Exhibit 15.2

EXECUTIVE REPORT FOR RESERVES ASSESSMENT

OF THE MISSAN OIL FIELDS

IN EASTERN IRAQ

AS OF 31ST DECEMBER, 2011

Prepared for

CHINA NATIONAL OFFSHORE OIL CORPORATION LIMITED

MARCH, 2012

CONFIDENTIAL

This document contains proprietary and confidential information which may not, without the express written permission of Gaffney, Cline & Associates, be released to any third party in any form, copied in any way or reproduced, nor utilized for any purpose except that for which it is intended, and must be returned upon request.

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		Page No.
INTRODUCTION		1

1. EXECUTIVE SUMMARY		6

1.1	Hydrocarbons In-Place	6
1.2	Estimated Ultimate Recovery	6
1.3	Reserves	7
1.4	Net Present Value Summary	8

2. GEOLOGY SUMMARY		9

2.1	Regional Geology	9
2.2	Missan Fields	14

3. GEOPHYSICS REVIEW		15

3.1	Abu Ghirab Field	16
3.2	Buzurgan Field	17
3.3	Fauqi Field	18

4. PETROPHYSICS REVIEW		20

5. VOLUMETRIC CALCULATIONS		21

6. RESERVOIR ENGINEERING		22

6.1	Reservoir and Fluid Properties	22
6.2	Production History	23
	6.2.1 Abu Ghirab	24
	6.2.2 Buzurgan	25
	6.2.3 Fauqi	26
6.3	Rehabilitation Plan Summary	27
6.4	Reserves Estimation	28
	6.4.1 Developed Reserves	29
	6.4.2 Undeveloped Reserves	31
	6.4.3 Production Profiles	31

7. COSTS AND ECONOMIC ANALYSIS		33

7.1	Costs	33
7.2	Economic Analysis	35
	7.2.1 Contract and Fiscal Terms	36
	7.2.2 Economic Limit Test (ELT)	37
	7.2.3 Oil Price Scenario	37
	7.2.4 Entitlement Results	38

8. BASIS OF OPINION		40

TABLES

1.1	Missan Oilfields, Iraq STOIIP Volumetric Estimation	6
1.2	Missan Fields, Iraq Estimated Ultimate Recovery Estimation	6
1.3	Missan Oilfields, Iraq – CNOOC’s Net Entitlement Reserves	7
1.4	Missan Oilfields, Iraq Gross Reserves	7
1.5	Missan Oilfields, Iraq – Summary of Post-Tax NPV of Future Revenue from Reserves Net to CNOOC	8
2.1	Missan Oilfields Reservoirs	14
5.1	Missan Fields Oil In-Place Summary	21
6.1	Proposed New Wells and Well Interventions During Rehabilitation Plan	27
6.2	Decline Rate Assumptions for Developed Producing Profiles	29
6.4	EUR and Recovery Factor from the Rehabilitation Plan	32
7.1	Gross Input Cost Profiles Proved Developed Producing and Proved Cases	34
7.2	Gross Input Cost Profiles Proved + Probable And Proved + Probable + Possible Cases	35
7.3	Missan Oil Price Scenario	. 38
7.4	Summary of CNOOC Net Entitlement Reserves	38
7.5	Post-Tax NPV Ranges for CNOOC’s Entitlement Interest in the Missan Fields	39


FIGURES

0.1	Missan Fields Location Map	2
2.1	Geological Location of Missan Fields	9
2.2	Stratigraphy and Petroleum System	13
3.1	Missan Field Seismic Database	15
3.2	Abu Ghirab Depth Structure Map	17
3.3	Buzurgan Depth Structure Map	18
3.4	Fauqi Depth Structure Map	19
6.1	Reservoir Pressure for the Missan Fields	22
6.3	Abu Ghirab Oil Production History	24
6.4	Buzurgan Oil Production History	25
6.5	Fauqi Oil Production History	26
6.7	GCA Production Profile Estimates for the Missan Asset	32


APPENDIX

I.	SEC Reserve Definitions
II.	Glossary
III.	CNOOC’s Net Interest Cashflow Analyses
IV.	Technical Qualifications of Person Responsible for Audit


	Gaffney, Cline & Associates (Consultants) Pte. Ltd. 80 Anson Road #31-01C Fuji Xerox Towers Singapore 079907 Telephone: +65 6225 6951 www.gaffney-cline.com
DSA/AK/dh/L0132/2012/KK1810	15th March, 2012

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 RESERVES ASSESSMENT

OF THE MISSAN OIL FIELDS IN EASTERN IRAQ

AS AT 31ST DECEMBER 2011

INTRODUCTION

Gaffney, Cline and Associates (GCA) was contracted by China National Offshore Oil Corporation Limited (CNOOC) in October, 2011 to provide an independent reserves assessment for the Missan Oil Fields (Missan) as at 31st December, 2011. Missan is located 350 km southeast of Baghdad, Iraq (Figure 0.1). It is understood that the results of this assessment may be used for CNOOC’s annual financial report to the New York Stock Exchange (NYSE) and the Hong Kong Stock Exchange (HKEx).

Missan currently comprises the Abu Ghirab, Buzurgan and Jabal Fauqi (Fauqi) Oil Fields which were discovered between 1969 and 1973. The Abu Ghirab and Fauqi fields extend across Iraq’s border with Iran (Figure 0.1). First production from the Abu Ghirab and Buzurgan fields commenced in 1976; with start-up of the Fauqi field occurring in early 1978. The production from all the Missan fields was shut down between October, 1979 and June, 1998 during the Iran-Iraq War; production was again shut-in for a period in 2003 during the Gulf War.

CNOOC, through its wholly owned subsidiary CNOOC International Limited, together with the Turkish Petroleum Corporation (TPAO), have signed a 20-year Technical Service Contract (TSC) with the Missan Oil Company of The Iraqi Ministry of Oil (MOC) for the rehabilitation of improved production and enhanced recovery of petroleum from Missan in May, 2010. The contract formally came into force on 20th December, 2010.

CNOOC is the Operator of and holds a 63.75% participating interest in the project. TPAO holds 11.25% and the state partner - Iraqi Drilling Company, a local Iraqi company holds the remaining 25% in the project.

FIGURE 0.1

MISSAN FIELDS LOCATION MAP

In accordance with the commitments in the contract, the Missan Oil Fields shall be redeveloped with the daily production reaching 450,000 bbl/d within 6 years of the effective date, or by the end of 2016. Implementation will be achieved in two periods: the first three years are the Rehabilitation Period, while the second three years are the Enhanced Redevelopment Period. The rehabilitation of surface facilities, drilling of new wells and reservoir surveillance program shall be completed in the Rehabilitation Period and a Minimum Work Obligation is also required. The Enhanced Redevelopment Plan applies to the overall adjustment and development period of the oilfields and will maintain the production rate of 450,000 bbl/d of crude oil for 7 years.

CNOOC has prepared and submitted a Rehabilitation Plan for the Missan Oil Fields that has been approved by the Iraqi authorities. CNOOC’s original Rehabilitation Plan envisaged a 3-year (2011-2013) development scheme for the Missan fields that included the upgrade of surface facilities, drilling of 128 new wells, 26 workovers, installation of 33 ESP’s, 49 stimulation operations and implementing reservoir surveillance that considerably exceeded the Minimum

Work Obligations for the Rehabilitation Plan defined in the contract, which are summarized below.

The Minimum Work Obligations specified in the TSC contract terms consist of three main parts:

	i.	The first is appraisal work, including 3D seismic acquisition, processing and interpretation, appraisal well drilling, and geological and engineering studies.
	ii.	The second is the Rehabilitation Plan, including drilling 20 new wells and conducting 22 workovers, installing 9 ESP’s and 35 stimulation operations as well as reservoir testing, sampling, engineering and construction of new facilities as well as refurbishment of existing facilities.
	iii.	The third is the design and construction of an oil export pipeline from the oilfields to Fao Port.

During 2011, CNOOC has commenced operations under the Rehabilitation Plan but progress has been slower than expected with only 7 new wells drilled and no workovers or stimulation operations completed. CNOOC has provided to GCA a summary of an updated accelerated plan for the Missan Oil Fields which preserves the same completion target date (year-end 2013) as the original plan.

This revised plan includes the drilling of 127 new wells and 71 well interventions (including workovers, ESP’s and stimulation operations) over the period 2011-2013, most of which are yet to be executed. The most significant differences between the original and the updated versions of the Rehabilitation Plan are the withdrawal of 9 planned injector wells, resulting in all new wells planned being producers, and the reduction of planned well interventions from 108 to 71. CNOOC’s expectation prior to commencement of the Rehabilitation Plan was for the total Missan production to reach 120,000 stb/d by year-end 2011, 180,000 stb/d by year-end 2012 and 245,000 stb/d by year-end 2013. As of year-end 2011, the total field production rate was 90,000 stb/d. Hence, the production rate needs to be doubled in 2012 if the initial target rates are to be achieved.

In order to meet these production targets, CNOOC expects to have a total of 19 drilling rigs and 2 workover rigs operating during 2012. Three rigs were used for the wells drilled in 2011 and are the only ones currently drilling. Four additional rigs are on stand-by and it is expected that they will start drilling in Q1 2012. The remaining rigs are expected to start operating over Q2 and Q3 2012. In GCA’s view, the timely deployment of all the rigs required to meet CNOOC’s target of 68 wells in 2012 presents a significant challenge. Although, if executed, GCA considers the production targets could be achieved providing that the new well productivity is as expected.

GCA has classified as Reserves those hydrocarbon volumes that would be economically recoverable as a result of implementing the 3-year Rehabilitation Plan. Any volumes produced as a result of further development under the Enhanced Redevelopment Period (ERP) are currently classified as Contingent Resources. CNOOC is required to submit an Enhanced Redevelopment Plan within 36 months from the Effective Date of the contract (ie. by 20th December, 2013). Details of the ERP have not been provided to GCA at this stage. Therefore, the reserves estimates included in this report are limited to volumes produced from operations planned under the 3-year Rehabilitation Plan.

In line with the foregoing, the statement of reserves, presented herein, is based on a program that is expected to be superseded by the redevelopment activities proposed under the ERP to be submitted by 20th December, 2013. As such, the volumes actually recovered under the enlarged plan are expected to be significantly greater than those presented; however, should the ERP not be approved, it is possible that the CNOOC would be seen as in default of the contract and there could be an early termination and a consequential reduction in reserves.

Under the terms of the TSC, the Contractor is entitled to use any quantity of Associated Gas from the oil reservoirs necessary for Petroleum Operations and for power generation. However, all Associated Gas that is not used in Petroleum Operations or for power generation “shall be delivered unprocessed to MOC”. Thus, the contractor has no entitlement to any Gas Reserves.

The study was based on an audit of CNOOC’s interpretations of the existing data. During initial discussion in Beijing it was agreed that GCA would attempt to rectify, where possible, elements of CNOOC’s analysis where GCA considered alternative interpretations may be more appropriate. It was recognized however that a complete reconciliation of all matters was beyond the scope of this study.

This audit examination was based on information and data provided by CNOOC to GCA on or before 31st December, 2011, and included such tests, procedures and adjustments as were considered necessary. All questions that arose during the course of the audit process were resolved to our satisfaction. The results presented in this report are based upon information and data made available to GCA on or before 31st December, 2011. 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, 2011.

Economic models were constructed based on terms of the TSC as provided by CNOOC, in order to calculate CNOOC’s Net Entitlement volumes, which are made up of CNOOC’s share of Service Fees (Petroleum Cost Recovery and Remuneration Fees) plus Supplementary Fees, converted to volumetric equivalents. The economic tests for the reserve volumes as at 31st December, 2011 were based on a prior twelve-month first-day-of-the-month average reference price for UK North Sea Brent crude of U.S.$110.85/barrel, corrected for location and quality to an average wellhead price of U.S.$105.23/barrel. No price escalation has been included.

Future capital costs were derived from development plans prepared by CNOOC for the field. Recent historical operating expense data were utilized as the basis for operating cost projections. GCA has found that CNOOC has projected sufficient capital investments and operating expenses to produce economically the projected volumes recoverable from the development activities planned under the Rehabilitation Period of the contract.

It is GCA’s opinion that the estimates of total remaining recoverable hydrocarbon liquid volumes at 31st December, 2011, presented in this document are, in the aggregate, reasonable and the reserves categorization is appropriate and consistent with the definitions for reserves set out in Part 210 Rule 4-10(a) of Regulation S-X of the United States Securities and Exchange Commission (as set out in Appendix I). GCA concludes that the methodologies employed by CNOOC in the derivation of the reserves estimates are appropriate and that the quality of the data relied upon, the depth and thoroughness of the reserves estimation process is adequate.

It should be understood that any evaluation, particularly one involving future improvement developments, may be subject to significant variations over short periods of time, as new information becomes available and perceptions change. In this regard, it is noted again that the reserves estimates included in this report are limited to volumes produced from operations planned under the 3-year Rehabilitation Plan and as such are expected to be superseded by a revised assessment when the redevelopment activities proposed under the ERP has been approved by MOC and implementation of the plan initiated.

As such, the volumes actually recovered under the enlarged plan are expected to be significantly greater than those presented herein; however, should the ERP not be approved, it is possible that the CNOOC would be seen as in default of the contract and there could be an early termination and a consequential reduction in reserves.

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

The total proved reserves covered by this report is about 1.8% of CNOOC's total proved reserves as of 31st December, 2011. This is based on information provided by CNOOC.

1.	EXECUTIVE SUMMARY

1.1	Hydrocarbons In-Place

Table 1.1 presents the GCA Low, Best and High case volumetric estimates of Gross Stock Tank Oil Initially In Place (STOIIP) within the Missan project boundary.

TABLE 1.1

MISSAN OILFIELDS, IRAQ

STOMP VOLUMETRIC ESTIMATION

(GROSS 100% VOLUMES)

Field	Low	Best	High
Field	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)
Abu Ghirab	876	1,316	1,908
Buzurgan	1,889	2,917	5,039
Fauqi	838	1,409	2,227
Total	3,603	5,642	9,174

Note: Only volumes within the boundaries of the TSC have been considered.

1.2	Estimated Ultimate Recovery

Table 1.2 presents the Estimated Ultimate Recoveries (EURs) of Low, Best and High volumetric estimates within the Missan Fields, assuming CNOOC’s proposed development plan for the Rehabilitation Phase. It should be noted that these estimates only consider the Rehabilitation Phase and do not include volumes to be produced from the Enhanced Redevelopment Plan, which is currently still undefined. Cumulative production, to end December, 2011, is also included in the Low, Best and High estimates reported below.

TABLE 1.2

MISSAN FIELDS, IRAQ

ESTIMATED ULTIMATE RECOVERY ESTIMATION

(GROSS 100% VOLUMES)

Field	Cumulative Production As of 31st December. 2011	Low	Best	High
Field	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)
Abu Ghirab	185.2	355.2	412.1	457.6
Buzurgan	188.4	487.4	579.8	654.3
Fauqi	88.8	186.2	218.6	248.2
Total	462.4	1028.8	1210.5	1360.1

Notes:

1. Only volumes within the boundaries of the TSC have been considered.

2. Cumulative production statistics were based on history production data provided. Since the data sources in different periods are from different levels (field/well), cumulative production may not be entirely accurate.

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

1.3

Reserves

Table 1.3 presents a statement of the net entitlement to Proved Developed Producing (PDP), Proved Un-Developed (PUD), Probable and Possible Oil Reserves attributable to CNOOC’s working interest in the Missan Oil Fields as at 31st December, 2011 and which were estimated in accordance with SEC regulations. The economic cut offs were applied following Economic Limit Tests (ELTs) using costs and prices which are un-escalated throughout the period of calculation. CNOOC has no entitlement to any Gas Reserves.

TABLE 1.3

MISSAN OILFIELDS, IRAQ

CNOOC’S NET ENTITLEMENT RESERVES

AS OF 31st DECEMBER, 2011

	PDP	PUD	Total Proved	Probable	Possible
Field	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)
Abu Ghirab	0.0	18.6	18.6	1.4	1.0
Buzurgan	0.0	23.5	23.5	3.6	2.0
Fauqi	0.0	10.9	10.9	0.7	2.1
Total	0.0	53.0	53.0	5.7	5.1

Notes:

1. Net Entitlement Reserves are Post-Tax and reflect CNOOC’s Iraq Tax Liability if paid in crude as opposed to cash.

2. Only volumes within the boundaries of the TSC have been considered.

3. Individual field volumes have been back allocated proportionally based on individual production forecasts and are only approximate.

Gross reserves, corresponding to the above Net Reserves, are presented, for reference information only, in Table 1.4. They represent a 100% interest in commercially recoverable volumes as of 31st December, 2011, i.e. after economic cutoffs have been applied. Gross reserves include volumes attributable to third parties (government and other working interest partners).

TABLE 1.4

MISSAN OILFIELDS, IRAQ

GROSS RESERVES AS OF 31st DECEMBER, 2011

	PDP	PUD	Total Proved	Probable	Possible
	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)
Abu Ghirab	50.1	119.9	170.0	56.9	45.5
Buzurgan	114.1	185.0	299.0	92.4	74.5
Fauqi	28.3	69.1	97.4	32.4	29.6
Total	192.5	373.9	566.4	181.7	149.6

Note: Only volumes within the boundaries of the TSC have been considered.

1.4	Net Present Value Summary

Reference post-tax Net Present Values (NPVs) have been attributed to the Proved, the Proved plus Probable and the Proved plus Probable plus Possible Reserves at discount rates of 7.5%, 10.0% and 12.5%.

The NPVs as of 31st December, 2011 of estimated cash flows, after taxes, attributable to CNOOC’s share of Service Fees from the Missan project identified above (excluding any balance sheet adjustments or financing costs), are estimated on the basis of the Rehabilitation 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

MISSAN OILFIELDS, IRAQ

SUMMARY OF POST-TAX NPV OF

FUTURE REVENUE FROM RESERVES NET TO CNOOC

AS OF 31st DECEMBER, 2011

Discount Rate (%)	Proved	Proved plus Probable	Proved plus Probable plus Possible
Discount Rate (%)	US$ MM	US$ MM	US$ MM
7.5	22.1	143.5	155.2
10.0	-31.6	102.8	114.5
12.5	-80.7	65.8	78.2

Notes:

1. The NPVs are calculated from discounted cash flows incorporating the fiscal terms governing the field.

2. All cash flows are discounted on a mid-year basis to 31st December, 2011.

3. The reference NPVs reported here do not represent an opinion as to the market value of a property or any interest in it.

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, 2011).

It should be noted that the NPVs of future revenue potential of a petroleum property, such as those discussed in this report, do not represent an opinion as to the market value of that property, nor any interest in it. In assessing a likely market value, it would be necessary to take into account a number of additional factors including: reserves risk (i.e. that Reserves may not be realized within the anticipated timeframe for their exploitation); perceptions of economic and sovereign risk; potential upside; other benefits, encumbrances or charges that may pertain to a particular interest; and the competitive state of the market at the time. GCA has explicitly not taken such factors into account in deriving the reference NPVs presented herein.

2.	GEOLOGY SUMMARY

Iraq is one of the most hydrocarbon-rich countries in the Middle East. A thick sedimentary succession, robust structures, high individual well productivity and extensive oil reserves are some of the main characteristics of Iraqi oil fields.

2.1	Regional Geology

The Missan Fields are geographically located on the border of two countries; its multi petroleum systems are also geologically located on the border of two sub-basins: the Mesopotamian Foreland Basin and the Dezful Embayment in front of the Zagros orogenic belt (Figure 2.1).

FIGURE 2.1

GEOLOGICAL LOCATION OF MISSAN FIELDS

Source: Modified from J. Vergés and E. Saura et al. 2011

The Zagros orogenic belt is commonly subdivided into five structural zones parallel to the NW-SE trend of the belt (from the NE to the SW): the Urumieh Dokhtar Magmatic arc, the Sanandaj Sirjan Metamorphic Zone, the Imbricated Zone (or High Zagros Zone), the Zagros (Simply) Folded Belt (ZSFB) and the Mesopotamian-Persian Gulf Foreland Basin.

The ZSFB is separated from the foreland basin by the Mountain Front Flexure (or Mountain Front Fault - MFF). This structural and topographic front defines the arcs and embayments in the folded belt from SE to NW: the Fars Arc (Fars stratigraphic province, SE to Missan in Iran), the Dezful Embayment (Khuzestan stratigraphic province), and the Pusht-e Kuh Arc (Lurestan stratigraphic province, NW to Missan). In front of the MFF, the inner-most part of the Mesopotamian foreland basin is affected by the Zagros Deformation giving rise to NW-SE buried anticlines. These buried anticlines are containing the richest oil traps in frontal part of the ZSFB. The Dezful Embayment within the ZSFB and the Mesopotamia Foreland Basin are separated based on differences in the structural trends. The border between the regions is defined by the NW-SE trending gentle anticlines which are located along the southwestern margin of the Dezful Embayment.

The timing of the orogenic events associated with the closure of the Neo-Tethys significantly influenced the generation, migration and entrapment of the hydrocarbons in the ZSFB. Two major structural trends control oil and gas reservoirs in this area. Within the ZSFB oil fields are aligned with NW-SE trending folds while to the south of the ZSFB, the main Arabian (including eastern Mesopotamian and Persian Gulf) oilfields are aligned with north-south trend anticlines.

The structural trends of the Missan are much coincidence with those in the Dezful Embayment. Besides, structurally the Missan is located on the edge zone of the ZSFB within the Zagros Deformation Front (ZDF). That makes it more inclining to be part of the Dezful Embayment, geologically, than the Mesopotamian Foreland Basin.

Existing study shows that the influence of the tectonic events on petroleum entrapment is particularly important in the Dezful Embayment of the ZSFB. Since this area is one of the world richest oil provinces, which contains about 8% of global oil reserves in an area about 60,000 km2, mainly in Iran, and endows an impressive gathering of giant fields, producing from the Asmari limestone of Early Miocene and from the Cenomanian Sarvak (counterpart Mishrif in Mesopotamian Foreland Basin in Iraq) limestone. But this area is still under-explored, even after about 100 years of production. As the most obvious accumulations have been located, many in structural traps, stratigraphic models are of increasing exploration importance.

2.2	Petroleum System

Source Rocks

Two excellent source rocks are associated with these reservoirs, the Kazhdumi Formation (counterpart Maudud and Aptian Burgan or Nahr Umr in Iraq) of Albian in Lower Cretaceous, and the upper part of the Pabdeh (Asmari in Iraq) Formation of Middle Eocene.

The deep marine units of the Kazhdumi Formation in the northern part of Dezful Embayment, where the Missan locates, is considered as a main source rock, whereas uplift and subsequent erosion of the Arabian Shield in Late Aptian led to sedimentation of clastics in Albian (Nahr-Umr Formation in SE Iraq, Burgan Formation in Kuwait, Safania Formation in Saudi Arabia, and Burgan member of Kazhdumi Formation in SW Iran). The Kazhdumi Formation is considered the principal oil-generating sequence, i.e. the richest hydrocarbon

source in the region. The Kazhdumi sequence is composed of alternating dark gray marls and clayey limestones. The organic matter of this sequence is enriched in sulfur (5–7%). Together with bitumens, a part of this sulfur was delivered to pools of the main productive fields and oils of these fields are enriched in sulfur. Available data shows that the associated gas from Buzurgan field contains H2S up to 2.5%.

A study shows a monotonous and thick (200 to 1000 m) sequence of grey marls were deposited. Euxinic conditions prevailed in the central part of the depression during Middle/Late Eocene. The average TOC values varying from 3% in Fars (SE) to 7.5% in Lurestan (NW).

Other source rocks to the charge of the Missan, are potentially from Cretaceous sources, such as Aptian Shuaiba, Albian Zubair and Sulaiy, and from Jurassic, but their contribution to the charge of the reservoirs is negligible.

Maturation

Some models indicate the expulsion (maturation) commenced as early as 90 Ma (Late Cretaceous) with peak expulsion about 27 Ma (Oligocene). Most models show peak generation to be very recent (15 Ma or less) in the Mid Miocene (Neogene) coincident with the Zagros collision and the thick accumulation of orogenic clastics in the Zagros foredeep. One modeling shows that Kazhdumi and Pabdeh reached the onset of oil expulsion, 1 to10 Ma, after the beginning of the Zagros folding.

Migration

Migrations took place almost vertically and were facilitated by intense fracturing in high-relief anticlines. Although expulsion may have started in Late Cretaceous, significant migration commenced probably no earlier than latest Oligocene/earliest Miocene and continues to present.

Traps and Seals

In Dezful Embayment, the main seal rock is Gachsaran for the Asmari Formation. Gurpi and Pabdeh are considered not only contributed significant amounts of hydrocarbon to the Asmari Formation but also act as a good seal for Bangestan (Mishrif).

Reservoirs

The main proved and producing reservoir rocks in the Missan Fields are the Cretaceous Mishrif (Bangestan Sarvak in the Dezful Embayment) and the Tertiary.

Mishrif Reservoir

In the time period of Cenomanian to Turonian of early Late Cretaceous, the deposition of the Mishrif was widely spread with shallow-marine platform carbonates. The majority of previous studies assigned the age of Mishrif Formation together with Rumaila and Ahmadi formations and their equivalents to Cenomanian, with extension up into early Turonian and with respect to Mishrif Formation. The so-called paleohighs, or ridges, had strongly affected the distribution of Mishrif facies, such as the Samarra-Dujaila-Amarah ridge where the Missan located. A study based on some key well data scattered in the southern Mesopotamian Basin in Iraq shows the Mishrif play includes rudist-bearing shoals and biostromal carbonate reservoirs with thickness may reach 400 m and the thickest area is nearby the Missan. Mishrif reservoir property is quite good with porosity

up to 30% and permeability locally in excess of 1,000 mD. Studies indicate the Mishrif accommodates about 30% of total Iraq oil reserves, characterized by 26-28 APIo.

Asmari Reservoir

The Asmari Formation deposited during the Oligocene-Miocene. Studies indicate the Asmari Formation is a thick sequence of shallow water carbonate representing sedimentation on a carbonate ramp. The Asmari reservoir is one of the best known carbonate reservoirs in the world. Lithologically, the Asmari Formation consists of limestone, dolomitic limestone, dolomite and marly limestone. Some anhydrite and lithic and limy sandstones also occur within the Asmari Formation. The formation is generally characterized by a large-scale trend of upward-decreasing accommodation. Basal strata were deposited under relatively open-marine, high-energy conditions, whereas the Middle to Upper Asmari succession was deposited in relatively protected settings with more frequent evidence of exposure and evaporitic conditions. There is a general upward increase in the abundance of both anhydrite (occurring as nodules and cement) and dolomite. Based on the lithological heterogeneity, the complex geometries, and both early and late diagenetic alterations, the Asmari Reservoirs are classified in four main stratigraphic reference types: Type 1, sandstone dominated; Type 2, mixed carbonate-siliciclastic; Type 3, mixed carbonate-anhydrite; and Type 4, carbonate dominated

The generalized startigraphy and petroleum system summary of the Missan area is presented in Figure 2.2.

FIGURE 2.2

STRATIGRAPHY AND PETROLEUM SYSTEM

Source: Adapted from M.L. Bordenave, 2002

2.2 Missan Fields

Abu Ghirab, Buzurgan and Fauqi Oilfields were discovered in 1969, 1971 and 1979, respectively. Buzurgan began to produce in early 1976, and later Abu Ghirab Field was also put on production in the same year. Fauqi Field was put on production in early 1979. The three fields were shut down due to the war in late 1980. The fields resumed production in 1998, but their productions were interrupted for a while in 2003.

The main formation and oil group reservoirs in the fields are presented in Table 2.1, below.

TABLE 2.1

MISSAN OILFIELDS RESERVOIRS

Field	Block	Formation	Oil Group Reservoirs
Abu Ghirab	South (Main)	Asmari	Asmari-A
			Asmari-B
			Asmari-C & Below C
	North	Asmari	Asmari-A
			Asmari-B
Buzurgan	South	Mishrif	Mishrif-MA
			Mishrif-MB1x (MB11&MB12)
			Mishrif-MB21
			Mishrif-MB22
			Mishrif-MC (MC1+MC2)
	North	Mishrif	Mishrif-MA
			Mishrif-MB1x (MB11&MB12)
			Mishrif-MB21
			Mishrif-MC (MC1 & MC2)
Fauqi		Asmari	Asmari-A
			Asmari-B
			Asmari-C & D
		Mishrif	Mishrif-MA
			Mishrif-MB21
			Mishrif-MB22+MC

3. GEOPHYSICS REVIEW

In total, 54 seismic lines were acquired over Missan Fields, encompassing the fields: Abu Ghirab, Faqui and Buzurgan (Figure 3.1). In most of the area, well control helps to define the structures. However, the interpretation of the seismic lines is needed to have a better definition of the structure shape. Only 38% of the seismic lines were interpreted by CNOOC and have no problems with visualization or projection. The problems associated with the majority of the seismic data did not allow proceeding with validation of the seismic interpretation. All the seismic lines were reviewed and the issues encountered were inventoried by field.

The main issues encountered regarding the geophysical data provided by CNOOC were as follows:

(a)

9% of seismic data were not correctly displayed.

(b)

30% of seismic lines were not properly projected, even though they were loaded using the same coordinate system, as provided by CNOOC. The coordinate system provided was used to load the other seismic data which seems to be correctly. It is important to mention, that the other 38 seismic lines that cover these fields, do not have apparent projection or displacement issues.

(c)

40% of the seismic lines displayed over the field structures were not interpreted.

FIGURE 3.1

MISSAN FIELD SEISMIC DATABASE

CNOOC provided depth structure maps for most of the formation tops and these have been reviewed by GCA. GCA did not validate the seismic interpretation, depth conversion nor well to seismic correlation for the primary structural mapping review. The maps consistency was reviewed and crosschecked with the well formation tops. The maps generated by CNOOC are generally reasonable and were used for estimating gross rock volumes together with the defined oil water contacts from the well data. Specific analyses on the depth structural maps were made in the following sections.

The Gross Rock Volume (GRV) was estimated considering: a) the top and bottom depth structure maps; b) the lateral variation extents such as oil water contacts, structure mapping uncertainties, lithology variations and distance from well control; and c) the vertical extents such as the lowest known oil contacts that were defined by perforation and logs results for the low case and contacts defined by non-tested logs or spill points for the High Cases. GRV calculations constituted the inputs to the deterministic volume calculations.

3.1 Abu Ghirab Field

Well control is sufficient to define the southern structure (Figure 3.2). However, the interpretation of the seismic lines would be useful to define the structure’s complete dimensions. In this area only 33% of the seismic lines are interpreted without display issues. The High, Best and Low Case areas are not following the depth structure behaviour at the northern and southern extremes because the seismic coverage is poor in these areas and uncertainty in the structure shape increases.

In the northern structure there is insufficient well control to define the anticline axis and flanks solely by well data. In this case, the interpreted seismic lines could have been useful to better define the anticline structure. The seismic lines B-4 and B-58-2 should be also interpreted and issues with the projection of B-17, B-18 and B-57 should be resolved. Therefore, uncertainty is associated with the extension and shape of the depth structure. There are significant inconsistencies between the depth structure shape and the well data results. In this case, Low, Best and High Case areas were defined based on well control and assumptions of lateral facies changes, instead of following the depth structural map due to the associated uncertainty.

FIGURE 3.2

ABU GHIRAB DEPTH STRUCTURE MAP

3.2 Buzurgan Field

In the northern structure, the well control is not enough to solely define the reservoir structure. In this case, the structure map should be defined using also seismic interpretation. Nevertheless, only 2 of 8 seismic lines are interpreted. There are no strike seismic lines (along the structure); therefore all the dip lines available should be interpreted to reduce uncertainty. Low, Best and High Case areas were defined considering the well results and the depth structure map behaviour.

Well control is sufficient to define the southern structure (Figure 3.3). Seismic interpretation could be useful to define the anticline flanks, but only 1 of 5 seismic lines is interpreted without issues of projection. The Low, Best and High Case areas are not following the depth structure behaviour at the northern and southern extremes because the seismic coverage is poor in these areas.

FIGURE 3.3

BUZURGAN DEPTH STRUCTURE MAP

3.3 Fauqi Field

The well control is sufficient to define the structure main shape, but not its flanks. Seismic interpretation could be useful to define the full extent of the structure. However, 50% of the seismic lines are not interpreted or have incorrect projection (Figure 3.4). There is uncertainty associated with the extension and border shape of the depth structure. In this case, Low, Best and High Case areas were defined based on well control. The areas are not following the structural trend on the edges of the map due to the low confidence associated with the lack of interpreted data and poor seismic coverage.

FIGURE3.4

FAUQI DEPTH STRUCTURE MAP

4. PETROPHYSICS REVIEW

The purpose of the petrophysical interpretation was to cross check CNOOC’s interpretations and to verify the reservoir parameters used in the estimation of in-place volumes. In order to do this, GCA interpreted 14 wells from a total database of the 72 well interpretations that had been provided. The subset of wells chosen for detailed review were selected to ensure full coverage of the three fields, their reservoirs and if there were concerns regarding contacts.

The most important selection criteria however was that at least one well from each field must have core data in order to ground-truth the petrophysical models. Thus wells AG-10, BU-4 and FQ-10 with routine core analysis enabled the lithology, porosity and permeability models to be calibrated; while additionally well AG-4, with special core analysis, enabled the saturation models to be checked.

The workflow followed a standard approach of first determining the shaliness of the formations; calculating the effective porosity once the total porosity had been corrected for shale volume; and then determining the water saturations. The procedure was complicated by the presence of several types of lithology, including, shale, sandstone, limestone, dolomite and anhydrite. Each of these rock types has its own characteristic effect on well log response and hence on the interpreted reservoir parameters.

In terms of lithology, GCA found (using relatively simple cutoffs of neutron and density) that the clients’ interpretations were generally satisfactory in presenting the main lithologies. However, the client interpreted sandier limestones in wells AG-10 and FQ-10, than indicated by the core descriptions. This had little effect on the matrix porosity measurements in these wells, which, compared to GCA and core data, were in good agreement; though neither the client nor the GCA porosity models could adequately capture the occasional higher fracture porosity seen in the cores.

In general, the GCA matrix porosity matched the clients’ interpretation in most formations with the exception of the A Formation. This horizon is dominated by the presence of dolomite, which has a higher density than limestone and could possibly have been misinterpreted as a tight limestone if an inappropriate log response parameter had been used. The A Formation is below an anhydrite cap rock, which implies the dolomite may have been exposed as a weathering surface before the evaporite was deposited and may therefore have secondary porosity enhancement.

In terms of the saturations, GCA calculated similar values to the client and these compared well with the special core analysis of well AG-4. GCA calculated lower water saturations in the A Formation, which means this zone may have more potential than is currently assumed by the client. Fracturing may also have been played down previously but could in fact be a significant aspect of the reservoirs deliverability. If this is the case, then pay zones could exist below the assumed porosity cut-offs of 8 and 10%, used by the client. These cut-offs are considered to be reasonable for a matrix porosity system.

In conclusion, from the 14 well subset of wells analyzed in this audit, it is GCA’s belief that the client has used reasonable petrophysical models to consistently describe the majority of the reservoirs to a suitable standard. Consequently, GCA believes the values derived by the client can be used as the basis for the inputs to the STOOIP calculation. As there may be some upside potential in the dolomitic A Formation that might have been overlooked, GCA has widened the range of these reservoir parameters accordingly.

5. VOLUMETRIC CALCULATIONS

After analyzing the depth maps provided by CNOOC and having completed independent petrophysical analysis on the selected wells as described above, GCA has established a range to account for the uncertainty of oil volumes contained within the Abu Ghirab, Fauqi and Buzurgan Fields. The Formation Volume Factor values are based on PVT analysis reports of wells BU-1, FQ-1 and AG-1 for Buzurgan, Fauqi and Abu Ghirab Fields, respectively.

TABLE 5.1

MISSAN FIELDS

OIL IN-PLACE SUMMARY

AS OF 31ST DECEMBER, 2011

Field	Block	Oil Group Reservoirs	GRV (Acre-Ft)			NTG			Porosity			Sw			FVF			GCA STOIIP (MMstb)
Field	Block	Oil Group Reservoirs	Low	Best	High	Low	Best	High	Low	Best	High	Low	Best	High	Low	Best	High	Low	Best	High
Abu Ghirab	South	Asm ari-A	838,277	1,128,917	1,753,652	0.41	0.43	0.45	0.133	0.140	0.147	0.24	0.23	0.22	1.39	1.36	1.33	196	301	533
		Asm ari-B	1,310,841	1,590,294	1,767,191	0.82	0.86	0.90	0.152	0.160	0.168	0.30	0.29	0.28	1.39	1.36	1.33	633	887	1,131
		Asm ari-C & Below C	184,649	357,810	556,921	0.36	0.38	0.40	0.200	0.210	0.221	0.55	0.52	0.49	1.39	1.36	1.33	34	79	146
	North	Asm ari-A	105,149	298,910	401,100	0.24	0.25	0.26	0.088	0.093	0.098	0.53	0.50	0.48	1.39	1.36	1.33	6	20	31
	North	Asm ari-B	139,848	499,792	965,988	0.15	0.16	0.17	0.116	0.123	0.129	0.50	0.48	0.45	1.39	1.36	1.33	7	29	67
		TOTAL																876	1,316	1,908

Buzurgan	South	Mis hrif-MA	-	-	-	0.02	0.02	0.02	0.092	0.097	0.101	0.59	0.57	0.54	1.44	1.41	1.38	-	-	-
		Mis hrif-MB1x (MB11&MB12)	2,011,378	2,926,996	4,656,084	0.45	0.48	0.50	0.119	0.125	0.131	0.35	0.33	0.32	1.44	1.41	1.38	378	638	1,171
		Mis hrif-MB21	2,754,152	3,021,931	4,138,322	0.83	0.88	0.92	0.137	0.145	0.152	0.24	0.23	0.22	1.44	1.41	1.38	1,291	1,626	2,542
		Mis hrif-MB22	209,812	505,885	639,304	0.29	0.31	0.32	0.130	0.137	0.144	0.52	0.49	0.47	1.44	1.41	1.38	21	59	88
		Mis hrif-MC (MC1+MC2)	436,593	860,806	1,073,545	0.39	0.41	0.43	0.120	0.127	0.133	0.53	0.51	0.48	1.44	1.41	1.38	51	120	178
	North	Mis hrif-MA	37,439	106,892	193,866	0.26	0.28	0.29	0.187	0.197	0.207	0.42	0.40	0.38	1.44	1.41	1.38	6	19	41
		Mis hrif-MB1x (MB11&MB12)	115,340	540,324	1,080,477	0.45	0.48	0.50	0.135	0.142	0.149	0.34	0.32	0.31	1.44	1.41	1.38	25	136	313
		Mis hrif-MB21	416,706	729,584	1,672,970	0.61	0.65	0.68	0.138	0.145	0.152	0.48	0.46	0.44	1.44	1.41	1.38	98	203	545
		Mis hrif-MC (MC1&MC2)	95,202	518,613	630,378	0.44	0.47	0.49	0.118	0.125	0.131	0.32	0.30	0.29	1.44	1.41	1.38	18	115	161
		TOTAL																1,889	2,917	5,039

Fauqi	Asmari	Asm ari-A	650,759	780,595	1,140,640	0.65	0.68	0.75	0.124	0.130	0.137	0.33	0.30	0.29	1.24	1.22	1.20	217	307	540
		Asm ari-B	825,476	1,235,274	1,457,985	0.61	0.65	0.71	0.164	0.173	0.181	0.48	0.44	0.42	1.24	1.22	1.20	268	491	710
		Asm ari-C & D	65,904	142,126	237,513	0.06	0.07	0.07	0.171	0.180	0.189	0.41	0.37	0.35	1.24	1.22	1.20	3	7	13
		Sub Total Asmari																487	805	1,264
	Mishrif	Mis hrif-MA	65,481	143,472	221,414	0.56	0.59	0.65	0.110	0.116	0.122	0.29	0.26	0.25	1.49	1.46	1.43	15	38	71
		Mis hrif-MB21	1,654,713	2,241,936	2,860,688	0.53	0.56	0.61	0.118	0.124	0.130	0.39	0.36	0.34	1.49	1.46	1.43	327	529	818
		Mis hrif-MB22+MC	72,218	213,380	357,346	0.42	0.44	0.49	0.123	0.129	0.136	0.49	0.44	0.42	1.49	1.46	1.43	10	36	74
		Sub Total Mishrif																351	604	963
		TOTAL																838	1,409	2,227
		TOTAL MISSAN FIELDS (MMstb)																3,603	5,642	9,174

Notes:

1. Only volumes within the boundaries of the TSC have been considered.

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

3. GRV = Gross Rock Volume, NTG = Net To Gross, Sw = Water Saturation, FVF = Formation Volume Factor (rbbl/stb).

4. Oil volume is in Millions stock tank barrels (MMstb).

6. RESERVOIR ENGINEERING

6.1 Reservoir and Fluid Properties

The Missan in-situ hydrocarbon fluid is a medium to heavy oil (21-25º API) with a viscosity between 0.96 and 3.4 cp and a solution gas-oil ratio between 485 and 700 scf/stb. The fluid is highly undersaturated; with bubble point pressures over 2,000 psi below initial reservoir pressures.

Reservoirs within the Asmari and Mishrif Formations fall on different pressure regimes, as shown in Figure 6.1 with the Mishrif Formation being overpressured by about 700-800 psi with respect to the Asmari Formation. Generally speaking, the Asmari Formation has better reservoir characteristics (with permeability up to 1 D), but it is stratigraphically and dynamically more complex, with multiple flow units and oil-water contacts.

FIGURE 6.1

RESERVOIR PRESSURE FOR THE MISSAN FIELDS

6.2 Production History

The Missan asset commenced production in 1976 and reached its peak oil production at 123 Mstb/d in February, 1980. Production from the three fields was suspended in October,1980 and resumed in June 1998. Since then the average oil production rate has been 69 Mstb/d. As of December, 2011, oil production rate was 90 Mstb/d. Production has exhibited a steadily increasing trend since March, 2010. Figure 6.2 shows production profiles for the individual fields and the total for the asset. Cumulative oil production from the three fields to December, 2011 is 457 MMstb. This represents 8% of GCA’s Mid Case aggregated STOIIP estimate.

FIGURE 6.2

MISSAN OIL PRODUCTION HISTORY

A total of 65 production wells have been drilled in the Missan fields, of which 40 are currently active.

6.2.1 Abu Ghirab

The Abu Ghirab Oilfield started production in August, 1976, and its production reached the peak of 45 Mstb/d in May, 1980. After the 18-year field shutdown, production was resumed in 1998 at a rate of 30 Mstb/d. The production of the oilfield was interrupted several times between 2003 and 2004. The oil production from this field has declined significantly from May, 2011. As of end December, 2011, oil production rate was 27 Mstb/d and cumulative production was 185 MMstb, which represents 20.7% and 13.8% of GCA’s Low Case and Mid Case STOIIP estimates.

Abu Ghirab has 17 production wells (2 of them with dual completion in two different reservoirs), including 11 wells in production and 6 shut-in wells, 5 due to water production and 1 due to formation damage. Two new wells (AG-16 and AG-18) were put in production in early 2010.

The field is divided in a North and a South Dome. 3 producers are located in the North Dome and 14 are located in the South Dome. Most of the production comes from the Asmari reservoir, which is split into three major production units (A, B and C), all of which have been completed.

Figure 6.3 shows the production history of the Abu Ghirab Field.

FIGURE 6.3

ABU GHIRAB OIL PRODUCTION HISTORY

6.2.2 Buzurgan

This oilfield was put on production in November, 1976 and reached a production rate of 43 Mstb/d in May, 1979. Once production was re-established normally in 2003, its daily output stabilized around 35 Mstb/d. CNOOC’s development efforts in 2011 have been focused on the Buzurgan Field. Production has steadily increased over the last two years and as of December, 2011, the field production rate was 48 Mstb/d, with approximately 30% coming from the North Dome and 70% coming from the South Dome. Cumulative production to end December, 2011 was 188 MMstb, which represents 9.9% and 6.4% of GCA’s Low Case and Mid Case STOIIP estimates.

The main producing reservoir in this field is the Mishrif, in particular the MB21 section which accounts for 95% of the production. Wells are producing on natural flowing mode. A total of 27 wells have been drilled in this field. As of December, 2011, there were 21 wells in production, 3 of which have dual completions producing from more than one reservoir section (BU-6, BU-12, BU-17). Four new wells (BU-24, BU-26, BU-27 and BU-28) have been brought online during 2011. Seven of the producing wells have had water production so far, usually in very small percentage; there are reasons to believe that the natural fracture system has played a role in the flow of water towards the wells. Additionally, two wells have been shut-in due to water production, one well was drilled as a delineation well and three wells have been drilled but not completed.

Figure 6.4 shows the production history of the Buzurgan Field.

FIGURE 6.4

BUZURGAN OIL PRODUCTION HISTORY

6.2.3 Fauqi

The Fauqi oilfield was put on production in January 1979 and reached a peak daily output of 43.2 Mstb/d in the early stages of the field life. Following the field shut down between 1980 and 1998, production rate has oscillated between 10 Mstb/d and 40 Mstb/d for most of the time. Steady production increment has been observed since 2009. The current oil output from the field is 14 Mstb/d. Cumulative oil production to end December, 2011 was 89 MMstb, which represents 10.6% and 6.3% of GCA’s Low Case and Mid Case STOIIP estimates.

The Fauqi field produces from both the Asmari and the Mishrif reservoirs. A total of 23 wells have been drilled in this field, including two wells that have been completed in both reservoirs. As of December, 2011, 11 wells were in production, 3 wells in the Mishrif, 7 wells in the Asmari and 1 well completed in both.

Most of the Asmari wells that have been shut-in, were due to water production. The oil water system at this reservoir level is believed to be complex. On the other hand, none of the Mishrif wells that have been shut-in are due to water production; most of the wells have been shut-in because of poor reservoir or formation damage. Based on reservoir pressure measurements and other available information, the Asmari shows better reservoir quality and stronger water drive than the Mishrif. Because the Fauqi field straddles across the Iranian border, it is unknown the effect that any production from the Iranian side could be having in the subsurface.

Figure 6.5 shows the production history of the Fauqi Field.

FIGURE 6.5

FAUQI OIL PRODUCTION HISTORY

6.3 Rehabilitation Plan Summary

The Operator’s original Rehabilitation Plan envisaged a 3-year (2011-2013) development scheme for the Missan fields that included the upgrade of surface facilities, drilling new wells and implementing reservoir surveillance. An updated accelerated plan which preserves the same completion target date (year-end 2013) was made available to GCA by the Operator. This plan includes 127 wells and 71 well interventions over the period 2011-2013, most of which are yet to be executed. The most significant differences between the original and the updated versions of the Rehabilitation Plan are the withdrawal of 9 planned injector wells, resulting in all new wells planned being producers, and the reduction of planned well interventions from 108 to 71. The Operator’s expectation after commencement of the Rehabilitation Plan was for the total Missan production to reach 120 Mstb/d by year-end 2011, 180 Mstb/d by year-end 2012 and 245 Mstb/d by year-end 2013. As of year-end 2011, the total field production rate was 90 Mstb/d. Hence, the production rate needs to be doubled in 2012 if the initial target rates are to be achieved.

Table 6.1 summarizes the new wells and well interventions planned as part of the updated Rehabilitation Plan.

TABLE 6.1

PROPOSED NEW WELLS AND WELL INTERVENTIONS

DURING REHABILITATION PLAN

Field		Abu Ghirab	Buzurgan	Fauqi	TOTAL MISSAN
Deviated producers	2011 (actual)	0	4	0	4
	2012	28	24	11	63
	2013	11	18	21	50
	Total	39	46	32	117
Horizontal producers	2011 (actual)	0	0	0	0
	2012	0	3	2	5
	2013	0	0	5	5
	Total	0	3	7	10
TOTAL NEW WELLS		39	49	39	127
TOTAL INTERVENTIONS		23	21	27	71

For the completion of the Rehabilitation plan, CNOOC expects to have a total of 19 drilling rigs and 2 workover rigs. Three rigs are responsible for the four wells drilled in 2011 and are the only ones currently drilling. Four additional rigs are on stand-by and it is expected that they will start drilling in Q1 2012. The remaining rigs are expected to start operating over Q2 and Q3 2012. In GCA’s view, the timely deployment of all the rigs required to meet CNOOC’s target of 68 wells in 2012, presents significant challenges.

All the production wells planned in the Abu Ghirab Field target the Limestone B Reservoir within the Asmari Formation, which holds an estimated 67% of the total STOIIP for the field. Development in Buzurgan is focused on the massive MB21 reservoir within the Mishrif

Formation, which holds over 80% of the STOIIP. In Fauqi, new development wells will target both the Asmari (A and B) and the Mishrif (M21) reservoirs.

Two areas of focus for CNOOC during the Rehabilitation Plan period are to gain a better understanding of the aquifer behavior in all three fields, and to assess the implementation of reservoir pressure maintenance through a water injection pilot programme that includes both deviated and horizontal injectors in Buzurgan and Fauqi. By the end of the Rehabilitation period the operator expects to have decided on the optimum waterflood pattern for the full development of the fields.

6.4 Reserves Estimation

GCA has classified as Reserves those hydrocarbon volumes that would be economically recoverable as a result of implementing the 3-year Rehabilitation Pan. Any volumes produced as a result of further development are currently classified as Contingent Resources. CNOOC envisages an Enhanced Redevelopment Plan to follow immediately after the Rehabilitation Plan. Details of the ERP have not been provided to GCA at this stage. Therefore, GCA’s estimates included in this report are limited to volumes classified as Reserves.

Developed Producing Reserves account for those hydrocarbon volumes to be produced by wells currently in production. Given the sparse nature of the field production data available, GCA selected those periods where reliable Decline curve analysis (DCA) could be conducted between 2005 to 2011 to estimate the field decline. Because none of the Missan fields exhibit clear decline trends at a field level for the small percentage of STOIIP produced so far, GCA focused on a well-by-well analysis to estimate field decline rates.

Developed Non Producing Reserves include those volumes coming from planned well interventions as part of the Rehabilitation Plan. CNOOC’s intervention program includes re-opening of shut-in wells, choke enlargements, ESP installation, acid stimulation and new perforations. GCA has assumed that well interventions will help in sustaining the decline rates forecasted for producing wells and new drills; hence it has not specifically assigned additional production to well interventions.

Undeveloped Reserves account for those volumes coming from new wells planned as part of the Rehabilitation Plan. A total of 127 wells are planned over 3 years. For the estimation of production coming from new wells, GCA analyzed the historical performance of existing wells and conducted checks on the productivity index (PI) calculated by CNOOC for a number of tested wells. PIs were broadly found to be reasonable. GCA generated Low Case, Mid Case and High Case single wells production profiles on the basis of the PI and expected pressure depletion in the fields.

GCA built Low Case, Mid Case and High Case production profiles for the three fields for the estimation of Proved, Proved plus Probable and Proved plus Probable plus Possible Reserves categories respectively. In accordance with PRMS guidelines, GCA has limited the Reserves to volumes produced up to the expiration date of the TAC, which is 20th December, 2030. Recoverable volumes produced beyond that date are classified as Contingent Resources.

6.4.1 Developed Reserves

Decline curve analysis (DCA) by well was utilized to estimate the field decline rates for the three fields. Full field decline rates for the field could not be interpreted due to the lack of clear decline production trends at this stage.

The following assumptions were applied to build the Developed Producing profiles:

● Low Case: all wells will decline at the average rate of wells currently declining. Wells producing at a flat rate were excluded from the calculation of the average decline rate.

● Mid and High Cases: two realizations of an average field decline rate calculated from all the wells (including those producing at a flat rate). Mid Case assumes exponential decline and high case assumes hyperbolic decline.

Table 6.2 shows a summary of the decline parameters utilized to estimate developed producing for the three Reserves category, including the exponent b and the yearly decline rate.

TABLE 6.2

DECLINE RATE ASSUMPTIONS FOR DEVELOPED PRODUCING PROFILES

Field	Low Case		Mid Case		High Case
	Oil (MMbbl)		Oil (MMbbl)		Oil (MMbbl)
	b	Decline	b	Decline	b	Decline
Abu Ghirab	0	19%	0	13%	0.25	13%
Buzurgan	0	13%	0	7%	0.40	7%
Fauqi	0	17%	0	13%	0.70	13%

Figure 6.6 depicts the result of the Mid Case DCA conducted on the Abu Ghirab Field, showing a 13% exponential decline trend.

FIGURE 6.6

MID CASE FIELD DECLINE FOR ABU GHIRAB

A major uncertainty related to existing wells is the prediction of water breakthrough and subsequent oil production decline. Water production data was not made available to GCA, so any assessment of water production was based on CNOOC’s Rehabilitation Plan report. A total of 12 wells (5 in Abu Ghirab, 2 in Buzurgan and 5 in Fauqi) have been shut-in due to premature water production. By reservoir, only 2 of the 12 wells shut-in are completed in the Misrif Formation, demonstrating the higher complexity of the oil-water system in the Asmari Formation.

There are two aspects to the water prediction uncertainty:

●	Aquifer size and activity, which would influence the movement of water through the reservoir towards the wells. There is very little information available to date regarding the aquifer properties and its dynamic properties.

●

The probable existence of high permeability streaks throughout the fracture system that would allow water to prematurely reach some wells. Some wells have shown high water-cut despite being completed near the crest of the structure and a large distance from the contact. Likewise, wells completed closer to the contact have not shown any water production. These facts suggest that water flow along the natural fracture system is likely.

The Operator has planned a significant effort aimed at characterizing the behaviour of water in the three fields during the Rehabilitation phase. These plans include pilot injection tests in Buzurgan and Fauqi.

6.4.2 Undeveloped Reserves

GCA assigned Low Case, Mid Case and High Case initial flow rate and exponential decline rate to all new wells to be drilled in 2012, based on historical performance of existing wells in each field. The initial rate assigned to wells drilled in 2013 was reduced on the basis of the observed field pressure depletion of each field.

Horizontal wells, which account for less than 10% of the production wells to be drilled during the Rehabilitation Plan period, were assigned 1.5 times the rate of a vertical well as estimated by the Operator. Table 6.3 shows a summary of initial flowrate and decline rate for 2012 wells:

TABLE 6.3

INITIAL RATE AND DECLINE RATE ASSUMED FOR NEW WELLS IN 2012

Field	Low Case	Mid Case	High Case	Decline Rate
Field	Oil (bopd)	Oil (bopd)	Oil (bopd)	Decline Rate
Abu Ghirab	2,350	2,700	3,240	19%
Buzurgan	1,925	2,226	2,605	13%
Fauqi	1,207	1,372	1,654	17%

The average oil flowrate for the four wells drilled in the Buzurgan Field in 2011 was around 1,800 bopd, with three of the four wells flowing between 2,000 and 2,400 bopd.

In order to account for the uncertainty related to water production described above, GCA has made the assumption that a number of wells in each field will be closed due to water production before they have made any contribution to production. The Low Case profiles for all fields assume that 20% of wells will be prematurely shut-in due to water production. The Mid and High Case profiles assume that 10% of the wells will be affected.

6.4.3 Production Profiles

Figure 6.7 shows the Low Case, Mid Case and High Case production profiles generated by GCA for the Rehabilitation Phase of the Missan Asset.

Table 6.4 shows a summary of the STOIIP alongside the cumulative production to date and the EUR and Recovery Factors associated with GCA’s Low, Mid and High Case production profiles for the Rehabilitation Plan.

FIGURE 6.7

GCA PRODUCTION PROFILE ESTIMATES FOR THE MISSAN ASSET

TABLE 6.4

EUR AND RECOVERY FACTOR FROM THE REHABILITATION PLAN

	Low Case	Mid Case	High Case
	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)
STOIIP	3,603	5,642	9,174
Cum. Prodn. to 31st December, 2011	457.5
Cum RF to 31st December, 2011	12.7%	8.1%	5.0%
Rehab EUR	560	740	889
Rehab RF	15.5%	13.1%	9.7%

7. COSTS AND ECONOMIC ANALYSIS

7.1 Costs

The cost estimates provided in CNOOC’s Rehabilitation Plan for the Missan Oil Field are generally in line with estimates developed by GCA. These cost estimates are considered to be reasonable, within an accuracy range of -15% +30%, indicating that there is a greater chance that costs will be higher than the cost estimates provided in the Development Plans, due to market conditions and project execution risk.

CNOOC’s cost estimates, provided for the period from 2011 to 2013, have been used for the purpose of the economic analysis, with the following adjustments:

●

The Petroleum Costs (Opex and Capex components), as well as Supplementary Costs that were provided on an annual basis, were assumed to be incurred in equal amounts in each quarter.

●

The 2011 Rehabilitation Plan costs have been updated to reflect the estimated actual amounts spent, on the basis of the work completed, as provided by CNOOC.

The following assumptions were made for the determination of costs beyond the Rehabilitation Plan, from 2014 onwards:

●

The Rehabilitation Plan is assumed to be carried out by end-2013, and no further Supplementary Costs and Petroleum Cost Capex are expected to be incurred in the subsequent years;

●

The Petroleum Cost Opex (based on US$3.00/bbl) at the end of the Development Period was used to project the annual Opex for the remainder of the contract, and results in costs that are somewhat higher than during the Rehabilitation Phase;

●

The Contractor is assumed not to incur any sustaining Capex or Abandonment costs during the Contract Term.

Cost profiles associated with the Proved Developed Producing (PDP), Proved (1P) cases are provided below in Table 7.1, Proved plus Probable (2P) and Proved plus Probable plus Possible (3P) cases are provided below in Table 7.2. These profiles are in gross (100% project) 2011 Real terms.

TABLE 7.1

GROSS INPUT COST PROFILES (U.S.$ MM)

PROVED DEVELOPED PRODUCING AND PROVED CASES

	PDP				1P
	CAPEX	OPEX	Supp.	NCR	CAPEX	OPEX	Supp.	NCR
2011	166.6	44.7	-	-	166.6	44.7	-	-
2012	-	203.4	-	5.0	2,263.0	203.4	237.0	5.0
2013	-	77.6	-	5.0	1,874.9	226.7	334.4	5.0
2014	-	65.7	-	5.0	-	219.6	-	5.0
2015	-	55.7	-	5.0	-	184.9	-	5.0
2016	-	47.5	-	-	-	156.3	-	-
2017	-	40.2	-	-	-	131.6	-	-
2018	-	34.2	-	-	-	111.1	-	-
2019	-	29.1	-	-	-	94.0	-	-
2020	-	24.9	-	-	-	79.8	-	-
2021	-	21.2	-	-	-	67.4	-	-
2022	-	18.1	-	-	-	57.2	-	-
2023	-	15.5	-	-	-	48.6	-	-
2024	-	13.3	-	-	-	41.4	-	-
2025	-	11.3	-	-	-	35.1	-	-
2026	-	9.7	-	-	-	29.9	-	-
2027	-	8.3	-	-	-	25.5	-	-
2028	-	7.2	-	-	-	21.8	-	-
2029	-	6.1	-	-	-	18.6	-	-
TOTAL	166.6	733.7	0.0	20.0	4,304.5	1,797.6	571.4	20.0

Notes:

1. Supp. = Supplementary Costs Paid

2. NCR = Non Cost Recoverable

TABLE 7.2

GROSS INPUT COST PROFILES (U.S.$ MM)

PROVED + PROBABLE AND PROVED + PROBABLE + POSSIBLE CASES

	2P				3P
	CAPEX	OPEX	Supp.	NCR	CAPEX	OPEX	Supp.	NCR
2011	166.6	44.7	-	-	166.6	44.7	-	-
2012	2,263.0	203.4	237.0	5.0	2,263.0	203.4	237.0	5.0
2013	1,874.9	274.9	334.4	5.0	1,874.9	317.5	334.4	5.0
2014	-	274.3	-	5.0	-	319.7	-	5.0
2015	-	234.8	-	5.0	-	274.5	-	5.0
2016	-	201.9	-	-	-	237.2	-	-
2017	-	172.9	-	-	-	204.4	-	-
2018	-	148.8	-	-	-	177.2	-	-
2019	-	128.4	-	-	-	154.2	-	-
2020	-	111.2	-	-	-	135.1	-	-
2021	-	96.0	-	-	-	118.1	-	-
2022	-	83.3	-	-	-	103.9	-	-
2023	-	72.4	-	-	-	91.8	-	-
2024	-	63.3	-	-	-	81.6	-	-
2025	-	55.0	-	-	-	72.4	-	-
2026	-	48.1	-	-	-	64.7	-	-
2027	-	42.1	-	-	-	58.1	-	-
2028	-	37.1	-	-	-	52.5	-	-
2029	-	32.5	-	-	-	47.3	-	-
TOTAL	4,304.5	2,325.1	571.4	20.0	4,304.5	2,758.3	571.4	20.0

Notes:

1. Supp. = Supplementary Costs Paid

2. NCR = Non Cost Recoverable

7.2 Economic Analysis

GCA has conducted an economic analysis for each case to assess the Economic Limit of the project; CNOOC’s Net Entitlement Reserves, which are made up of CNOOC’s share of Cost Recovery and Remuneration Fees; and to estimate the NPVs of these cash flows net to CNOOC’s working interest in the project.

The economic analyses presented in this report are based upon GCA’s understanding of the fiscal and contractual terms governing these assets, and the various economic and commercial assumptions described herein.

7.2.1 Contract and Fiscal Terms

The Technical Service Contract (TSC) for the Missan Fields was signed on 17th May, 2010. Parties to the contract are the Missan Oil Company, on behalf of the Government of Iraq and the Contractor Group comprising CNOOC (63.75%), TPAO (11.25%) and the Iraqi Drilling Company, the “State Partner” (25.00%).

The terms of the TSC are summarised below:

●

The Contractor is entitled to be reimbursed for its actual costs and paid a profit element in the form of Service Fees and Supplementary Fees to be taken in cash or in kind;

●

Service Fees represent the payment of the Remuneration Fee as well as the reimbursement of Petroleum Costs;

●

Service Fees are payable from 50% of the Contract Area’s Deemed Revenue attributable to the Incremental Production, defined as the production above a contractually specified Baseline Production level that declines by 5% per annum from the Initial Production Rate of 88,000 Bbl/d over the life of the Contract;

●

Remuneration Fees are generated for each barrel of Incremental Production, according to the sliding scale shown below.

R-Factor	Remuneration Fee (U.S. $/Bbl)
< 1.0	2.30
1.0 – 1.25	1.84
1.25 – 1.5	1.38
1.5 – 2.0	1.15
> 2.0	0.69

The R-Factor is the ratio of cumulative Contactor Revenue to cumulative Contractor Expenditures. The Remuneration Fee is reduced by a performance factor, only applicable during the Plateau Production Period, and calculated as the Net Production Rate divided by the Plateau Production Target. Remuneration Fees are paid from the remaining available deemed revenue once the Petroleum Costs due in that quarter have been paid. A nominated State‐owned company participates as a “carried” partner with a 25% interest and receives that proportion of Remuneration Fees;

●

Supplementary Fees provide a separate recovery mechanism for costs that are not strictly Petroleum Costs but nevertheless essential to effective performance of the contract, such as costs associated with de-mining and the removal of war remnants, construction of facilities downstream of the contractually-defined Transfer Point and the remediation of existing environmental problems. Supplementary Fees are payable from 10% of the revenues attributable to the Baseline Production;

●

The Contractor is subject to income tax in the Republic of Iraq. The Contract also “stabilizes” the Contractor for taxes imposed in excess of 35% of the Remuneration Fees received;

●

The Contractor is required to contribute a non-recoverable amount of U.S.$5.00 MM annually for training purposes.

The economic model is run on a quarterly basis in order to reflect the contract terms for the accrual and payment of fees and costs.

7.2.2 Economic Limit Test (ELT)

GCA has conducted an Economic Limit Test (ELT) for each of the cases for the Missan project in order to assess the Proved Developed Producing (PDP), Proved (1P), Proved plus Probable (2P), and Proved plus Probable plus Possible (3P) Reserves, as at 31st December, 2011. The ELT is a 2-stage process:

●

Firstly, if the cumulative Operating Revenue from the Effective Date goes positive at some point, then the volumes can be classified as Reserves

●

Secondly, the year in which the Net Operating Revenue goes negative for the last time is the Economic Limit (EL) of the project. The cumulative production from the Effective Date to the EL is the Gross Reserve volume for the particular case.

Additionally, GCA has conducted an economic entitlement calculation based on the TSC for the Missan Oil Fields in order to derive CNOOC’s Net Entitlement volumes, which are made up of CNOOC’s share of Service Fees (Petroleum Cost Recovery and Remuneration Fees) plus Supplementary Fees, converted to volumetric equivalents. Summary cash flows for CNOOC’s Net Entitlement for each case are presented in Appendix III. NPVs estimated from these cash flows are discounted on a mid-year basis to 31st December, 2011.

7.2.3 Oil Price Scenario

The oil price used for the calculation of the Deemed Revenue is related to the Oil Sales Prices published by the State Oil Marketing Organization of Iraq (SOMO).

GCA has employed the standard SEC method for oil price scenario used in this evaluation (Table 7.3). The price used was determined by calculating the percentage differential between the SEC Brent Price and the Iraq average oil price as published by SOMO for each month in 2011 and applying the average differential to the SEC price for 2011 Reserve Audits. The oil price remains flat at U.S.$105.23 for the duration of the project life.

TABLE 7.3

MISSAN OIL PRICE SCENARIO

Month	SEC Brent Price (U.S.$/bbl)	Differential (%)	SOMO Iraq Price (U.S.$/bbl)
Jan-11	93.70	97%	90.78
Feb-11	100.45	98%	98.44
Mar-11	113.22	95%	107.13
Apr-11	118.62	96%	114.36
May-11	124.89	87%	108.26
Jun-11	116.43	90%	105.18
Jul-11	109.51	99%	108.80
Aug-11	115.98	90%	104.92
Sep-11	117.45	89%	104.90
Oct-11	104.37	100%	104.04
Nov-11	106.66	100%	106.60
Dec-11	108.94	97%	106.18
Average/Used	110.85	95%	105.23

7.2.4 Entitlement Results

Based on the profiles and assumptions provided above, CNOOC Entitlement Reserves on a post-tax basis, as at 31st December, 2011 are shown in Table 7.4 below. It should be noted that the Entitlement volumes do not include any contribution from unrecovered costs at the end of the TSC.

TABLE 7.4

SUMMARY OF CNOOC NET ENTITLEMENT RESERVES

AS OF 31st DECEMBER, 2011

	PDP	PUD	Total Proved	Probable	Possible
Field	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)	Oil (MMbbl)
Abu Ghirab	0.0	18.6	18.6	1.4	1.0
Buzurgan	0.0	23.5	23.5	3.6	2.0
Fauqi	0.0	10.9	10.9	0.7	2.1
Total	0.0	53.0	53.0	5.7	5.1

Note: Post-Tax Entitlement numbers reflect CNOOC’s Iraq Tax Liability if paid in crude as opposed to cash.

Reference post-tax Net Present Values (NPVs) have been attributed to CNOOC’s Proved (1P) and Proved plus Probable (2P) and Proved plus Probable plus Possible (3P) Reserves Entitlement volumes, and have been calculated at nominal discount rates of 7.5%, 10.0%, 12.5%.

The NPVs of estimated post-tax cashflows (as of 31 December, 2011) attributable to CNOOC’s Net Entitlement, summarised in Table 7.5, have been derived using the contractual and pricing assumptions described previously. No allowances have been made for cash flows prior to 31st December, 2011, balances, inventories, indebtedness or other balance sheet effects.

The NPVs have been provided below for the Reserves cases presented as part of this report, but do not reflect GCA’s opinion in respect of the fair market value (FMV) of the asset, nor any part share thereof.

TABLE 7.5

POST-TAX NPV RANGES FOR

CNOOC’S ENTITLEMENT INTEREST IN THE MISSAN FIELDS

AS OF 31st DECEMBER, 2011

	7.5% (U.S.$ MM)	10.0% (U.S.$ MM)	12.5% (U.S.$ MM)
1P Case	22.1	-31.6	-80.7
2P Case	143.5	102.8	65.8
3P Case	155.2	114.5	78.2

8. BASIS OF OPINION

GCA is not aware of any potential changes in regulations applicable to these fields that could affect the ability of CNOOC to produce the estimated reserves.

This assessment has been conducted within the context of GCA’s understanding of CNOOC’s petroleum property rights as represented by CNOOC’s management. GCA is not in a position to attest to property title, financial interest relationships or encumbrances thereon for any part of the appraised properties or interests. GCA has used all assumptions, data, procedures, and methods that it considers necessary and appropriate under the circumstances to prepare this report.

There are numerous uncertainties inherent in estimating reserves, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas reserve engineering must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas reserves prepared by other parties may differ, perhaps materially, from those contained within this report. The accuracy of any reserve estimate is a function of the quality of the available data and of engineering and geological interpretation. Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.

For this assignment, GCA served as an independent reserve estimator. The firm’s officers and employees have no direct or indirect interest holding in CNOOC or in the property units evaluated. GCA’s remuneration was not in any way contingent on reported reserve estimates. The qualifications of the technical person primarily responsible for overseeing this estimate are included in Appendix IV.

Finally, please note that GCA reserves the right to approve, in advance, the use and context of the use of any results, statements or opinions expressed in this report. Such approval shall include, but not be confined to, statements or references in documents of a public or semi-public nature such as loan agreements, prospectuses, reserve statements, press releases etc.

Yours faithfully,

GAFFNEY, CLINE & ASSOCIATES (CONSULTANTS) PTE LTD

/s/ David S. Ahye

David S. Ahye

Principal

APPENDIX I

SEC RESERVE DEFINITIONS

U.S. SECURITIES AND EXCHANGE COMMISSION (SEC)

MODERNIZATION OF OIL AND GAS REPORTING1

Oil and Gas Reserves Definitions and Reporting

(a) Definitions

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)

Same environment of deposition;

(iii)

Similar geological structure; and

(iv)

Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

1	Extracted from 17 CFR Parts 210, 211, 229, and 249 [Release Nos. 33-8995; 34-59192; FR-78; File No. S7-15-08] RIN 3235-AK00].

A1.I

(ii)

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities are costs incurred to:

(i)

Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii)

Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii)

Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv)

Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in pail as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)

Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii)

Costs of carrying and retaining undeveloped properties, such as delay rentals, ad

A1.II

valorem taxes on properties, legal costs for title-defense, and the maintenance of land and lease records.

(iii)

Dry hole contributions and bottom hole contributions. (iv)Costs of drilling and equipping exploratory wells.

(iv)

Costs of drilling and equipping exploratory wells.

(v)

Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)

Oil and gas producing activities include:

(A)

The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B)

The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C)

The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1)

Lifting the oil and gas to the surface; and

(2)

Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D)

Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

A1.III

In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)

Oil and gas producing activities do not include:

(A)

Transporting, refining, or marketing oil and gas;

(B)

Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C)

Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D)

Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)

Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)

Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)

The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v)

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)

Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has

A1.IV

defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18)	Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

	(i)	When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
	(ii)	Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
	(iii)	Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
	(iv)	See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19)	Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20)	Production costs.

(i)

Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities, they become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

	(A)	Costs of labor to operate the wells and related equipment and facilities. (B)Repairs and maintenance.

	(C)	Materials, supplies, arid fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

	(D)	Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

	(E)	Severance taxes.

(ii)

Some support equipment or facilities may serve two or more oil and gas producing

A1.V

activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22)

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)

The area of the reservoir considered as proved includes:

(A)

The area identified by drilling and limited by fluid contacts, if any, and

(B)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)

The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by

A1.VI

the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon

A1.VII

exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

A1.VIII

APPENDIX II

GLOSSARY

List of Standard Oil Industry Terms and Abbreviations

ABEX	Abandonment Expenditure
ACQ	Annual Contract Quantity
oAPI	Degrees API (American Petroleum Institute)
AAPG	American Association of Petroleum Geologists
AVO	Amplitude versus Offset
A$	Australian Dollars
B	Billion (109)
Bbl	Barrels
/Bbl	per barrel
BBbl	Billion Barrels
BHA	Bottom Hole Assembly
BHC	Bottom Hole Compensated
Bscf or Bcf	Billion standard cubic feet
Bscfd or Bcfd	Billion standard cubic feet per day
Bm3	Billion cubic metres
bcpd	Barrels of condensate per day
BHP	Bottom Hole Pressure
blpd	Barrels of liquid per day
bpd	Barrels per day
boe	Barrels of oil equivalent @ xxx mcf/Bbl
boepd	Barrels of oil equivalent per day @ xxx mcf/Bbl
BOP	Blow Out Preventer
bopd	Barrels oil per day
bwpd	Barrels of water per day
BS&W	Bottom sediment and water
BTU	British Thermal Units
bwpd	Barrels water per day
CBM	Coal Bed Methane
CO2	Carbon Dioxide
CAPEX	Capital Expenditure
CCGT	Combined Cycle Gas Turbine
cm	centimetres
CMM	Coal Mine Methane
CNG	Compressed Natural Gas
Cp	Centipoise (a measure of viscosity)
CSG	Coal Seam Gas
CT	Corporation Tax
DCQ	Daily Contract Quantity
Deg C	Degrees Celsius
Deg F	Degrees Fahrenheit
DHI	Direct Hydrocarbon Indicator
DST	Drill Stem Test
DWT	Dead-weight ton
E&A	Exploration & Appraisal
E&P	Exploration and Production
EBIT	Earnings before Interest and Tax
EBITDA	Earnings before interest, tax, depreciation and amortisation
EI	Entitlement Interest
EIA	Environmental Impact Assessment
EMV	Expected Monetary Value
EOR	Enhanced Oil Recovery
EUR	Estimated Ultimate Recovery
FDP	Field Development Plan
FEED	Front End Engineering and Design
FPSO	Floating Production, Storage and Offloading
FSO	Floating Storage and Offloading
ft	Foot/feet
Fx	Foreign Exchange Rate

AII.I

g	gram
g/cc	grams per cubic centimetre
gal	gallon
gal/d	gallons per day
G&A	General and Administrative costs
GBP	Pounds Sterling
GDT	Gas Down to
GIIP	Gas initially in place
GJ	Gigajoules (one billion Joules)
GOR	Gas Oil Ratio
GTL	Gas to Liquids
GWC	Gas water contact
HDT	Hydrocarbons Down to
HSE	Health, Safety and Environment
HSFO	High Sulphur Fuel Oil
HUT	Hydrocarbons up to
H2S	Hydrogen Sulphide
IOR	Improved Oil Recovery
IPP	Independent Power Producer
IRR	Internal Rate of Return
J	Joule (Metric measurement of energy) I kilojoule = 0.9478 BTU)
k	Permeability
KB	Kelly Bushing
KJ	Kilojoules (one Thousand Joules)
kl	Kilolitres
km	Kilometres
km2	Square kilometres
kPa	Thousands of Pascals (measurement of pressure)
KW	Kilowatt
KWh	Kilowatt hour
LKG	Lowest Known Gas
LKH	Lowest Known Hydrocarbons
LKO	Lowest Known Oil
LNG	Liquefied Natural Gas
LoF	Life of Field
LPG	Liquefied Petroleum Gas
LTI	Lost Time Injury
LWD	Logging while drilling
m	Metres
M	Thousand
m3	Cubic metres
Mcf or Mscf	Thousand standard cubic feet
MCM	Management Committee Meeting
MMcf or MMscf	Million standard cubic feet
m3d	Cubic metres per day
mD	Measure of Permeability in millidarcies
MD	Measured Depth
MDT	Modular Dynamic Tester
Mean	Arithmetic average of a set of numbers
Median	Middle value in a set of values
MFT	Multi Formation Tester
mg/l	milligrams per litre
MJ	Megajoules (One Million Joules)
Mm3	Thousand Cubic metres
Mm3d	Thousand Cubic metres per day
MM	Million
MMBbl	Millions of barrels
MMBTU	Millions of British Thermal Units
Mode	Value that exists most frequently in a set of values = most likely
Mscfd	Thousand standard cubic feet per day
MMscfd	Million standard cubic feet per day
MW	Megawatt
MWD	Measuring While Drilling
MWh	Megawatt hour

AII.II

mya	Million years ago
NGL	Natural Gas Liquids
N2	Nitrogen
NPV	Net Present Value
OBM	Oil Based Mud
OCM	Operating Committee Meeting
ODT	Oil down to
OPEX	Operating Expenditure
OWC	Oil Water Contact
p.a.	Per annum
Pa	Pascals (metric measurement of pressure)
P&A	Plugged and Abandoned
PDP	Proved Developed Producing
PI	Productivity Index
PJ	Petajoules (1015 Joules)
PSDM	Post Stack Depth Migration
psi	Pounds per square inch
psia	Pounds per square inch absolute
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
cf or scf	Standard Cubic Feet
cfd or scfd	Standard Cubic Feet per day
scf/ton	Standard cubic foot per ton
SL	Straight line (for depreciation)
so	Oil Saturation
SPE	Society of Petroleum Engineers
SPEE	Society of Petroleum Evaluation Engineers
ss	Subsea
stb	Stock tank barrel
STOIIP	Stock tank oil initially in place
sw	Water Saturation
T	Tonnes
TD	Total Depth
Te	Tonnes equivalent
THP	Tubing Head Pressure
TJ	Terajoules (1012 Joules)
Tscf or Tcf	Trillion standard cubic feet
TCM	Technical Committee Meeting
TOC	Total Organic Carbon
TOP	Take or Pay
Tpd	Tonnes per day
TVD	True Vertical Depth
TVDss	True Vertical Depth Subsea
USGS	United States Geological Survey
US$	United States Dollar
VSP	Vertical Seismic Profiling
WC	Water Cut
WI	Working Interest
WPC	World Petroleum Council
WTI	West Texas Intermediate
wt%	Weight percent
1H05	First half (6 months) of 2005 (example of date)
2Q06	Second quarter (3 months) of 2006 (example of date)
2D	Two dimensional
3D	Three dimensional

AII.III

4D	Four dimensional
1P	Proved Reserves
2P	Proved plus Probable Reserves
3P	Proved plus Probable plus Possible Reserves
%	Percentage

AII.IV

APPENDIX III

CNOOC’s NET INTEREST CASH FLOWS

TABLE Alll.1

MISSAN 1P CASH FLOW AS OF 31ST DECEMBER, 2011

CNOOCI Cashflow

31-Dec-10

Field:	Missan	Nominal Net Present Values			Nominal Net Present Values
Case:	1P	as at 31-Dec-10			as at 31-Dec-11
G:WYD SmartWare_swstori6C.t65280\Volum e_94000e68 d4e5 11df9341 028037ec0200\Ptoject A'chiv e s\sing2011\k1810_cnooc missan k1810_summar y_010312 xls x)lo_gross		Disc Rate	Pre-Tax	Post-Tax	Disc Rate	Pre-Tax	Post-Tax
		0.0%	7.4	- 51.8	0.0%	276.2	217.0
		5.0%	- 136.9	- 185.2	5.0%	131.7	81.0
Comments:		7.5%	- 194.9	- 238.7	7.5%	69.2	22.1
		10.0%	- 245.1	- 285.0	10.0%	12.3	31.6
		12.5%	- 288.7	- 325.2	12.5%	39.7	80.7
		15.0%	- 326.5	- 359.9	15.0%	87.2	125.6
Cost NWI:	85.00%	IRR	0.2%	- 1.6%	IRR	10.6%	8.5%

Costs Incurred by Company

Revenue Received by Contractor

Company

Period Beginning	Oil		Field	Capital Costs	Operating Costs	Supp. Costs	Non-Allowable Costs	Bonus & Training	Tot. Comp.	Pet.Costs	Supp. Costs + Int.	Remuner -ation	Cont -ractor	State Partner	Comp -any	Pre Tax	Corp -orate	Post Tax	Field Revenue less Capex/ Opex/Supp Costs NCF US$ M M	Entitlement Volume	Entitlement Volume
	Production MMB	Price US$/Bbl	Revenue US$ M M	Paid US$ M M	Paid US$ M M	Paid US$ M M	Paid US$ M M	Paid US$ M M	Costs US$ M M	Receive US$ M M	Received US$ M M	Received US$ M M	Revenue US$ M M	Carry US$ M M	Revenue US$ M M	NCF US$ M M	Tax US$ M M	NCF US$ M M	Field Revenue less Capex/ Opex/Supp Costs NCF US$ M M	Before Tax Bbls	After Tax Bbls
Jan-11	29	105	3,010	142	38			89	269							- 269		- 269	2,830
Jan-12	42	105	4,458	1,924	173	201	4	4	2,306	827	151		978		978	-1,329		- 1,329	2,160	9,290,445	9,290,445
Jan-13	64	105	6,759	1,594	193	284	4	4	2,079	2,107	240		2,347		2,347	268		268	4,688	22,306,363	22,306,363
Jan-14	62	105	6,548		187		4	4	195	1,271	95	160	1,526	47	1,486	1,291	42	1,249	6,361	14,121,978	13,723,324
Jan-15	52	105	5,514		157		4	4	166	164		25	189	7	183	17	7	11	5,356	1,740,383	1,677,150
Jan-16	44	105	4,661		133			4	137	139		15	154	5	150	13	4	9	4,528	1,428,159	1,389,647
Jan-17	37	105	3,922		112			4	116	117		10	126	3	124	8	3	5	3,810	1,178,486	1,154,151
Jan-18	31	105	3,314		94			4	99	99		6	105	2	103	4	2	3	3,219	979,698	964,612
Jan-19	27	105	2,802		80			4	84	83		4	87	1	86	2	1	1	2,722	817,512	808,539
Jan-20	23	105	2,379		68			4	72	71		2	73	1	72	0	1	0	2,311	686,528	681,477
Jan-21	19	105	2,011		57			4	62	60		3	63	1	62	1	1	0	1,953	592,401	583,811
Jan-22	16	105	1,706		49			4	53	43		2	45	1	44		0		1,657	422,673	418,282
Jan-23	14	105	1,449		41			4	46										1,407
Jan-24	12	105	1,235		35			4	39										1,200
Jan-25	10	105	1,048		30			4	34										1,018
Jan-26	8	105	892		25			4	30										867
Jan-27	7	105	761		22			4	26										739
Jan-28	6	105	651		19			4	23										633
Jan-29	5	105	554		16			4	20										539
Jan-30		105

Totals:	510	MMBbl	53,672	3,659	1,528	486	17	166	5,855	4,980	486	227	5,693	67	5,637	7	60	- 52	47,999	53,564,626	52,997,801
As at 31st Dec 2011:																			45,169	53.6	53.0
																				(MMBbl)	(MMBbl)

AIII.I

TABLE AIII.2

MISSAN 2P CASH FLOW AS OF 31ST DECEMBER, 2011

Field:	Missan	Nominal Net Present Values			Nominal Net Present Values
Case:	2P	as at 31-Dec-10			as at 31-Dec-11
G:\WD Sm artWare.s ws tor\GCA65280\Volum e.94090e68.d4e5.11df.9341.028037ec0200\Project Archives \s ing2011\k1810_cnooc m is s an\[Mis s an - v07 - 20120218(pm g010312).xls x]P		Disc Rate	Pre-Tax	Post-Tax	Disc Rate	Pre-Tax	Post-Tax
		0.0%	132.7	24.5	0.0%	401.5	293.3
		5.0%	2.4	- 83.0	5.0%	278.0	188.3
Comments:		7.5%	- 49.0	- 125.8	7.5%	226.0	143.5
		10.0%	- 93.4	- 162.8	10.0%	179.2	102.8
		12.5%	- 131.7	- 194.9	12.5%	136.9	65.8
		15.0%	- 165.0	- 222.8	15.0%	98.5	32.0
Cost NWI:	85.00%	IRR	5.1%	1.0%	IRR	22.7%	17.6%

Costs Incurred by Company

Revenue Received by Contractor

Company

Period Beginning	Oil		Field	Capital Costs	Operating Costs	Supp. Costs	Non-Allowable Costs	Bonus & Training	Tot. Comp.	Pet. Costs	Supp. Costs + Int.	Remuner -ation	Cont -ractor	State Partner	Comp -any	Pre Tax	Corp -orate	Post Tax	Field Revenue less Capex/ Opex/Supp Costs NCF US$ M M	Entitlement Volume	Entitlement Volume
	Production MMB	Price US$/Bbl	Revenue US$ M M	Paid US$ M M	Paid US$ M M	Paid US$ M M	Paid US$ M M	Paid US$ M M	Costs US$ M M	Receive US$ M M	Received US$ M M	Received US$ M M	Revenue US$ M M	Carry US$ M M	Revenue US$ M M	NCF US$ M M	Tax US$ M M	NCF US$ M M	Field Revenue less Capex/ Opex/Supp Costs NCF US$ M M	Before Tax Bbls	After Tax Bbls
Jan-11	29	105	3,057	142	38			89	269							- 269		- 269	2,878
Jan-12	47	105	4,987	1,924	173	201	4	4	2,306	1,155	151		1,306		1,306	-1,001		- 1,001	2,689	12,407,023	12,407,023
Jan-13	78	105	8,195	1,594	234	284	4	4	2,120	2,508	240	139	2,888	41	2,853	733	37	696	6,084	27,109,472	26,762,341
Jan-14	78	105	8,180		233		4	4	242	618	95	89	803	26	780	539	23	515	7,947	7,416,521	7,193,354
Jan-15	67	105	6,999		200		4	4	208	208		46	254	14	242	34	12	22	6,800	2,300,722	2,185,631
Jan-16	57	105	6,018		172			4	176	178		30	209	9	201	25	8	17	5,847	1,909,703	1,834,384
Jan-17	49	105	5,155		147			4	151	153		21	173	6	168	17	5	12	5,008	1,599,220	1,547,304
Jan-18	42	105	4,437		126			4	131	131		14	146	4	142	11	4	8	4,311	1,350,628	1,314,782
Jan-19	36	105	3,827		109			4	113	113		10	123	3	121	7	3	5	3,718	1,146,149	1,121,585
Jan-20	32	105	3,316		95			4	99	98		7	105	2	103	4	2	3	3,222	979,921	963,119
Jan-21	27	105	2,863		82			4	86	85		13	97	4	94	8	3	5	2,782	895,339	863,457
Jan-22	24	105	2,484		71			4	75	73		17	90	5	86	11	4	6	2,413	815,796	774,349
Jan-23	21	105	2,159		62			4	66	64		12	76	4	73	7	3	4	2,098	692,341	662,082
Jan-24	18	105	1,886		54			4	58	56		9	64	3	62	4	2	2	1,832	589,539	568,312
Jan-25	16	105	1,641		47			4	51	48		5	54	2	52	1	1	- 0	1,594	498,091	484,759
Jan-26	14	105	1,435		41			4	45	42		3	45	1	44		1		1,394
Jan-27	12	105	1,256		36			4	40	9			9		9				1,221
Jan-28	11	105	1,106		32			4	36										1,074
Jan-29	9	105	969		28			4	32										942
Jan-30		105

Totals:	665	MMBbl	69,971	3,659	1,976	486	17	166	6,303	5,540	486	415	6,441	122	6,337	133	109	25	63,850	59,710,466	58,682,483
As at 31st Dec 2011:																			60,972	59.710	58.682
																				(MMBbl)	(MMBbl)

AIII.II

TABLE Alll.3

MISSAN 3P CASH FLOW AS OF 31ST DECEMBER, 2011

Field:	Missan	Nominal Net Present Values			Nominal Net Present Values
Case:	3P	as at 31-Dec-10			as at 31-Dec-11
G:\WD SmartWare swstor\GC.to65280\Volume_94090e66.d4 e5.11df93 41 020037edJ200\Project .Archi'lles\sing2011\k1810_cnooc mis san\{k1810_ summar:t_010312.>4sxJ1i_gross		Disc Rate	Pre-Tax	Post-Tax	Disc Rate	Pre-Tax	Post-Tax
		0.0%	276.6	112.6	0.0%	477.8	313.8
		5.0%	119.0	4.8	5.0%	331.1	201.2
Comments:		7.5%	59.8	- 49.7	7.5%	272.9	155.2
		10.0%	10.0	- 87.7	10.0%	222.0	114.5
		12.5%	32.2	120.1	12.5%	177.1	78.2
		15.0%	68.2	147.8	15.0%	137.3	45.7
Cost NWI:	85.00%	IRR	10.6%	4.8%	IRR	26.5%	19.0%

				Costs Incured by Company						Revenue Received by Contractor										Company
Period Beginning	Oil		Field	Capital Costs	Operating Costs	Supp. Costs	Non-Allowable Costs	Bonus & Training	Tot. Comp.	Pet. Costs	Supp. Costs + Int.	Remune -ration	Cont -ractor	State Partner	Company	Pre Tax	Corporate	Post Tax	Field Revenue less Capex/ Opex/Supp Costs NCF US$ M M	Entitlement Volume	Entitlement Volume
	Production MMB	Price US$/Bbl	Revenue US$ M M	Paid US$ M M	Paid US$ M M	Paid US$ M M	Paid US$ M M	Paid US$ M M	Costs US$ M M	Receive US$ M M	Received US$ M M	Received US$ M M	Revenue US$ M M	Carry US$ M M	Revenue US$ M M	NCF US$ M M	Tax US$ M M	NCF US$ M M		Before Tax Bbls	After Tax Bbls
Jan-11	29	105	3,089	142	38			89	269	68			68		68	201		201	2,910	642,310	642,310
Jan-12	52	105	5,454	1,924	173	201	4	4	2,306	1,388	151		1,539		1,539	767		767	3,157	14,629,720	14,629,720
Jan-13	90	105	9,465	1,594	270	284	4	4	2,156	2,233	240	172	2,645	51	2,602	446	45	401	7,317	24,726,562	24,296,957
Jan-14	91	105	9,533		272		4	4	280	658	95	121	874	36	844	564	32	532	9,261	8,018,887	7,716,600
Jan-15	78	105	8,185		233		4	4	242	242		67	310	20	293	51	18	33	7,952	2,782,545	2,614,955
Jan-16	67	105	7,071		202			4	206	209		45	254	13	243	37	12	25	6,869	2,308,381	2,196,349
Jan-17	58	105	6,093		174			4	178	180		32	212	9	204	26	8	18	5,919	1,938,841	1,859,474
Jan-18	50	105	5,264		151			4	155	156		23	179	7	173	18	6	12	5,133	1,645,376	1,588,660
Jan-19	44	105	5,284		131			4	135	136		16	152	5	148	13	4	8	4,467	1,405,605	1,365,011
Jan-20	38	105	4,027		115			4	119	119		12	130	3	128	8	3	5	3,912	1,212,128	1,182,812
Jan-21	33	105	3,520		100			4	105	104		21	124	6	119	15	5	9	3,419	1,132,178	1,080,814
Jan-22	29	105	3,097		88			4	93	91		28	119	8	112	19	7	12	3,009	1,062,331	993,698
Jan-23	26	105	2,736		78			4	82	80		22	103	7	97	15	6	9	2,658	923,759	867,981
Jan-24	23	105	2,433		69			4	74	71		18	90	5	85	12	5	7	2,363	808,754	763,353
Jan-25	21	105	2,160		62			4	66	63		15	78	4	74	8	4	5	2,098	705,766	669,533
Jan-26	18	105	1,930		55			4	59	57		12	68	3	65	6	3	3	1,875	620,277	591,391
Jan-27	16	105	1,732		49			4	54	51		9	60	3	58	4	2	2	1,683	547,229	524,424
Jan-28	15	105	1,565		45			4	49	46		7	53	2	51	2	2	0	1,520	486,450	468,470
Jan-29	13	105	1,411		40			4	44	41		5	47	2	45	1	1	1	1,371	431,050	417,396
Jan-30		105

Totals:	792	MMBbl	83,382	3,659	2,344	486	17	166	6,672	5,993	486	625	7,104	184	6,948	277	164	113	76,893	66,026,148	64,469,908
As at 31st Dec 2011:																			73,983	65.386	63.828
																				(MMBbl)	(MMBbl)

AIII.III

APPENDIX IV

TECHNICAL QUALIFICATIONS OF PERSON RESPONSIBLE FOR AUDIT

GCA is an independent international energy advisory group of 50 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 mainly include Mr. David S. Ahye, Mr. Stephen M. Lane, Mr. Rawdon Seager, Dr. Hu Yundong, Ms. Arse Kusumastuti, Mr. Gary William Holmes, Mr. J. Miguel Muruais, Mr. Paul McGhee, Ms. Maria Soto Abreu, and Mr. Florent Rousset. All hold degrees in geoscience, petroleum engineering or related discipline.

Mr. Ahye holds a B.Sc (Hons) in Chemical Engineering, is a member of the Society of Petroleum Engineers, Society of Professional Well Log Analysts, the South East Asia Petroleum Exploration Society and Geological Society of Trinidad and Tobago. He is a senior Reservoir/Petroleum Engineer with a strong petrophysical background and over 30 years' industry experience worldwide, and is one of GCA’s senior Project Managers and with a particular background in the valuation and evaluation of both exploration and producing assets, reserves certification and the conduct and management of integrated field studies.

Mr. Lane holds a BSc (Hons) in Geology, is a member of Petroleum Exploration Society of Great Britain and Geophysical Exploration and Interpretation for Petroleum Explorationist, AMF etc. and is a very experienced Geoscientist and Petrophysicist with over 30 years’ background in providing geological and petrophysical expertise to clients worldwide. He has particular involvement as lead petrophysicist/geologist and Project Manager in many oil and gas reserve certifications both for project finance and for SEC reporting purposes, frequent involvement in the valuation of E&P assets for acquisition and divestment purposes and production of public documents such as Competent Person’s Reports.

Mr. Seager holds a BSc. (Hons) in Physics and a MSc. (Distinction) in Petroleum Reservoir Engineering, is a member of Society of Petroleum Engineers (Chairman of SPE Oil and Gas Reserves Committee), Society of Petroleum Evaluation Engineers and American Association of Petroleum Geologists, is a member of the Energy Institute, UK, Chartered Petroleum Engineer, UK and European Engineer, registered with FEANI. He has over 40 years of experience in the international oil and gas arena and has managed numerous field studies, reserve assessments, and asset evaluations. He has made presentations within the industry relating to reserves estimating and reporting issues and has given expert testimony during arbitration hearings.

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.

Ms. Arse Kusumastuti holds a MSc in Petroleum Geoscience, is a member of American Association of Petroleum Geologists, Indonesia Petroleum Association and Southeast Asia Petroleum Exploration Society, and has 20 years of experience in the international oil and gas industry primarily as a geologist.

AIV.I

Mr. Holmes holds a BSc (Hons) in Geology and Geography, is a member of Society of Petroleum Engineers, Petroleum Exploration Society of Great Britain, South East Asia Petroleum Exploration Society and London Petrophysical Society, and has 30 years international experience in Exploration and Production, with key strengths includes innovative approach to integrated formation evaluation, field studies and operations.

Mr. Muruais holds a BSc in Mining Engineering and a MSc in Petroleum Engineering and Energy Engineering, is a member of Society of Petroleum Engineers, and has about 15 years of E&P industry experience working primarily as a reservoir engineer in both operating and service companies.

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 25 years industry experience, with a background in the fiscal modeling and economic evaluation of numerous petroleum producing nations.

Ms. Soto Abreu holds a BSc in Geophysical Engineering and a MSc in Earth Sciences / Geophysics, is a member of Society of Exploration Geophysicists and European Association of Geoscientists & Engineers.

Mr. Rousset holds a BSc in Mathematics and a MSc in Management, is a member of International Association of Energy Economists and Association of International Petroleum Negotiators.

AIV.II

EXECUTIVE REPORT FOR RESERVES CERTIFICATION

OF THE GREATER ANGOSTURA FIELDS

IN BLOCK 2C, TRINIDAD & TOBAGO

AS OF 31ST DECEMBER, 2011

Prepared for

CHINA NATIONAL OFFSHORE OIL CORPORATION LIMITED

MARCH, 2012

CONFIDENTIAL

www.gaffney-cline.com

				Page No.

INTRODUCTION				1

1.	RESULTS SUMMARY			5

	1.1	In-Place Volumes		5

	1.2	Estimated Ultimate Recovery		5

	1.3	Net Reserves		6

	1.4	Gross Reserves		6

	1.5	Net Present Values		7

	1.6	Reserves Reconciliation		7

2.	PROJECTS SUMMARY			10

	2.1	Exploration And Appraisal History		10

	2.2	Development Projects		10

		2.2.1	Phase I – Angostura Field Development Project	10

		2.2.2	Phase Ii – Angostura Gas Project	12

	2.3	Well Status And Plans		13

3.	ECONOMIC EVALUATION			14

	3.1	Capital Expenditure		14

	3.2	Operating Expenditure		14

	3.3	Economic Analysis		15

	3.4	Reserves		15

	3.5	Economic Test Results		16

	3.6	Summary Report for CNOOC’s Filling to the SEC		16

4.	QUALIFICATIONS			17

5.	BASIS OF OPINION			17

TABLES

1.1	Block 2C – Trinidad & Tobago STOIIP & GIIP Volumetric Estimation	5
1.2	Block 2C – Trinidad & Tobago Estimated Ultimate Recovery Estimation	5
1.3	Block 2C – Trinidad & Tobago CNOOC Net Entitlement Reserves	6
1.4	Block 2C – Trinidad & Tobago Gross Reserves	6
1.5	Block 2C – Trinidad & Tobago CNOOC Net Present Values	7
1.6	Block 2C – Trinidad & Tobago CNOOC Net Entitlement PDP and Proved Reserves Summary	8
1.7	Block 2C – Trinidad & Tobago CNOOC Net Entitlement PDP and Proved Reserves Reconciliation	8
1.8	Block 2C – Trinidad & Tobago Gross PDP and Proved Reserves Summary	9

1.9	Block 2C – Trinidad & Tobago Gross PDP and Proved Reserves Reconciliation	9
2.1	Wells Drilled and Current Status	12
3.1	Operating Expenses Forecasts for Economic Analysis	14
3.2	Block C Gross (100%) Reserves	15
3.3	CNOOC’s Net Entitlement Reserves in Block C	16
3.4	CNOOC’s Pre- and Post-Tax NPV at 10% Discount Rate for its 12.5% Net Working Interest in Block C	16


FIGURES

0.1	Block 2C Location in Trinidad & Tobago	2
0.2	Block 2C Boundaries and Five Fields Location	2
2.1	Production Facilities Layout of the Greater Angostura Development Plan(Phase I)	11


APPENDIX

I.	Glossary
II.	Cashflow Analysis

	Gaffney, Cline & Associates (Consultants) Pte. Ltd.
	80 Anson Road
	#31-01C Fuji Xerox Towers Singapore 079907 Telephone: +65 6225 6951 www.gaffney-cline.com

DSA/YDH/dh/L0065/2012/KK1828.00

14th March, 2012

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 RESERVES CERTIFICATION

OF THE GREATER ANGOSTURA FIELDS

IN BLOCK 2C, TRINIDAD & TOBAGO

AS OF 31ST DECEMBER, 2011

INTRODUCTION

In accordance with the Signed Instruction of CNOOC Limited (CNOOC) dated 5th December, 2011, 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 years 2009 and 2010.

GCA visited CNOOC’s office in Beijing on 24th October, 2011 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 Greater Angostura Fields in 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 commenced on 8th May, 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 0.2) on the southern part of the Block and the Canteen North Field/Block, which is still in its exploration and appraisal phases, GCA did not estimate reserves for these areas in the previous certification and will not include it in this update report.

FIGURE 0.1

BLOCK 2C LOCATION IN TRINIDAD & TOBAGO

FIGURE 0.2

BLOCK 2C BOUNDARIES AND FIVE FIELDS LOCATION

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 November, 2011. 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, 2011.

It is GCA’s considered opinion that the estimates of oil and gas reserve volumes as of 31st December, 2011, 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, 2011, the SEC Reserves Estimates were allocated up to the end of the license contract period.

The economic tests for the 31st December, 2011 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, 2011 and this data is provided by CNOOC. The gas prices used were based on the gas sales information for 2011 provided by CNOOC, as opposed to the 2009 GSA pricing, as there is a large discrepancy between the two that CNOOC has been unable to explain. 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 its cost share through 2010 from the transaction on 27th May, 2009, plus updates for the 2010 certification. For this update, CNOOC provided its cost share in 2011. GCA estimated the Fixed OPEX and Variable OPEX for the operation based on forecast production profiles. These costs were not escalated but kept constant throughout the evaluation period.

CNOOC’s net entitlement 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 2011 sales prices, provided by CNOOC. It should be noted, however, that the 2011 realised gas prices were much higher than provided for the year end 2009 work, but no clarification has been provided by CNOOC.

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).

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, 2011.

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 of which may be used in this report, is attached as Appendix I.

The total proved reserves covered by this report is only about 0.2% of CNOOC's total proved reserves as of 31st December, 2011. This is based on information provided by CNOOC.

1. RESULTS SUMMARY

1.1 In-Place Volumes

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

TABLE 1.1

BLOCK 2C – TRINIDAD & TOBAGO STOIIP & GIIP VOLUMETRIC ESTIMATION

(GROSS 100% VOLUMES)

	Low		Best		High
Field	Oil	Gas	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
Aripo	11	301	27	413	34	521
E Kairi Horst	8	65	10	73	11	98
Kairi	146	392	165	464	190	613
Canteen	62	58	70	65	85	85
Total	227	816	271	1015	319	1317

1.2 Estimated Ultimate Recovery

Table 1.2 presents the Estimated Ultimate Recoveries (EURs) of Low, Best and High volumetric estimates within the Block 2C.

TABLE 1.2

BLOCK 2C – TRINIDAD & TOBAGO ESTIMATED ULTIMATE RECOVERY ESTIMATION

(GROSS 100% VOLUMES)

	Low		Best		High
Field	Oil	Gas	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
Aripo	-	243	-	343	-	449
E Kairi Horst	-	38	-	59	-	85
Kairi	55.7	288	57.5	380	59.6	496
Canteen	23.6	40	25.5	45	27.4	76
Total	79.3	609	83.0	828	86.9	1,106

Note: Totals may not add exactly due to rounding errors.

1.3 Net Reserves

Table 1.3 presents the net entitlement to Proved Developed Producing (PDP), Proved, Probable and Possible oil and gas reserves attributable to CNOOC’s working interests (WI) as of 31st December, 2011 and which were estimated in accordance with SEC Final Rules. The economic cut offs were applied following Economic Limit Tests (ELTs) using costs and prices which are un-escalated throughout the period of calculation.

TABLE 1.3

BLOCK 2C – TRINIDAD & TOBAGO CNOOC NET ENTITLEMENT RESERVES

AS OF 31st DECEMBER, 2011

	PDP		Proved		Probable		Possible
Field	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
Aripo	0.00	11.8	0.00	11.9	0.00	4.3	0.00	3.8
E Kairi Horst	0.00	0.0	0.00	2.3	0.00	1.1	0.00	0.8
Kairi	0.70	0.0	0.86	17.4	0.09	2.3	0.10	2.4
Canteen	0.24	0.0	0.33	2.5	0.09	0.1	0.09	0.7
Total	0.94	11.8	1.18	34.1	0.18	7.7	0.19	7.7

Notes:

1. All Proved, Probable and Possible reserves are Developed.

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

1.4 Gross Reserves

Gross reserves, corresponding to the above Net Reserves, are presented in Table 1.4 for reference only. They represent a 100% interest in commercially recoverable volumes as of 31st December, 2011, i.e. after economic cutoffs have been applied. Gross reserves include volumes attributable to third parties (government and other working interest partners).

TABLE 1.4

BLOCK 2C – TRINIDAD & TOBAGO GROSS RESERVES

AS OF 31st DECEMBER, 2011

	PDP		Proved		Probable		Possible
Field	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
Aripo	0.00	190.5	0.00	190.5	0.00	69.8	0.00	64.1
E Kairi Horst	0.00	0.0	0.00	36.9	0.00	17.1	0.00	13.8
Kairi	14.07	0.0	17.37	277.0	1.89	38.5	2.21	40.9
Canteen	4.73	0.0	6.62	39.9	1.94	1.5	1.82	12.3
Total	18.80	190.5	23.99	544.3	3.83	126.9	4.03	131.0

Notes:

1. All Probable and Possible reserves are Developed.

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

1.5 Net Present Values

The NPVs as of 31st December, 2011 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 in cases of PDP, Proved (1P), Proved+Probable (2P) and Proved+Probable+Possible (3P).

TABLE 1.5

BLOCK 2C – TRINIDAD & TOBAGO CNOOC NET PRESENT VALUES

AS OF 31st DECEMBER, 2011

Case	Pre -Tax NPV10	Post -Tax NPV10
	U.S.$ MM	U.S.$ MM
PDP	118.5	118.5
Proved (1P)	195.9	195.9
Proved + Probable (2P)	225.5	225.5
Proved + Probable + Possible (3P)	254.4	254.4

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 prices and un-escalated costs. 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, 2011) except in instances where alternate prices are prescribed by contract. The gas prices used were based on the 2011 average realised prices, as provided by CNOOC.

1.6 PDP and Proved Reserves Reconciliation

Tables 1.6 and 1.7 summarize the Net Entitlement PDP and Proved reserves and the reconciliation of changes to the Net Entitlement reserves for the years ending 31st December, 2009, 2010 and 2011.

Tables 1.8 and 1.9 summarize the Gross PDP and Proved reserves, corresponding to the above Net Reserves, and the reconciliation of changes to the Gross reserves for the years ending 31st December, 2009, 2010 and 2011.

TABLE 1.6

BLOCK 2C – TRINIDAD & TOBAGO

CNOOC NET ENTITLEMENT PDP AND PROVED RESERVES SUMMARY

Reserves Category	31st December, 2009		31st December, 2010		31st December, 2011
	Oil	Gas	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
PDP	1.97	0.0	0.99	0.0	0.94	11.8
Proved	1.97	46.0	1.15	42.9	1.18	34.1

TABLE 1.7

BLOCK 2C – TRINIDAD & TOBAGO

CNOOC NET ENTITLEMENT PDP AND PROVED RESERVES RECONCILIATION

	PDP		Proved
Reserves Reconciliation	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
Reserves as of 31st December, 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 December, 2010	0.99	0.0	1.15	42.9
Annual Production	-0.59	-6.6	-0.59	-6.6
Revisions	0.54	18.4	0.62	-2.2
Extensions and Discoveries	-	-	-	-
Improved Recovery	-	-	-	-
Acquisition and Sales	-	-	-	-
Reserves as of 31st December, 2011	0.94	11.8	1.18	34.1

TABLE 1.8

BLOCK 2C – TRINIDAD & TOBAGO

GROSS PDP AND PROVED RESERVES SUMMARY

	31st December, 2009		31st December 2010		31st December, 2011
Reserves Category	Oil	Gas	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
PDP	17.99	0.0	16.88	0.0	18.80	190.5
Proved	17.99	574.2	16.96	595.5	23.99	544.3

TABLE 1.9

BLOCK 2C – TRINIDAD & TOBAGO

GROSS PDP AND PROVED RESERVES RECONCILIATION

	PDP		Proved
Reserves Reconciliation	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
Reserves as of 31st December, 2009	17.99	0.0	17.99	574.2
Annual Production	-3.45	0.0	-3.45	0.0
Revisions	2.34	0.0	2.34	21.3
Extensions and Discoveries	-	-	-	-
Improved Recovery	-	-	-	-
Acquisition and Sales	-	-	-	-
Reserves as of 31st December, 2010	16.88	0.0	16.96	595.5
Annual Production	-4.70	-53.0	-4.70	-53.0
Revisions	6.62	243.5	11.73	1.8
Extensions and Discoveries	-	-	-	-
Improved Recovery	-	-	-	-
Acquisition and Sales	-	-	-	-
Reserves as of 31st December, 2011	18.80	190.5	23.99	544.3

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 commenced in May, 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 follow:

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

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, 2011, a total of 37 wells, including exploration and appraisal wells, have been drilled in the Greater Angostura area (Table 2.1, not including Canteen North Field/Block). The Angostura complex currently contains 16 oil wells capable of production, 4 gas producing wells and 6 gas injection wells. 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, E Kairi Horst and Canteen fields is coming from 16 wells drilled from three WPPs, with processing and separation facilities on a single CPP. An estimated 57 MMbbl of oil have been produced through to the end of December, 2011. Oil is sent to an onshore storage facility on the southeast coast of Trinidad via pipeline and then exported from a Catenary Anchor 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.

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	1	16
Gas Injector	0	0	4	2	0	6
Converted Gas Injector	0	0	1	0	0	1
Gas Producer	0	3	0	0	1	4
Dry Hole	0	0	0	1	1	2
Total	3	4	17	10	3	37

2.2.2	Phase II – Angostura Gas Project

	The field production had been shut in for the Gas Project facilities installation from 20th September, 2010 and was resumed on 11th January, 2011.

	The Angostura Gas Project (Phase II) includes 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) has been installed for production and compression of the sales gas. The GEP equipment includes inlet separation, export compression and sales metering.

	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 have been installed from the GEP (36” to Trinidad and 12” to Tobago). These export pipelines are owned and installed by NGC (the National Gas Company of Trinidad & Tobago). Additional facilities have been installed on GEP on behalf of NGC and include 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 installed those components on behalf of NGC with ownership transferred to them at first gas per the Gas Sales Contract (GSC).

	The first gas sale started in May, 2011.

2.3	Well Status and Plans

Gas production from Angostura began in 2011, with three producers from the Aripo Field (ARI-A01 ST, ARIA02 ST1, ARI-A03). Another gas producer in E Kairi Horst Field (KAI-B12), drilled and completed, will also provide production in the early phase of the Angostura gas development. The KAI-B12 used to produce oil in late 2007 and 2008, but was frequently shut-in due to high GOR production. Gas production from the Aripo and Kairi Horst fields is expected to have minimal impact on 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 existing gas injection wells in the Kairi and Canteen fields.

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.

In the Kairi Horst Field there is one oil producer and one gas producer currently shut-in.

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.

3. ECONOMIC EVALUATION

3.1 Capital Expenditure

The Capital Expenditure (CAPEX) in the gas development project is mainly the cost of the drilling campaign that began in 2011 and which will continue in 2012. Apart from the KAI-B13 well drilled, completed and produced in 2011, drilling of KAI-B14 (T5 well) and CAN-A9 are expected to be completed in 2012. CAPEX is also budgeted for the conversion of gas injectors to producers. As the PSC implies a field abandonment cost at the end of the license term, an abandonment obligation of U.S.$32 MM at the end of the contract is also assumed. 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 MM for Low Case, U.S.$25 MM for Best Case and U.S.$27 MM for High 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 (OPEX) includes processing cost and chemical consumption for the producing oil and gas. The cost of processing a barrel of oil has been estimated as U.S.$ 2.5/Bbl and the corresponding cost for producing and transporting gas has been estimated as US$ 0.2/Mscf. The cost profiles are given in 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)	1 P Case CAPEX (U.S.$MM)	1 P Case OPEX (U.S.$MM)	2 P Case CAPEX (U.S.$MM)	2 P Case OPEX (U.S.$MM)	3 P Case CAPEX (U.S.$MM)	3 P Case OPEX (U.S.$MM)
2012		29.6	37	58.3	37	61.6	37	65.0
2013		30.7	4	57.4	4	60.9	4	64.5
2014		27.2	4	55.0	4	58.7	4	62.4
2015		27.4	4	53.1	4	56.8	4	60.8
2016		22.6	10	51.2	10	55.0	10	58.8
2017		21.9		43.7		51.8		55.0
2018		16.9		33.7		43.9		50.4
2019		16.4		27.2		34.6		45.8
2020	13	11.9	16	22.2	16	28.4	16	38.3
2021	13	3.5	16	6.9	16	11.2	16	17.3

3.3 Economic Analysis

The effective date of the evaluation is 31st December, 2011.

Based on the 2011 sales price data provided to GCA, it was noted that the discount off Brent crude amounted to some U.S.$5.28/bbl, as provided by CNOOC. GCA has assumed that this discount remains constant for the life of the fields considered in this report.

The Brent price for the Reserves evaluation to SEC guidelines, as of 31st December, 2011, was U.S.$111.02/bbl, giving a realised price of U.S.$105.74/bbl for Block C crude sales. The gas price forecast, based on the GSA provided by CNOOC for the year-end 2009 Reserves Report, was based on average sales prices realised in 2011, as there did not seem to be any correlation with the GSA provided to GCA as part of the YE2009 reserves work, and amounted to a price of U.S.$3.96/Mcf.

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

3.4 Reserves

Tables 3.2 and 3.3 summarise the Gross (100%) Reserves and Net Entitlement Reserves for CNOOC’s 12.5% Net Working Interest under the PSC, as of 31st December, 2011. 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 represent the volumes attributable to CNOOC under the terms of the PSC, and are the volumetric equivalent of Cost Hydrocarbons plus Profit Share.

TABLE 3.2

BLOCK C GROSS (100%) RESERVES

AS OF 31st DECEMBER, 2011

	PDP		Proved		Probable		Possible
Field	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
Aripo	0.00	190.5	0.00	190.5	0.00	69.8	0.00	64.1
E Kairi Horst	0.00	0.0	0.00	36.9	0.00	17.1	0.00	13.8
Kairi	14.07	0.0	17.37	277.0	1.89	38.5	2.21	40.9
Canteen	4.73	0.0	6.62	39.9	1.94	1.5	1.82	12.3
Total	18.80	190.5	23.99	544.3	3.83	126.9	4.03	131.0

TABLE 3.3

CNOOC’S NET ENTITLEMENT RESERVES

IN BLOCK C

AS OF 31st DECEMBER, 2011

	PDP		Proved		Probable		Possible
Field	Oil	Gas	Oil	Gas	Oil	Gas	Oil	Gas
	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)	(MMbbl)	(Bscf)
Aripo	0.00	11.8	0.00	11.9	0.00	4.3	0.00	3.8
E Kairi Horst	0.00	0.0	0.00	2.3	0.00	1.1	0.00	0.8
Kairi	0.70	0.0	0.86	17.4	0.09	2.3	0.10	2.4
Canteen	0.24	0.0	0.33	2.5	0.09	0.1	0.09	0.7
Total	0.94	11.8	1.18	34.1	0.18	7.7	0.19	7.7

Notes:

1. All Probable and Possible reserves are Developed.

2. 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 3.4.

TABLE 3.4

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, 2011

Case	Pre -Tax NPV10 U.S.$ MM	Post -Tax NPV10 U.S.$ MM
PDP	118.5	118.5
Proved (1P)	195.9	195.9
Proved + Probable (2P)	225.5	225.5
Proved + Probable + Possible (3P)	254.4	254.4

3.6 Summary Report for CNOOC’s Filing 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 to AII.4 in Appendix II, represent CNOOC’s PDP, Proved (1P), Proved+probable (2P) and Proved+Probable+Possible (3P) Net Reserves and associated NPVs in Block 2C, respectively.

4. QUALIFICATIONS

GCA is an independent international energy advisory group of 49 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, Mr. Chew Hai Hong, Mr. Paul McGhee, Dr. Hu Yundong, and Dr. Azlan Abdul Majid. All hold degrees in geoscience, petroleum engineering or related discipline.

Mr. Ahye 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. 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. 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 25 years industry experience. 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. 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. GCA has used all assumptions, data, procedures, and methods that it considers necessary and appropriate under the circumstances to prepare this report. 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.

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 faithfully,

GAFFNEY, CLINE & ASSOCIATES (CONSULTANTS) PTE LTD

/s/ David S. Ahye

David S. Ahye

Principal

APPENDIX I

GLOSSARY

List of Standard Oil Industry Terms and Abbreviations

ABEX	Abandonment Expenditure
ACQ	Annual Contract Quantity
o API	Degrees API (American Petroleum Institute)
AAPG	American Association of Petroleum Geologists
AVO	Amplitude versus Offset
A$	Australian Dollars
B	Billion (109 )
Bbl	Barrels
/Bbl	per barrel
BBbl	Billion Barrels
BHA	Bottom Hole Assembly
BHC	Bottom Hole Compensated
Bscf or Bcf	Billion standard cubic feet
Bscfd or Bcfd	Billion standard cubic feet per day
Bm3	Billion cubic metres
bcpd	Barrels of condensate per day
BHP	Bottom Hole Pressure
blpd	Barrels of liquid per day
bpd	Barrels per day
boe	Barrels of oil equivalent @ xxx mcf/Bbl
boepd	Barrels of oil equivalent per day @ xxx mcf/Bbl
BOP	Blow Out Preventer
bopd	Barrels oil per day
bwpd	Barrels of water per day
BS&W	Bottom sediment and water
BTU	British Thermal Units
bwpd	Barrels water per day
CBM	Coal Bed Methane
CO2	Carbon Dioxide
CAPEX	Capital Expenditure
CCGT	Combined Cycle Gas Turbine
cm	centimetres
CMM	Coal Mine Methane
CNG	Compressed Natural Gas
Cp	Centipoise (a measure of viscosity)
CSG	Coal Seam Gas
CT	Corporation Tax
DCQ	Daily Contract Quantity
Deg C	Degrees Celsius
Deg F	Degrees Fahrenheit
DHI	Direct Hydrocarbon Indicator
DST	Drill Stem Test
DWT	Dead-weight ton
E&A	Exploration & Appraisal
E&P	Exploration and Production
EBIT	Earnings before Interest and Tax
EBITDA	Earnings before interest, tax, depreciation and amortisation
EI	Entitlement Interest
EIA	Environmental Impact Assessment
EMV	Expected Monetary Value
EOR	Enhanced Oil Recovery
EUR	Estimated Ultimate Recovery
FDP	Field Development Plan
FEED	Front End Engineering and Design
FPSO	Floating Production, Storage and Offloading
FSO	Floating Storage and Offloading
ft	Foot/feet
Fx	Foreign Exchange Rate
g	gram
g/cc	grams per cubic centimetre
gal	gallon

AI.1

gal/d	gallons per day
G&A	General and Administrative costs
GBP	Pounds Sterling
GDT	Gas Down to
GIIP	Gas initially in place
GJ	Gigajoules (one billion Joules)
GOR	Gas Oil Ratio
GTL	Gas to Liquids
GWC	Gas water contact
HDT	Hydrocarbons Down to
HSE	Health, Safety and Environment
HSFO	High Sulphur Fuel Oil
HUT	Hydrocarbons up to
H2S	Hydrogen Sulphide
IOR	Improved Oil Recovery
IPP	Independent Power Producer
IRR	Internal Rate of Return
J	Joule (Metric measurement of energy) I kilojoule = 0.9478 BTU)
k	Permeability
KB	Kelly Bushing
KJ	Kilojoules (one Thousand Joules)
kl	Kilolitres
km	Kilometres
km2	Square kilometres
kPa	Thousands of Pascals (measurement of pressure)
KW	Kilowatt
KWh	Kilowatt hour
LKG	Lowest Known Gas
LKH	Lowest Known Hydrocarbons
LKO	Lowest Known Oil
LNG	Liquefied Natural Gas
LoF	Life of Field
LPG	Liquefied Petroleum Gas
LTI	Lost Time Injury
LWD	Logging while drilling
m	Metres
M	Thousand
m3	Cubic metres
Mcf or Mscf	Thousand standard cubic feet
MCM	Management Committee Meeting
MMcf or MMscf	Million standard cubic feet
m3 d	Cubic metres per day
mD	Measure of Permeability in millidarcies
MD	Measured Depth
MDT	Modular Dynamic Tester
Mean	Arithmetic average of a set of numbers
Median	Middle value in a set of values
MFT	Multi Formation Tester
mg/l	milligrams per litre
MJ	Megajoules (One Million Joules)
Mm3	Thousand Cubic metres
Mm3 d	Thousand Cubic metres per day
MM	Million
MMBbl	Millions of barrels
MMBTU	Millions of British Thermal Units
Mode	Value that exists most frequently in a set of values = most likely
Mscfd	Thousand standard cubic feet per day
MMscfd	Million standard cubic feet per day
MW	Megawatt
MWD	Measuring While Drilling
MWh	Megawatt hour
mya	Million years ago
NGL	Natural Gas Liquids
N2	Nitrogen
NPV	Net Present Value

AI.2

OBM	Oil Based Mud
OCM	Operating Committee Meeting
ODT	Oil down to
OPEX	Operating Expenditure
OWC	Oil Water Contact
p.a.	Per annum
Pa	Pascals (metric measurement of pressure)
P&A	Plugged and Abandoned
PDP	Proved Developed Producing
PI	Productivity Index
PJ	Petajoules (1015 Joules)
PSDM	Post Stack Depth Migration
psi	Pounds per square inch
psia	Pounds per square inch absolute
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
cf or scf	Standard Cubic Feet
cfd or scfd	Standard Cubic Feet per day
scf/ton	Standard cubic foot per ton
SL	Straight line (for depreciation)
so	Oil Saturation
SPE	Society of Petroleum Engineers
SPEE	Society of Petroleum Evaluation Engineers
ss	Subsea
stb	Stock tank barrel
STOIIP	Stock tank oil initially in place
sw	Water Saturation
T	Tonnes
TD	Total Depth
Te	Tonnes equivalent
THP	Tubing Head Pressure
TJ	Terajoules (1012 Joules)
Tscf or Tcf	Trillion standard cubic feet
TCM	Technical Committee Meeting
TOC	Total Organic Carbon
TOP	Take or Pay
Tpd	Tonnes per day
TVD	True Vertical Depth
TVDss	True Vertical Depth Subsea
USGS	United States Geological Survey
US$	United States Dollar
VSP	Vertical Seismic Profiling
WC	Water Cut
WI	Working Interest
WPC	World Petroleum Council
WTI	West Texas Intermediate
wt%	Weight percent
1H05	First half (6 months) of 2005 (example of date)
2Q06	Second quarter (3 months) of 2006 (example of date)
2D	Two dimensional
3D	Three dimensional
4D	Four dimensional
1P	Proved Reserves
2P	Proved plus Probable Reserves
3P	Proved plus Probable plus Possible Reserves
%	Percentage

AI.3

DSAIYDH/dh/L0065/2012/KK1828.00

CNOOC- T&T

APPENDIX II

CASHFLOW ANALYSIS

DSAIYDH/dh/L0065/2012/KK1828.00

CNOOC- T&T

TABLE All.1

BLOCK 2C -TRINIDAD & TOBAGO

CNOOC PDP NET RESERVES & NPVs AS OF 31ST DECEMBER, 2011

Case: PDP
CNOOC 12.5% WI	NPV7, US$MM =	125.4
	NPV8, US$MM =	123.0
	NPV9, US$MM =	120.7
	NPV10, US$MM =	118.5
	NPV11, US$MM =	116.4
	CNOOC Net Oil Reserves, MMstb =	0.939
	CNOOC Net Gas Reserves, Bscf =	11.8

Year

WI Oil

Prod'n

WI Gas

Prod'n

Crude

Price

Gas Price

Opex

Capex

Cost

Recovered

CNOOC

Profit

Pre-Tax

Cash

Flow

Net Cash

Flow

Net Oil

Reserves

Net Gas

Reserves

Recoverable

Unrecoverable

MMstb

Bscf

US$/bbl

US$/Mscf

US$M

MMstb

Bscf

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

0.479

0.425

0.360

0.299

0.235

0.184

0.144

0.112

0.088

0.025

0.000

8.336

5.461

3.577

2.343

1.535

1.006

0.659

0.432

0.283

0.185

0.000

105.74

3.96

3,325

36,343

28,778

22,312

17,269

12,987

9,765

7,380

5,603

4,271

1,414

36,343

28,778

22,312

17,269

12,987

9,765

7,380

5,603

4,271

1,414

-3,325

36,343

28,778

22,312

17,269

12,987

9,765

7,380

5,603

4,271

1,414

-3,325

0.190

0.170

0.144

0.119

0.094

0.074

0.057

0.045

0.035

0.010

0.000

4.094

2.731

1.789

1.172

0.768

0.503

0.330

0.216

0.142

0.093

0.000

TOTAL

2.3

23.8

3,325

146,121

142,796

0.9389

11.8

Notes

1. WI oil production refers 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 based on 2011average realised

6. US$5.28/bbl discount off Brent based on information provided by CNOOC

AII.1

DSAIYDH/dh/L0065/2012/KK1828.00

CNOOC- T&T

TABLE All.2

BLOCK 2C -TRINIDAD & TOBAGO

CNOOC 1P (PO) NET RESERVES & NPVs AS OF 31ST DECEMBER, 2011

Case: 1P
CNOOC 12.5% WI	NPV7, US$MM =	210.0
	NPV8, US$MM =	205.1
	NPV9, US$MM =	200.4
	NPV10, US$MM =	195.9
	NPV11, US$MM =	191.7
	CNOOC Net Oil Reserves, MMstb =	1.184
	CNOOC Net Gas Reserves, Bscf =	34.1

Year

WI Oil

Prod'n

WI Gas

Prod'n

Crude

Price

Gas Price

Opex

Capex

Cost

Recovered

CNOOC

Profit

Pre-Tax

Cash

Flow

Net Cash

Flow

Net Oil

Reserves

Net Gas

Reserves

Recoverable

Unrecoverable

MMstb

Bscf

US$/bbl

US$/Mscf

US$M

MMstb

Bscf

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

0.631

0.587

0.469

0.374

0.287

0.220

0.170

0.131

0.101

0.028

0.000

10.044

10.615

8.035

4.126

2.480

1.580

1.025

0.000

105.74

3.96

4,625

500

1,250

4,000

1,857

1,132

1,232

1,332

806

455

354

253

44,111

42,830

38,446

34,416

32,038

24,774

15,168

10,320

7,408

3,229

41,336

43,455

39,171

35,241

31,588

25,224

15,518

10,570

7,408

3,229

-4,000

41,336

43,455

39,171

35,241

31,588

25,224

15,518

10,570

7,408

3,229

-4,000

0.244

0.228

0.187

0.149

0.115

0.088

0.068

0.052

0.040

0.011

0.000

5.104

5.010

5.023

5.036

5.224

4.016

2.108

1.272

0.791

0.513

0.000

TOTAL

3.0

68.0

11,375

7,426

252,737

248,737

1.1835

34.1

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 based on 2011 average realised

6. US$5.28/bbl discount off Brent based on information provided by CNOOC

AII.2

DSAIYDH/dh/L0065/2012/KK1828.00

CNOOC- T&T

TABLE All.3

BLOCK 2C -TRINIDAD & TOBAGO

CNOOC 2P NET RESERVES & NPVs AS OF 31ST DECEMBER, 2011

	NPV7, US$MM =	244.2
Case: 2P	NPV8, US$MM =	237.6
CNOOC 12.5% WI	NPV9, US$MM =	231.4
	NPV10, US$MM =	225.5
	NPV11, US$MM =	219.9
	CNOOC Net Oil Reserves, MMstb =	1.367
	CNOOC Net Gas Reserves, Bscf =	41.8

Year

WI Oil

Prod'n

WI Gas

Prod'n

Crude

Price

Gas Price

Opex

Capex

Cost

Recovered

CNOOC

Profit

Pre-Tax

Cash

Flow

Net Cash

Flow

Net Oil

Reserves

Net Gas

Reserves

Recoverable

Unrecoverable

MMstb

Bscf

US$/bbl

US$/Mscf

US$M

MMstb

Bscf

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

0.674

0.638

0.528

0.435

0.358

0.274

0.214

0.172

0.142

0.042

0.000

10.044

10.615

11.110

8.820

5.652

4.209

3.313

0.000

105.74

3.96

4,625

500

1,250

4,000

1,858

1,133

1,232

1,332

807

456

355

254

45,721

44,748

40,603

37,012

35,034

32,502

25,934

18,343

14,335

8,335

42,946

45,373

41,328

37,837

34,584

32,952

26,284

18,593

14,335

8,335

-4,000

42,946

45,373

41,328

37,837

34,584

32,952

26,284

18,593

14,335

8,335

-4,000

0.259

0.246

0.208

0.174

0.143

0.109

0.085

0.069

0.057

0.017

0.000

5.104

5.010

5.023

5.036

5.224

5.401

4.357

2.858

2.105

1.657

0.000

TOTAL

3.5

83.9

11,375

7,433

302,569

298,569

1.3672

41.8

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 based on 2011 average realized

6. US$5.28/bbl discount off Brent based on information provided by CNOOC

AII.3

DSAIYDH/dh/L0065/2012/KK1828.00

CNOOC- T&T

TABLE AII.4

BLOCK 2C – TRINIDAD & TOBAGO

CNOOC 3P NET RESERVES & NPVs AS OF 31ST DECEMBER, 2011

	NPV7, US$MM =	278.1
Case: 3P	NPV8, US$MM =	269.7
CNOOC 12.5% WI	NPV9, US$MM =	261.9
	NPV10, US$MM =	254.4
	NPV11, US$MM =	247.4
	CNOOC Net Oil Reserves, MMstb =	1.558
	CNOOC Net Gas Reserves, Bscf =	49.5

Year

WI Oil

Prod'n

WI Gas

Prod'n

Crude

Price

Gas Price

Opex

Capex

Cost

Recovered

CNOOC Profit Share

Pre-Tax Cash Flow

Net Cash

Flow

Net Oil

Reserves

Net Gas

Reserves

Recoverable

Unrecoverable

MMstb

Bscf

US$/bbl

US$/Mscf

US$M

MMstb

Bscf

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

0.719

0.694

0.591

0.508

0.432

0.329

0.257

0.213

0.183

0.056

0.000

10.044

10.615

11.110

11.186

9.220

6.776

0.000

105.74

3.96

4,625

500

1,250

4,000

1,860

1,135

1,234

1,334

809

458

357

256

47,376

46,792

42,923

39,805

38,150

34,828

31,981

30,190

25,539

15,779

44,601

47,417

43,648

40,630

37,700

35,278

32,331

30,440

25,539

15,779

-4,000

44,601

47,417

43,648

40,630

37,700

35,278

32,331

30,440

25,539

15,779

-4,000

0.274

0.266

0.230

0.200

0.173

0.131

0.103

0.085

0.073

0.022

0.000

5.104

5.010

5.023

5.036

5.225

5.401

5.423

5.409

4.492

3.388

0.000

TOTAL

4.0

100.3

11,375

7,451

353,362

349,362

1.5581

49.5

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 based on 2011 average realised

6. US$5.28/bbl discount off Brent based on information provided by CNOOC

AII.4

YDH/als/L0183/2012/KK1810

Gaffney,

Cline &

Associates

Gaffney, Cline & Associates

Consultants Pte. Ltd.

80 Anson Road

#31-01C Fuji Xerox Towers

Singapore 079907

Telephone: +65 6225 6951

www.gaffney-cline.com

11 April 2012

Mr Wang Qingru

Director of Reserves Management

CHINA NATIONAL OFFSHORE

OIL CORPORATION LIMITED

No 25 Chaoyangmenbei Dajie

Beijing 100010

PR China

Dear Mr Wang

GCA CONSENT LETTER

The results of our third party studies presented in the EXECUTIVE REPORT FOR RESERVES ASSESSMENT OF THE MISSAN OIL FIELDS IN EASTERN IRAQ and EXECUTIVE REPORT FOR RESERVES AUDIT OF THE GREATER ANGOSTURA FIELDS IN BLOCK 2C, TRINIDAD & TOBAGO, as of 31 December 2011, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by CNOOC Limited.

We hereby consent to the references to our name and our third party report as well as the filing of our third party report as an exhibit to CNOOC Limited's annual report on Form 20-F for the fiscal year ended 31 December 2011.

Yours sincerely,

GAFFNEY, CLINE & ASSOCIATES (CONSULTANTS) PTE LTD

/s/ David S. Ahye

David S. Ahye

Principal

UEN: 198701453N