CORRESP 1 filename1.htm
 
 
 
October 26, 2010

Mr. Mark C. Shannon
Mr. Mark Wojciechowski
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, 2009
Filed April 23, 2010
Comment Letter Dated September 17, 2010
File No. 1-14966

Dear Messrs. Shannon and Wojciechowski:

We provide the following response to the comment letter from the Staff of the Securities and Exchange Commission (the “SEC”) dated September 17, 2010 with respect to the Form 20-F for the fiscal year ended December 31, 2009 of CNOOC Limited (the “Company”), which was filed on April 23, 2010 (the “2009 20-F”).  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, 2009

Risk Factors, page 12

Changes in laws and regulations could have an adverse effect .... , page 14

1.
We note your disclosure on page 14 concerning the risks related to your non-PRC interests, as well as your acknowledgment of your “geographic risk profile,” a reference to the fact that your operations and assets are mainly in the People’s Republic of China. Please add risk-factor disclosure that specifically addresses your geographic risk profile stemming from the concentration of your market risk in China. Alternatively, tell us why you believe this does not pose a material risk.

 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 2
 
 
The Company respectfully notes that its geographic risk profile stemming from the concentration of its market risk in China primarily includes potential changes in PRC laws and regulations and other potential changes in the PRC market, which has been addressed in various risk factors in its 2009 20-F, including the following:

·
The risk factor entitled “Our future prospects largely depend on our capital expenditure plans, which are subject to various risks” on pages 12 and 13, which discusses that the Company’s capital expenditure plans are subject to the economic, political and other conditions in the PRC, among other factors;

·
The risk factor entitled “Changes in laws and regulations could have an adverse effect on our operation” on page 14, which discusses that the Company’s operations are subject to laws and regulations in countries in which it operates and that the Company currently has operations and assets mainly in the PRC and also in various foreign countries and regions;

·
The risk factor entitled “Government control of currency conversion and future movements in exchange rates may adversely affect our operations and financial condition” on pages 15 and 16, which discusses that the Company’s operation and financial condition may be adversely affected by the PRC government’s control of currency conversion; and

·
The risk factor entitled “Certain legal restrictions on dividend distribution may have a material adverse effect on our cash flows” on page 16, which discusses that the Company’s cash flows may be adversely affected by the PRC government’s restriction on dividend distribution.

In order to further clarify the Company’s risks related to potential changes in PRC laws and regulations, the Company will add another stand-alone risk factor (in italics) in “Item 3. Key Information—D. Risk Factors” in the Form 20-F for the fiscal year ending December 31, 2010 of the Company (the “2010 20-F”) as follows:

 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 3
 
Changes in PRC laws and regulations could have an adverse effect on our operation

Our operations and assets are mainly in the Peoples Republic of China.  The PRC government exercises control over the PRC petroleum industry, including licensing, exploring, producing, distributing, pricing, taxing, importing, exporting and allocating of various resources.  We have benefited from various favorable PRC government policies, laws and regulations that have been enacted to encourage the development of the offshore petroleum industry. We cannot guarantee that the legal and fiscal regimes affecting our businesses will remain substantially unchanged or that we will continue to benefit from favorable PRC government policies.  For instance, in 2006, the State Council of the PRC issued the Decision to Impose a Special Oil Gain Levy and the Ministry of Finance promulgated the Management Rules on the Administration of Special Oil Gain Levy, effective March 26, 2006.  For detailed information on the Special Oil Gain Levy, see “Item 4. Information on the Company—B. Business Overview—Regulatory Framework—Special Policies Applicable to the Offshore Petroleum Industry in China.”  In addition, see “—Government control of currency conversion and future movements in exchange rates may adversely affect our operations and financial condition” and “—Certain legal restrictions on dividend distribution may have a material adverse effect on our cash flows” for detailed information on the risks related to government control of currency conversion and the risks related to certain legal restrictions on dividend distribution, respectively.

In addition, existing PRC regulations require us to obtain various PRC government licenses and other approvals, including in some cases approvals for amendments and extensions of existing licenses and approvals to conduct exploration and development activities off the shores of China.  If we are unable to obtain any necessary approvals, our reserves and production would be adversely affected.

Our controlling shareholder, CNOOC, or its affiliates’ activities ... , page 15

2.
We note from pages 13 and 45 that CNOOC indirectly owns 64.41 % of your shares and is your controlling shareholder. We are aware of a September 2008 news report that CNOOC was a partner in certain oil exploratory leases in Cuba, of a July 2009 news report that CNOOC was a major end-user of the Sudanese Dar Blend crude, and of an April 2010 news report that CNOOC was participating in talks to finalize a $16 billion deal to develop the North Pars gas field and construct a liquefied natural gas plant in Iran. As you know, Cuba, Sudan, and Iran are countries that are identified by the U.S. Department of State as state sponsors of terrorism, and are subject to U.S. economic sanctions and export controls. Please provide us with updated information, since your letter to us dated May 21, 2007, regarding (i) any dividends, loans or other payments you have made to CNOOC that you know have been used or that may be used to fund operations in Cuba, Iran or Sudan; and (ii) any of your directors, officers or employees who also are engaged in activities associated with CNOOC and Cuba, Iran, or Sudan.

 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 4
 
(i) The Company respectfully advises the Staff that it has not made any loans to CNOOC and has not imposed any restriction on how its shareholders (including CNOOC) may use the dividends distributed by the Company.  The Company believes it would be unreasonable and against the principle of corporate governance for a company to impose limitations on how a shareholder could use the dividend it receives.  In addition, the Company is not aware that any of its other payments made to CNOOC have been directly used to fund operations in Cuba, Iran or Sudan.
 
(ii) The Company respectfully advises the Staff that: (A) it is not aware that any of its directors, officers or employees is engaged in activities associated with CNOOC and Cuba; and (B) there has been no updated information with respect to the directors and senior management of the Company which are engaged in activities associated with CNOOC and Iran or Sudan since the Company's letter to the SEC dated May 21, 2007; however, please find all information about the directors and senior management of the Company and their positions on pages 61 through 68 of the Company’s 2009 20-F.

Information on the Company, page 16

History and Development, page 16

3.
We note your disclosure on pages 16 and 17 regarding certain undertakings which your controlling shareholder, China National Offshore Oil Corporation, has made to you. Please disclose how those undertakings are memorialized.

The Company respectfully notes that it has filed with the SEC the form of the undertaking agreement it entered into with CNOOC as Exhibit 10.27 to its registration statement on Form F-1 filed with the SEC (File Number: 333-10862).  The Company confirms that there has been no subsequent amendment to the undertaking agreement.

Business Overview, page 17

4.
You describe yourself as an “independent” exploration and development company. Given that the PRC holds a 64.41 % controlling interest in CNOOC and that it also holds controlling interests in PetroChina and Sinopec, clarify your statement that you are independent.

The Company notes that, in the oil and gas industry, “independent oil and gas company” typically refers to oil and gas companies that primarily engage in exploring, developing and producing crude oil and natural gas upstream, such as the Company.  In contrast, “integrated oil and gas company” refers to a company that engages in both upstream operations (including exploration and production of oil and gas) and downstream operations (including refining, petrochemical and marketing).  In this regard, the statement that the Company is an “independent” oil and gas company accurately describes the Company’s status in the oil and gas industry.
 
 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 5
 
5.
In this regard, we note your disclosure throughout the filing regarding your relationships with PetroChina and Sinopec, which are also controlled by the Chinese government. In footnote 34 on page F-59, for example, you disclose that Sinopec and PetroChina are by far your largest customers, and on page 36 you state that these companies are also your principal competitors. Please describe more comprehensively the interrelationship between you, PetroChina, Sinopec, and the Chinese government, clarifying the implications of your position as part of a state-controlled oil and gas oligopoly. For example, and without limitation, discuss the following:

·
The extent to which the Chinese government influences the planning and execution of your business plan and operations.
·
The extent to which the Chinese government coordinates policies or actions on behalf of you and these other related companies; For example, clarify whether you and either PetroChina and Sinopec pursue the same production sharing contracts or other ventures and, if so, the role of the government in the selection.

The Company respectfully notes that, since its business operations are primarily conducted in the PRC, it is obligated to comply with all applicable PRC laws, regulations and rules.  Please see “Item 4. Information of the Company—B. Business Overview—Regulatory Framework” beginning on page 41 of the Company’s 2009 20-F.  The Company’s business operations are managed by its senior management, who are supervised by the Company’s board of directors, eight of which are non-executive directors, on behalf of its shareholders.  Other than the relevant laws, rules, and regulations that may affect the Company’s operation, the PRC government does not impose any specific requirement upon the Company’s business activities and daily operations.

The Company respectfully advises the Staff that the PRC government does not interfere with the planning or execution of the Company’s business plan and operations.  The PRC government does not coordinate policies or actions on behalf of the Company.  The Company advises the Staff that it makes independent decisions based on its own commercial interests when it pursues any production sharing contracts or other ventures.
 
 
 
 

 

 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 6
 
The Company respectfully notes that it is an independent commercial entity. On the one hand, the Company enters into arm’s-length transactions with PetroChina and Sinopec in the ordinary course of business from time to time.  In particular, the downstream business of PetroChina and Sinopec, as the Company’s customers, purchases a substantial portion of the crude oil and natural gas produced by the Company upstream.  On the other hand, PetroChina and Sinopec also compete with the Company for certain upstream exploration, development and production projects as well as other business opportunities.  The sales to Sinopec and PetroChina and the competition with Sinopec and PetroChina have been disclosed on page 35 (under “Item 4. Information on the Company—B. Business Overview—Sales and Marketing”) and page 36 (under “Item 4. Information on the Company—B. Business Overview—Competition”), respectively, of the 2009 20-F.

Delivery Commitment, page 34

6.
We note your disclosure that you did not have any material delivery commitments at December 31, 2009. Please tell us how you considered the take-or-pay contracts you describe on page F-23 with respect to your disclosures pursuant to Item 1207 of Regulation S-K.
 
The Company advises the Staff that it is aware that it has certain delivery commitments under the take-or-pay contracts described on page F-23.  However, the Company believes that there is no material information to be disclosed as required by Item 1207 of Regulation S-K as the annual sales from the largest gas contract signed by the Company contributed to only approximately 3% of the total oil and gas sales in 2009. Moreover, gas sales accounts for no more than 7% of the Company’s total oil and gas sales.  Therefore, the Company does not think there is material delivery commitment.
 
Operating Hazards and Uninsured Risks, page 40

7.
We note your disclosure on page 40 concerning your insurance coverage. In light of recent events involving the oil spill in the Gulf of Mexico, please review your disclosure to ensure that you have disclosed all material information regarding your potential liability in the event that one of your rigs is involved in an explosion or similar event in any of your offshore locations. For example, and without limitation, please address the following:

·
Disclose the applicable policy limits related to your insurance coverage;
·
Disclose whether your existing insurance would cover any claims made against you by or on behalf of individuals who are not your employees in the event of personal injury or death, and whether your customers would be obligated to indemnify you against any such claims; and
 
 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 7
 
·
Clarify your insurance coverage with respect to any liability related to any resulting negative environmental effects, including your coverage for operational third-party liability with respect to onshore and offshore activities, including environmental risks such as oil spills.

In this regard, discuss what remediation plans or procedures you have in place to deal with the environmental impact that would occur in the event of an oil spill or leak from your offshore operations.

The Company respectfully advises the Staff that the Company has reviewed its insurance coverage disclosure on page 40 in light of recent events involving the oil spill in the Gulf of Mexico and believes that it has disclosed all material information regarding its potential liability in the event that one of its rigs is involved in an explosion or similar event in any of its offshore locations. In addition, the Company provides the Staff with the following supplemental information:

·
The Company has purchased a number of insurance policies with varying policy limits to meet the Company’s risk management requirements and cover the Company’s potential liability in the event that one of its rigs is involved in an explosion or similar event in any of its offshore locations.  The policy limits and other terms and conditions of these insurance policies comply with all applicable laws and regulations in the PRC and other relevant jurisdictions.

·
The Company carries third-party liability insurance policies to cover claims made against the Company by or on behalf of individuals who are not its employees in the event of personal injury or death.  In addition, the Company imposes contractual requirements upon its contractors to purchase insurance policies that cover their liabilities for the personal injuries of their own employees.  The Company’s customers are obligated to indemnify the Company against such claims.

·  
The Company carries third-party liability insurance policies to cover the legal liabilities for environmental damages resulting from the Company’s onshore and offshore activities, including oil spills.

 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 8
 
The Company respectfully advises the Staff that, for all of its offshore operations, the Company has conducted comprehensive environmental impact evaluations and adopted emergency plans to deal with potential oil spills.  Pursuant to the requirements of the PRC government, the evaluations and plans for the Company’s offshore operations in the PRC have been reviewed and approved by the industry experts and been filed with the PRC government.  The evaluations and plans for the Company’s offshore operations overseas have complied with the legal and regulatory requirements of the relevant local jurisdictions.  In addition, the Company relies on both its seven oil spill emergency handling bases in the PRC and Oil Spill Response Limited, a large oil spill preparedness and response organization, to deal with the environmental impact that would occur in the event of an oil spill or leak from the Company’s offshore operations.

Operating and Financial Review and Prospects, page 46

F. Tabular Disclosure of Contractual Obligations, page 61

8.
It is unclear from your disclosure whether the long term debt you present in this table includes the related interest payments. Please tell us how you have considered footnote 46 of SEC Release 33-8350, Commission Guidance Regarding Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The Company respectfully advises the Staff that the long-term debt in the table does not include the related interest payments.  The Company has considered footnote 46 of SEC Release 33-8350, Commission Guidance Regarding Management’s Discussion and Analysis of Financial Condition and Results of Operations, and believes that borrowing interest is not material to the Company’s future cash requirements primarily because:

(1)
Since the amount of interest expense for bank and other borrowings is RMB474 million and the amount of net cash inflows from operating activities is RMB52,858 million for the year ended December 31, 2009, borrowing interest only accounts for 0.90% of net cash flows from the Company’s operating activities; and

(2)
Since the Company had unutilized banking facilities in the amount of approximately RMB174,843 million as at December 31, 2009 (as disclosed in Note 32(i) on page F-57 of the Company’s 2009 20-F), the Company believes that it has sufficient cash to meet its future cash requirements, including the payment of borrowing interest.

Therefore, the Company believes that the borrowing interest is not material to the Company’s future cash requirements and the disclosure of contractual obligations on page 61 of the 2009 20-F is sufficient.

 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 9
 
Related Party Transactions, page 74

9.
We note your disclosure in footnote 29 on page F-53 that you have not included certain transactions with other state-owned enterprises in your related-party transaction disclosure because you consider the transactions to be “in the ordinary course of business and there are no indicators that the Group influenced, or was influenced by, those state-owned enterprises.” Please tell us what transactions you are omitting, and explain your basis for concluding that these transactions do not meet the disclosure threshold under Item 7.B(1)-(2) of Form 20-F.

The Company respectfully advises the Staff that the transactions it is omitting include, but not limited to, the following:

·     
Sales and purchase of goods and services;
·     
Purchases of assets, goods and services;
·     
Leases of assets; and
·     
Bank deposits and borrowings.

The Company believes that these transactions with other state-owned enterprises (other than CNOOC and its associates), including PetroChina and Sinopec, are conducted in the ordinary course of business and arm’s-length in nature, or are not otherwise material.  In response to the Staff’s comment, the Company will make additional disclosures (in italics) after the paragraph in “Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transaction—Overview” in its 2010 20-F as follows:

Apart from transactions with CNOOC and its associates, we have transactions with other state-owned enterprises, including, but not limited to, the following:
 
·    
Sales and purchase of goods and services;
·    
Purchases of assets, goods and services;
·    
Leases of assets; and
·    
Bank deposits and borrowings.

These transactions are conducted in the ordinary course of business.
 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 10
 

Engineering Comments

Risk Factors, page 12

The oil and gas reserve estimates in this annual report may require substantial revision as a result of future drilling, testing, production and oil and gas price changes, page 12

10.
We note your statement, “Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove to be incorrect over time.” Please expand this to discuss also the factors over which you do have control, e.g. recovery factor estimates, projected production decline rates.

The Company respectfully notes that the factors involved in estimating reserves over which it does have control include the recovery factor estimates and the projected production decline rates.  In order to clarify these factors, the Company will make additional disclosures (in italics) in “Item 3. Key Information—D. Risk Factors” in its 2010 20-F as follows:

“The oil and gas reserve estimates in this annual report may require substantial revision as a result of future drilling, testing, production and oil and gas price changes
 
The reliability of reserve estimates depends on a number of factors, including the quality and quantity of technical and economic data, the prevailing oil and gas prices for our production, the production performance of reservoirs, extensive engineering judgments, and the fiscal regime in the PRC and overseas where we have operations or assets.
 
Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove to be incorrect over time.  In addition, many of the factors involved in estimating reserves over which we do have control, such as the recovery factor estimates and the projected production decline rates, may also prove to be incorrect over time.  Consequently, the results of drilling, testing and production may require substantial upward or downward revisions in our initial reserves data.”

 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 11
 
Extreme weather conditions may have a material and adverse impact on us and could result in losses that are not covered by insurance, page 14

11.
We note your risk factors do not address potential losses due to insufficient control of drilling wells. Please expand your discussion to include the consequences of loss of hydrocarbon containment, i.e. blow outs. Address offshore incidents separately.

The Company respectfully notes that it has disclosed the potential losses due to insufficient control of drilling wells, including blowouts, and other offshore operational risks on page 40 of the 2009 20-F under “Item 4. Information on the Company—B. Business Overview—Operating Hazards and Uninsured Risks.” Since almost all of the Company’s operations in 2009 were offshore, the operational risks discussed in the Company’s 2009 20-F refers to the Company’s offshore operational risks.  In order to clarify the risks related to potential blowouts and address offshore incidents separately, the Company will add a stand-alone risk factor (in italics) in “Item 3. Key Information—D. Risk Factors” in its 2010 20-F as follows:

“Blowout incidents may result in platform explosion, fire accidents and oil spills

Our operations are mainly conducted offshore.  Although we have adopted standard workflow procedures and various measures to control the risks of blowouts, we cannot assure you that we could avoid the potential losses caused by blowouts.  If one or more blowout incidents occur, platform explosions and fire accidents caused by blowouts may result in casualties, property losses and environmental damages, which may have a material adverse effect on our business, financial condition and results of operation.”

Business Overview, page 17

Competitive cost structure, page 18

12.
With a view toward possible disclosure, please explain to us the “new technologies” that you have adopted to minimize your offshore China lifting costs.

The Company notes that the new technologies adopted by the Company mainly include (1) the reservoir protection technology during workover that shortens the shutdown and watercut recovery periods of oil wells and (2) the offshore power grid interlink technology that reduces the electricity consumption and lowers costs through resource sharing.  To the extent applicable, the Company will make additional disclosure for the new technologies in the competitive strength entitled “Competitive cost structure” in “Item 4. Information on the Company—B. Business Overview—Competitive Strengths” in its 2010 20-F.
 
 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 12
 
Proved Undeveloped Reserves, page 25

13.
We note the disclosure that your proved undeveloped reserves decreased by 131 million BOE in 2009 including 333 million BOE converted to the proved developed category. Paragraph (b) of Item 103 of Regulation S-K requires the disclosure of “material changes in proved undeveloped reserves that occurred during the year, including proved undeveloped reserves converted into proved developed reserves.” Please amend your document to expand your disclosure to include the other sources of change to your PUD reserves, e.g. discoveries and extensions, revisions.

The Company respectfully advises the Staff that the Company’s proved undeveloped reserves, or PUD, in 2009 was 1,375 million BOE, representing a decrease of 131 million BOE from 1,506 million BOE in 2008, primarily due to 333 million BOE of PUD converted into the proved developed reserves, 18 million BOE of PUD output and 3 million BOE of PUD sold, partially offset by new discoveries and extensions that increased PUD by 178 million BOE and revisions that increased PUD by 45 million BOE.  The Company will add similar disclosure of material changes in proved undeveloped reserves that will occur during 2010 in its 2010 20-F.

Bohai Bay, page 28

14.
We note your statement, “Because of our streamlined management, the decline rates of existing oilfields in Bohai Bay have been slowed over time.” Please explain to us the role of “streamlined management” in the decline rates of Bohai Bay fields.

The Company respectfully notes that “streamlined management” refers to the reservoir management measures and the production management measures adopted by the Company to streamline operation management and slow down the decline rates of existing oilfields in Bohai Bay, including various measures for water injectors, such as stratified waterflooding and acidification, and various measures for production wells, such as acidification, major repair and using big pump to increase liquid production.

 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 13
Oil and Gas Production, Production Prices and Production Costs, page 31

15.
Paragraph (b)(2) of Item 1204 of Regulation S-K specifies the disclosure of the average production cost, not including ad valorem and severance taxes, per unit of production. On page 18, you state “Lifting costs consist of operating expenses and production taxes.” Please amend your document to modify the “Average Lifting Cost” table to present the unit production costs without production tax as well as the production tax per BOE.

The Company respectfully advises the Staff that the table below presents the Company’s unit production costs without production tax in the years of 2007, 2008 and 2009.  The Company will replace the “Average Lifting Cost” column on page 31 in conformity with the table below in its 2010 20-F to comply with Item 1204(b)(2) of Regulation S-K.

   
Average Production Cost
 
   
(US$/boe)
 
2009
     
Offshore China
    7.23  
Overseas
       
Asia
    17.10  
Oceania
    6.94  
Africa
    8.72  
North America
    13.66  
Subtotal
    11.85  
Total
    8.04  
         
2008
       
Offshore China
    6.32  
Overseas
       
Asia
    17.81  
Oceania
    7.86  
Subtotal
    14.71  
Total
    7.54  
         
2007
       
Offshore China
    5.34  
Overseas
       
Asia
    17.69  
Oceania
    6.76  
Subtotal
    13.98  
Total
    6.49  

 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 14
Oil and Gas Properties, Wells, Operations, and Acreage, page 34

16.
We note the “Undeveloped Acreage (km2)” table. Paragraph (b) of Item 1208 of Regulation S-K specifies the disclosure of minimum remaining terms of material leases and concessions. If applicable, please amend your document to comply with Item 1208.

The Company respectfully advises the Staff that the Company has considered the disclosure required by Item 1208(b) of the Regulation S-K and does not believe it has any material leases or concessions to be disclosed under Item 1208(b) of Regulation S-K.

Production Sharing Formula, page 38

17.
We note that the two line items payable to the PRC government – production tax and royalty – are either a share of production or a share of revenue from production. With a view towards possible disclosure:

·     
Please explain to us the distinctions between these items; and
·     
Tell us whether your disclosed proved reserves are net of royalty due the PRC government.

The Company respectfully notes that

·     
The production tax is levied based on production volume and is calculated at 5% of the related revenue, while the royalty representing the entitlement of the government (i.e. a share of production) is assessed at rates ranging from 0% to 12.5% of annual gross production.  The production tax is tax deductible under PRC tax laws.

·     
The Company’s disclosed proved reserves are net of royalty due to the PRC government.

Exhibit 15.1

18.
We note that the Ryder Scott report did not present the benchmark oil and gas prices or the average adjusted prices used in the estimation of proved reserves. Please procure a third party report that includes these items.

The Company notes that Ryder Scott Company, L.P. (“Ryder Scott”) has revised its report as Exhibit A attached to this letter.  The benchmark oil and gas prices and the average adjusted prices used in the estimation of proved reserves have been presented in the section entitled “Hydrocarbon Prices” on pages 6 and 7 of the revised Ryder Scott report.
 
 
 
 

 
 

Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 15
 
 
19.
This report is filed pursuant to Item 1202(a)(8) of Regulation S-K. It is therefore inappropriate to suggest that only CNOOC may rely on it without written consent, as is done in the last paragraph of this exhibit. Amend the report to remove that limitation.

The Company notes that the revised Ryder Scott report as Exhibit A attached to this letter has complied with Item 1202(a)(8) of Regulation S-K by replacing the last paragraph with the follows in the section entitled “Terms of Usage” on page 9 of the revised report:

“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.

We have provided CNOOC with a digital version of the original signed copy of this report letter.  In the event there are any differences between the digital version included in filings made by CNOOC and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.”

Exhibit 15.2

20.
We note that the Gaffney Cline report did not present the date on which the report was completed and the professional qualifications of the person responsible for the report. In addition, they report that they acted as an independent auditor while you state that they estimated your reserves at Trinidad and Tobago (page 20). Please procure a third party report without these shortfalls.

 
The Company respectfully notes that:

·    
Gaffney, Cline & Associates (“GCA”) completed its report on March 12, 2010, which is presented on the first page of the report.

·    
Mr. David S. Ahye is the person responsible for the GCA report.  He holds a B.Sc (Hons) in Chemical Engineering, is a member of the Society of Petroleum Engineers, the Society of Professional Well Log Analysts, the Geological Society of Trinidad and Tobago, the South East Asia Petroleum Exploration Society, and has more than 30 years industry experience worldwide.  GCA has revised its report as Exhibit B attached to this letter, which includes the professional qualifications of Mr. Ahye in the fourth paragraph of the section entitled “3. Qualifications” on page 7 of the revised report.
 
 
 
 

 
 
 
Mr. Mark C. Shannon
Mr. Mark Wojciechowski
Page 16
 
·    
The GCA’s audit is comprehensive with independent checks on key parameters, including the audit of the seismic interpretation, re-interpretation of four key wells, and an independent estimation of the in-place volumes and reserves on the basis of geoscience, engineering and economic analysis.
 
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) 6401-6650 or email address zhonghua@cnooc.com.cn or Show-Mao Chen of Davis Polk & Wardwell LLP at telephone number (86-10) 8567-5001 or email address show-mao.chen@davispolk.com.  Thank you very much for your assistance.

Sincerely,
 
     
By:
/s/ Hua Zhong  
Name:  Hua Zhong  
 
 
Title:  Chief Financial Officer  
     
 
cc:
Show-Mao Chen, Davis Polk & Wardwell LLP
KC Yau, Ernst & Young
 
 
 

 
 
 
EXHIBIT A

CNOOC LIMITED




 


Estimated
 
Future Reserves and Income
 
Attributable to Certain
 
Interests
 
 
 
 
 
SEC Parameters
 
 
 
 
 
As of
 
December 31, 2009
 
 
 

 

RYDER SCOTT COMPANY  PETROLEUM CONSULTANTS

 

 
 

 

 
 
   HOUSTON, TEXAS 77002-5235
FAX (713) 651-0849
TELEPHONE (713) 651-9191
 
 
 
 
March 8, 2010
 
 
CNOOC Limited

No. 25 Chaoyangmenbei Dajie
Dongcheng District
Beijing 100010
China

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production and income attributable to certain interests of CNOOC Limited (CNOOC) as of December 31, 2009. The subject properties are located in the countries of Australia, China, Indonesia and Nigeria. 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 (SEC regulations). Our third party study, completed on February 28, 2010 and presented herein, was prepared for public disclosure by CNOOC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of CNOOC’s total net proved reserves as of December 31, 2009. Based on information provided by CNOOC, the third party estimate conducted by Ryder Scott addresses over 99 percent of the total proved developed net liquid hydrocarbon reserves, over 99 percent of the total proved developed net gas reserves, 100 percent of the total proved undeveloped net liquid hydrocarbon reserves and 100 percent of the total proved undeveloped net gas reserves of CNOOC.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2009, 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.

 
 
 
1200, 530  8TH AVENUE, S.W. CALGARY, ALBERTA T2P 3S8 TEL (403) 262-2799 FAX (403) 262-2790
621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258
 
 
 
 

 

 
 
CNOOC Limited
March 8, 2010
Page 2

 
SEC PARAMETERS
Estimated Net Reserves and Income Data
Attributable to Certain Interests of
CNOOC Limited
As of December 31, 2009 

 
   
Proved
 
   
Developed
             
   
Producing
   
Non-Producing
   
Undeveloped
   
Total Proved
 
Net Remaining Reserves
                       
Oil/Condensate – Barrels
    795,164,736       94,753,842       762,225,376       1,652,143,954  
Plant Products – Barrels
    8,710,153       1,005,315       3,904,181       13,619,649  
Gas – MMCF
    1,965,442       280,339       3,652,222       5,898,003  
                                 
Income Data (M$)
                               
Future Gross Revenue
  $ 50,840,156     $ 6,314,581     $ 55,879,553     $ 113,034,290  
Deductions
    18,816,739       2,625,224       28,740,333       50,182,296  
Future Net Income (FNI)
  $ 32,023,417     $ 3,689,357     $ 27,139,220     $ 62,851,994  
Discounted FNI @ 10%
  $ 24,855,573     $ 2,355,074     $ 12,904,924     $ 40,115,571  
 


Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” 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$).

The future gross revenue is after royalty and government profit share of in-kind hydrocarbons and deduction of value added (VAT) taxes. The deductions incorporate the normal direct costs of operating the wells, windfall profit taxes, recompletion costs, development costs and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal or 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. Liquid hydrocarbon reserves account for approximately 78 percent and gas reserves account for the remaining 22 percent of total future gross revenue from proved reserves.

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.

 
      Discounted Future Net Income
As of December 31, 2009
 
  Discount Rate
  Percent
 
Total
Proved (M$)
 
7  
 
$45,357,317
 
8  
 
$43,493,589
 
9  
 
$41,749,642
 
11  
 
$38,582,435
 


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

 
 

CNOOC Limited
March 8, 2010
Page 3



Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 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.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves. Non-hydrocarbon or inert gas volumes have been excluded from the reserves reported herein.

Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. 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’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

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. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

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 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. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with CNOOC the net economic
 

 
RYDER SCOTT COMPANY  PETROLEUM CONSULTANTS
 
 
 

 
 
 
CNOOC Limited
March 8, 2010
Page 4


benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of CNOOC’s representations regarding such contractual information should be construed as a legal opinion on this matter.

Ryder Scott did not evaluate the country and geopolitical risks in the countries where CNOOC operates or has interests. CNOOC’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which CNOOC owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

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 the Securities and Exchange Commission’s Regulations 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.

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. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding
 

 
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CNOOC Limited
March 8, 2010
Page 5


 
proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

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.

The proved reserves for the properties included herein were estimated by performance methods, the volumetric methods or a combination of performance and volumetric methods. The following table summarizes the approximate percent of reserves estimated by each of these methods.

   
Approximate Percent Proved Reserves Estimated by the Various Methods
 
Method
 
Liquid Hydrocarbons
    Gas  
 
Developed
    Undeveloped     Developed     Undeveloped  
Performance
    50%       7%       43%       0%  
Volumetric
    12%       92%       39%       96%  
Combination
    38%       1%       18%       4%  


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 October 31, 2009 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by CNOOC and were considered sufficient for the purpose thereof. The volumetric method was 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 Ryder Scott by CNOOC that were available through November 30, 2009. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

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. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

CNOOC has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by CNOOC with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, VAT taxes, windfall profit taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or


RYDER SCOTT COMPANY  PETROLEUM CONSULTANTS
 
 
 

 
 
 
CNOOC Limited

March 8, 2010
Page 6


differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by CNOOC. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues 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 the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “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. 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 CNOOC. 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.

CNOOC furnished us with the above mentioned average prices in effect on December 31, 2009. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below

RYDER SCOTT COMPANY  PETROLEUM CONSULTANTS
 
 
 

 
 
 
CNOOC Limited
March 8, 2010
Page 7


summarizes the “benchmark prices” and “price reference” used for the geographic areas included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

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 and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by CNOOC. The differentials furnished by CNOOC were reviewed by us for their reasonableness using information supplied by CNOOC for this purpose.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.


Geographic Area
Product
Price Reference
Average
Benchmark
Prices
Average
Realized
Prices
   
Daqing
$58.84/Bbl
 
 
Oil/Condensate
Duri
$54.31/Bbl
$54.83/Bbl
China
  Tapis
$63.99/Bbl
 
 
NGLs
Jinzhou
$490.04/MT
$45.35/Bbl
 
Maoming
$612.88/MT
 
Gas
Gas Sales Agreements
$5.00/MCF
   
Ardjuna
$59.35/Bbl
 
   
Cinta
$57.83/Bbl
 
 
Oil/Condensate
Dubai
$64.40/Bbl
$58.39/Bbl
Asia
 
Lalang
$62.90/Bbl
 
   
Widuri
$57.88/Bbl
 
   
WTI Cushing
$61.18/Bbl
 
 
NGLs
Dubai
$64.40/Bbl
$51.09/Bbl
 
Gas
JCC
$60.60/Bbl
$3.27/MCF
   
SoCal Border (ICE)
$3.65/MMBTU
 
Oceania
Oil/Condensate
NWS Condensate
$54.52/Bbl
$54.52/Bbl
NGLs
Saudi CP
$511.25/MT
$62.44/Bbl
 
Gas
JCC
$60.60/Bbl
$3.24/MCF
Africa
Oil/Condensate
Brent (DTD)
$60.15/Bbl
$59.30/Bbl


The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of CNOOC 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
 

 
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CNOOC Limited

March 8, 2010
Page 8


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 CNOOC. 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 CNOOC 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 estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by CNOOC were accepted without independent verification.

The proved non-producing and undeveloped reserves in this report have been incorporated herein in accordance with CNOOC’s plans to develop these reserves as of December 31, 2009. The implementation of CNOOC’s development plans as presented to us and incorporated herein is subject to the approval process adopted by CNOOC’s management. As the result of our inquires during the course of preparing this report, CNOOC has informed us that the development activities included herein have been subjected to and received the internal approvals required by CNOOC’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to CNOOC. Where appropriate, CNOOC has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, CNOOC has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Certain development of proved undeveloped gas fields in the Tangguh LNG Project in Indonesia and Northwest Shelf Venture LNG Project in Australia, were scheduled beyond the SEC nominal 5 year development period because the gas deliverability of these fields are not needed within this period. CNOOC Limited and its partners anticipated for these fields to be developed prior to the expiration of the long term LNG sales and purchase agreement period.

Current costs used by CNOOC were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.


RYDER SCOTT COMPANY  PETROLEUM CONSULTANTS
 
 
 

 
 
 
CNOOC Limited
March 8, 2010
Page 9


Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to CNOOC Limited. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

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.

We have provided CNOOC with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by CNOOC and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

 
 
Very truly yours,
 
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
   
HG/sm


RYDER SCOTT COMPANY  PETROLEUM CONSULTANTS


 
 

 





Professional Qualifications of Primary Technical Engineer

The conclusions presented in this third party report for CNOOC Limited dated March 8, 2010 are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Harris Ghozali was the primary technical person responsible for the estimate of the reserves, future production and income presented herein.

Mr. Ghozali, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1997, is a Senior Vice President and an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Ghozali served in a number of engineering positions with ExxonMobil. For more information regarding Mr. Ghozali’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Ghozali earned a Bachelor of Science degree in Petroleum Engineering with High Scholastic Honors from the Colorado School of Mines in 1990 and a Master of Science degree in Petroleum Engineering from the University of Houston in 1997. He is a registered Professional Engineer in the State of Texas and also a member of the Society of Petroleum Engineers.

As part of his 2009 continuing education hours, Mr. Ghozali attended an internally presented 13 hours of formalized SEC-related training as well as a day long public forum, and/or various professional society presentations specifically on the new SEC regulations relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Ghozali attended an additional 7 hours of formalized in-house training as well as 10 hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. Mr. Ghozali is also an instructor and has taught several one day and three day seminars on Hydrocarbon Reserves and Resources Evaluation Methods.

Based on his educational background, professional training and more than 19 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Ghozali has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.



RYDER SCOTT COMPANY  PETROLEUM CONSULTANTS
 
 
 
 

 



PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)



PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC Regulations”. The SEC Regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein).

Reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve some degree of uncertainty. 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. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

 
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PETROLEUM RESERVES DEFINITIONS
Page 2



Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.


RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

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).


PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

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

 

RYDER SCOTT COMPANY  PETROLEUM CONSULTANTS
 
 
 
 

 
 
 
PETROLEUM RESERVES DEFINITIONS
Page 3



(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.

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(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 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.

 


[Remainder of this page is left blank intentionally.]



 

RYDER SCOTT COMPANY  PETROLEUM CONSULTANTS
 
 
 
 
 

 
 
 
RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

 
and

 
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE),

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)



Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).


DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

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

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.


RYDER SCOTT COMPANY  PETROLEUM CONSULTANTS


 
 

 


 
RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 2



Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In
Shut-in Reserves are expected to be recovered from:
(1)  
completion intervals which are open at the time of the estimate but which have not yet started producing;
(2)  
wells which were shut-in for market conditions or pipeline connections; or
(3)  
wells not capable of production for mechanical reasons.

Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.


UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

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.



 



RYDER SCOTT COMPANY  PETROLEUM CONSULTANTS
 
 
 
 

 
 
EXHIBIT B
 
 
 

 

 
 

 

EXECUTIVE REPORT FOR RESERVES CERTIFICATION &
ECONOMIC EVALUATION OF GREATER ANGOSTURA FIELDS
IN BLOCK 2C, TRINIDAD & TOBAGO
 
 
Prepared for

CHINA NATIONAL OFFSHORE OIL CORPORATION LIMITED
 
 


MARCH, 2010

 
 
 

 
 


 


The Americas
Europe, Africa, FSU
  Asia Pacific
 
and the Middle East
 
1360 Post Oak Blvd.,
Bentley Hall, Blacknest
80 Anson Road
Suite 2500
Alton, Hampshire
31-01C Fuji Xerox Towers
Houston, Texas 77056
United Kingdom GU34 4PU
Singapore 079907
Tel: +1 713 850 9955
Tel: +44 1420 525366
Tel: +65 6225 6951
Fax: +1 713 850-9966
Fax: +44 1420 525367
Fax: +65 6224 0842
email: gcah@gaffney-cline.com
email: gcauk@gaffney-cline.com
email: gcas@gaffney-cline.com
     
and at Argentina     -     Brazil     -     Kazakhstan     -     Russia     -     UAE     -     Australia
  www.gaffney-cline.com
     
     
     
CNOOC
Copy No. 1
  KK1498
 
 
 

 
 
 
GCA   Gaffney, Cline & Associates (Consultants) Pte Ltd
Technical and Management Advisers to the Petroleum Industry Internationally Since 1962
 
 
Registration No. 198701453N
 
80 Anson Road, #31-01C
Fuji Xerox Towers
Singapore 079907
Telephone: +65 6225 6951
Facsimile: +65 6224 0842
email:gcas@gaffney-cline.com
www.gaffney-cline.com
     
     
YDH/jbi/L0399/2009/KK1498   12th March, 2010


Mr. Sun Bingyi
Director of Reserves Office
CHINA NATIONAL OFFSHORE
OIL CORPORATION LIMITED
No 25 Chaoyangmenbei Dajie
Beijing 100010, P.R. China

Dear Mr. Sun,

EXECUTIVE REPORT FOR RESERVES CERTIFICATION &
ECONOMIC EVALUATION OF GREATER ANGOSTURA FIELDS
IN BLOCK 2C, TRINIDAD & TOBAGO


1.
GENERAL SUMMARY

Gaffney, Cline & Associates (GCA) has been contracted by China National Offshore Oil Corporation Limited (CNOOC) for an independent reserves certification and economic evaluation for its 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 1.1). The fields 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 1.2), based on separate fluid contacts and initial pressures in the Angostura Oligocene reservoir and has been in 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. Sales of natural gas are expected to commence in 2011 following the fabrication and installation of additional facilities in the fields as part of the Angostura Gas Project.

The Block 2C Production Sharing Contract (PSC) between President of Trinidad and Tobago, Ministry of Energy and Energy Industries (MOEEI), BHP Petroleum (Trinidad) Inc and Elf Petroleum Trinidad BC was originally signed on 22nd April, 1996. GCA understands that CNOOC, through Chaoyang Petroleum (BVI) Ltd (Chaoyang), a CNOOC jointly-controlled entity, acquired a minority interest in Block 2C from Talisman Energy Inc (TLM) on 27th May, 2009. Chaoyang acquired from TLM a 100% equity interest in Talisman Trinidad Ltd (TTL), which held a 25% working interest under a PSC in Block 2C. CNOOC owns 50% equity interest of Chaoyang. The operator of Block 2C, BHP Billiton, holds a 45% working interest. The other partner Total holds 30%. The expiry date of Block 2C production contract is April, 2021, with an option to be extended by 5 years.
 
 
                             
                             
 UNITED KINGDOM    UNITED STATES    SINGAPORE    AUSTRALIA    ARGENTINA    BRAZIL    KAZAKHSTAN    RUSSIA
 
 
 

 
                                                                                                                                               


FIGURE 1.1

BLOCK 2C LOCATION IN TRINIDAD & TOBAGO
 

 
FIGURE 1.2

BLOCK 2C BOUNDARIES AND FIVE FIELDS LOCATIONS
 


     
CNOOC
2
  KK1498

 
 

 
 
 
 
There have been 36 wells drilled, including 8 exploration/appraisal wells, 17 oil producers (11 in Kairi, 5 in Canteen, 1 in E Kairi Horst), 6 gas injectors ( 4 in Kairi, 2 in Canteen), 3 shut-in gas producers (in Aripo), and 2 dry holes (1 each in Canteen and E Kairi Horst). Production data provided to GCA shows the cumulative oil production to August, 2009 is 47 MMbbl and the production rate is 14.9 MBbl/d.

In carrying out the review, 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 re-interpreted four key wells (Kairi-1, Canteen-1, Aripo-1 and Angostura-1) and checked and verified the Operator’s volumetric analysis. Well and reservoir performance were reviewed employing decline curve analysis and material balance techniques.

The results presented in this report are based upon information and data made available to GCA on or before 30th October, 2009. 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, 2009.

It is GCA’s considered opinion that the estimates of oil and gas reserve volumes as of 31st December, 2009, 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, 2009, the PD and 1P SEC reserves estimates were allocated till 2018 while the 2P and 3P SEC reserves estimates were allocated up to the end of the license contract period.

The economic tests for the 31st December, 2009 reserve volumes incorporated oil sales pricing levels based on the average actual sales price of Calypso crude oil available on the first day of each month in 2009 and this data is provided by CNOOC. The gas prices used were based on the gas pricing formulae agreed upon in the Gas Sales Agreement. Oil and gas prices were not escalated throughout the evaluation period.

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

CNOOC has provided historical cost data and 2009 Budget summary. GCA estimated the Fixed OPEX and Variable OPEX for the operation based on these and actual production. These costs were not escalated and kept constant throughout the evaluation period.

CNOOC’s net reserve volumes are derived by converting calculated net revenues accruing to CNOOC under the terms of the relevant petroleum contract into equivalent barrels of oil or thousands of cubic feet of natural gas utilising the average of actual 2009 sales price in the case of oil and anticipated gas contract prices in the case of gas. The CNOOC net revenue interest volumes reported in this document represent those amounts that are determined to be attributable to CNOOC’s net
 
     
CNOOC
3
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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, 2009.

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.

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.

The firm’s senior partners, officers, and employees have no direct or indirect interest holding in either CNOOC or its affiliated companies. GCA’s remuneration was not in any way contingent upon reported reserve estimates. No representations are made herein in respect of property title or encumbrances thereon. The economic analyses presented have been utilized solely for the calculation of net reserves and do not represent assessments of market value. This report has been prepared for CNOOC and should not be used for purposes other than those for which it is intended.

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

 
     
CNOOC
4
  KK1498

 
 

 
 


2.
RESULTS SUMMARY

2.1
In-Place Volumes

Table 2.1 presents the Gross STOIIPs and GIIPs (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 2.1
 
BLOCK 2C – TRINIDAD & TOBAGO
STOIIP & GIIP VOLUMETRIC ESTIMATION
(GROSS 100% VOLUMES)
 
 
Low
Best
  High
Field
Oil
Gas
Oil
Gas
Oil
Gas
 
(MMbbl)
(Bcf)
(MMbbl)
(Bcf)
(MMbbl)
(Bcf)
Aripo
11
301
27
413
34
521
Canteen
62
58
70
65
85
85
Kairi
146
392
165
464
190
613
E Kairi Horst
8
65
10
73
11
98
Total
227
816
271
1015
319
1317
Angostura-2
13
79
14
88
16
99
 

2.2
Estimated Ultimate Recovery

Table 2.2 presents the Estimated Ultimate Recoveries (EURs) of Low, Best and High volumetric estimates within the Block 2C. Since there is no plan to develop the Angostura Field and the oil in the Aripo and E Kairi Horst Fields, the EURs and related estimates for these parts are not included hereinafter.

TABLE 2.2

BLOCK 2C – TRINIDAD & TOBAGO
ESTIMATED ULTIMATE RECOVERY ESTIMATION
(GROSS 100% VOLUMES)
 
 
Low
Best
High
Field
Oil
Gas
Oil
Gas
Oil
Gas
 
(MMbbl)
(Bcf)
(MMbbl)
(Bcf)
(MMbbl)
(Bcf)
Aripo
-
246
-
346
-
453
Canteen
21.1
39
22.6
44
23.9
76
Kairi
46.5
287
49.5
380
52.1
530
E Kairi Horst
-
39
-
60
-
86
Total
67.6
611
72.1
830
76
1,145

Note:   Totals may not add exactly due to rounding errors.
 
     
CNOOC
5
  KK1498

 
 

 
 

2.3
Net Reserves

Table 2.3 presents the net entitlement to PD, 1P, 2P and 3P oil and gas reserves attributable to CNOOC’s working interests (WI) as of 31st December, 2009 and which were estimated in accordance with SEC new Final Rules. The economic cut offs were applied following Economic Limit Tests (ELTs) using costs and prices which are kept constant throughout the period of calculation.


TABLE 2.3

BLOCK 2C – TRINIDAD & TOBAGO
CNOOC NET ENTITLEMENT RESERVES AS OF 31st DECEMBER, 2009
 
 
PD
1P
2P
3P
Field
Oil
Gas
Oil
Gas
Oil
Gas
Oil
 Gas
 
(MMbbl)
(Bcf)
(MMbbl)
(Bcf)
(MMbbl)
(Bcf)
(MMbbl)
(Bcf)
Aripo
0
18.6
0
18.6
0
27.8
0
32.4
Canteen
0.698
2.8
0.698
2.8
0.805
3.5
0.893
4.7
Kairi
1.268
21.5
1.268
21.5
1.508
29.6
1.684
32.9
E Kairi Horst
0
3.1
0
3.1
0
5.3
0
6.8
Total
1.966
46.0
1.966
46.0
2.313
66.2
2.577
76.8

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

 
2.4
Gross Recoverable Volumes

Gross recoverable volumes, corresponding to the above Net Reserves, are presented in Table 2.4 for reference information only. They represent a 100% interest in commercially recoverable volumes as of 31st December, 2009, i.e. after economic cutoffs have been applied. Gross volumes include volumes attributable to third parties (government and other working interest partners).

TABLE 2.4

BLOCK 2C – TRINIDAD & TOBAGO
GROSS RECOVERABLE VOLUMES AS OF 31st DECEMBER, 2009
 
 
PD
1P
2P
3P
Field
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
 
(MMbbl)
(Bcf)
(MMbbl)
(Bcf)
(MMbbl)
(Bcf)
(MMbbl)
(Bcf)
Aripo
0
230
0
230
0
302
0
361
Canteen
6.386
35
6.386
35
7.880
39
9.199
53
Kairi
11.599
272
11.599
272
14.759
328
17.340
372
E Kairi Horst
0
37
0
37
0
57
0
76
Total
17.985
574
17.985
574
22.638
725
26.539
862
 
Note:   Totals may not add exactly due to rounding errors.


     
CNOOC
6
  KK1498

 
 

 
 

2.5
Net Present Values

The NPVs as of 31st December, 2009 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 2.5 summarise the NPVs.
 
TABLE 2.5
 
BLOCK 2C – TRINIDAD & TOBAGO
CNOOC NET PRESENT VALUES AS OF 31st DECEMBER, 2009
 
Case
Pre-Tax NPVs
U.S. $MM
Post-Tax NPVs
U.S. $MM
PD
60.4
60.4
1P
60.4
60.4
2P
74.5
74.5
3P
84.8
84.8
 

3.
QUALIFICATIONS

GCA is an independent international energy advisory group of 47 years’ standing, whose expertise includes petroleum reservoir evaluation and economic analysis.

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

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

Mr. Ahye, in charge of the whole project, holds a B.Sc (Hons) in Chemical Engineering, is a member of the Society of Petroleum Engineers, the Society of Professional Well Log Analysts, the Geological Society of Trinidad and Tobago, the South East Asia Petroleum Exploration Society, and has more than 30 years industry experience worldwide. Dr. Hu holds a PhD in Petroleum Geology, is a member of the Society of Petroleum Engineers and a Registered Mineral Reserve Evaluator of the P.R. China, and has more than 25 years industry experience in China. Mr. Chew holds a BE (Hons) in Civil Engineering and an MBA, is a member of the Society of Petroleum Engineers, a fellow of Institution of Engineers Malaysia, an associate member of Malaysian Institute of Management and a professional engineer registered with the Board of Engineers Malaysia, and has more than 30 years petroleum industry experience. Mr. Kumar holds a B. Tech. in Mechanical Engineering and an MBA in International Business, is a member of the Society of Petroleum Engineers, the Institution of Engineers, India and the Operational Research Society of India, and has more than 25 years industry experience. 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. Ms. Redjeki holds a B.Sc in Metallurgical Engineering and a Master of Business Administration, is a member of Southeast Asia Petroleum Exploration Society and Society of Indonesian Petroleum Engineers, and has 18 years industry experience.


     
CNOOC
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4.
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 4.1 to 4.4 are CNOOC’s PD, 1P, 2P and 3P Net Reserves and NPVs of the Block 2C, respectively.

Tables 4.5 to 4.8 are block level and field level production profiles for PD, 1P, 2P and 3P, respectively.


Yours sincerely,
GAFFNEY, CLINE & ASSOCIATES (CONSULTANTS) PTE LTD
 
 
David S. Ahye
Regional Manager, Asia Pacific

 
     
CNOOC
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TABLE 4.1
 
BLOCK 2C – TRINIDAD & TOBAGO
CNOOC PD NET RESERVES & NPVs AS OF 31st DECEMBER, 2009
 
 
Case: PD
   
CNOOC 12.5% WI
NPV7, US$MM  =
67.2
 
NPV8, US$MM  =
64.8
 
NPV9, US$MM  =
62.5
 
NPV10, US$MM  =
60.4
 
NPV11, US$MM  =
58.3
 
CNOOC Net Oil Reserves, MMstb  =
  2.0
 
CNOOC Net Gas Reserves, Bscf  =
46.0
 
                 
CNOOC's
Pre-Tax
Net
   
 
WI Oil
WI Gas
Crude
Gas
Opex
 
Cost
Profit
Cash
Cash
Net Oil
Net Gas
Year
Prod'n
Prod'n
Price
Price
   
Capex
Recovered
Share
Flow
Flow
Reserves
Reserves
         
Recoverable
Unrecoverable
             
 
MMstb
Bscf
US$/bbl
US$/Mscf
US$M
US$M
US$M
US$M
US$M
US$M
US$M
MMstb
Bscf
                           
                           
2010
0.635
0.000
61.85
1.47
4,359
119
15,624
13,742
9,849
3,489
3,489
0.546
0.000
2011
0.459
10.038
61.85
1.51
6,554
126
15,624
17,492
11,033
6,221
6,221
0.418
0.757
2012
0.343
10.065
61.85
1.54
6,330
134
0
15,179
9,268
17,983
17,983
0.312
5.036
2013
0.284
10.038
61.85
1.58
6,204
142
0
14,056
8,394
16,105
16,105
0.258
5.141
2014
0.222
10.038
61.85
1.61
6,292
150
0
12,901
7,488
13,948
13,948
0.201
5.151
2015
0.165
10.038
61.85
1.65
5,966
159
0
11,856
6,663
12,394
12,394
0.145
9.335
2016
0.085
10.751
61.85
1.69
5,233
169
0
10,921
5,742
11,262
11,262
0.052
  11.333
2017
0.037
7.304
61.85
1.73
4,912
179
0
7,124
3,739
5,772
5,772
0.023
6.746
2018
0.019
3.504
61.85
1.77
3,776
190
0
3,508
1,853
1,396
1,396
0.012
2.477
                           
                           
TOTAL
2.2
71.8
   
49,625
1,368
31,248
106,781
64,030
88,569
88,569
2.0
46.0

Notes:
1.  
WI Oil and Gas Production refer to Total Production x CNOOC’s WI.
2.  
CNOOC Net Oil and Gas Reserves refer to CNOOC Net Oil and Gas Entitlement.
3.  
Tax will be paid for from the Minister’s Profit Share.
4.  
Totals may not add exactly due to rounding errors.


     
CNOOC
9
  KK1498

 
 

 
 

TABLE 4.2
 
BLOCK 2C – TRINIDAD & TOBAGO
CNOOC 1P NET RESERVES & NPVs AS OF 31st DECEMBER, 2009
 
Case: 1P
   
CNOOC 12.5% WI
NPV7, US$MM  =
67.2
 
NPV8, US$MM  =
64.8
 
NPV9, US$MM  =
62.5
 
NPV10, US$MM  =
60.4
 
NPV11, US$MM  =
58.3
 
CNOOC Net Oil Reserves, MMstb  =
  2.0
 
CNOOC Net Gas Reserves, Bscf  =
46.0
 
                 
CNOOC's
Pre-Tax
Net
   
 
WI Oil
WI Gas
Crude
Gas
Opex
 
Cost
Profit
Cash
Cash
Net Oil
Net Gas
Year
Prod'n
Prod'n
Price
Price
   
Capex
Recovered
Share
Flow
Flow
Reserves
Reserves
         
Recoverable
Unrecoverable
             
 
MMstb
Bscf
US$/bbl
US$/Mscf
US$M
US$M
US$M
US$M
US$M
US$M
US$M
MMstb
Bscf
                           
                           
2010
0.635
0.000
61.85
1.47
4,359
119
15,624
13,742
9,849
3,489
3,489
0.546
0.000
2011
0.459
10.038
61.85
1.51
6,554
126
15,624
17,492
11,033
6,221
6,221
0.418
0.757
2012
0.343
10.065
61.85
1.54
6,330
134
0
15,179
9,268
17,983
17,983
0.312
5.036
2013
0.284
10.038
61.85
1.58
6,204
142
0
14,056
8,394
16,105
16,105
0.258
5.141
2014
0.222
10.038
61.85
1.61
6,292
150
0
12,901
7,488
13,948
13,948
0.201
5.151
2015
0.165
10.038
61.85
1.65
5,966
159
0
11,856
6,663
12,394
12,394
0.145
9.335
2016
0.085
10.751
61.85
1.69
5,233
169
0
10,921
5,742
11,262
11,262
0.052
11.333
2017
0.037
7.304
61.85
1.73
4,912
179
0
7,124
3,739
5,772
5,772
0.023
6.746
2018
0.019
3.504
61.85
1.77
3,776
190
0
3,508
1,853
1,396
1,396
0.012
2.477
                           
                           
TOTAL
2.2
71.8
   
49,625
1,368
31,248
106,781
64,030
88,569
88,569
2.0
46.0

Notes:
1.  
WI Oil and Gas Production refer to Total Production x CNOOC’s WI.
2.  
CNOOC Net Oil and Gas Reserves refer to CNOOC Net Oil and Gas Entitlement.
3.  
Tax will be paid for from the Minister’s Profit Share.
4.  
Totals may not add exactly due to rounding errors.


     
CNOOC
10
  KK1498

 
 

 
 

TABLE 4.3
 
BLOCK 2C – TRINIDAD & TOBAGO
CNOOC 2P NET RESERVES & NPVs AS OF 31st DECEMBER, 2009
 
Case: 2P
   
CNOOC 12.5% WI
NPV7, US$MM  =
84.4
 
NPV8, US$MM  =
80.9
 
NPV9, US$MM  =
77.6
 
NPV10, US$MM  =
74.5
 
NPV11, US$MM  =
71.6
 
CNOOC Net Oil Reserves, MMstb  =
  2.3
 
CNOOC Net Gas Reserves, Bscf  =
66.2
 
                 
CNOOC's
Pre-Tax
Net
   
 
WI Oil
WI Gas
Crude
Gas
Opex
 
Cost
Profit
Cash
Cash
Net Oil
Net Gas
Year
Prod'n
Prod'n
Price
Price
   
Capex
Recovered
Share
Flow
Flow
Reserves
Reserves
         
Recoverable
Unrecoverable
             
 
MMstb
Bscf
US$/bbl
US$/Mscf
US$M
US$M
US$M
US$M
US$M
US$M
US$M
MMstb
Bscf
                           
                           
2010
0.639
0.000
61.85
1.47
4,931
119
15,624
13,840
9,913
3,079
3,079
0.542
0.000
2011
0.490
10.038
61.85
1.51
7,179
126
15,624
18,170
11,473
6,714
6,714
0.443
0.485
2012
0.395
10.065
61.85
1.54
6,996
134
0
16,297
10,099
19,266
19,266
0.357
4.772
2013
0.337
10.038
61.85
1.58
6,873
142
0
15,208
9,249
17,442
17,442
0.305
4.877
2014
0.306
10.038
61.85
1.61
7,023
150
0
14,729
8,846
16,402
16,402
0.268
5.254
2015
0.254
10.038
61.85
1.65
6,707
159
0
13,793
8,102
15,028
15,028
0.155
11.740
2016
0.184
10.751
61.85
1.69
6,144
169
0
13,067
7,336
14,090
14,090
0.112
12.064
2017
0.092
11.178
61.85
1.73
6,861
179
0
11,663
6,130
10,754
10,754
0.056
11.053
2018
0.056
8.376
61.85
1.77
5,924
190
0
8,630
4,544
7,061
7,061
0.034
7.773
2019
0.039
5.333
61.85
1.81
4,452
201
0
5,668
3,038
4,053
4,053
0.024
4.672
2020
0.029
3.773
61.85
1.85
3,616
213
0
4,013
2,252
2,436
2,436
0.017
3.044
2021
0.008
1.013
61.85
1.90
1,613
75
0
1,131
607
49
49
0.005
0.505
                           
                           
TOTAL
2.8
90.6
   
68,318
1,858
31,248
136,209
81,589
116,373
116,373
2.3
66.2
 
Notes:

1.  
WI Oil and Gas Production refer to Total Production x CNOOC’s WI.
2.  
CNOOC Net Oil and Gas Reserves refer to CNOOC Net Oil and Gas Entitlement.
3.  
Tax will be paid for from the Minister’s Profit Share.
4.  
Totals may not add exactly due to rounding errors.


     
CNOOC
11
  KK1498

 
 

 
 
 
 
TABLE 4.4
 
BLOCK 2C – TRINIDAD & TOBAGO
CNOOC 3P NET RESERVES & NPVs AS OF 31st DECEMBER, 2009
 
Case: 3P
   
CNOOC 12.5% WI
NPV7, US$MM  =
97.1
 
NPV8, US$MM  =
92.7
 
NPV9, US$MM  =
88.6
 
NPV10, US$MM  =
84.8
 
NPV11, US$MM  =
81.2
 
CNOOC Net Oil Reserves, MMstb  =
2.6
 
CNOOC Net Gas Reserves, Bscf  =
76.8

                 
CNOOC's
Pre-Tax
Net
   
 
WI Oil
WI Gas
Crude
Gas
Opex
 
Cost
Profit
Cash
Cash
Net Oil
Net Gas
Year
Prod'n
Prod'n
Price
Price
   
Capex
Recovered
Share
Flow
Flow
Reserves
Reserves
         
Recoverable
Unrecoverable
             
 
MMstb
Bscf
US$/bbl
US$/Mscf
US$M
US$M
US$M
US$M
US$M
US$M
US$M
MMstb
Bscf
                           
                           
2010
0.648
0.000
61.85
1.47
5,511
119
15,624
14,033
10,038
2,817
2,817
0.543
0.000
2011
0.516
10.038
61.85
1.51
7,793
126
15,624
18,728
11,836
7,021
7,021
0.464
0.095
2012
0.434
10.065
61.85
1.54
7,637
134
0
17,147
10,730
20,107
20,107
0.391
4.450
2013
0.374
10.038
61.85
1.58
7,510
142
0
16,020
9,853
18,221
18,221
0.337
4.554
2014
0.361
10.038
61.85
1.61
7,694
150
0
15,905
9,720
17,780
17,780
0.280
6.290
2015
0.326
10.038
61.85
1.65
7,413
159
0
15,337
9,249
17,014
17,014
0.199
12.248
2016
0.280
10.751
61.85
1.69
7,160
169
0
15,140
8,876
16,688
16,688
0.171
12.689
2017
0.155
11.178
61.85
1.73
7,771
179
0
13,028
7,144
12,223
12,223
0.095
11.316
2018
0.091
11.178
61.85
1.77
7,541
190
0
9,526
7,210
9,006
9,006
0.040
9.188
2019
0.066
11.178
61.85
1.81
6,866
201
0
6,866
8,072
7,871
7,871
0.029
7.275
2020
0.052
10.514
61.85
1.85
6,179
213
0
6,179
7,715
7,502
7,502
0.022
6.750
2021
0.015
2.736
61.85
1.90
2,272
75
0
2,272
1,797
1,721
1,721
0.007
1.929
                           
                           
TOTAL
3.3
107.8
   
81,346
1,858
31,248
150,182
102,240
137,970
137,970
2.6
76.8

Notes:

1.  
WI Oil and Gas Production refer to Total Production x CNOOC’s WI.
2.  
CNOOC Net Oil and Gas Reserves refer to CNOOC Net Oil and Gas Entitlement.
3.  
Tax will be paid for from the Minister’s Profit Share.
4.  
Totals may not add exactly due to rounding errors.


     
CNOOC
12
  KK1498

 
 

 
 

 
TABLE 4.5

BLOCK 2C – TRINIDAD & TOBAGO
PD PRODUCTION PROFILES

 
Aripo
Canteen
Kairi
E Kairi Horst
Total
 
Gross
WI
Gross
WI
Gross
WI
Gross
WI
Gross
WI
 
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
 
Prod
 Prod'n
Prod'n
Prod'n
Prod'n
 Prod'n
Prod'n
Prod'n
Prod'n
 Prod'n
Prod'n
Prod'n
Prod'n
 Prod'n
Prod'n
Prod'n
Prod'n
 Prod'n
Prod'n
Prod'n
Year
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
2010
-
0.0
-
0.0
1.797
0.0
0.225
0.0
3.281
0.0
0.409
0.0
-
0.0
-
0.0
5.078
0.0
0.635
0.0
2011
-
62.1
-
4.0
1.311
0.0
0.163
0.0
2.360
0.0
0.296
0.0
-
18.3
-
6.0
3.670
80.3
0.459
10.0
2012
-
57.7
-
4.0
0.990
0.9
0.122
0.6
1.752
7.5
0.221
4.5
-
14.3
-
0.9
2.743
80.5
0.343
10.1
2013
-
39.8
-
4.0
0.825
4.1
0.101
0.6
1.444
32.8
0.183
4.5
-
3.7
-
0.9
2.270
80.3
0.284
10.0
2014
-
26.7
-
4.0
0.645
5.8
0.079
0.6
1.130
47.0
0.143
4.5
-
0.8
-
0.9
1.775
80.3
0.222
10.0
2015
-
17.9
-
4.0
0.475
6.9
0.059
0.6
0.844
55.4
0.106
4.5
-
0.2
-
0.9
1.319
80.3
0.165
10.0
2016
-
12.0
-
4.3
0.230
8.4
0.030
0.7
0.450
65.6
0.055
4.9
-
0.0
-
0.9
0.680
86.0
0.085
10.8
2017
-
8.0
-
2.9
0.082
6.4
0.013
0.4
0.217
44.0
0.024
3.3
-
0.0
-
0.6
0.299
58.4
0.037
7.3
2018
-
5.4
-
1.4
0.030
2.9
0.007
0.2
0.121
19.8
0.012
1.6
-
0.0
-
0.3
0.151
28.0
0.019
3.5
2019
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2020
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2021
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Total
0
230
0.0
29
6.4
35
0.8
4
11.6
272
1.4
28
0.0
37
0.0
11
18.0
574
2.2
72

Notes:

1.  
Gross production volumes represent a 100% interest in commercially recoverable volumes as of 31st December, 2009, i.e. after economic cutoffs have been applied. Gross volumes include volumes attributable to third parties (government and other working interest partners).
2.  
WI  production volumes  represent CNOOC’s  12.5%  working interests  in commercially  recoverable volumes  as  of  31st December, 2009, i.e. after economic cutoffs have been applied. This volumes still includes volumes attributable to government.
3.  
Totals may not add exactly due to rounding errors.


     
CNOOC
13
  KK1498

 
 

 
 
 

TABLE 4.6

BLOCK 2C – TRINIDAD & TOBAGO
1P PRODUCTION PROFILES

 
Aripo
Canteen
Kairi
E Kairi Horst
Total
 
Gross
WI
Gross
WI
Gross
WI
Gross
WI
Gross
WI
 
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
 
Prod
 Prod'n
Prod'n
Prod'n
Prod'n
 Prod'n
Prod'n
Prod'n
Prod'n
 Prod'n
Prod'n
Prod'n
Prod'n
 Prod'n
Prod'n
Prod'n
Prod'n
 Prod'n
Prod'n
Prod'n
Year
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
2010
-
0.0
-
0.0
1.797
0.0
0.225
0.0
3.281
0.0
0.409
0.0
-
0.0
-
0.0
5.078
0.0
0.635
0.0
2011
-
62.1
-
4.0
1.311
0.0
0.163
0.0
2.360
0.0
0.296
0.0
-
18.3
-
6.0
3.670
80.3
0.459
10.0
2012
-
57.7
-
4.0
0.990
0.9
0.122
0.6
1.752
7.5
0.221
4.5
-
14.3
-
0.9
2.743
80.5
0.343
10.1
2013
-
39.8
-
4.0
0.825
4.1
0.101
0.6
1.444
32.8
0.183
4.5
-
3.7
-
0.9
2.270
80.3
0.284
10.0
2014
-
26.7
-
4.0
0.645
5.8
0.079
0.6
1.130
47.0
0.143
4.5
-
0.8
-
0.9
1.775
80.3
0.222
10.0
2015
-
17.9
-
4.0
0.475
6.9
0.059
0.6
0.844
55.4
0.106
4.5
-
0.2
-
0.9
1.319
80.3
0.165
10.0
2016
-
12.0
-
4.3
0.230
8.4
0.030
0.7
0.450
65.6
0.055
4.9
-
0.0
-
0.9
0.680
86.0
0.085
10.8
2017
-
8.0
-
2.9
0.082
6.4
0.013
0.4
0.217
44.0
0.024
3.3
-
0.0
-
0.6
0.299
58.4
0.037
7.3
2018
-
5.4
-
1.4
0.030
2.9
0.007
0.2
0.121
19.8
0.012
1.6
-
0.0
-
0.3
0.151
28.0
0.019
3.5
2019
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2020
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2021
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Total
0
230
0.0
29
6.4
35
0.8
4
11.6
272
1.4
28
0.0
37
0.0
11
18.0
574
2.2
72

Notes:

1.  
Gross production volumes represent a 100% interest in commercially recoverable volumes as of 31st December, 2009, i.e. after economic cutoffs have been applied. Gross volumes include volumes attributable to third parties (government and other working interest partners).
2.  
WI  production volumes  represent CNOOC’s  12.5%  working interests  in commercially  recoverable volumes  as  of  31st December, 2009, i.e. after economic cutoffs have been applied. This volumes still includes volumes attributable to government.
3.  
Totals may not add exactly due to rounding errors.


     
CNOOC
14
  KK1498

 
 

 
 

 
TABLE 4.7

BLOCK 2C – TRINIDAD & TOBAGO
2P PRODUCTION PROFILES

    Aripo   Canteen   Kairi   E Kairi Horst   Total
 
Gross
WI
Gross
WI
Gross
WI
Gross
WI
Gross
WI
 
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
 
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Year
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
2010
-
0.0
-
0.0
1.770
0.0
0.223
0.0
3.344
0.0
0.417
0.0
-
0.0
-
0.0
5.115
 0.0
0.639
0.0
2011
-
62.1
-
4.2
1.371
0.0
0.171
0.0
2.550
0.0
0.319
0.0
-
18.3
-
5.9
3.920
80.3
0.490
10.0
2012
-
62.2
-
4.2
1.111
0.0
0.137
0.0
2.045
0.0
0.257
0.0
-
18.3
-
5.9
3.156
80.5
0.395
10.1
2013
-
49.8
-
4.2
0.952
2.2
0.117
0.5
1.743
18.4
0.220
4.5
-
9.9
-
0.8
2.695
80.3
0.337
10.0
2014
-
34.4
-
4.2
0.866
4.5
0.107
0.5
1.585
37.4
0.200
4.5
-
4.0
-
0.8
2.450
80.3
0.306
10.0
2015
-
25.2
-
4.2
0.718
5.6
0.089
0.5
1.317
47.2
0.166
4.5
-
2.2
-
0.8
2.035
80.3
0.254
10.0
2016
-
19.3
-
4.5
0.518
7.0
0.064
0.6
0.955
58.3
0.120
4.9
-
1.4
-
0.8
1.473
86.0
0.184
10.8
2017
-
15.2
-
4.7
0.251
7.5
0.032
0.6
0.488
65.8
0.060
5.0
-
0.9
-
0.9
0.739
89.4
0.092
11.2
2018
-
12.3
-
3.5
0.145
5.9
0.020
0.5
0.306
48.1
0.037
3.8
-
0.7
-
0.7
0.451
67.0
0.056
8.4
2019
-
10.2
-
2.2
0.094
3.5
0.014
0.3
0.216
28.5
0.025
2.4
-
0.5
-
0.4
0.311
42.7
0.039
5.3
2020
-
8.6
-
1.6
0.067
2.3
0.010
0.2
0.163
18.9
0.019
1.7
-
0.4
-
0.3
0.230
30.2
0.029
3.8
2021
-
2.5
-
0.4
0.018
0.6
0.003
0.1
0.045
4.9
0.005
0.5
-
0.1
-
0.1
0.063
 8.1
0.008
1.0
Total
0
302
0
38
7.9
39
1.0
4
14.8
328
1.8
32
0
57
0
17
22.6
725
2.8
91

Notes:

1.  
Gross production volumes represent a 100% interest in commercially recoverable volumes as of 31st December, 2009, i.e. after economic cutoffs have been applied. Gross volumes include volumes attributable to third parties (government and other working interest partners).
2.  
WI  production volumes  represent CNOOC’s  12.5%  working interests  in commercially  recoverable volumes  as  of  31st December, 2009, i.e. after economic cutoffs have been applied. This volumes still includes volumes attributable to government.
3.  
Totals may not add exactly due to rounding errors.


     
CNOOC
15
  KK1498

 
 

 
 

 
TABLE 4.8

BLOCK 2C – TRINIDAD & TOBAGO
3P PRODUCTION PROFILES

  Aripo Canteen Kairi E Kairi Horst Total
 
Gross
WI
Gross
WI
Gross
WI
Gross
WI
Gross
WI
 
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
 
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n
Prod'n  Prod'n Prod'n
Year
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
MMstb
Bscf
2010
-
 0.0
-
0.0
1.790
0.0
0.225
0.0
3.396
0.0
0.424
0.0
-
0.0
-
0.0
5.186
0.0
0.648
0.0
2011
-
62.1
-
4.2
1.433
0.0
0.179
0.0
2.694
0.0
0.337
0.0
-
18.3
-
5.8
4.127
80.3
0.516
10.0
2012
-
62.2
-
4.2
1.209
0.0
0.150
0.0
2.261
0.0
0.283
0.0
-
18.3
-
5.8
3.470
80.5
0.434
10.1
2013
-
58.5
-
4.2
1.045
0.8
0.130
0.6
1.950
5.4
0.245
4.3
-
15.6
-
0.9
2.995
80.3
0.374
10.0
2014
-
42.6
-
4.2
1.006
3.8
0.125
0.6
1.878
26.6
0.236
4.3
-
7.3
-
0.9
2.885
80.3
0.361
10.0
2015
-
32.5
-
4.2
0.908
5.4
0.113
0.6
1.697
37.9
0.213
4.3
-
4.5
-
0.9
2.606
80.3
0.326
10.0
2016
-
26.3
-
4.5
0.779
7.0
0.097
0.7
1.459
49.4
0.183
4.6
-
3.3
-
0.9
2.239
86.0
0.280
10.8
2017
-
22.1
-
4.7
0.432
8.1
0.054
0.7
0.811
56.7
0.102
4.8
-
2.6
-
1.0
1.244
89.4
0.155
11.2
2018
-
19.0
-
4.7
0.247
8.5
0.032
0.7
0.482
59.8
0.060
4.8
-
2.1
-
1.0
0.729
89.4
0.091
11.2
2019
-
16.7
-
4.7
0.174
8.8
0.023
0.7
0.351
62.1
0.043
4.8
-
1.8
-
1.0
0.526
89.4
0.066
11.2
2020
-
14.9
-
4.4
0.135
8.5
0.018
0.6
0.279
59.1
0.034
4.5
-
1.6
-
0.9
0.414
84.1
0.052
10.5
2021
-
 4.6
-
1.1
0.038
2.1
0.005
0.2
0.080
14.7
0.010
1.2
-
0.5
-
0.2
0.119
21.9
0.015
2.7
Total
0
361
0
45
9.2
53
1.1
5
17.3
372
2.2
38
0
76
0
19
26.5
862
3.3
108

Notes:

1.  
Gross production volumes represent a 100% interest in commercially recoverable volumes as of 31st December, 2009, i.e. after economic cutoffs have been applied. Gross volumes include volumes attributable to third parties (government and other working interest partners).
2.  
WI  production volumes  represent CNOOC’s  12.5%  working interests  in commercially  recoverable volumes  as  of  31st December, 2009, i.e. after economic cutoffs have been applied. This volumes still includes volumes attributable to government.
3.  
Totals may not add exactly due to rounding errors.


     
CNOOC
16
  KK1498

 
 

 
 



 
 
 
 
 
 




APPENDIX I

GLOSSARY




 
 

 


 
 

     
CNOOC
 
  KK1498

 
 

 
 
 
List of Standard Oil Industry Terms and Abbreviations
 
ABEX
Abandonment Expenditure
EOR
Enhanced Oil Recovery
ACQ
Annual Contract Quantity
EUR
Estimated Ultimate Recovery
oAPI
Degrees API (American
FDP
Field Development Plan
 
Petroleum Institute)
FEED
Front End Engineering and Design
AAPG
American Association of
FPSO
Floating Production, Storage and
 
Petroleum Geologists
 
Offloading
AVO
Amplitude versus Offset
FSO
Floating Storage and Offloading
A$
Australian Dollars
ft
Foot/feet
B
Billion (109)
Fx
Foreign Exchange Rate
Bbl
Barrels
g
gram
/Bbl
per barrel
g/cc
grams per cubic centimetre
Bbbl
Billion Barrels
gal
gallon
BHA
Bottom Hole Assembly
gal/d
gallons per day
BHC
Bottom Hole Compensated
G&A
General and Administrative costs
Bscf or Bcf
Billion standard cubic feet
GBP
Pounds Sterling
Bscf/d or Bcf/d
Billion standard cubic feet per day
GDT
Gas Down to
Bm3
Billion cubic metres
GIIP
Gas initially in place
bcpd
Barrels of condensate per day
Gj
Gigajoules (one billion Joules)
BHP
Bottom Hole Pressure
GOR
Gas Oil Ratio
blpd
Barrels of liquid per day
GTL
Gas to Liquids
bpd
Barrels per day
GWC
Gas water contact
boe
Barrels of oil equivalent @xxx mcf/bbl
HDT
Hydrocarbons Down to
boepd
Barrels of oil equivalent per day@
HSE
Health, Safety and Environment
 
xxx mcf/bbl
HSFO
High Sulphur Fuel Oil
BOP
Blow Out Preventer
HUT
Hydrocarbons up to
bopd
Barrels oil per day
H2S
Hydrogen Sulphide
bwpd
Barrels of water per day
IOR
Improved Oil Recovery
BS&W
Bottom sediment and water
IPP
Independent Power Producer
BTU
British Thermal Units
IRR
Internal Rate of Return
bwpd
Barrels water per day
J
Joule (Metric measurement of
CBM
Coal Bed Methane
 
energy. I kilojoule = 0.9478 BTU)
CO2
Carbon Dioxide
k
Permeability
CAPEX
Capital Expenditure
KB
Kelly Bushing
CCGT
Combined Cycle Gas Turbine
KJ
Kilojoules (one Thousand Joules)
cm
centimetres
kl
Kilolitres
CMM
Coal Mine Methane
km
Kilometres
CNG
Compressed Natural Gas
km2
Square kilometres
Cp
Centipoise (a measure of viscosity)
kPa
Thousands of Pascals
CSG
Coal Seam Gas
 
measurement of pressure)
CT
Corporation Tax
KW
Kilowatt
DCQ
Daily Contract Quantity
KWh
Kilowatt hour
Deg C
Degrees Celsius
LKG
Lowest Known Gas
Deg F
Degrees Fahrenheit
LKH
Lowest Known Hydrocarbons
DHI
Direct Hydrocarbon Indicator
LKO
Lowest Known Oil
DST
Drill Stem Test
LNG
Liquefied Natural Gas
DWT
Dead-weight ton
LoF
Life of Field
E&A
Exploration & Appraisal
LPG
Liquefied Petroleum Gas
E&P
Exploration and Production
LTI
Lost Time Injury
EBIT
Earnings before Interest and Tax
LWD
Logging while drilling
EBITDA
Earnings before interest, tax,
m
Metres
 
depreciation and amortisation
M
Thousand
EI
Entitlement Interest
m3
Cubic metres
EIA
Environmental Impact Assessment
Mcf or Mscf
Thousand standard cubic feet
EMV
Expected Monetary Value
MCM
Management Committee Meeting
MMcf or MMscf
Million standard cubic feet
cf or scf
Standard Cubic Feet
 
     
CNOOC
AI.I
  KK1498

 
 

 
 

 
m3d
Cubic metres per day
cf/d or scf/d
Standard Cubic Feet per day
MDT
Modular Dynamic Tester
scf/ton
Standard cubic foot per ton
mD
Measure of Permeability in
SL
Straight line (for depreciation)
 
millidarcies
so
Oil Saturation
MD
Measured Depth
SPE
Society of Petroleum Engineers
Mean
Arithmetic average of a set of
SPEE
Society of Petroleum Evaluation
 
numbers
 
Engineers
Median
Middle value in a set of values
ss
Subsea
MFT
Multi Formation Tester
stb
Stock tank barrel
mg/l
milligrames per litre
STOIIP
Stock tank oil initially in place
MJ
Megajoules (One Million Joules)
sw
Water Saturation
Mm3
Thousand Cubic metres
T
Tonnes
Mm3d
Thousand Cubic metres per day
TD
Total Depth
MM
Million
Te
Tonnes equivalent
MMbbl
Millions of barrels
THP
Tubing Head Pressure
MMBTU
Millions of British Thermal Units
TJ
Terajoules (1012 Joules)
Mode
Value that exists most frequently in
Tscf or Tcf
Trillion standard cubic feet
 
a set of values = most likely
TCM
Technical Committee Meeting
Mscf/d
Thousand standard cubic feet per day
TOC
Total Organic Carbon
MMscf/d
Million standard cubic feet per day
TOP
Take or Pay
MW
Megawatt
Tpd
Tonnes per day
MWD
Measuring While Drilling
TVD
True Vertical Depth
MWh
Megawatt hour
TVDss
True Vertical Depth Subsea
mya
Million years ago
USGS
United States Geological Survey
NGL
Natural Gas Liquids
U.S.$
United States Dollar
N2
Nitrogen
VSP
Vertical Seismic Profiling
NPV
Net Present Value
WC
Water Cut
OBM
Oil Based Mud
WI
Working Interest
OCM
Operating Committee Meeting
WPC
World Petroleum Council
ODT
Oil down to
WTI
West Texas Intermediate
OPEX
Operating Expenditure
wt%
Weight percent
OWC
Oil Water Contact
1H05
First half (6 months) of 2005
p.a.
Per annum
 
(example of date)
Pa
Pascals (metric measurement of
2Q06
Second quarter (3 months) of 2006
 
pressure)
 
(example of date)
P&A
Plugged and Abandoned
2D
Two dimensional
PD
Proved Developed
3D
Three dimensional
PDP
Proved Developed Producing
4D
Four dimensional
PI
Productivity Index
1P
Proved Reserves
PJ
Petajoules (1015 Joules)
2P
Proved plus Probable Reserves
PSDM
Post Stack Depth Migration
3P
Proved plus Probable plus Possible
psi
Pounds per square inch
 
Reserves
psia
Pounds per square inch absolute
%
Percentage
psig
Pounds per square inch gauge
   
PUD
Proved Undeveloped
   
PVT
Pressure volume temperature
   
P10
10% Probability
   
P50
50% Probability
   
P90
90% Probability
   
RF
Recovery factor
   
RFT
Repeat Formation Tester
   
RT
Rotary Table
   
Rw
Resistivity of water
   
SCAL
Special core analysis
   


     
CNOOC
AI.II
  KK1498