excess of what is required to sustain growth of 5 to 7 percent,” said Dr. Irani. “The extra cash
will be used to increase our growth rate and to buy back shares. Our preference is to grow the
business at a faster rate, but if the new projects we are currently considering encounter timing
delays or fail to measure up to our hurdle rates, we will use the excess cash to buy back
additional shares. We will compare the potential for value creation of new projects with share
repurchases and asset acquisitions and make decisions based on what will create the greatest value
for our shareholders over the long haul.”
Dr. Irani also pledged that the company would remain focused on the fundamentals of the
business, including optimizing profits and free cash flow per equivalent barrel, keeping finding
and development costs in the top quartile, growing oil and gas reserves at a rate well in excess of
production and maintaining financial discipline. “Focusing on these fundamentals,” Dr. Irani
stressed, “should keep our returns on equity and capital employed in the top quartile — and
ultimately generate top quartile total returns for our stockholders.”
Forward-Looking Statements
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 results to differ materially
include, but are not limited to: exploration risks such as drilling of unsuccessful wells; global
commodity pricing fluctuations and supply/demand considerations
2
for oil, gas and chemicals; higher-than-expected costs; political risk; changes in tax rates;
unrealized acquisition benefits or higher than expected integration costs; and not successfully
completing (or any material delay in) any expansion, capital expenditure, acquisition, or
disposition. 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. U.S. investors are urged to consider carefully the disclosure in our 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.
-0-
| Contacts: | Lawrence P. Meriage (media) 310-443-6562 Kenneth J. Huffman (investors) 212-603-8183 |
3
EXHIBIT 99.3
For
Immediate Release: February 23, 2006
OCCIDENTAL REPLACES 191 PERCENT OF 2005 PRODUCTION
LOS ANGELES — Occidental Petroleum Corporation (NYSE: OXY) announced today that in 2005 the
company’s consolidated subsidiaries had proved reserve additions from all sources of 380 million
barrels of oil equivalent (BOE) compared to production of 199 million BOE, for a production
replacement rate of 191 percent. Occidental incurred $4.37 billion in costs for oil and gas
property acquisitions and exploration and development activities. At the end of 2005, Occidental’s
consolidated reserves-to-production ratio, assuming production remained at the 2005 level, was 13.4
years.
At year-end 2005, Occidental’s worldwide proved reserves, on a consolidated basis, totaled
2.66 billion BOE compared to 2.49 billion BOE at the end of 2004. Following the closing of the
acquisition of Vintage Petroleum in January 2006, consolidated pro-forma proved reserves, excluding
72 million BOE of Vintage reserves held for sale, were 3.01 billion BOE.
The breakdown by category of the 2005 consolidated proved reserve additions shows improved
recovery added 139 million BOE (37%), extensions and discoveries added 123 million BOE (32%),
revisions to previous estimates reduced 21 million BOE (-6%), and acquisitions added 139 million
BOE (37%).
For the three-year period, 2003-2005, Occidental’s consolidated reserve additions totaled 997
million BOE, and total production equaled 587 million BOE, for a reserve replacement rate of 170
percent. Over the three years, Occidental incurred $7.73 billion in costs for property
acquisitions and exploration and development activities.
Occidental also had investments in other interests that recorded 10 million BOE of proved
reserve additions in 2005 compared to production of 8 million BOE. These investment interests
accounted for 45 million BOE of proved reserves at year-end 2005, compared to 43 million BOE at the
end of 2004.
During 2003-2005, proved reserve additions from the other interests were 30 million BOE, and
production totaled 27 million BOE. During this three-year period, the costs incurred for these
investment interests for property acquisitions and exploration and development activities totaled
$20 million.
Forward-Looking Statements
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 results to differ materially
include, but are not limited to: exploration risks such as drilling of unsuccessful wells, global
commodity pricing fluctuations and supply/demand considerations for oil, gas and chemicals; higher
than expected costs; political risks; changes in tax rates; unrealized acquisition benefits or
higher than expected integration costs; and not successfully completing (or any material delay in)
any expansion, capital expenditure, acquisition or disposition. 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 proved reserves demonstrated by actual production or conclusive
formation tests to be economically producible under existing economic and operating conditions. We
use certain terms in this release, such as probable, possible and recoverable reserves, pro-forma
reserves and oil in place, that the SEC’s guidelines strictly prohibit us from using in filings
with the SEC. Additionally, the SEC requires oil and natural gas companies, in their filings, to
disclose non-financial statistical information about their consolidated entities separately from
such information about their equity holdings and not to show combined totals. Certain information
in this release is given on a combined basis; however, the information is disclosed separately in
this release. U.S investors are urged to consider carefully the disclosure in our Form 10-K,
available through 1-888-699-7383 or at www.oxy.com. You also can obtain a copy from the SEC
by calling 1-800-SEC-0330.
-0-
| Contacts: | Lawrence P. Meriage (media) 310-443-6562 Kenneth J. Huffman (investors) 212-603-8183 |
2
OIL AND GAS RESERVES
The following table sets forth Occidental’s net interests in quantities of proved developed and undeveloped reserves of crude oil, condensate and natural gas, and changes in such quantities. Crude oil reserves (in millions of barrels) include condensate. Natural gas volumes (in billion cubic feet) have been converted to barrels of oil equivalent (BOE) based on energy content of 6,000 cubic feet of gas to one barrel of oil.
The following table sets forth Occidental’s net interests in quantities of proved developed and undeveloped reserves of crude oil, condensate and natural gas, and changes in such quantities. Crude oil reserves (in millions of barrels) include condensate. Natural gas volumes (in billion cubic feet) have been converted to barrels of oil equivalent (BOE) based on energy content of 6,000 cubic feet of gas to one barrel of oil.
| Consolidated | Other | |||||||||||||||||||||||
| Subsidiaries | Interests | |||||||||||||||||||||||
| (million BOE) | Oil | Gas | BOE | Oil | Gas | BOE | ||||||||||||||||||
PROVED DEVELOPED AND UNDEVELOPED
RESERVES |
||||||||||||||||||||||||
Balance at December 31, 2002 |
1,928 | 2,049 | 2,269 | 42 | — | 42 | ||||||||||||||||||
Revisions of previous estimates |
(1 | ) | 44 | 6 | 6 | — | 6 | |||||||||||||||||
Improved recovery |
85 | 70 | 97 | 4 | 9 | 6 | ||||||||||||||||||
Extensions and discoveries |
41 | 597 | 141 | 6 | — | 6 | ||||||||||||||||||
Purchases of proved reserves |
98 | 55 | 107 | — | — | — | ||||||||||||||||||
Sales of proved reserves |
(8 | ) | (9 | ) | (9 | ) | — | — | — | |||||||||||||||
Production (a) |
(153 | ) | (221 | ) | (190 | ) | (10 | ) | — | (10 | ) | |||||||||||||
Balance at December 31, 2003 |
1,990 | 2,585 | 2,421 | 48 | 9 | 50 | ||||||||||||||||||
Revisions of previous estimates |
5 | 241 | 45 | 5 | (9 | ) | 3 | |||||||||||||||||
Improved recovery |
88 | 185 | 120 | 1 | — | 1 | ||||||||||||||||||
Extensions and discoveries |
30 | 191 | 61 | 2 | — | 2 | ||||||||||||||||||
Purchases of proved reserves |
39 | 7 | 40 | (4 | ) | — | (4 | ) | ||||||||||||||||
Sales of proved reserves |
— | (1 | ) | — | — | — | — | |||||||||||||||||
Production |
(159 | ) | (233 | ) | (198 | ) | (9 | ) | — | (9 | ) | |||||||||||||
Balance at December 31, 2004 |
1,993 | 2,975 | 2,489 | 43 | — | 43 | ||||||||||||||||||
Revisions of previous estimates |
(26 | ) | 30 | (21 | ) | 8 | 9 | |||||||||||||||||
Improved recovery |
117 | 131 | 139 | — | — | — | ||||||||||||||||||
Extensions and discoveries |
52 | 427 | 123 | 1 | — | 1 | ||||||||||||||||||
Purchases of proved reserves |
112 | 164 | 139 | — | — | — | ||||||||||||||||||
Sales of proved reserves |
(8 | ) | (3 | ) | (8 | ) | — | — | — | |||||||||||||||
Production |
(158 | ) | (246 | ) | (199 | ) | (7 | ) | (6 | ) | (8 | ) | ||||||||||||
Balance at December 31, 2005 |
2,082 | 3,478 | 2,662 | 45 | — | 45 | ||||||||||||||||||
PROVED DEVELOPED RESERVES |
(b | ) | ||||||||||||||||||||||
December 31, 2002 |
1,508 | 1,740 | 1,798 | 34 | — | 34 | ||||||||||||||||||
December 31, 2003 |
1,616 | 1,803 | 1,917 | 35 | 9 | 37 | ||||||||||||||||||
December 31, 2004 |
1,625 | 1,839 | 1,932 | 37 | — | 37 | ||||||||||||||||||
December 31, 2005 |
1,624 | 1,999 | 1,957 | 37 | — | 37 | ||||||||||||||||||
| (a) | Production excludes 12.7 bcf subject to volumetric production payments for 2003. | |
| (b) | Approximately 1 percent of the proved developed oil reserves and approximately 2 percent of the proved developed gas reserves at December 31, 2005 are non-producing. Plans are to begin producing these reserves in 2006. |
3
COSTS INCURRED
Occidental’s 2005, 2004 and 2003 costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, were as follows:
Occidental’s 2005, 2004 and 2003 costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, were as follows:
| Consolidated | Other | |||||||
| (in millions) | Subsidiaries | Interests (b) | ||||||
FOR THE YEAR ENDED
DECEMBER 31, 2005 |
||||||||
Property Acquisition Costs |
||||||||
Proved Properties |
$ | 1,782 | $ | — | ||||
Unproved Properties |
398 | — | ||||||
Exploration Costs |
257 | (2 | ) | |||||
Development Costs |
1,932 | 15 | ||||||
Costs Incurred (a,b) |
$ | 4,369 | $ | 13 | ||||
FOR THE YEAR ENDED
DECEMBER 31, 2004 |
||||||||
Property Acquisition Costs |
||||||||
Proved Properties |
$ | 158 | $ | (12 | ) | |||
Unproved Properties |
8 | — | ||||||
Exploration Costs |
158 | — | ||||||
Development Costs |
1,463 | 10 | ||||||
Costs Incurred (a,b) |
$ | 1,787 | $ | (2 | ) | |||
FOR THE YEAR ENDED
DECEMBER 31, 2003 |
||||||||
Property Acquisition Costs |
||||||||
Proved Properties |
$ | 364 | $ | — | ||||
Unproved Properties |
4 | — | ||||||
Exploration Costs |
98 | (1 | ) | |||||
Development Costs |
1,109 | 10 | ||||||
Costs Incurred (a,b) |
$ | 1,575 | $ | 9 | ||||
| (a) | Excludes capitalized CO2 of $59 million in 2005, $54 million in 2004 and $48 million in 2003. | |
| (b) | Includes equity investees’ costs in Russia and Yemen, partially offset by minority interests in a Colombian affiliate. |
4
PROVED RESERVE ADDITIONS
Revisions of Previous Estimates
In 2005, Occidental had net negative revisions of its proved reserves of 26 million BOE due to
changes in price. The decrease was mainly due to negative revisions of 52 million BOE from the
Dolphin Project, Qatar, Oman and Yemen where reserve amounts decrease when prices rise. These
revisions were partially offset by positive revisions at domestic operations in Elk Hills and the
Permian Basin. If oil prices increase, less oil volume is required to recover costs, and
production sharing contracts would reduce Occidental’s share of proved reserves. Oil price changes
would also tend to affect the economic lives of proved reserves from other contracts, in a manner
partially offsetting the PSC reserve volume changes.
Improved Recovery
In 2005, Occidental added reserves of 139 million BOE through improved recovery, mainly in the
Permian Basin, Elk Hills field, and Long Beach in the United States and also in Qatar. In an
effort to partially mitigate the decline in oil and gas production from the Elk Hills field,
Occidental has successfully implemented an infill drilling program. The Elk Hills operations
employ both gas flood and water flood techniques. In the Permian Basin, the increased reserves
were primarily attributable to enhanced recovery techniques, such as drilling additional
CO2 flood and water flood wells.
Extensions and Discoveries
Occidental obtains reserve additions from extensions which are dependent on successful
exploitation programs. In 2005, Occidental added reserves of 123 million BOE, with 23 million BOE
in the United States and 91 million BOE in the Middle East. In western Colorado, Occidental added
approximately 9 million BOE from the extension of gas reserves to proved locations, most of which
will require additional development capital.
Purchases of Proved Reserves
In 2005, Occidental purchased reserves of 139 million BOE, of which 135 million BOE are in the
United States. The reserve additions in the United States were from various acquisitions,
primarily in the Permian Basin, of which 71 percent were proved developed reserves. Occidental
continues to add reserves through acquisitions when properties are available at reasonable prices.
PROVED UNDEVELOPED RESERVES
In 2005, Occidental’s proved undeveloped reserves increased by 148 million BOE. This net
increase resulted from improved recovery, extensions, discoveries and purchases, primarily in the
Elk Hills field, in the Permian Basin, in western Colorado and in the Dolphin Project. The Dolphin
project was 63 percent of the 2005 increase, and the projected start-up for Dolphin production is
late 2006. These proved undeveloped additions were partially offset by reserve transfers to the
proved developed category as a result of 2005 development programs.
5