October 10, 2013

Mr. Brad Skinner

Mr. Ronald Winfrey

Division of Corporation Finance

Securities and Exchange Commission

100 F Street, NE

Mail Stop 7010

Washington, DC 20549

U.S.A.

Re:	CNOOC Limited Form 20-F for Fiscal Year Ended December 31, 2012 Filed April 24, 2013 Comment Letter Dated August 29, 2013 File No. 001-14966

Dear Mr. Skinner and Mr. Winfrey:

We provide the following response to the comment letter from the Staff of the Securities and Exchange Commission (the “SEC”) dated August 29, 2013 with respect to the Form 20-F for the fiscal year ended December 31, 2012 of CNOOC Limited (the “Company”), which was filed on April 24, 2013 (the “2012 20-F”). For your convenience, the italicized paragraphs below restate the numbered paragraphs in the Staff’s comment letter, and the discussion set out below each such paragraph is the Company’s response to the Staff’s comments.

Form 20-F for fiscal year ended December 31, 2012

Information on the Company, page 21

Summary of Oil and Gas Reserves, page 26

1.	We are unable to locate disclosure responsive to the requirements of Item 1202(a)(6) of Regulation S-K. Explain to us where this disclosure has been provided or revise your disclosure to include the required information. Alternatively, explain to us why the disclosure is not required.

Response: The Company respectfully advises the Staff that the Company’s proved reserves estimates are prepared using standard geological and engineering methods generally accepted by the petroleum industry, and the definitions and standards of reserves required by the United States SEC. Generally accepted methods for estimating reserves include volumetric calculations, material balance techniques, production decline curves, pressure transient analysis, analogy with similar reservoirs, and reservoir simulation. The method or combination of methods used is based on professional judgment and experience. The

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Mr. Ronald Winfrey

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Company believes that the conventional technologies used by it provide a high degree of confidence in establishing reliable and consistent reserves estimates. The Company interprets Item 1202(a)(6) of Regulation S-K to apply to the use of reliable technology related to the inclusion of new technologies in the Company reserve disclosures. Therefore, the Company is of the view that the disclosure under Item 1202(a)(6) of Regulation S-K is not required. However, the related discussions on the technologies currently used to establish the appropriate level of certainty have been described in Exhibits 15.1-15.6 of the Company’s 2012 20-F.

A summary description of the methodologies described in Exhibits 15.1-15.6 is as follows:

“Our estimates are prepared using standard geological and engineering methods generally accepted by the petroleum industry, and the definitions and standards of reserves required by the United States SEC. Generally accepted methods for estimating reserves fall into three broad categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. The method or combination of methods used is based on our professional judgment and experience.”

Proved Undeveloped Reserves, page 28

You state that you converted proved undeveloped reserves of 167 MMBOE to proved developed status. This is about ten percent of your year-end 2011 PUD reserves. It appears you converted 13%, 21% and 22% in 2011, 2010 and 2009 respectively. Rule 4-10(a)(31)(ii) of Regulation S-X requires that PUD reserves have a development plan indicating that they are scheduled to be drilled within five years of initial booking as proved reserves, unless the specific circumstances justify a longer time. Please explain to us the reasons for the reduction in PUD conversion rate in 2012 and 2011. Tell us your projected conversion ratios in each of the next five years.

Response: The Company respectfully advises the Staff that its PUD conversion rate varied from year to year due to changes in development activities and the status of conversion of reserves to proved developed status. The Company’s PUD conversions are typically related to the following two types of development activities:

(1)

Completion of production infrastructure and commencement of production by production wells; and

(2)

Infill drilling of PUD wells required by development projects as production declines.

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Mr. Ronald Winfrey

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The changes in PUD conversion ratios generally result from variations in the reserves being recognized from the completion of production infrastructure and the commencement of production by production wells as well as infill drilling needs. The Company’s PUD conversion ratios have been in line with the Company’s development schedule and plan.

PUD conversion ratios in 2009 and 2010 were 21% and 22%, respectively, but decreased to 13% and 10% in 2011 and 2012, respectively. The variation of PUD conversions during these periods have primarily resulted from domestic offshore developments, mainly located in Bohai, Western South China Sea and Eastern South China Sea. For example, in 2010, 317 PUD wells were converted into proved developed reserves, which were attributable to 21 major development projects and infill drilling within 18 oil and gas fields in 2010. Whereas,

In 2011, 174 PUD wells were converted into proved developed reserves, which were attributable to 12 major development projects and infill drilling within 13 oil and gas fields; and

In 2012, 119 PUD wells were converted to proved developed reserves, which were attributable to 12 major development projects and infill drilling within 20 oil and gas fields.

The Company believes that the need for it to take more than five years from initial bookings as PUD reserves to drill certain projects of the Company can be justified by the following specific circumstance, which the Company believes is in compliance with Rule 4-10(a)(31)(ii) of Regulation S-X:

Approximately 82% of the Company’s reserves are associated with offshore activities, primarily in offshore China (Bohai, Western South China Sea, Eastern South China Sea, and East China Sea), Asia (outside China), Africa, Oceania and South America, among others. The offshore development in these areas involves the construction of centralized production platforms and development of production feedstock over numerous years in order to economically justify project development.

Gas fields in China, Australia and Indonesia are associated with long-term gas supply or LNG sales contracts, for which development is required to maintain delivery that is obligated to occur after five years.

In Canada, the synthetic crude oil and bitumen PUDs are related to the reserves required to supply the Long Lake upgrader over its expected life. These wells are expected to be converted into developed status during the next 27 years.

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The development of PUDs relating to the above projects is not expected to be completed within five years due to the specific circumstances associated with the relevant development activities and delivery obligations. All projects that do not have these associated development requirements or delivery obligations are expected to be developed within five years from initial bookings as PUD reserves.

The Company expects that its PUD conversion rate to continue to vary considerably from year to year in the future due to differences in the stage and characteristics of projects associated with its crude oil and gas producing assets. The low conversion rates in 2011 and 2012 may not be indicative of future PUD conversion rates. Therefore, the Company believes that the reductions in PUD conversion rate in 2011 and 2012 are attributable to the Company’s business condition and does not affect the Company’s compliance with Rule 4-10(a)(31)(ii) of Regulation S-X.

The Company’s projected conversion ratios in each of the next five years are set out in the table below:

Year	PUD Conversions
Year	Regions Primarily Distributed	Gross Wells	PUDs to be converted (MMBOE)	% of Total PUDs (2,041.5 MMBOE as of December 31, 2012)
2013	China, North America, South America, Asia(excluding China)	1,485	326.5	16.0%
2014	China, Oceania, North America, South America, Asia(excluding China)	1,443	408.4	20.0%
2015	China, North America, South America, Asia(excluding China)	1,555	470.2	23.0%
2016	China, South America	917	467.9	22.9%
2017	China, South America, Africa, Oceania	734	168.8	8.3%
Sub-total		6,134	1,841.9	90.2%
Remaining PUDs			199.6	9.8%

PUD reserves at the end of 2012 that are expected to remain undeveloped by 2017 are in the amount of 199.6 MMBOE, which represent less than 6% of the Company’s total proved reserves (3,491.9 MMBOE) at the end of 2012. Please refer to the Company’s response to Comment No.3 below for more information on specific circumstances justifying reporting these quantities as proved reserves.

The Company expects its exploration and development to continue to generate additional PUD reserves in the future, which are expected to be evaluated for booking in accordance with Rule 4-10(a)(31)(ii) of Regulation S-X.

Proved Undeveloped Reserves, page 28

3.	You indicated that 142.7 million BOE of your proved reserves were first booked before 2008. In addition to these quantities, tell us whether, as of December 31,

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Mr. Ronald Winfrey

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2012, there are any other proved undeveloped reserves which are not scheduled to be developed within five years of initial booking as proved reserves. If so, disclose the quantities involved and the specific circumstances that justify reporting the quantities as proved reserves. See Rule 4-10(a)(31) of Regulation S-X and Item 1203 of Regulation S-K.

Response: The Company respectfully advises the Staff that the Company’s proved reserves have been included in the business plan and have been scheduled for development. As disclosed in the Company’s response to Comment No.2 above, more than 90% of the PUD reserves at the end of 2012 were scheduled to be converted into developed status over next 5 years by 2017. The Company only books proved reserves for which development is scheduled to commence after more than five years if these proved reserves satisfy the SEC’s standards for attribution of proved status and the Company’s management has reasonable certainty that these proved reserves will be produced.

Other than the 142.7 MMBOE reserves that have been disclosed, there are 199.6 MMBOE (please refer to the table included in the Company’s response to Comment No.2 above) in aggregate of the Company’s PUD reserves that are not scheduled to be developed before 2017. The specific circumstances justifying reporting these quantities as proved reserves are set out as follows:

82.7 MMBOE PUDs attributed to the Canadian oil sand Long Lake/K1A property: The synthetic crude oil PUDs are related to reserves that will be upgraded by the Long Lake upgrader over its expected life, while the bitumen PUDs represent reserves that will be produced when the upgrader is not in operation. The Company plans to complete the conversion within the next 27 years while additional SAGD wells are expected to be drilled to offset declines from the initial wells, which are part of the initial field development plan and have been included in the project investment decision;

42.6 MMBOE PUDs in the EGINA deep-water oilfield located in Nigeria: The initial development decision included the construction of additional platforms and drilling and completions of wells under deep water in depth of 1,500 meters. The Company expects the PUDs to be converted as development continues till 2020 and the associated production to be concluded within the contract period;

36.1 MMBOE PUDs at the TANGGUH gas-field located in Southeast Asia: PUDs are associated with a gas supply agreement requiring the Company to meet delivery obligations over the contract period. To maintain delivery, additional wells are required to be drilled. As the wells are developed, the associated reserves are converted into developed status. The associated PUD drilling and conversion are

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expected to occur during the 12-year period from 2018 to 2029 in accordance with the delivery obligations pursuant to the gas supply agreement;

28.7 MMBOE PUDs of Project Bridas: This project is a joint venture requiring the investment and cooperation of joint venture partners to advance this project. The Carina Phase I, Vega Pleyade and Carina Phase II development projects were included in the original CMA-1 Development Plan as agreed in mid-2001. The project development was expected to take a long period through developing each field by sequence, including Carina/Aries first, followed by Vega Pleyade, and Carina Phase II at the end. This project has been developed in accordance with the original plan with partial delays due to (i) the severe downturn in the Argentine’s economy in January 2002 and (ii) the debt default by the Argentine’s government, which temporarily prevented Argentina from any foreign direct investment. Although it is expected to take longer than five years to complete the three phases of this project, Carina Phase I is expected to be completed soon and the remaining two phases are being invested extensively, with the external infrastructure being installed for Vega Pleyade, which is expected to be completed and commence production in 2016. The remaining PUD reserves of 28.7 MMBOE associated with Carina Phase II are expected to be developed over a 5-year period from 2018 to 2022 to maintain the overall stable production as the productions of Carina Phase I and Vega begin to decline.

9.5 MMBOE of PUDs primarily in Western South China Sea and NWS are associated with gas supply agreements. As with the TANGGUH gas-field discussed above, the wells are required to be drilled in the future to meet delivery obligations. These PUDs are expected to remain undeveloped beyond five years of initial booking as proved reserves but will be developed when required to meet gas delivery obligations.

Notes to Consolidated Financial Statements, page F-11

Reserve quantity information, page F-79

4.	FASB ASC Paragraph 932-235-50-5 requires “appropriate explanation of significant changes” for line items in the reconciliation of your disclosed proved reserves. Please revise your disclosure to explain the details/circumstances of discoveries and extensions for the years 2010, 2011 and 2012.

Response: The Company respectfully notes the Staff’s comment. The following description explains the details/circumstances of discoveries and extensions for the years 2010, 2011 and 2012 requested by the Staff:

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In 2010, the significant change for discoveries and extensions in the amount of 414 MMBOE was primarily attributable to:

Offshore China:

Bohai: the discoveries and extensions of oil and gas reserves in the amount of 70.20 MMBOE and 49.86 MMBOE, respectively, for example, Jinzhou 20-2N, Kenli 10-1 and Bozhong 34-1W;

Western South China: the discoveries and extensions of oil and gas reserves in the amount of 6.92 MMBOE and 56.11 MMBOE, respectively, for example, Block DF1-1-14 and Yacheng 13-1; and

Eastern South China: the discoveries and extensions of oil and gas reserves in the amount of 95.46 MMBOE and 31.26 MMBOE, respectively, for example, Liwan 3-1 and Huizhou 25-8;

Overseas:

Africa: the extensions of oil and gas reserves in the amount of 75.07 MMBOE; and

Asia (excluding China): the extensions of oil and gas reserves in the amount of 22.66 MMBOE.

In 2011, the significant change for discoveries and extensions in the amount of 289 MMBOE was primarily attributable to:

Offshore China:

Bohai: the discoveries and extensions of oil and gas reserves in the amount of 72.02 MMBOE and 60.23 MMBOE, respectively, for example, Qinhuangdao 33-1S and Penglai 13-2;

Western South China: the discoveries and extensions of oil and gas reserves in the amount of 18.77 MMBOE and 33.72 MMBOE, respectively, for example, Wushi 17-2 and Weizhou 11-7N; and

Eastern South China: the discoveries and extensions of oil and gas reserves in the amount of 63.48 MMBOE and 28.27 MMBOE, respectively, for example, Enping 24-2 and Lufeng 7-2;

In 2012, the significant change for discoveries and extensions in the amount of 546 MMBOE was primarily attributable to:

Offshore China:

Bohai: the discoveries and extensions of oil and gas reserves in the amount of 79.16 MMBOE and 45.07 MMBOE, respectively, for example, Penglai 9-1;

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Western South China: the discoveries and extensions of oil and gas reserves in the amount of 139.55 MMBOE and 8.90 MMBOE, respectively, for example, Dongfang 13-2; and

Eastern South China: the discoveries and extensions of oil and gas reserves in the amount of 30.05 MMBOE and 42.50 MMBOE, respectively, for example, Liuhua 16-2 and Xijiang 24-3; and

Overseas:

North America: the extensions of oil and gas reserves in the amount of 187.00 MMBOE.

In response to the Staff’s comment, starting from the Company’s Form 20-F for the fiscal year ending December 31, 2013, the Company will provide appropriate explanation of significant changes for line items in the reconciliation of the Company’s disclosed proved reserves as required by FASB ASC Paragraph 932-235-50-5 as applicable.

Exhibit 15.6

On page three, your third party engineering report states “The estimated reserves and future net income amounts presented in this report, as of December 31, 2012, are based on the reserve audit review that RPS performed for PAE’s year-end 2012 reserve report.” This differs from your statement on page 29 “we have engaged independent third party consulting firms, including Ryder Scott Company, L.P., Gaffney, Cline & Associates (Consultants) Pte Ltd., Lee Keeling and Associates, Inc., and McDaniel & Associates Consultants Ltd. to perform annual estimates for our proved oil and gas reserves under our consolidated subsidiaries.” As RPS audited seven percent of your reserves and is omitted from this description, it appears that third parties estimated materially less reserves than you have disclosed. Please revise your disclosure to clearly indicate the function(s) performed by your third party engineers.

Response:

The Company respectfully advises the Staff that the function performed by RPS on the reserves of Pan American Energy (“PAE”) at the end of 2012 was reserve estimate, rather than reserve audit. As the relevant reserve disclosure in the Company’s 2012 20-F is based on RPS’s estimate, rather than PAE’s internal estimate, RPS has issued an amended Third Party Letter, which is attached as Exhibit A hereto, to clarify that: “The estimated reserves and future net income amounts presented in this report, as of December 31, 2012, are based on the reserve estimation that RPS performed for PAE’s year-end 2012 reserve report.” In addition, since the Company owns 20% participating interests through holding 50% interest in Bridas Corporation, which holds 40% interests in PAE, the Company used equity-method to account for its portion of reserves in PAE, and did not include RPS in the disclosure of third party consulting firms that performed

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estimates for reserves under its consolidated subsidiaries on page 29 of the 2012 20-F.

In providing the above responses, and in response to the SEC’s request, we hereby acknowledge that:

CNOOC Limited is responsible for the adequacy and accuracy of the disclosure in its filings with the Commission;

Staff comments or changes to this disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

CNOOC Limited may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

* * *

Should you have any questions regarding the foregoing or require additional information, please do not hesitate to contact me at fax number (86-10) 8452-1441or email address zhonghua@cnooc.com.cn or Li He of Davis Polk & Wardwell LLP at telephone number (86-10) 8567-5005 or email address li.he@davispolk.com. Thank you very much for your assistance.

Sincerely,

By:	/s/ Hua Zhong
Name:	Hua Zhong
Title:	Chief Financial Officer

cc:	Li He, Davis Polk & Wardwell LLP

Exhibit A

411 N. Sam Houston Parkway E., Suite 400, Houston, Texas 77060-3545 USA

T +1 281 448 6188 F +1 281 488 6189 W www.rpsgroup.com

January 31, 2013

CNOOC Limited

No. 25, Chaoyangmenbei Dajie

Dongcheng District

Beijing 100010, P.R. China

Gentlemen:

As per your request, RPS has prepared an estimate of the proved reserves, future production and income attributable to certain leasehold interests owned by CNOOC Limited as of December 31, 2012. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register, including all references to Regulation S-X and Regulation S-K (SEC regulations). Our third party revision, completed on January 30, 2013 and presented herein, was prepared for public disclosure by CNOOC Limited in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves and future net income amounts presented in this report, as of December 31, 2012, are based on the reserve estimation that RPS performed for PAE’s year-end 2012 reserve report. In our opinion, the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

CNOOC Limited holds 50% interest in Bridas Corporation and Bridas Corporation holds 40% interests in PAE. Therefore CNOOC Limited, through Bridas Corporation, owns 20% of participating interests in PAE.

The subject properties are located in Argentina and Bolivia, South America. The properties evaluated by RPS account for a portion of CNOOC Limited’s total net proved reserves as of December 31, 2012.

	Area	CNOOC Limited Net WI %
ARGENTINA	Cerro Dragon	20.0%
	Anticlinal Funes	16.0%
	Piedra Clavada	20.0%
	Koluel Kayke	20.0%
	Acambuco	10.4%

BOLIVIA

Caipipendi

5.0%

The estimated reserves and future net income amounts presented in this report, as of December 31, 2012, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized in the following table.

SEC PARAMETERS

Estimated Net CNOOC Limited Reserves and Income Data

As of December 31, 2012

NET REMAINING RESERVES		Total Argentina	Total Bolivia	Total
Oil/Condensate/ Gasoline M Bbl	Proved
	Developed	97,673	3,358	101,031
	Undeveloped	93,374	631	94,005
	Total Proved	191,047	3,989	195,036
GAS MM cf * includes sales 8 field usage	Proved
	Developed	199,311	91,945	291,256
	Undeveloped	98,566	23,425	121,991
	Total Proved	297,877	115,370	413,247
GAS Sales MM cf	Proved
	Developed	142,891	90,900	233,791
	Undeveloped	65,804	23,158	88,962
	Total Proved	208,695	114,058	322,753

INCOME DATA (M USS)		Total Argentina	Total Bolivia	Total
Future Gross Revenue	Proved
	Developed	4,797,512	288,068	5,085,580
	Undeveloped	4,421,396	75,073	4,496,469
	Total Proved	9,218,908	363,141	9,582,049
OPEX & CAPEX	Proved
	Developed	2,404,590	82,562	2,487,152
	Undeveloped	2,650,165	34,439	2,684,604
	Total Proved	5,054,755	117,001	5,171,756
Future Net Income (FNI)	Proved
	Developed	2,392,921	205,506	2,598,427
	Undeveloped	1,771,232	40,634	1,811,866
	Total Proved	4,164,153	246,140	4,410,293
Discounted FNI @ 10 %	Proved
	Developed	1,203,570	122,852	1,326,422
	Undeveloped	373,218	20.108	393,326
	Total Proved	1,576,788	142,960	1,719,748

Note: Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes reported include gas sales and fuel gas expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions and income data are expressed as thousands of U.S. dollars (M$).

Note: Values by property are showed in Table 1 included in the report.

Note: The future gross revenue is after the deduction of royalty and turnover taxes in Argentina, and royalty IDH & YPFB Part in Bolivia. The deductions incorporate the normal direct costs of operating the wells, recompletion costs, development costs, certain abandonment costs, which are shown as “other” deductions. The future net income is before the deduction of foreign government income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

Total Proved Discounted Future Net Income As of December 31, 2012
Discount Rate (Percent)	Argentina (MUS$)	Bolivia (MUS$)	Total (MUS$)
7.0%	$ 2,023,885	$ 164,897	$ 2,188,782
8.0%	$ 1,856,194	$ 156,969	$ 2,013,163
9.0%	$ 1,708,111	$ 149,679	$ 1,857,790
10.0%	$ 1,576,788	$ 142,960	$ 1,719,748
11.0%	$ 1,459,864	$ 136,755	$ 1,596,619

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Rules and Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from Part 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind-pipe categories.

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.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At CNOOC Limited’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production, unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to CNOOC Limited for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance

characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through December 31, 2012 in those cases where such data were considered to be definitive. The volumetric method, analogy or a combination of methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. The volumetric analysis utilized pertinent well and seismic data supplied to RPS by PAE that were available through December 31, 2012. The data utilized from the analogues as well as the well and seismic data incorporated into our volumetric analysis were considered sufficient and appropriate for the purpose thereof.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. All quantities of reserves within the same reserve category must meet the SEC definitions.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.

PAE has made all of the material accounts, records, geological and other data required for this investigation available to us. In preparing our forecast of future proved production and income, we have relied upon data furnished by CNOOC Limited joint venture partner. RPS considers the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with SEC regulations. In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated, in which case an estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by PAE. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by PAE. The differentials furnished by PAE were reviewed by us for their reasonableness using information furnished by PAE for this purpose.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of PAE and include only those costs directly applicable to the leases or wells. The operating costs

include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by PAE. No deduction was made for loan repayments, interest expenses or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by PAE and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimates of the net abandonment costs furnished by PAE were accepted without independent verification. Current costs used by PAE were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

RPS is a multi-disciplinary consultancy, providing technical, commercial and project management support services in the fields of operations, geoscience, engineering and health, safety and environment to the energy sector worldwide. RPS’s clients around the world include governments, national oil companies, integrated majors, independents, and start-ups, legal and financial institutions.

RPS USA is part of the larger UK based RPS Group plc that employs nearly 5,000 staff based in offices located in the UK, Ireland, the Netherlands, USA, Canada, Australia and Brazil.

As an independent and experienced consultancy company with a global capability, RPS is well qualified to provide both technical and economic assessments of reserves/resources, prospect evaluation, field discoveries and producing fields. In the Oil and Gas Sector, RPS personnel have provided SPE and SEC and Competent Persons reports for inclusion in both public and private circulars for funding purposes. We have provided investors with confidential valuations and assessments during mergers and acquisitions. Asset appraisal and valuation have always been a core element of RPS consulting business.

As indicated above, this study was based on data supplied by PAE. The supplied information was reviewed for reasonableness from a technical perspective. As is common in oil field situations, basic physical measurements taken over time cannot be verified independently in retrospect. As such, beyond the application of normal professional judgment, such data must be accepted as representative. While we are not aware of any falsification of records or data pertinent to the results of this study, RPS does not warrant the accuracy of the data and accepts no liability for any losses from actions based upon reliance on data, which is subsequently shown to be falsified or erroneous.

RPS personnel who prepared this report are degreed professionals with the appropriate qualifications and experience to complete the reserve estimation work. RPS and its staff do not claim expertise in accounting, legal and environmental matters, and opinions on such matters do not form part of this report.

The results and conclusions represent informed professional judgments based on the data available and time frame allowed to perform this work. No warranty is implied or expressed that actual results will conform to these estimates. RPS accepts no liability for actions or losses derived from reliance on this report or the data on which it was based.

Terms of Usage

The results of our third party study, presented in report form herein, 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.

Very truly yours,

RPS

/s/ Victor Wayne Taylor

Victor Wayne Taylor

PE License# 71417

Principal Engineer