This document provides an overview of ConocoPhillips' annual energy conference in March 2009. It summarizes the major changes in the global economic and energy environment over the past year, including a recession, declining commodity prices, and reduced energy demand. The document outlines how ConocoPhillips has adjusted its operating plans and cost structure in response. It reaffirms the company's long-term strategic objectives and provides details on its exploration and production and refining activities and investments over the past decade.

1. Howard Weil
37th Annual Energy
Conference
Jim Mulva
Chairman &
Chief Executive Officer

2. CAUTIONARY STATEMENT
FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS
OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
The following presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section
21E of the Securities Exchange Act of 1934, as amended, which are intended to be covered by the safe harbors created thereby. You can identify our
forward-looking statements by words such as “anticipates,” “expects,” “intends,” “plans,” “projects,” “believes,” “estimates,” and similar expressions.
Forward-looking statements relating to ConocoPhillips’ operations are based on management’s expectations, estimates and projections about
ConocoPhillips and the petroleum industry in general on the date these presentations were given. These statements are not guarantees of future
performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Further, certain forward-looking statements are based
upon assumptions as to future events that may not prove to be accurate. Therefore, actual outcomes and results may differ materially from what is
expressed or forecast in such forward-looking statements.
Factors that could cause actual results or events to differ materially include, but are not limited to, crude oil and natural gas prices; refining and marketing
margins; potential failure to achieve, and potential delays in achieving expected reserves or production levels from existing and future oil and gas
development projects due to operating hazards, drilling risks, and the inherent uncertainties in interpreting engineering data relating to underground
accumulations of oil and gas; unsuccessful exploratory drilling activities; lack of exploration success; potential disruption or unexpected technical
difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected
cost increases or technical difficulties in constructing or modifying company manufacturing or refining facilities; unexpected difficulties in manufacturing,
transporting or refining synthetic crude oil; international monetary conditions and exchange controls; potential liability for remedial actions under existing or
future environmental regulations; potential liability resulting from pending or future litigation; general domestic and international economic and political
conditions, as well as changes in tax and other laws applicable to ConocoPhillips’ business. Other factors that could cause actual results to differ
materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting
ConocoPhillips’ business generally as set forth in ConocoPhillips’ filings with the Securities and Exchange Commission (SEC), including our Form 10-K for
the year ending December 31, 2008. ConocoPhillips is under no obligation (and expressly disclaims any such obligation) to update or alter its forward-
looking statements, whether as a result of new information, future events or otherwise.
Cautionary Note to U.S. Investors – The U.S. Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to
disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally
producible under existing economic and operating conditions. We may use certain terms in this presentation such as “oil/gas resources,” “oil in place,”
“recoverable bitumen,” “exploitable bitumen in place,” and “bitumen in place” that the SEC’s guidelines strictly prohibit us from including in filings with the
SEC. The term “reserves,” as used in this presentation, includes proved reserves from Syncrude oil sands operations in Canada which are currently
reported separately as mining operations in our SEC reports. Under amendments to the SEC rules, mining oil sands reserves will no longer be reported
separately. U.S. investors are urged to consider closely the oil and gas disclosures in our Form 10-K for the year ended December 31, 2008.
This presentation includes certain non-GAAP financial measures, as indicated. Such non-GAAP measures are intended to supplement, not substitute for,
comparable GAAP measures. Investors are urged to consider closely the GAAP reconciliation tables provided in the presentation Appendix.

3. A Year Ago – March 2008
Business Environment
Strong global economic growth
Energy demand outpacing supply
Record commodity prices
ConocoPhillips Outlook
Cash flow in excess of optimal reinvestment levels
2008 share repurchases of $10 billion
Long-term production growth ~2%
100% reserve replacement

4. The World Has Changed
Energy Commodity
Demand Price
Destruction Collapse
Worst recession
in recent history
Credit
Financial Global No indication of
Market
Crisis Downturn
Collapse a bottom
No confidence
in markets
Sharp
Equity
Declines
Adjusting to near-term environment, maintaining long-term view

5. Declining Global Economic Growth & Oil Demand
Global Real GDP Global Oil Demand
Growth in Percent Avg. Annual Growth / Decline
Percent MMbbls/day
6 3.0
Emerging
2.5 Developed
5
Net Change
2.0
4
1.5
3
1.0
2 0.5
0.0
1
-0.5
0
-1.0
Range of estimates
-1
-1.5
-2 -2.0
2004 2005 2006 2007 2008 2009F 2010F 2004 2005 2006 2007 2008 2009F 2010F
Source: Upper bound on forecast represents International Monetary Fund, January Source: International Energy Agency & Deutsche Bank for 2010.
2009. Bar represents range of other views.

6. Sharp Declines in Commodity Expectations
Forward Curve Comparison
$/bbl WTI Crude $/mmbtu Henry Hub Natural Gas
$120 $12
$100 $10
$80 $8
$60 $6
$40 $4
$20 $2
$0 $0
4/2008 4/2009 4/2010 4/2011 4/2012 4/2013 4/2008 4/2009 4/2010 4/2011 4/2012 4/2013
$/bbl USGC Crack Spread
$14
$12
$10
$8 March 1, 2008
$6 Current
$4
$2
$0
4/2008 4/2009 4/2010
Source: Platts, Goldman Sachs
Current Futures as of March 6, 2009

7. S&P Index Historical Returns
2007
2005
1994
1993 2006
1992 2004
1987 1988
1984 1986 2003
2000 1978 1979 1999
1990 1970 1972 1998
1981 1960 1971 1996
1977 1956 1968 1983
1969 1948 1965 1982
1962 1947 1964 1976
1953 1923 1959 1967 1997
1946 1916 1952 1963 1995
1940 1912 1949 1961 1991
1939 1911 1944 1951 1989
2001 1934 1906 1926 1943 1985
1973 1932 1902 1921 1942 1980
1966 1929 1899 1919 1925 1975
1957 1914 1896 1918 1924 1955
1941 1913 1895 1905 1922 1950
2009 YTD 1920 1903 1894 1904 1915 1945
2002 1917 1890 1891 1898 1909 1938
1971 1910 1887 1889 1897 1901 1936 1958 1954
2008 1930 1893 1883 1887 1892 1900 1927 1935 1933
1931 1937 1907 1884 1882 1881 1886 1880 1908 1928 1885
-50 to -40% -40 to -30% -30 to -20% -20 to -10% -10 to 0% 0 to 10% 10 to 20% 20 to 30% 30 to 40% 40 to 50% 50 to 60%
This is a severe bear market
Source: Value Square Asset Management; International Center for Finance, Yale School of Management
As of March 6, 2009

8. Impact on ConocoPhillips
Operating performance according to plan
Commodity price declines
Lower income and cash flow
Share price decline (July 2008 – present)
• ConocoPhillips -63%
• LUKOIL -67%
Non-cash LUKOIL / goodwill impairments

9. Challenging Political Environment
2006 U.S. Greenhouse Gas Emissions
Fiscal actions taken during high
Million Metric Tons CO2 Equivalent
price environment unlikely to be 8,000 Natural Gas Combustion
reversed Petroleum Combustion
7,000 Coal Combustion
Increased taxation / regulation 6,000
proposed
5,000 Proposed U.S.
oil & gas sector
Resource access remains 4,000
responsibility1
constrained 3,000
Increased likelihood of climate 2,000
change legislation 1,000
Alternative / renewable energy 0
Total U.S. U.S. U.S. Oil & Gas
projects emphasized GHG
Emissions
Combustion
Emissions
Operations
Emissions
Sources: EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006, April 2008;
World Resources Institute, US GHG Emissions Flow Chart.
1As proposed under S.2191 (Lieberman Warner)

10. Response to the Current Environment
Adjusted operating plans and
capital program
Implemented appropriate cost
reduction
Focused on maintaining balance
sheet strength and financial
flexibility
Suspended share repurchase
program
Increased engagement in public
policy debate / formulation

11. Creation of an International, Integrated Major
Scope achieved over past decade:
• >50 BBOE captured resources
• >10 BBOE proven reserves
• 2.2 MMBOED production
• 3.0 MMBPD refining capacity
• 2008 revenues of $241 billion
• Operations in nearly 40 countries
Resources, reserves, production and refining capacity include LUKOIL

12. $65 B in Strategic Transactions
1999 – 2008
Paid Transaction Achieved Metric*
Legacy Upstream position in Alaska Premise: $18/bbl
$7 B Added proved reserves of 2 BBOE and 1.1 MM net
Actual: $52/bbl
ARCO Alaska exploration acres
Legacy Upstream position in Canada Premise: $3.84/mcf
$5 B Added proved reserves of 1 BBOE and bolstered position in
Actual: $6.57/mcf
Canada SE Asia
Legacy U.S. Refining position Premise: $4.50/bbl
$7 B
Added 1.4 MMBPD refining capacity Actual: $8.40/bbl
Highly competitive international, integrated major Premise: $20/bbl
Captured $1.9 B in annual synergies Actual:$61/bbl
Legacy Upstream position in North America Premise: $7.77/mcfe
$34 B Added 18.1 TCF (3 BBOE) to proved and probable reserves
Actual: $9.24/mcfe
(70% natural gas / 30% oil)
Strategic alignment with Russian partner Premise: 1.8 Bboe
$7.5 B Creates future investment options in Russia, Caspian and
LUKOIL
Actual: 1.8 Bboe
Middle East
Asset Integrated North American heavy oil business Premise: $45/bbl
Created two JVs with access to ~6.5 B BBLS gross
Swap Actual: $86/bbl
recoverable bitumen and refining capacity of 450+ MBPD
Legacy Australasian natural gas business $1.44/mcf for 3P resource
$4.7 B Created JV with access to estimated 42 TCF gross coal bed
$0.38/mcf for total resource
methane resources1
*Actual prices are full years after transaction closing through 2008. Oil and gas prices represent WTI and Henry Hub
except Tosco, which represents GCC 3:2:1, and Origin, which represents transaction value.
1Includes 17 TCF of gross prospective resources. Price paid represents initial investment.

13. Organic Growth
1999 – 2008
$73 billion invested in organic growth
• Enabled resource capture, reserve
development, and expansion of
production base
• Increased refining capacity and
conversion capability
Significant value to
ConocoPhillips’ shareholders
• $13.5 billion returned via
dividends
• $18 billion in share repurchases
• Leading Shareholder Return
– ConocoPhillips1 12.0%
– Peer average 7.7%
– S&P 500 average (1.4)%
1Includes Phillips through Aug. 2002, ConocoPhillips from Sep. 2002 – Dec. 2008.

14. Strategic Objectives Unchanged
Market position International, integrated energy major
70 - 75% E&P
~20 - 25% R&M
Portfolio balance
5% in Midstream, Chemicals,
Alternatives and Renewables
Capital program $12.5 billion (2009)
Dividend Competitive with peers
Cash and Income per BOE Competitive with peers
ROCE Improve relative position
Debt ratio 20% - 25%
5-year reserve replacement 100+%
Production Maintain near-term / Grow long-term

15. Exploration & Production
>10 BBOE Proven Reserves >900 MBOED New Production
Oil
Converting
reserves to new
production
Gas
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
>50 BBOE Captured Resources
2009 to 2013
Five-year average reserve replacement 100+%
Oil Gas
Migrating captured resources to proven reserves and production

16. Refining & Marketing
Crude Advantage Product Yield
Investment Impacts
San Francisco
Wood River
Wilhelm shaven
Yanbu Refinery
Crude Clean Advantaged
Capacity Products Crude
2008 Future
2008 Future
Sweet Other
Medium Sour Gasoline
Heavy Sour Distillate
Improving margins through conversion capability and increased yields

17. 2009 Operational Objectives
E&P Production (ex LUKOIL) 1.8 million BOED
Reserve Replacement 100+%
Refining Crude Capacity Availability 95+%
Capital Program $12.5 billion
Cost Reduction 10+%
Improve employee and
HSE Performance
contractor TRR

18. 2009 Financial Priorities
Fund capital program
Disciplined cost management
Pay competitive dividends
Preserve balance sheet strength
and financial flexibility

19. 2009 Capital Program
2009 By Segment
2%
$ Billions 16%
19.9
16.4 82%
E&P
12.9 12.5 R&M
11.9 Other
2009 By Region
6%
9%
15%
54%
16%
2005 2006* 2007 2008 2009
Estimate
Am ericas
E&P R&M Other Asia Pacific
Europe
Middle East & Africa
Russia & Caspian
*Excludes purchase price for Burlington Resources, but includes its
capital program from purchase date of March 31, 2006 forward

20. Capex & Shareholder Distributions
2006 – 2008 Average 2009E
140%
131%
121% 35% Peer avg. 117%
116% 24%
Peer avg. 109% 105% 108%
30% 16% 104% 101%
103% 102% 101% 98%
22% 13% 19%
28%
23%
25% 35% 21%
29% 58% 11% 26%
18%
105% 107%
15% 77% 82% 80%
75% 70%
68%
62% 63% 62%
31%
BP RDS XOM CVX COP TOT BP RDS XOM CVX COP TOT
Share Repurchase / CFOA
Dividends/CFOA
Dividends / CFOA
Capex / CFOA Capital Program/CFOA
Peer Average Peer Average
Source: First Call estimates as of March 6, 2009, company filings and announcements

21. Return on Capital Employed
25%
Peer Group
20%
15%
22%
10%
17%
15% 15%
14%
5% 10%
0%
2003 2004 2005 2006 2007 2008
Delivering competitive returns
All companies Income adjusted to exclude certain non-core earnings impacts (based solely on publicly
available information). Purchase accounting basis. See Appendix for additional information.

22. Financial Performance – Income per BOE/BBL
E&P R&M
$ / BOE $ / BBL
5.00
25.00
4.00
20.00
3.00
15.00
4.50
10.00 2.00 3.85 2.40
18.44 3.59
14.79 13.76
12.19 2.39
5.00 9.97 1.00
7.08 1.26
0.00 0.00
2003 2004 2005 2006 2007 2008 2003 2004 2005 2006 2007 2008
Peer Group
Delivering competitive returns
E&P based on total BOE production. All companies Income adjusted to exclude certain non-core earnings impacts
(based solely on publicly available information). See Tables 1 and 2 of Appendix for additional information.

23. Financial Performance – Cash per BOE/BBL
E&P R&M
$ / BOE
$ / BBL
35.00 6.00
30.00
5.00
25.00
30.70 4.00
20.00 5.16
22.96 3.00
15.00 4.64
22.35 3.16
20.60 2.00 4.28
10.00
3.06
15.07
5.00 11.62 1.00 1.88
0.00 0.00
2003 2004 2005 2006 2007 2008 2003 2004 2005 2006 2007 2008
Peer Group
Delivering competitive returns
E&P based on total BOE production. All companies Income adjusted to exclude certain non-core earnings impacts (based
solely on publicly available information). Cash Contribution is calculated as Income plus DD&A.
See Tables 1 and 2 of Appendix for additional information.

24. Competitive Dividend Yield
10%
Peer Group
5%
4%
3% 2% 2% 2% 2%
0%
2003 2004 2005 2006 2007 2008

25. Positioned to Create Shareholder Value
Capital
Operating Discipline &
Shareholder
Excellence Project Financial
Value
Execution Optimization
Shareholder
Technology & Innovation Value
Portfolio of High-Quality Assets
Competitive integrated, international energy firm
Consistent long term strategy
Managing through the downturn
Funding commitments and preserving optionality
Positioned for significant value creation as economy improves

26. Appendix

27. Definitions
RESOURCE
The company uses the term “resources” in this presentation. The company has estimated its total resources based on a system developed by the
Society of Petroleum Engineers. The system classifies recoverable hydrocarbons into six categories based on their status at the time of reporting – three
deemed commercial and three deemed noncommercial. Within the commercial classification are proved reserves and two categories of unproved –
probable and possible. The noncommercial categories are also referred to as contingent resources. The resource estimate encompasses volumes
associated with all six categories.
NET RISKED RESOURCE
The estimate of potential hydrocarbon reserves discounted for subsurface chance of success, royalty, and working interest.
BITUMEN IN PLACE
Bitumen in place (gross before royalty) estimated to a zero contour for all pay horizons.
EXPLOITABLE BITUMEN IN PLACE
Applies current economic cutoffs to total in place (gross before royalty) volumes for McMurray zone only.
RECOVERABLE BITUMEN
Based on the 11.5 B BBL of exploitable bitumen in the McMurray and current technology. All bitumen estimates are provided by McDaniel & Associates
Consultants Ltd. and represent 100% interest.
OIL IN PLACE
The total quantity of trapped oil believed to exist in a geologic feature or structure, based on the analysis of well information, geological, geophysical and
petrophysical data.
SWEET CRUDE
Sulfur content less than or equal to 0.54 wt. %.
MEDIUM SOUR CRUDE
API gravity between 24 and 30 degrees and sulfur content greater than 2.0 weight percent.
HEAVY SOUR CRUDE
API gravity less than 24 degrees and sulfur content greater than 0.54 weight percent or API gravity less than 30 degrees and sulfur content greater than
2.0 weight percent.

28. Definitions (continued)
CAPITAL PROGRAM
Capital Program includes capital expenditures and investments, loans to affiliates, and obligations to fund the upstream business venture with EnCana.
CAUTIONARY NOTE TO U.S. INVESTORS
Cautionary Note to U.S. Investors – The U.S. Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to
disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally
producible under existing economic and operating conditions. We may use certain terms in this presentation such as “oil/gas resources,” “oil in place,”
“recoverable bitumen,” “exploitable bitumen in place,” and “bitumen in place” that the SEC’s guidelines strictly prohibit us from including in filings with the
SEC. The term “reserves,” as used in this presentation, includes proved reserves from Syncrude oil sands operations in Canada which are currently
reported separately as mining operations in our SEC reports. Under amendments to the SEC rules, mining oil sands reserves will no longer be reported
separately. U.S. investors are urged to consider closely the oil and gas disclosures in our Form 10-K for the year ended December 31, 2008. U.S.
investors are urged to consider closely the disclosures in the company’s 2008 Form 10-K, File No. 001-32395, available from the company at 600 N.
Dairy Ashford, Houston, Texas 77079, and the company’s web site at www.conocophillips.com/investor/sec.htm. The 2008 Form 10-K can also be
obtained from the SEC by calling 1-800-SEC-0330.

29. COP Non-GAAP Reconciliations
2003 2004 2005 2006 2007 2008
GAAP E&P Net Income - $MM 4,302 5,702 8,430 9,848 4,615 (13,479)
GAAP E&P Net Income - $ / BOE 7.33 9.97 14.79 13.78 6.73 (20.59)
non-core earnings impacts - $MM
gains and (losses) on asset dispositions 565 590
asset impairments (118) (4,752) (26,070)
tax legislation / regulatory / other 142 (4) 133 436 (71)
E&P Income - $ / BOE 7.08 9.97 14.79 13.76 12.19 18.44
E&P DD&A - $ / BOE 4.54 5.10 5.81 8.59 10.77 12.26
E&P Cash Contribution - $ / BOE 11.62 15.07 20.60 22.35 22.96 30.70
2003 2004 2005 2006 2007 2008
GAAP R&M Net Income - $MM 1,272 2,743 4,173 4,481 5,923 2,322
GAAP R&M Net Income - $ / BBL 1.14 2.39 3.52 3.53 5.00 2.09
non-core earnings impacts - $MM
gains and (losses) on asset dispositions 339 224
asset impairments (441) 112 (550)
tax legislation / regulatory / other (125) (83) 34 141 (24)
R&M Income - $ / BBL 1.26 2.39 3.59 3.85 4.50 2.40
R&M DD&A - $ / BBL 0.62 0.67 0.69 0.79 0.66 0.76
R&M Cash Contribution - $ / BBL 1.88 3.06 4.28 4.64 5.16 3.16
2003 2004 2005 2006 2007 2008
GAAP ROCE 10% 15% 23% 17% 11% -17%
non-core earnings impacts - $MM
gains and (losses) on asset dispositions 306 904 814
asset impairments (559) (4,640) (34,145)
tax legislation / regulatory / other 142 (22) (111) 167 639 (64)
Goodwill impairment equity adjustment - $MM - - - - - 25,443
ROCE 10% 15% 22% 17% 14% 15%
Table 1

30. COP Non-GAAP Reconciliations
2003 2004 2005 2006 2007 2008
GAAP E&P CFOA - $MM 7,751 9,109 12,126 16,978 16,228 20,976
GAAP E&P CFOA - $ / BOE 13.20 15.92 21.27 23.77 23.65 32.04
excluded GAAP items - $MM
non-cash working capital 356 221 31 244 393 389
non-working capital adjustments* 573 267 350 770 78 488
E&P Cash Contribution - $ / BOE 11.62 15.07 20.60 22.35 22.96 30.70
2003 2004 2005 2006 2007 2008
GAAP R&M CFOA - $MM 2,208 2,671 4,914 4,625 6,757 1,903
GAAP R&M CFOA - $ / BBL 1.99 2.32 4.14 3.65 5.70 1.71
excluded GAAP items - $MM
non-cash working capital (104) (702) 267 (1,095) 1,188 (1,294)
non-working capital adjustments* 225 (142) (427) (172) (546) (314)
R&M Cash Contribution - $ / BBL 1.88 3.06 4.28 4.64 5.16 3.16
*Includes items such as deferred tax, accretion on discounted liabilities, and undistributed equity earnings
For Peer Companies, Cash Contribution is calculated as adjusted Income plus DD&A for each full year 2003 through 2008.
For 2008, RDS and TOT DD&A data has not yet been made public by E&P and R&M segments, so 2008 Peer Company DD&A splits by
segment have been made based on year end 2007 DD&A segment weightings as applied to 2008 total company DD&A expense.
Table 2

31. Peer Capital Employed
XOM CVX BP TOT**
Equity issued for purchase* 72,795 35,690 49,091 65,055
Less: Equity of companies acquired (19,015) (14,330) (15,682) (20,458)
Excess Capital Employed under 53,780 21,360 33,409 44,597
Purchase Accounting
Peer Group: ExxonMobil, Chevron, BP, TOTAL and Royal Dutch Shell (note: no adjustments for Shell)
* Based on the number of shares issued in the transaction and the average price two days before and two days after
the deals were announced
** Shown in Euros
Table 3

32. North America Programs
Working Acreage2
Area 2008 Production
Interest1 ‘000 (MBOED)
Acres
San Juan Basin ~80% 1,300 192
Permian Basin ~87% 310 50
Lobo ~90% 450 47
Lower 48
Panhandle / Anadarko ~80% 1,500 41
Bossier ~100% 80 24
Barnett ~94% 110 16
Elmworth ~85% 990 36
Kaybob ~60% 560 23
Grande Prairie ~55% 590 24
Canada Central & Southern Plains ~70% 2,400 63
O’Chiese ~70% 640 26
Foothills ~55% 460 14
Northern Plains ~60% 820 17
Edson ~80% 500 17
1 Working interest is calculated based on average net working interest in the area at December 31, 2008
2 Acreage is total net acreage at December 31, 2008

33. Major Projects
Gross Peak
Start- Current
Region Significant Project WI% Production
Up Project Phase
MBOED
Canada Foster Creek 1D 50 30 1 Construction
Foster Creek 1E 50 30 1 Construction
Asia Pacific Bohai Phase II 49 173 Construction
2009- North Belut 40 64 Construction
2010
Su Tu Den Northeast 23 32 Construction
Middle East / North Qatargas-3 30 263 Construction
Africa Libya – Faregh 2 16 36 Construction
COP operated
1 Represents operator's forecasted plant capacity and SOR

34. Major Projects
Gross Peak
Start- Current
Region Significant Project WI% Production
Up Project Phase
MBOED
Asia Pacific Suban 3 54 33 Optimize
South Sumatra 54 24 Appraise
Kebabangan 30 1 145 Optimize
Malikai 35 47 Optimize
Gumusut-Kakap 33 129 Construction
Sunrise 30 148 Appraise
2011+ APLNG 50 2 364 3 Appraise
Panyu 25 42 Appraise
Block B – Future fields 40 20 Appraise
Petai 35 38 Appraise
Ubah 35 58 Appraise
Kamunsu East 30 60 Appraise
Su Tu Nau 23 25 Appraise
COP operated
1 Jointly operated
2 COP to operate the downstream LNG plant; Origin to operate upstream development
3 Based on 4 LNG train development

35. Major Projects
Gross Peak
Start- Current
Region Significant Project WI% Production
Up Project Phase
MBOED
Canada Christina Lake C 50 40 1 Construction
Christina Lake D 50 40 1 Define
Surmont 2 50 84 Optimize
Surmont 3-6 50 254 Optimize
Thornbury 1-2 100 92 Optimize
2011+ Clyden 1 100 46 Appraise
Saleski 100 110 Appraise
Christina Lake E & F 50 80 1 Appraise
Foster Creek 1F & 1G 50 60 1 Appraise
Parsons Lake 75 56 Optimize
Amaugliak 51 210 Appraise
COP operated
1 Represents operator's forecasted plant capacity and SOR

36. Major Projects
Gross Peak
Start- Current
Region Significant Project WI% Production
Up Project Phase
MBOED
Alaska ANS Gas 36 660 Appraise
Prudhoe WRD 1 36 22 Define
Kuparuk Viscous Oil 2 56 23 Appraise / Define
Mooses Tooth Oil & 78 30 Appraise
Fiord West
2011+ Middle East / North Algeria – El Merk (EMK) 17 60 Construction
Africa Shah Gas Project 40 TBD 3 Optimize
Libya - NC98 16 80 - 120 Appraise
Libya - North Gialo 16 80 - 120 Appraise
Libya – Further Waha 13 80 - 120 Appraise
Development
COP operated
1 Includes IPAD and Gas Partial Processing projects
2 Includes North East West Sak & Ugnu
3 To be defined

37. Major Projects
Gross Peak
Start- Current
Region Significant Project WI% Production
Up Project Phase
MBOED
North Sea Jasmine 37 85 Appraise
Ekofisk South 35 71 Optimize
Eldfisk II 35 75 Optimize
Tor Redevelopment 31 42 Appraise
Tommeliten 28 53 Appraise
Clair II 24 100 Appraise
2011+ Russia / Caspian Kashagan Phase 1 8 450 1 Construction
Kashagan Phase 2+ 8 1,050 Optimize
Kalamkas 8 77 Appraise
Aktote 8 75 Appraise
Kairan 8 65 Appraise
West Africa NLNG Train 6 supply 20 49 Construction
Uge 20 79 Appraise
COP operated
1 Represents operator's forecasted plant capacity