Exhibit 15.2

EXECUTIVE REPORT FOR PROVED RESERVES CERTIFICATION

OF THE GREATER ANGOSTURA FIELDS

IN BLOCK 2C, TRINIDAD & TOBAGO

Prepared for

CNOOC LIMITED

MARCH, 2011

The Americas	Europe, Africa, FSU	Asia Pacific
	and the Middle East
1300 Post Oak Blvd.,	Bentley Hall, Blacknest	80 Anson Road
Suite 1000	Alton, Hampshire	31-01C Fuji Xerox Towers
Houston, Texas 77056	United Kingdom GU34 4PU	Singapore 079907
Tel: +1 713 850 9955	Tel: +44 1420 525366	Tel: +65 6225 6951
Fax: +1 713 850-9966	Fax: +44 1420 525367	Fax: +65 6224 0842
email: gcah@gaffney-cline.com	email: gcauk@gaffney-cline.com	email: gcas@gaffney-cline.com

and at Argentina   -  Brazil  -  Kazakhstan  -  Russia   -   UAE   -   Australia

www.gaffney-cline.com

CNOOC Copy No. KK1658.00

YDH/jbi/L0008/2011/KK1658 8th March, 2011

Mr. Wang Qingru

Director of Reserve Management Office

CHINA NATIONAL OFFSHORE

OIL CORPORATION LIMITED

No 25 Chaoyangmenbei Dajie

Beijing 100010, P.R. China

Dear Mr. Wang,

EXECUTIVE REPORT FOR PROVED RESERVES CERTIFICATION

OF THE GREATER ANGOSTURA FIELDS

IN BLOCK 2C, TRINIDAD & TOBAGO

INTRODUCTION

In accordance with the Signed Instruction of CNOOCLimited (CNOOC) dated 17th December, 2010, Gaffney, Cline & Associates (GCA) has conducted an update of independent reserves certification for CNOOC’s annual financial report to the New York Stock Exchange (NYSE) and the Hong Kong Stock Exchange (HKEx) for the Greater Angostura Fields in Block 2C located 24 miles offshore, east coast of Trinidad & Tobago (Figure 0.1). GCA had previously undertaken the reserves certification for the year 2009.

GCA visited CNOOC’s office in Beijing on 29th October, 2010 and collected the new data and discussed the potential changes regarding well status, production adjustment, new well plan, gas facility installation and contract terms etc.

The Great Angostura Fields in the Block 2C are located in relatively shallow water depths of approximately 120 to 200 ft. Block 2C currently contains five identified gas cap oil fields or gas fields with oil rims: Kairi, the East Kairi Horst, Canteen, Aripo and Angostura (Figure 0.2), based on separate fluid contacts and initial pressures in the Angostura Oligocene reservoir. The development of the fields consists of two phases: Phase I - focusing on oil production mainly from Canteen and Kairi since 2005 with produced gas being recycled, according to the Greater Angostura Field Development Plan that was approved in 2002; Phase II – production and sale of gas from the Aripo and the Kairi Horst fields initially and from the free and associated gas from the Kari and Canteen fields late in the development when Aripo gas rates begin to decline. The gas sales are expected to commence in 2011 following the fabrication and installation of additional facilities in the fields as part of the Angostura Gas Project.

Since there is no development plan or project covering the Angostura Field, Angostura-1 and Angostura-2 (Figure 1.2), on the southern part of the Block, GCA did not estimate reserves for this area in the previous certification and will not include it in this update report.

UNITED KINGDOM                               UNITED STATES                               SINGAPORE                               AUSTRALIA                               ARGENTINA                               BRAZIL                              KAZAKHSTAN                              RUSSIA

FIGURE 0.1

BLOCK 2C LOCATION IN TRINIDAD & TOBAGO

FIGURE 0.2

BLOCK 2C BOUNDARIES AND FIVE FIELDS LOCATIONS

CNOOC 2 KK1658.00

GCA has adopted a deterministic methodology in conducting its reserves evaluation. The reported Oil Reserves are estimates based on professional judgment and are subject to future revisions, upward or downward, as a result of future operations or as additional information become available.

In carrying out the review and update, GCA has relied upon information and data provided by CNOOC, which comprised: general FDP & reserves reports; Best Case geological model and G&G interpretation presentations in PDF format; well data, etc. GCA has reviewed, to the extent possible in the time period allowed, the available data and interpretations for reasonableness and the latter adjusted where appropriate. GCA has made no changes to the previously re-interpreted four key wells (Kairi-1, Canteen-1, Aripo-1 and Angostura-1) and checked and verified the previous volumetric analysis. Well and reservoir performance were reviewed and updated employing decline curve analysis and material balance techniques.

The results presented in this report are based upon information and data made available to GCA on or before 30th October, 2010. The reserve estimates, forward production estimates and Net Present Value (“NPV”) computations as presented herein are based upon these data and represent GCA’s opinion as of 31st December, 2010.

It is GCA’s considered opinion that the estimates of oil and gas reserve volumes as of 31st December, 2010, presented in this document are, in aggregate, reasonable and were prepared in accordance with the Final Rule of Modernization of Oil and Gas Reporting (17 CFR Parts 210, 211, 229 and 249) of the United States Securities and Exchange Commission (SEC) using generally accepted petroleum engineering principles. The definitions applicable to the Proved, Probable and Possible reserve categories and sub-classifications recognized in the conduct of these examinations correspond to the above Final Rule, which was published by the SEC on 14th January, 2009 on Federal Register/Vol. 74,No. 9 and can be found on web:http://www.sec.gov/rules/final/2009/33-8995fr.pdf).

Economic models were constructed based on terms of the applicable petroleum contracts as provided by CNOOC, in order to calculate CNOOC’s net revenue interest Proved (1P), Proved plus Probable (2P) and Proved plus Probable plus Possible (3P) Reserves. As of 31st December, 2010, the PD and 1P SEC Reserves Estimates were allocated till 2018 while the 2P and 3P SEC Reserves Estimates were allocated up to the end of the license contract period.

The economic tests for the 31st December, 2010 reserve volumes incorporated oil sales pricing levels based on the average actual sales price of Calypso crude oil available of each month through to September, 2010 and this data is provided by CNOOC. The gas prices used were based on the gas pricing formulae agreed upon in the Gas Sales Agreement. Oil and gas prices were not escalated throughout the evaluation period.

Based on the Gas Project Depletion Plan prepared by the operator and provided by CNOOC, GCA assumed that there would be no more major future capital costs from the as-of-date forward.

In the previous certification, CNOOC had provided historical cost data and 2009 Budget summary. For this update, CNOOC provided its cost share through 2010 from the transaction on 27th May, 2009. GCA estimated the Fixed OPEX and Variable OPEX for the operation based on these and actual production. These costs were not escalated and kept constant throughout the evaluation period.

CNOOC’s net reserve volumes are derived by converting calculated net revenues accruing to CNOOC under the terms of the relevant petroleum contract into equivalent barrels of oil or thousands of cubic feet of natural gas utilising the average of actual 2010 sales price in the case of oil and anticipated gas contract prices in the case of gas. The CNOOC net revenue interest volumes reported in this document represent those amounts that are determined to be attributable to CNOOC’s net economic interest after the deduction of amounts attributable to third parties (government and other working interest partners).

CNOOC 3 KK1658.00

Net Present Value (“NPV”) computations were also undertaken and derived using cost and production profiles input to the economic model established. These NPVs represent future net revenue, after taxes, attributable to the interests of CNOOC, discounted over the economic life of the project at a specified discount rate to a present value as of 31st December, 2010.

This assessment was conducted within the context of GCA’s understanding of the effects of petroleum legislation, taxation and other regulations that currently pertain to the property. GCA is not aware of any potential regulation amendments which could affect the ability to recover the estimated reserves. GCA is not in a position to attest to the property title, financial interest relationships or encumbrances thereon for any part of the property reviewed.

It should be understood that any evaluation, particularly one involving future petroleum developments, may be subject to significant variations over short periods of time, as new information becomes available and perceptions change.

A glossary of abbreviations and key industry standard terms, some or all which may be used in this report, is attached as Appendix I.

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1.         RESULTS SUMMARY

1.1       In-Place Volumes

Table 1.1 presents the Gross STOIIP and GIIP (including solution gas) of the Low Casevolumetric estimates in the Depletion Plan covered areas within Block 2C and which were estimated as volumetric checks.

TABLE 1.1

BLOCK 2C – TRINIDAD & TOBAGO

LOW CASE STOIIP & GIIP VOLUMETRIC ESTIMATION

(GROSS 100% VOLUMES)

Field	Oil (MMbbl)	Gas (Bscf)
Aripo	11	301
Canteen	62	58
Kairi	146	392
E Kairi Horst	8	65
Total	227	816

1.2        Estimated Ultimate Recovery

Table 1.2 presents the Estimated Ultimate Recoveries (EURs) of the Low Case volumetricestimates within the Block 2C.

TABLE 1.2

BLOCK 2C – TRINIDAD & TOBAGO

LOW CASE ESTIMATED ULTIMATE RECOVERY ESTIMATION

(GROSS 100% VOLUMES)

Field	Oil (MMbbl)	Gas (Bscf)
Aripo	-	243
Canteen	21.3	40
Kairi	48.4	288
E Kairi Horst	-	38
Total	69.7	610
Note: Totals may not add exactly due to rounding errors.

CNOOC 5 KK1658.00

1.3        Net Proved Reserves

Table 1.3 presents the net entitlement to PDP and 1P oil and gas reserves attributable toCNOOC’s working interests (WI) as of 31st December, 2010 and which were estimated in accordance with SEC new Final Rules. The economic cut offs were applied following Economic Limit Tests (ELTs) using costs and prices which are unescalated throughout the period of calculation. According to CNOOC, the net reserves of the Block 2C are only about 0.3% of CNOOC’s total reserves.

TABLE 1.3

BLOCK 2C – TRINIDAD & TOBAGO

CNOOC NET ENTITLEMENT PROVED RESERVES AS OF 31st DECEMBER, 2010

Field	PDP		1P
	Oil (MMbbl)	Gas (Bscf)	Oil (MMbbl)	Gas (Bscf)
Aripo	-	0.0	-	17.2
Canteen	0.32	0.0	0.37	2.9
Kairi	0.67	0.0	0.78	20.1
E Kairi Horst	-	0.0	-	2.7
Total	0.99	0.0	1.15	42.9

Notes:

1.   All 1P gas reserves are PDNP (Produced Developed Non-producing). No PUD (Proved Undeveloped) reserves.

2.   Totals may not add exactly due to rounding errors.

1.4   Gross Proved Reserves

Gross Proved reserves, corresponding to the above Net Proved Reserves, are presented in Table 1.4 for reference information only. They represent a 100% interest in commercially recoverablevolumes as of 31st December, 2010, i.e. after economic cutoffs have been applied. Gross Proved reserves include volumes attributable to third parties (government and other working interest partners).

TABLE 1.4

BLOCK 2C – TRINIDAD & TOBAGO

GROSS PROVED RESERVES AS OF 31st DECEMBER, 2010

Field	PDP		1P
	Oil (MMbbl)	Gas (Bscf)	Oil (MMbbl)	Gas (Bscf)
Aripo	-	0	-	238.6
Canteen	5.43	0	5.51	40.0
Kairi	11.45	0	11.45	278.8
E Kairi Horst	-	0	-	38.1
Total	16.88	0	16.96	595.5

Notes:

1.   All 1P gas reserves are PDNP (Produced Developed Non-producing). No PUD (Proved Undeveloped) reserves.

2.   Totals may not add exactly due to rounding errors.

CNOOC 6 KK1658.00

1.5       Net Present Values

The NPVs as of 31st December, 2010 of estimated cash flows discounted at 10%, before and after taxes, attributable to CNOOC’s working interest in the projects identified above (excluding any balance sheet adjustments or financing costs), are estimated for the whole Block 2C on the basis of the FDP and the Depletion Plan in accordance with SEC Final Rule of Modernization of Oil and Gas Reporting using generally accepted petroleum engineering principles. Table 1.5 summaries the NPVs.

TABLE 1.5

BLOCK 2C – TRINIDAD & TOBAGO

CNOOC NET PRESENT VALUES AS OF 31st DECEMBER, 2010

Case	Pre-Tax NPV10 U.S.$ MM	Post-Tax NPV10 U.S.$ MM
PDP	44.7	44.7
1P	76.7	76.7

Note: Tax liability paid from government share of Profit, so the Post-Tax NPVs are the same as Pre-Tax NPVs.

The NPVs were calculated on the basis of SEC guidelines under which the economic cut-offs were applied using constant costs and prices. The oil prices used for these computations were the un-weighted 12-month arithmetic average of the first-day-of-the month price for each month within the 12-month period (January to December, 2010) except in instances where alternate prices are prescribed by contract. The gas prices used were based on the gas pricing formulae agreed upon in the Gas Sales Agreement.

1.6        Reserves Reconciliation

Tables 1.6 and 1.7 summarize the Net Entitlement PDP and 1P Reserves and the reconciliationof changes to the Net Entitlement reserves for the years ending 31st December, 2008, 2009 and 2010.

Tables 1.8 and 1.9 summarize the Gross reserves of PDP and 1P, corresponding to the aboveNet Reserves, and the reconciliation of changes to the Gross recoverable volumes for the years ending 31st December, 2008, 2009 and 2010.

CNOOC 7 KK1658.00

TABLE 1.6

BLOCK 2C – TRINIDAD & TOBAGO

CNOOC NET ENTITLEMENT PROVED RESERVES SUMMARY

	31st Dec, 2008		31st Dec, 2009		31st Dec, 2010
Reserves	Oil	Gas	Oil	Gas	Oil	Gas
Classification	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
PDP	N/A	N/A	1.97	0.0	0.99	0.0
1P	N/A	N/A	1.97	46.0	1.15	42.9

TABLE 1.7

BLOCK 2C – TRINIDAD & TOBAGO

CNOOC NET ENTITLEMENT PROVED RESERVES RECONCILIATION

	PDP		1P
Reserves Reconciliation	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
Reserves as of 31st Dec, 2008	N/A	N/A	N/A	N/A
Annual Production	N/A	N/A	N/A	N/A
Revisions	N/A	N/A	N/A	N/A
Extensions and Discoveries	N/A	N/A	N/A	N/A
Improved Recovery	N/A	N/A	N/A	N/A
Acquisition and Sales	N/A	N/A	N/A	N/A
Reserves as of 31st Dec, 2009	1.97	0.0	1.97	46.0
Annual Production	-0.26	0.0	-0.26	0.0
Revisions	-0.72	0.0	-0.56	-3.1
Extensions and Discoveries	-	-	-	-
Improved Recovery	-	-	-	-
Acquisition and Sales	-	-	-	-
Reserves as of 31st Dec, 2010	0.99	0.0	1.15	42.9
Note:  Totals may not add exactly due to rounding errors.

CNOOC 8 KK1658.00

TABLE 1.8

BLOCK 2C – TRINIDAD & TOBAGO

GROSS PROVED RESERVES SUMMARY

	31st Dec, 2008		31st Dec, 2009		31st Dec, 2010
Reserves	Oil	Gas	Oil	Gas	Oil	Gas
Classification	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
PDP	N/A	N/A	17.99	0.0	16.88	0.0
1P	N/A	N/A	17.99	574.2	16.96	595.5

TABLE 1.9

BLOCK 2C – TRINIDAD & TOBAGO

GROSS PROVED RESERVES RECONCILIATION

	PDP		1P		2P		3P
Reserves Reconciliation	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
Reserves as of 31st Dec., 2008	N/A	N/A	N/A	N/A	N/A	N/A	N/A	N/A
Annual Production	N/A	N/A	N/A	N/A	N/A	N/A	N/A	N/A
Revisions	N/A	N/A	N/A	N/A	N/A	N/A	N/A	N/A
Extensions and Discoveries	N/A	N/A	N/A	N/A	N/A	N/A	N/A	N/A
Improved Recovery	N/A	N/A	N/A	N/A	N/A	N/A	N/A	N/A
Acquisition and Sales	N/A	N/A	N/A	N/A	N/A	N/A	N/A	N/A
Reserves as of 31st Dec., 2009	17.99	0.0	17.99	574.2	22.64	725.1	26.54	862.0
Annual Production	-3.45	0.0	-3.45	0.0	-3.45	0.0	-3.45	0.0
Revisions	2.34	0.0	2.34	21.3	0.8	-8.5	-0.27	-27.9
Extensions and Discoveries	-	-	-	-	-	-	-	-
Improved Recovery	-	-	-	-	-	-	-	-
Acquisition and Sales	-	-	-	-	-	-	-	-
Reserves as of 31st Dec., 2010	16.88	0.0	16.96	595.5	19.99	716.6	22.82	834.9
Note:  Totals may not add exactly due to rounding errors.

CNOOC 9 KK1658.00

2.         PROJECTS SUMMARY

2.1       Exploration and Appraisal History

During the six-year Exploration Phase of the PSC, four exploration and three appraisal wells had been drilled, discovering significant oil and gas resources within a large faulted structure named the Greater Angostura Structure.

Angostura-1, drilled in 1999, was the discovery well for the field intersecting some 950 ft of gas within Early Oligocene sands (informally named the Angostura Sands) . The hydrocarbon potential of the structure was confirmed by the drilling of Aripo-1 (2000), Kairi-1 (2001), Canteen-1 (2001), Kairi-2 (2001/2), Angostura-2 (2002) and Canteen-2 (2002). Each of these exploration/appraisal wells intersected oil and gas in Oligocene sands.

The presence of a significant accumulation of crude oil was first indicated in July, 2001 when Kairi-1, the third exploration well on Block 2C, discovered a 350 ft column of black oil underneath a 580 ft gas cap. In November, 2001, the Canteen-1 well, north of Kairi- 1, confirmed the presence of thick oil columns in the region with the discovery of a 420-foot oil column with 300 ft of gas cap.

The Kairi and Canteen fault blocks contain the great majority of oil, with Kairi being the larger of the two. Aripo has a very thin oil rim overlain by a significant gas cap. Angostura-1 confirmed a gas on rock result with Angostura-2 confirming a result similar to Aripo.

2.2        Development Projects

As mentioned in the Introduction, the development of the fields consists of two phases: Phase I - focusing on oil production mainly from Canteen and Kairi since 2005 with produced gas being recycled, according to the Greater Angostura Field Development Plan that was approved in 2002; Phase II – production and sale of gas from the Aripo and the Kairi Horst fields initially and from the free and associated gas from the Kairi and Canteen fields late in the development when Aripo gas rates begin to decline. The gas sales are expected to commence in 2011 following the fabrication and installation of additional facilities in the fields as part of the Angostura Gas Project.

2.2.1     Phase I - Angostura Field Development Project

Development of the oil reserves (Phase I) in the Kairi and Canteen fields was sanctioned by the operator and the Joint Venture partnership in February, 2003. The initial project consisted of the design and fabrication of facilities including 3 WPPs, a CPP with living quarters and production and gas compression equipment, an onshore receiving and storage terminal, an export pipeline connecting the two, and a tanker buoy for crude oil loading (Figure 2.1). The offshore facilities that currently make up the Greater Angostura Development (Phase I) are listed as following:

CPP	Equipped with production, gas compression, gas dehydration, MCC/switch gear, power generation, utilities, and Living Quarters building, bridge connected to the K2 WPP.
Kairi-1 WPP	Connected to CPP via flowline and umbilical
Kairi-2 WPP	Bridge connected to CPP
Canteen WPP	Connected to CPP via flowline and umbilical
Aripo WPP	Monitoring wells only, no connections to CPP installed
Terminal	Onshore tank farm for receiving, handling and offloading of produced oil
CALM Buoy	Offshore Tie In Point for tanker offloading operations

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FIGURE 2.1

PRODUCTION FACILITIES LAYOUT OF

THE GREATER ANGOSTURA DEVELOPMENT PLAN (PHASE I)

(from BHP Billiton: Greater Angostura Development 2002)

The initial development project also provided for the future development of gas for sales with the fabrication and installation of the Aripo WPP, an initial pressure observation well and space for five additional wells. The original project also included funds for the drilling and completion of 31 well bores, 20 for oil production, 10 for gas injection and one for pressure monitoring and mentioned future gas development wells.

Development drilling began in October, 2003 with a jack-up rig positioned over the Kairi B platform. A second rig began work in the field in April, 2004 over the Canteen Platform. First oil production was achieved 9th January, 2005, from the Kairi B Platform. Production from the Kairi A Platform commenced on 29th January and from the Canteen Platform on 30th April the same year.

As of 31st December, 2010, a total of 36 wells, including exploration and appraisal wells, have been drilled in the Greater Angostura area (Table 2.1). The Angostura complex currently contains 15 oil wells capable of production, six gas injection wells and 2 converted gas injection wells (from oil producers in 2009), and three shut-in future gas producers. The oil producers are a mix of long horizontal wells and deviated wells. Gas is injected into the gas caps of both the Kairi and Canteen reservoirs for pressure maintenance.

At the present time, production from the Kairi, Kairi Horst and Canteen fields is coming from 15 wells drilled from three WPPs, with processing and separation facilities on a single CPP. About 52 MMbbl of oil have been produced through to the end of September, 2010. Oil is sent to an onshore storage facility on the southeast coast of Trinidad via pipeline and then exported from a Catenary Aanchor Leg Mooring (CALM) buoy with international tanker loadings. All natural gas that is not used for fuel or flared is re-injected into six wells completed in the gas caps of the reservoirs for pressure maintenance.

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TABLE 2.1

WELLS DRILLED AND CURRENT STATUS

Well Type	Angostura	Aripo	Kairi	Canteen	E Kairi Horst	Total
Exploration	1	1	1	1	0	4
Appraisal	2	0	1	1	0	4
Oil Producer	0	0	10	5	0	15
Gas Injector	0	0	4	2	0	6
Converted Gas Injector	0	0	1	0	1	2
Shut-in Gas Producer	0	3	0	0	0	3
Dry Hole	0	0	0	1	1	2
Total	3	4	17	10	2	36

2.2.2   Phase II - Angostura Gas Project

The field production has been shut in for the Gas Project facilities installation from mid-September, 2010 and is expected to be resumed in mid-December, 2010.

The Angostura Gas Project (Phase II) will include the necessary offshore gas facilities to achieve a total design capacity of 280 MMscfd through the compression system. Downstream of compression at the discharge scrubber, the facilities capacity is 340 MMscfd to accommodate future high pressure gas volume of 60 MMscfd. While gas is being developed from the Aripo field, oil production and associated gas re-injection at the Kairi and Canteen fields will continue to maximize oil recovery.

A new Gas Export Platform (GEP) will be installed for production and compression of the sales gas. The GEP equipment includes inlet separation, export compression and sales metering. From the data provided from CNOOC, the topsides facilities have been completed and added to the existing Aripo platform to facilitate gas production and measurement and a new 12” OD flowline and umbilical from the Aripo WPP to the GEP have also been added. In addition, facility modifications and tie-ins will be required on the Central Production Platform (CPP) and the existing wellhead platforms, C1, K1 and K2, to route gas production to the GEP.

The GEP has been bridge connected to the northwest corner of CPP platform. The flare system for CPP has been relocated and incorporated into the design of the GEP flare system.

Two new export pipelines will be installed from the GEP (36” to Trinidad and 12” to Tobago).

These export pipelines will be owned and installed by NGC (the National Gas Company of Trinidad & Tobago). Additional facilities will be installed on GEP on behalf of NGC and includes all required equipment, piping, instruments, and controls from the outlet flange of the custody transfer meter down to the flange located at the bottom of the riser. The operator, BHP Billiton, designed, procured and is installing those components on behalf of NGC with ownership being transferred to them at first gas per the Gas Sales Contract (GSC).

Up to the end of October, 2010, the Gas Project facilities installation has been about 90% completed, and the first gas sale is expected to start in March, 2011.

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2.3        Well Status and Plans

There are 4 existing wells, drilled and completed, that will provide gas production in the initial phase of the Angostura gas development. These wells are located in the Aripo and Kairi Horst reservoirs. Their gas production will not adversely impact oil recovery. When production from these wells can no longer fill the gas contract daily rate requirement, additional gas production will be accessed from the oil wells presently producing in the Kairi and Canteen fields.

The four existing gas wells, presently shut-in which have never produced commercially on the Aripo WPP are ARI-A01 ST, ARIA02 ST1, ARI-A03 (in the Aripo field) and the KAI-B12 (in the Kairi Horst field). They are available for gas production at project start -up. The KAI-B12 used to produce oil in late 2007 and 2008 but was frequently shut-in due to high GOR production.

In the Kairi Field currently there are 10 oil producers, 4 gas injection wells and 1 converted gas injection well from oil producer (converted in September, 2009).

In Canteen, there are 5 oil wells and 2 gas injection wells.

From January to September, 2010, average 197 MMscfd of associated gas and gas coning into the oil production have been produced and mostly re -injected. It is expected that the gas production capacity from the current oil production operations can reach or exceed 220 MMscfd. This gas stream (or a portion of it) will be re-directed to sales in the initial phase of the Kairi/Canteen gas cap blowdown without any modification of the wells to make up the rate shortfall.

All 7 gas injectors are available for gas production when gas injection is stopped.

Some high GOR oil wells may be converted to gas production if needed.

According to the Gas Project, no major well workovers or drilling are required to produce the gas associated with this development. Three to four wireline operations from the Kairi 1 and 2 platforms will be required to perforate the K2 B12 (Horst) well during the construction phase prior to first gas shifting of existing sliding sleeves for gas zones in wells K2 B9 and B10 in 2016 to 2017, and possibly including the wireline perforation of the K2 B11 well at that time if additional gas PI is needed for rate. All work can be done from wireline units on the deck of the K1 and K2 platforms.

CNOOC 13 KK1658.00

3.         ECONOMIC EVALUATION

3.1        Capital Expenditure

The Capital expenditure in the gas development project is mainly the Gas Export Platform (GEP) with process equipment connected to Aripo WHP with flow lines and umbilicals. The GEP is linked to CPP by a bridge and they will have a common upgraded flare. The PSC implies a field abandonment cost at the end of the license term. The GEP is in the process of offshore hook up and commissioning. The estimated remaining cost for the GEP project is U.S.$67 MM followed by an abandonment obligation of U.S.$32 MM at the end of the contract. The costs are common to all the three cases.

3.2        Operating Expenditure

The offshore field operating cost has three components, consisting of, fixed operating cost, variable operating cost for producing oil and variable operating cost for gas. The variable operating unit cost is same for all the three cases but the bulk of the cost is fixed cost based on the size of the operation and it is different in the three cases.

The fixed cost will include all overhead cost, fuel cost, staff pay, offshore supply vessel day rate including fuel, crew change cost, shore base, onshore overhead, administration cost and logistics cost. The fixed operating cost has been estimated as U.S.$22 Million for the 1P Case. As the production declines it has been assumed that the project will be phased down to operate within the constraints by reducing manpower or shutting down uneconomical wells or fault blocks. This will lead to a reduction in fixed operating cost by 5% annually from 2016 in every case.

The variable operating expenditure includes processing cost and chemical consumption for the producing oil and gas. The cost of processing a barrel of oil has been estimated as $2.5/bopd and the corresponding cost for producing and transporting gas has been estimated as U.S.$ 0.2/Mscfd. The cost profiles are given in the Table 3.1.

TABLE 3.1

OPERATING EXPENSES FORECASTS FOR ECONOMIC ANALYSIS

Year	PDP Case CAPEXx (U.S.$MM)	PDP Case OPEX (U.S.$MM)	1P Case CAPEX (U.S.$MM)	1P Case OPEX (U.S.$MM)
2011		33.4	67.00	55.0
2012		28.3		54.1
2013		28.8		52.3
2014		25.1		50.8
2015		25.3		49.5
2016		20.3		47.9
2017		19.8		40.2
2018		15.1		30.5
2019		15.0		24.8
2020	13.30	10.8	16.00	20.3
2021	13.30	3.2	16.00	5.41

CNOOC 14 KK1658.00

3.3   Economic Analysis

The effective date of the evaluation is 31st December, 2010.

Based on the sales price data provided to GCA, it was noted that the discount off WTI crude amounted to some U.S.$0.30/bbl, as provided by CNOOC. GCA has assumed that this discount remains constant for the life of the fields considered in this report.

The WTI price for the Reserves evaluation to SEC guidelines, as of 31st December, 2010, was U.S.$79.43/bbl. The gas price forecast, based on the GSC provided by CNOOC for the year-end 2009 Reserves Report, is shown in Table 3.2.

TABLE 3.2

CONTRACTED GAS PRICE

	U.S.$/MCF
2011	1.51
2012	1.54
2013	1.58
2014	1.61
2015	1.65
2016	1.69
2017	1.73
2018	1.77
2019	1.81
2020	1.85
2021	1.90

The cashflow outputs associated with the ELT are attached in Appendix II.

3.4 Reserves

Tables 3.3 and 3.4 summarise the Gross (100%) Reserves and Net Entitlement ProvedReserves for CNOOC’s 12.5% Net Working Interest under the PSC, as of 31st December, 2010. The Gross Oil Reserves represent the Reserves associated with total production from Block C attributable to both the Contractor and the State. Net Entitlement Reserves indicate the volumes attributable to CNOOC under the terms of the PSC, and are the volumetric equivalent of Cost Hydrocarbons plus Profit Share.

TABLE 3.3

BLOCK C GROSS (100%) PROVED RESERVES

AS OF 31st DECEMBER, 2010

Field	PDP		1P
	Oil (MMbbl)	Gas (Bscf)	Oil (MMbbl)	Gas (Bscf)
Aripo	-	0	-	238.6
Canteen	5.43	0	5.51	40.0
Kairi	11.45	0	11.45	278.8
E Kairi Horst	-	0	-	38.1
Total	16.88	0	16.96	595.5

CNOOC 15 KK1658.00

TABLE 3.4

CNOOC’S NET ENTITLEMENT PROVED RESERVES

IN BLOCK C

AS OF 31st DECEMBER, 2010

Field	PDP		1P
	Oil (MMbbl)	Gas (Bscf)	Oil (MMbbl)	Gas (Bscf)
Aripo	-	0.0	-	17.2
Canteen	0.32	0.0	0.37	2.9
Kairi	0.67	0.0	0.78	20.1
E Kairi Horst	-	0.0	-	2.7
Total	0.99	0.0	1.15	42.9

Notes:

1.   PDNP (Proved Developed Non-producing) oil reserves, 0.16 MMbbl, are in the Canteen field. All 1P gas reserves are PDNP (Produced Developed Non-producing). No PUD (Proved Undeveloped) reserves.

2.   Because of the way that the PSC works in terms of allocating costs for recovery purposes and how the cross gas:oil cost recovery mechanism works, the 1P (or PD) net entitlement oil reserves here are estimated to be slightly lower than the oil PDP reserves.

3.   Totals may not add exactly due to rounding errors.

3.5 Economic Test Results

The results of discounted pre- and post-tax NPVs, at a 10% Nominal discount rate, for CNOOC’s entitlement share in Block C, utilizing the price and cost assumptions provided previously, are summarized in Table 3.5.

TABLE 3.5

CNOOC’S PRE- AND POST-TAX NPV AT 10% DISCOUNT RATE

FOR ITS 12.5% NET WORKING INTEREST IN BLOCK C

AS OF 31st DECEMBER, 2010

Case	Pre-Tax NPV10	Post-Tax NPV10
	U.S.$ MM	U.S.$ MM
PDP	44.7	44.7
1P	76.7	76.7

Note: Tax liability paid from government share of Profit, so the Post-Tax NPVs are the same as Pre-Tax NPVs.

3.6        Summary Report for CNOOC’s Filling to the SEC

On CNOOC’s request, GCA extracted, from its economic analysis, a series of report forms, including profiles of company net production, company gross revenue, CAPEX, OPEX, and net cash flow, etc. to meet the requirements of annual report filing to the SEC.

Tables AII.1 and AII.2 representCNOOC’s PDP and 1P(PD) Net Reserves and associatedNPVs in Block 2C, respectively.

Tables AIII.1 and AIII.2 represent block level and field level production profiles for PDP, and1P(PD) respectively.

CNOOC 16 KK1658.00

4. QUALIFICATIONS

GCA is an independent international energy advisory group of 48 years’ standing, whose expertise includes petroleum reservoir evaluation and economic analysis.

The report is based on information compiled by professional staff members who are full time employees of GCA.

Staff who participated in the compilation of this report include Mr. David S. Ahye, Dr. Hu Yundong, Mr. Chew Hai Hong, Mr. Suresh Kumar, Mr. Paul McGhee and Dr. Azlan Abdul Majid. All hold degrees in geoscience, petroleum engineering or related discipline.

Mr. Ahye, in charge of the whole project, holds a B.Sc (Hons) in Chemical Engineering, is a member of the Society of Petroleum Engineers and the South East Asia Petroleum Exploration Society, and has more than 30 years industry experience worldwide. Dr. Hu holds a PhD in Petroleum Geology, is a member of the Society of Petroleum Engineers and a Registered Mineral Reserve Evaluator of the P.R. China, and has more than 25 years industry experience in China. Mr. Chew holds a BE (Hons) in Civil Engineering and an MBA, is a member of the Society of Petroleum Engineers, a fellow of Institution of Engineers Malaysia, and a professional engineer registered with the Board of Engineers Malaysia, and has more than 30 years petroleum industry experience. Mr. Kumar holds a B. Tech. in Mechanical Engineering and an MBA in International Business, is a member of the Society of Petroleum Engineers, the Institution of Engineers, India and the Operational Research Society of India, and has more than 25 years industry experience. Mr. McGhee holds a B.Sc in Chemical Engineering, is a member of the Society of Petroleum Engineers and the Association of International Petroleum Negotiators, and has more than 24 years industry experience. Dr. Majid holds a PhD and a M. Eng. in Chemical Engineering, is a member of the Society of Petroleum Engineers and the Society of Professional Well Log Analysts.

5.           BASIS OF OPINION

GCA has no reason to believe that any material facts have been withheld from it, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.

This assessment has been conducted within the context of GCA’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However, GCA is not in a position to attest to the property title, financial interest relationships or encumbrances thereon for any part of the appraised properties.

It should be understood that the evaluation of petroleum properties involves judgments in respect of a series of issues and parameters that cannot be measured precisely.

It should also be understood that any determination of resource volumes may be subject to significant variations over short periods of time, as new information becomes available and perceptions change.

The opinions expressed herein represent GCA’s judgment based upon its evaluation of these issues, the data that has been made available and the company’s professional experience in the consideration of these matters. Any evaluation may be subject to significant variation over time as new information becomes available or perceptions of market conditions change.

CNOOC 17 KK1658.00

So far, as GCA is aware, between the dates that GCA carried out its work and the date of this Certification Report, there has not been any change affecting CNOOC or the Greater Angostura Fields which would have a material effect on the contents of this report.

In preparing this report, GCA acted as independent reserve auditors, however, the GCA audit was in fact very comprehensive with independent checks on key parameters. This included a rigorous audit of the seismic interpretation, re-interpretation of four key wells, and independent estimation of the in-place volumes and reserves on the basis of geoscience, engineering and economic analysis.

GCA served as an independent energy consultancy specialising in petroleum reservoir evaluation and economic analysis. The firm’s management and employees have no direct or indirect interest holding in CNOOC. GCA’s remuneration was not in any way contingent on the contents of this report. In the preparation of this report, GCA has maintained, and continues to maintain, a strict consultant-client relationship with CNOOC. The management and employees of GCA have been, and continue to be, independent of CNOOC in the services they provide to the company including the provision of the opinions expressed in this report. Furthermore, the management and employees of GCA have no interest in any assets or share capital of CNOOC or in the promotion of this company.

Yours sincerely,

GAFFNEY, CLINE & ASSOCIATES (CONSULTANTS) PTE LTD

David S. Ahye

Regional Director, Asia Pacific

CNOOC 18 KK1658.00

 

APPENDIX I

GLOSSARY

CNOOC KK1658.00

 

List of Standard Oil Industry Terms and Abbreviations

ABEX	Abandonment Expenditure	EUR	Estimated Ultimate Recovery
ACQ	Annual Contract Quantity	FDP	Field Development Plan
oAPI	Degrees API (American	FEED	Front End Engineering and Design
	Petroleum Institute)	FPSO	Floating Production, Storage and
AAPG	American Association of		Offloading
	Petroleum Geologists	FSO	Floating Storage and Offloading
AVO	Amplitude versus Offset	ft	Foot/feet
A$	Australian Dollars	Fx	Foreign Exchange Rate
B	Billion (109)	g	gram
Bbl	Barrels	g/cc	grams per cubic centimetre
/Bbl	per barrel	gal	gallon
Bbbl	Billion Barrels	gal/d	gallons per day
BHA	Bottom Hole Assembly	G&A	General and Administrative costs
BHC	Bottom Hole Compensated	GBP	Pounds Sterling
Bscf or Bcf	Billion standard cubic feet	GDT	Gas Down to
Bscf/d or Bcf/d	Billion standard cubic feet per day	GIIP	Gas initially in place
Bm3	Billion cubic metres	Gj	Gigajoules (one billion Joules)
bcpd	Barrels of condensate per day	GOR	Gas Oil Ratio
BHP	Bottom Hole Pressure	GRV	Gross Rock Volume
blpd	Barrels of liquid per day	GTL	Gas to Liquids
bpd	Barrels per day	GWC	Gas water contact
boe	Barrels of oil equivalent @xxx mcf/bbl	HDT	Hydrocarbons Down to
boepd	Barrels of oil equivalent per day@	HSE	Health, Safety and Environment
	xxx mcf/bbl	HSFO	High Sulphur Fuel Oil
BOP	Blow Out Preventer	HUT	Hydrocarbons up to
bopd	Barrels oil per day	H2S	Hydrogen Sulphide
bwpd	Barrels of water per day	IOR	Improved Oil Recovery
BS&W	Bottom sediment and water	IPP	Independent Power Producer
BTU	British Thermal Units	IRR	Internal Rate of Return
bwpd	Barrels water per day	J	Joule (Metric measurement of
CBM	Coal Bed Methane		energy. I kilojoule = 0.9478 BTU)
CO2	Carbon Dioxide	k	Permeability
CAPEX	Capital Expenditure	KB	Kelly Bushing
CCGT	Combined Cycle Gas Turbine	KJ	Kilojoules (one Thousand Joules)
cm	centimetres	kl	Kilolitres
CMM	Coal Mine Methane	km	Kilometres
CNG	Compressed Natural Gas	km2	Square kilometres
Cp	Centipoise (a measure of viscosity)	kPa	Thousands of Pascals
CSG	Coal Seam Gas		measurement of pressure)
CT	Corporation Tax	KW	Kilowatt
DCQ	Daily Contract Quantity	KWh	Kilowatt hour
Deg C	Degrees Celsius	LKG	Lowest Known Gas
Deg F	Degrees Fahrenheit	LKH	Lowest Known Hydrocarbons
DHI	Direct Hydrocarbon Indicator	LKO	Lowest Known Oil
DST	Drill Stem Test	LNG	Liquefied Natural Gas
DWT	Dead-weight ton	LoF	Life of Field
E&A	Exploration & Appraisal	LPG	Liquefied Petroleum Gas
E&P	Exploration and Production	LTI	Lost Time Injury
EBIT	Earnings before Interest and Tax	LWD	Logging while drilling
EBITDA	Earnings before interest, tax,	m	Metres
	depreciation and amortisation	M	Thousand
EI	Entitlement Interest	m3	Cubic metres
EIA	Environmental Impact Assessment	Mcf or Mscf	Thousand standard cubic feet
EMV	Expected Monetary Value	MCM	Management Committee Meeting
EOR	Enhanced Oil Recovery	m3d	Cubic metres per day

CNOOC AI.I KK1658.00

MDT	Modular Dynamic Tester	scf or cf	Standard Cubic Feet
mD	Measure of Permeability in	scf/d or cf/d	Standard Cubic Feet per day scf/ton
	millidarcies		Standard cubic foot per ton
MD	Measured Depth	SL	Straight line (for depreciation)
Mean	Arithmetic average of a set of	so	Oil Saturation
	numbers	SPE	Society of Petroleum Engineers
Median	Middle value in a set of values	SPEE	Society of Petroleum Evaluation
MFT	Multi Formation Tester		Engineers
mg/l	milligrames per litre	ss	Subsea
MJ	Megajoules (One Million Joules)	stb	Stock tank barrel
Mm3	Thousand Cubic metres	STOIIP	Stock tank oil initially in place
Mm3d	Thousand Cubic metres per day	sw	Water Saturation
MM	Million	T	Tonnes
MMbbl	Millions of barrels	TD	Total Depth
MMBTU	Millions of British Thermal Units	Te	Tonnes equivalent
MMcf or MMscf	Million standard cubic feet	THP	Tubing Head Pressure
Mode	Value that exists most frequently in	TJ	Terajoules (1012 Joules)
	a set of values = most likely	Tscf or Tcf	Trillion standard cubic feet
Mscf/d	Thousand standard cubic feet per day	TCM	Technical Committee Meeting
MMscf/d	Million standard cubic feet per day	TOC	Total Organic Carbon
MW	Megawatt	TOP	Take or Pay
MWD	Measuring While Drilling	Tpd	Tonnes per day
MWh	Megawatt hour	TVD	True Vertical Depth
mya	Million years ago	TVDss	True Vertical Depth Subsea
NGL	Natural Gas Liquids	USGS	United States Geological Survey
N2	Nitrogen	U.S.$	United States Dollar
NPV	Net Present Value	VSP	Vertical Seismic Profiling
OBM	Oil Based Mud	WC	Water Cut
OCM	Operating Committee Meeting	WI	Working Interest
ODT	Oil down to	WPC	World Petroleum Council
OPEX	Operating Expenditure	WTI	West Texas Intermediate
OWC	Oil Water Contact	wt%	Weight percent
p.a.	Per annum	1H05	First half (6 months) of 2005
Pa	Pascals (metric measurement of		(example of date)
	pressure)	2Q06	Second quarter (3 months) of 2006
P&A	Plugged and Abandoned		(example of date)
PD	Proved Developed	2D	Two dimensional
PDP	Proved Developed Producing	3D	Three dimensional
PDNP	Proved Developed Non-producing	4D	Four dimensional
PI	Productivity Index	1P	Proved Reserves
PJ	Petajoules (1015 Joules)	2P	Proved plus Probable Reserves
PSDM	Post Stack Depth Migration	3P	Proved plus Probable plus Possible
psi	Pounds per square inch		Reserves
psia	Pounds per square inch absolute	%	Percentage
psig	Pounds per square inch gauge
PUD	Proved Undeveloped
PVT	Pressure volume temperature
P10	10% Probability
P50	50% Probability
P90	90% Probability
RF	Recovery factor
RFT	Repeat Formation Tester
RT	Rotary Table
Rw	Resistivity of water
SCAL	Special core analysis

CNOOC AI.II KK1658.00

 

APPENDIX II

CASHFLOW ANALYSIS

CNOOC KK1658.00

TABLE AII.1

BLOCK 2C – TRINIDAD & TOBAGO

CNOOC PDP NET RESERVES & NPVs AS OF 31st DECEMBER, 2010

Case: PDP

CNOOC 12.5% WI

	NPV7, US$MM =	46.7
	NPV8, US$MM =	46.0
	NPV9, US$MM =	45.3
	NPV10, US$MM =	44.7
	NPV11, US$MM =	44.1
CNOOC Net Oil Reserves, MMstb =		0.987
CNOOC Net Gas Reserves, Bscf =		0.0

									CNOOC	Pre-Tax
	WI Oil	WI Gas	Crude		Opex			Cost	Profit	Cash	Net Cash	Net Oil	Net Gas
Year	Prod'n	Prod'n	Price	Gas Price			Capex	Recovered	Share	Flow	Flow	Reserves	Reserves
					Recoverable	Unrecoverable
	MMstb	Bscf	US$/bbl	US$/Mscf	US$M	US$M	US$M	US$M	US$M	US$M	US$M	MMstb	Bscf
2011	0.563	0.000	79.13	1.51	4,179	126	0	4,179	15,777	15,651	15,651	0.252	0.000
2012	0.418	0.000	79.13	1.54	3,543	134	0	3,543	11,824	11,690	11,690	0.194	0.000
2013	0.334	0.000	79.13	1.58	3,604	142	0	3,604	9,116	8,974	8,974	0.161	0.000
2014	0.258	0.000	79.13	1.61	3,143	150	0	3,143	6,917	6,767	6,767	0.127	0.000
2015	0.194	0.000	79.13	1.65	3,164	159	0	3,164	4,888	4,728	4,728	0.102	0.000
2016	0.123	0.000	79.13	1.69	2,540	169	0	2,540	2,876	2,707	2,707	0.068	0.000
2017	0.079	0.000	79.13	1.73	2,477	179	0	2,196	1,631	1,171	1,171	0.048	0.000
2018	0.056	0.000	79.13	1.77	1,893	190	0	1,561	1,159	638	638	0.034	0.000
2019	0.042	0.000	79.13	1.81	1,879	201	0	1,163	864	-54	-54	0.000	0.000
2020	0.032	0.000	79.13	1.85	1,353	213	0	888	660	-18	-18	0.000	0.000
2021	0.009	0.000	79.13	1.90	400	75	3,325	244	181	-3,375	-3,375	0.000	0.000
TOTAL	2.11	0.00			28,173	1,739	3,325	26,223	55,893	48,878	48,878	0.99	0.0

Notes:

1.   WI oil and gas production refer to gross production x CNOOC WI.

2.   CNOOC Net Oil and Gas Reserves are CNOOC's economic entitlement (Cost Recovery + Profit Share).

3.   Tax liability paid from government share of Profit.

4.   Mid-year discounting assumed.

5.   Gas price assumed as for YE2009 audit.

6.   Unrecoverable costs assumed as for YE2009 audit.

7.   U.S.$0.30/bbl discount off WTI based on information provided by CNOOC.

8.   PD gas profile assumed same as 1P case.

9.   Totals may not add exactly due to rounding errors.

CNOOC AII.I KK1658.00

TABLE AII.2

BLOCK 2C – TRINIDAD & TOBAGO

CNOOC 1P (PD) NET RESERVES & NPVs AS OF 31st DECEMBER, 2010

Case:1P (PD)

CNOOC 12.5% WI

	NPV7, US$MM =	82.0
	NPV8, US$MM =	80.2
	NPV9, US$MM =	78.4
	NPV10, US$MM =	76.7
	NPV11, US$MM =	75.0
CNOOC Net Oil Reserves, MMstb =		1.152
CNOOC Net Gas Reserves, Bscf =		42.9

									CNOOC	Pre-Tax
	WI Oil	WI Gas	Crude		Opex			Cost	Profit	Cash	Net Cash	Net Oil	Net Gas
Year	Prod'n	Prod'n	Price	Gas Price			Capex	Recovered	Share	Flow	Flow	Reserves	Reserves
					Recoverable	Unrecoverable
	MMstb	Bscf	US$/bbl	US$/Mscf	US$M	US$M	US$M	US$M	US$M	US$M	US$M	MMstb	Bscf
2011	0.570	8.789	79.13	1.51	6,880	126	8,410	10,244	19,728	14,556	14,556	0.275	5.438
2012	0.421	10.044	79.13	1.54	6,759	134	0	8,441	17,299	18,847	18,847	0.220	5.425
2013	0.335	10.044	79.13	1.58	6,544	142	0	8,226	14,827	16,367	16,367	0.183	5.412
2014	0.259	10.044	79.13	1.61	6,354	150	0	8,036	12,678	14,210	14,210	0.152	5.400
2015	0.195	10.044	79.13	1.65	6,194	159	0	6,194	11,642	11,482	11,482	0.119	5.114
2016	0.123	10.615	79.13	1.69	5,990	169	0	5,990	9,934	9,765	9,765	0.075	5.910
2017	0.079	7.652	79.13	1.73	5,030	179	0	6,630	5,984	7,405	7,405	0.048	5.081
2018	0.056	3.582	79.13	1.77	3,818	190	0	4,618	2,800	3,411	3,411	0.034	2.655
2019	0.042	2.059	79.13	1.81	3,098	201	0	3,027	1,796	1,523	1,523	0.026	1.544
2020	0.032	1.258	79.13	1.85	2,536	213	0	2,054	1,243	548	548	0.020	0.944
2021	0.009	0.302	79.13	1.90	669	75	4,000	531	325	-3,889	-3,889	0.000	0.000
TOTAL	2.12	74.4			53,871	1,739	12,410	63,990	98,255	94,224	94,224	1.15	42.9

Notes:

1.   WI oil and gas production refer to gross production x CNOOC WI.

2.   CNOOC Net Oil and Gas Reserves are CNOOC's economic entitlement (Cost Recovery + Profit Share).

3.   Tax liability paid from government share of Profit.

4.   Mid-year discounting assumed.

5.   Gas price assumed as for YE2009 audit.

6.   Unrecoverable costs assumed as for YE2009 audit.

7.   U.S.$0.30/bbl discount off WTI based on information provided by CNOOC.

8.   There is no PUD (proved Undeveloped) reserves, PD (Proved Developed) reserves are the same as 1P reserves.

9.   Totals may not add exactly due to rounding errors.

CNOOC AII.II KK1658.00

 

APPENDIX III

PRODUCTION PROFILES

CNOOC KK1658.00

 

TABLE AIII.1

BLOCK 2C – TRINIDAD & TOBAGO

PDP PRODUCTION PROFILES

	Aripo				Canteen				Kairi				E Kairi Horst				Total
	Gross		WI		Gross		WI		Gross		WI		Gross		WI		Gross		WI
Year	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas
	Prod	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n
	Mstb	Bscf	MMstb	Bscf	Mstb	Bscf	Mstb	Bscf	Mstb	Bscf	Mstb	Bscf	Mstb	Bscf	MMstb	Bscf	Mstb	Bscf	Mstb	Bscf
2011	-	-	-	-	1306	0.0	163.3	0.0	3201	0.0	400.1	0.0	-	-	-	-	4507	0.0	563.4	0.0
2012	-	-	-	-	1014	0.0	126.8	0.0	2332	0.0	291.5	0.0	-	-	-	-	3347	0.0	418.3	0.0
2013	-	-	-	-	785	0.0	98.1	0.0	1884	0.0	235.5	0.0	-	-	-	-	2668	0.0	333.5	0.0
2014	-	-	-	-	610	0.0	76.2	0.0	1456	0.0	182.0	0.0	-	-	-	-	2066	0.0	258.3	0.0
2015	-	-	-	-	475	0.0	59.3	0.0	1081	0.0	135.1	0.0	-	-	-	-	1555	0.0	194.4	0.0
2016	-	-	-	-	371	0.0	46.4	0.0	612	0.0	76.5	0.0	-	-	-	-	984	0.0	122.9	0.0
2017	-	-	-	-	289	0.0	36.1	0.0	345	0.0	43.2	0.0	-	-	-	-	634	0.0	79.3	0.0
2018	-	-	-	-	226	0.0	28.2	0.0	225	0.0	28.1	0.0	-	-	-	-	451	0.0	56.4	0.0
2019	-	-	-	-	177	0.0	22.1	0.0	159	0.0	19.9	0.0	-	-	-	-	336	0.0	42.0	0.0
2020	-	-	-	-	139	0.0	17.3	0.0	118	0.0	14.7	0.0	-	-	-	-	257	0.0	32.1	0.0
2021	-	-	-	-	39	0.0	4.8	0.0	32	0.0	4.0	0.0	-	-	-	-	70	0.0	8.8	0.0
Total	-	-	-	-	5429	0	678.7	0.0	11446	0	1430.7	0	-	-	-	-	16875	0	2109.4	0

Notes:

1. Gross production volumes represent a 100% interest in commercially recoverable volumes as of 31st December, 2010, i.e. after economic cutoffs have been applied. Gross volumes include volumes attributable to third parties (government and other working interest partners).

2. WI production volumes represent CNOOC’s 12.5% working interests in commercially recoverable volumes as of 31st December, 2010, i.e. after economic cutoffs have been applied.This volumes still includes volumes attributable to government.

3.   Totals may not add exactly due to rounding errors.

CNOOC AIII.I KK1658.00

 

TABLE AIII.2

BLOCK 2C – TRINIDAD & TOBAGO

1P(PD) PRODUCTION PROFILES

	Aripo				Canteen				Kairi				E Kairi Horst				Total
	Gross		WI		Gross		WI		Gross		WI		Gross		WI		Gross		WI
Year	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas
	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n	Prod'n
	Mstb	Bscf	MMstb	Bscf	Mstb	Bscf	Mstb	Bscf	Mstb	Bscf	Mstb	Bscf	Mstb	Bscf	Mstb	Bscf	Mstb	Bscf	Mstb	Bscf
2011	-	54.3	-	6.8	1356	0.0	169.5	0.0	3201	0.0	400.1	0.0	-	16.0	-	2.0	4557	70.3	569.7	8.8
2012	-	59.7	-	7.5	1035	0.0	129.4	0.0	2332	4.7	291.5	0.6	-	16.0	-	2.0	3367	80.4	420.9	10.0
2013	-	42.6	-	5.3	793	0.0	99.1	0.0	1884	33.0	235.5	4.1	-	4.8	-	0.6	2677	80.4	334.6	10.0
2014	-	28.6	-	3.6	613	0.0	76.7	0.0	1456	50.7	182.0	6.3	-	1.1	-	0.1	2069	80.4	258.7	10.0
2015	-	19.1	-	2.4	476	0.0	59.5	0.0	1081	61.0	135.1	7.6	-	0.2	-	0.0	1557	80.4	194.6	10.0
2016	-	12.8	-	1.6	372	17.5	46.5	2.2	612	54.6	76.5	6.8	-	0.1	-	0.0	984	84.9	123.0	10.6
2017	-	8.6	-	1.1	289	19.3	36.1	2.4	345	33.3	43.2	4.2	-	0.0	-	0.0	635	61.2	79.3	7.7
2018	-	5.8	-	0.7	226	2.7	28.2	0.3	225	20.2	28.1	2.5	-	0.0	-	0.0	451	28.7	56.4	3.6
2019	-	3.9	-	0.5	177	0.4	22.1	0.0	159	12.2	19.9	1.5	-	0.0	-	0.0	336	16.5	42.0	2.1
2020	-	2.6	-	0.3	139	0.0	17.3	0.0	118	7.4	14.7	0.9	-	0.0	-	0.0	257	10.1	32.1	1.3
2021	-	0.7	-	0.1	39	0.0	4.8	0.0	32	1.8	4.0	0.2	-	0.0	-	0.0	70	2.4	8.8	0.3
Total	0	238.6	0	29.8	5514	40.0	689.3	5.0	11446	278.8	1430.7	34.9	0	38.1	0	4.8	16960	595.5	2120.0	74.4

Notes:

1. Gross production volumes represent a 100% interest in commercially recoverable volumes as of 31st December, 2010, i.e. after economic cutoffs have been applied. Gross volumes include volumes attributable to third parties (government and other working interest partners).

2. WI production volumes represent CNOOC’s 12.5% working interests in commercially recoverable volumes as of 31st December, 2010, i.e. after economic cutoffs have been applied. This volumes still includes volumes attributable to government.

3.   There is no PUD (proved Undeveloped) reserves, PD (Proved Developed) reserves are the same as 1P reserves.

4.   Totals may not add exactly due to rounding errors.

CNOOC AIII.II KK1658.00