UNITED STATES

 

SECURITIES AND EXCHANGE COMMISSION

 

Washington, D.C. 20549

 

FORM 20-F

 

(Mark One) 

¨REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

 

OR 

 

ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018

 

OR

 

¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

OR

 

¨SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Date of event requiring this shell company report ________________

 

Commission File Number 1-14966

 

CNOOC LIMITED 

(Exact name of Registrant as specified in its charter)

 

N/A 

(Translation of Registrant’s name into English)

 

 

 

Hong Kong 

(Jurisdiction of incorporation or organization)

 

 

 

65th Floor, Bank of China Tower 

One Garden Road, Central 

Hong Kong 

(Address of principal executive offices)

 

 

 

Xiaonan Wu

65th Floor, Bank of China Tower

One Garden Road, Central

Hong Kong

Tel +852 2213 2500 

Fax +852 2525 9322 

(Name, telephone, e-mail and/or facsimile number and address of company contact person)

 

 

 

Securities registered or to be registered pursuant to Section 12(b) of the Act.

 

Title of each class Name of each exchange on which registered

American depositary shares, each representing 100 shares
Shares(1)  

New York Stock Exchange, Inc. 

New York Stock Exchange, Inc.

 

 

(1)       Not for trading, but only in connection with the registration of American depositary shares.

 

Securities registered or to be registered pursuant to Section 12(g) of the Act. None 

(Title of Class)

 

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act. None 

(Title of Class)

 

 

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

 

Shares 44,647,455,984

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 

Yes ý    No ¨

 

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

 

Yes ¨    No ý

 

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

 

Yes ý   No ¨

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

 

Yes ý No ¨

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer, “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer    ý Accelerated filer  ☐ Non-accelerated filer     ☐
    Emerging growth company     ☐

 

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ¨

 

†The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

 

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

 

U.S. GAAP    ¨     International Financial Reporting Standards as issued by the International Accounting Standards Board     ý

Other    ¨ 

 

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

 

Item 17 ¨      Item 18 ¨

 

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

Yes ¨      No ý

 

(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)

 

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

 

Yes ¨      No ¨

 

 

 

Table of Contents

 

Page

TERMS AND CONVENTIONS 5
SPECIAL NOTE ON THE FINANCIAL INFORMATION AND CERTAIN STATISTICAL INFORMATION PRESENTED IN THIS ANNUAL REPORT 11
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS 12
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE 12
ITEM 3. KEY INFORMATION 12
A.   Selected Financial Data 12
B.   Capitalization and Indebtedness 14
C.   Reasons for the Offer and Use of Proceeds 14
D.   Risk Factors 14
ITEM 4. INFORMATION ON THE COMPANY 19
A.   History and Development 19
B.   Business Overview 20
C.   Organizational Structure 56
D.   Property, Plants and Equipment 57
ITEM 4A. unresolved staff comments 57
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS 57
A.   Operating Results 57
B.   Liquidity and Capital Resources 69
C.   Research and Development, Patents and Licenses, etc. 72
D.   Trend Information 72
E.   Off-Balance Sheet Arrangements 73
F.   Tabular Disclosure of Contractual Obligations 73
G.   Safe Harbor 73
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES 74
A.   Directors and Senior Management 74
B.   Compensation 82
C.   Board Practice 82
D.   Employees 85
E.   Share Ownership 85
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS 86
A.   Major Shareholders 86
B.   Related Party Transactions 86
C.   Interests of Experts and Counsel 91
ITEM 8. FINANCIAL INFORMATION 91
A.   Consolidated Statements and Other Financial Information 91
B.   Significant Changes 92
ITEM 9. THE OFFER AND LISTING 92
ITEM 10. ADDITIONAL INFORMATION 93
A.   Share Capital 93
B.   Memorandum and Articles of Association 93
C.   Material Contracts 96
D.   Exchange Controls 96
E.   Taxation 96
F.   Dividends and Paying Agents 101
G.   Statement by Experts 101
H.   Documents on Display 101
I.     Subsidiary Information 101
ITEM 11. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK 101
Item 12 Description of Securities other than equity securities 103
A.   Debt Securities 103
B.   Warrants and Rights 103
C.   Other Securities 103
D.   American Depositary Shares 103
PART II 106
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES 106
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS 106

 

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A.   Material Modifications to the Instruments Defining the Rights of Security Holders 106
B.   Material Modifications to the Rights of Registered Securities by Issuing or Modifying any Other Class of Securities 106
C.   Withdrawal or Substitution of a Material Amount of the Assets Securing any Registered Securities 106
D.   Change of Trustees or Paying Agents for any Registered Securities 106
E.   Use of Proceeds 106
ITEM 15. CONTROLS AND PROCEDURES 106
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT 107
ITEM 16B. CODE OF ETHICS 107
ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES 107
ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES 108
ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS 108
ITEM 16f. Change in Registrant’s Certifying Accountant 108
ITEM 16g. Corporate Governance 109
Item 16H. MINE SAFETY DISCLOSURE 109
PART III 109
ITEM 17. FINANCIAL STATEMENTS 109
ITEM 18. FINANCIAL STATEMENTS 109
ITEM 19. EXHIBITS 109

  

 

  

 

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TERMS AND CONVENTIONS

 

Definitions

 

Unless the context otherwise requires, references in this annual report to:

 

·“CNOOC” are to our controlling shareholder, China National Offshore Oil Corporation, a PRC state-owned enterprise, or China National Offshore Oil Corporation and its subsidiaries (excluding us and our subsidiaries), as the case may be;

 

·“CNOOC Limited” are to CNOOC Limited, a Hong Kong limited liability company and the registrant of this annual report;

 

·“Company”, “Group”, “we”, “our” or “us” are to CNOOC Limited and its subsidiaries;

 

·“ADRs” are to the American depositary receipts that evidence our ADSs;

 

·“ADSs” are to our American depositary shares, each of which represents 100 shares;

 

·“Cdn$” are to Canadian dollar, the legal currency of Canada;

 

·“China” or “PRC” are to the People’s Republic of China, excluding for purposes of geographical reference in this annual report, the Hong Kong Special Administrative Region, the Macau Special Administrative Region and Taiwan;

 

·“Hong Kong” are to the Hong Kong Special Administrative Region of the People’s Republic of China;

 

·“Hong Kong Stock Exchange” or “HKSE” are to The Stock Exchange of Hong Kong Limited;

 

·“HK$” are to Hong Kong dollar, the legal currency of the Hong Kong Special Administrative Region;

 

·“HKICPA” are to the Hong Kong Institute of Certified Public Accountants;

 

·“HKFRSs” are to all Hong Kong Financial Reporting Standards and Hong Kong Accounting Standards and Interpretations approved by the Council of the HKICPA;

 

·“IASB” are to the International Accounting Standards Board;

 

·“IFRSs” are to all International Financial Reporting Standards, including International Accounting Standards and Interpretations, as issued by the International Accounting Standards Board;

 

·“NYSE” are to the New York Stock Exchange;

 

·“Rmb” are to Renminbi, the legal currency of the PRC;

 

·“TSX” are to the Toronto Stock Exchange;

 

·“U.K.” are to the United Kingdom of Great Britain and Northern Ireland;

 

·“U.S.” are to the United States of America; and

 

·“US$” are to U.S. dollar, the legal currency of the United States of America.

 

  

 

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Conventions

 

We publish our financial statements in Renminbi. Unless otherwise indicated, we have translated amounts from Renminbi into U.S. dollars solely for the convenience of the reader at the noon buying rate for cable transfers of Renminbi per U.S. dollar certified for customs purposes by the Federal Reserve Bank of New York, as set forth in the H.10 weekly statistical release of the Federal Reserve Board on December 31, 2018 of US$1.00=Rmb 6.8755. We have translated amounts in Hong Kong dollars solely for the convenience of the reader at the noon buying rate for cable transfers of Hong Kong dollars per U.S. dollar certified for customs purposes by the Federal Reserve Bank of New York, as set forth in the H.10 weekly statistical release of the Federal Reserve Board on December 31, 2018 of US$1.00=HK$ 7.8305. We have also translated amounts in Canadian dollars solely for the convenience of the reader at the noon buying rate for cable transfers of Canadian dollars per U.S. dollar certified for customs purposes by the Federal Reserve Bank of New York, as set forth in the H.10 weekly statistical release of the Federal Reserve Board on December 31, 2018 of US$1.00=Cdn$ 1.3644. We make no representation that the Renminbi amounts, Hong Kong dollar amounts or Canadian dollar amounts could have been, or could be, converted into U.S. dollars at those rates on December 31, 2018, or at all. For further information on exchange rates, see “Item 3—Key Information—Selected Financial Data.”

 

Totals presented in this annual report may not add correctly due to rounding of numbers.

 

For the years 2016, 2017 and 2018, approximately 60%, 65% and 69% respectively, of our reserves were evaluated by our internal reserve evaluation staff, and the remaining were based upon estimates prepared by independent petroleum engineering consulting companies and reviewed by us. Our reserve data for 2016, 2017 and 2018 were prepared in accordance with the SEC’s final rules on “Modernization of Oil and Gas Reporting”, which became effective for accounting periods ended on or after December 31, 2009. Except as otherwise stated, all amounts of reserve and production in this report include our interests in equity method investees.

 

In calculating barrels-of-oil equivalent amounts, we have assumed that 6,000 cubic feet of natural gas equals one BOE, with the exception of natural gas from South America, Oceania, SES, Madura and Tangguh projects in Indonesia in Asia, and Wenchang 9-2/9-3/10-3 and Yacheng 13-1/13-4 gas fields in China, which we have used actual thermal unit for such conversion purpose.

 

Glossary of Technical Terms

 

Unless otherwise indicated in the context, references to:

 

·“API gravity” means the American Petroleum Institute’s scale for specific gravity for liquid hydrocarbons, measured in degrees;

 

·“appraisal well” means an exploratory well drilled after a successful wildcat well to gain more information on a newly discovered oil or gas reserve;

 

·“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 any well;

 

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·“exploratory well” means a well drilled to find either a new field or a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well;

 

·“LNG” means liquefied natural gas;

 

·“net wells” means a party’s working interests in wells;

 

·“proved oil and gas reserves” means 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. In addition,

 

(i) the area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geosciences 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 geosciences, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty;

 

(iii) where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, 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;

 

·“PSC” means production sharing contract. For more information about PSC, see “Item 4—Information on the Company—Business Overview—Regulatory Framework in the PRC”;

 

  

 

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·“share oil” means the portion of production that must be allocated to the relevant government entity under our PSCs in the PRC;

 

·“undeveloped oil and gas reserves” means 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. In addition,

 

(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; and

 

(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, or by other evidence using reliable technology establishing reasonable certainty.

 

For further definitions relating to reserves:

 

·“reserve replacement ratio” means, for a given year, total additions to proved reserves, which consist of additions from purchases, discoveries and extensions and revisions of prior reserve estimates, divided by production during the year. Reserve additions used in this calculation are proved developed and proved undeveloped reserves; unproved reserve additions are not used. Data used in the calculation of reserve replacement ratio is derived directly from the reserve quantity reconciliation prepared in accordance with U.S. Accounting Standards Codification 932-235-50, which reconciliation is included in “Supplementary Information on Oil and Gas Producing Activities” beginning on page F-79 of this annual report.

 

Our reserve replacement ratio reflects our ability to replace proved reserves. A rate higher than 100% indicates that more reserves were added than produced in the period. However, this measure has limitations, including its predictive and comparative value. Reserve replacement ratio measures past performance only and fluctuates from year to year due to differences in the extent and timing of new discoveries and acquisitions. It is also not an indicator of profitability because it does not reflect the cost or timing of future production of reserve additions. It does not distinguish between reserve additions that are developed and those that will require additional time and funding to develop. As such, reserve replacement ratio is only one of the indices used by our management in formulating our acquisition, exploration and development plans.

 

·“reserve life” means the ratio of proved reserves to annual production of crude oil or, with respect to natural gas, to wellhead production excluding flared gas, also known as reserve-to-production ratio;

 

·“seismic data” means data recorded in either two-dimensional (2D) or three-dimensional (3D) form from sound wave reflections off of subsurface geology;

 

·“success” means a discovery of oil or gas by an exploratory well. Such an exploratory well is a successful well and is also known as a discovery. A successful well is commercial, which means there are enough hydrocarbon deposits discovered for economic recovery;

 

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·“wildcat well” means an exploratory well drilled on any rock formation for the purpose of searching for petroleum accumulations in an area or rock formation that has no known reserves or previous discoveries;

 

References to:

 

·“bbls” means barrels, which is equivalent to approximately 0.134 tons of oil (33 degrees API);

 

·“mmbbls” means million barrels;

 

·“BOE” means barrels-of-oil equivalent;

 

·“mcf” means thousand cubic feet;

 

·“mmcf” means million cubic feet;

 

·“bcf” means billion cubic feet, which is equivalent to approximately 28.32 million cubic meters; and

 

·“BTU” means British Thermal Unit, a universal measurement of energy.

 

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FORWARD-LOOKING STATEMENTS

 

This annual report includes “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995, including statements regarding expected future events, business prospects or financial results. The words “expect”, “anticipate”, “continue”, “estimate”, “objective”, “ongoing”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends” and similar expressions are intended to identify such forward-looking statements.

 

These forward-looking statements address, among others, such issues as:

 

·                         the amount and nature of future exploration, development and other capital expenditures,

 

·                         wells to be drilled or reworked,

 

·                         development projects,

 

·                         exploration prospects,

 

·                         estimates of proved oil and gas reserves,

 

·                         development and drilling potential,

 

·                         expansion and other development trends of the oil and gas industry,

 

·                         business strategy,

 

·                         production of oil and gas,

 

·                         development of undeveloped reserves,

 

·                         expansion and growth of our business and operations,

 

·                         oil and gas prices and demand,

 

·                         future earnings and cash flow, and

 

·                         our estimated financial information.

 

These statements are based on assumptions and analysis made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will meet our expectations and predictions depend on a number of risks and uncertainties which could cause our actual results, performance and financial condition to differ materially from our expectations, including but not limited to those associated with fluctuations in crude oil and natural gas prices, our exploration or development activities, our capital expenditure requirements, our business strategy, whether the transactions entered into by us can complete on schedule pursuant to their terms and timetable or at all, the highly competitive nature of the oil and natural gas industry, our foreign operations, environmental liabilities and compliance requirements, and economic and political conditions in the PRC and overseas. For a description of these and other risks and uncertainties, see “Item 3—Key Information—Risk Factors.”

 

Consequently, all of the forward-looking statements made in this annual report are qualified by these cautionary statements. We cannot assure that the results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected effect on us, our business or our operations.

 

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SPECIAL NOTE ON THE FINANCIAL INFORMATION AND CERTAIN STATISTICAL INFORMATION PRESENTED IN THIS ANNUAL REPORT

 

Our consolidated financial statements for the years ended December 31, 2016, 2017 and 2018 included in this annual report on Form 20-F have been prepared in accordance with International Financial Reporting Standards, or IFRSs, as issued by the International Accounting Standards Board.

 

In accordance with rule amendments adopted by the U.S. Securities and Exchange Commission, or the SEC, which became effective on March 4, 2008, we are not required to provide reconciliation to Generally Accepted Accounting Principles in the United States.

 

The statistical information set forth in this annual report on Form 20-F relating to China is taken or derived from various publicly available government publications that have not been prepared or independently verified by us. This statistical information may not be consistent with other statistical information from other sources within or outside China.

 

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PART I

 

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

 

Not applicable, but see “Item 6—Directors, Senior Management and Employees—Directors and Senior Management.”

 

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

 

Not applicable.

 

ITEM 3. KEY INFORMATION

 

A.Selected Financial Data

 

The following tables present selected historical financial data of our Company as of and for the years ended December 31, 2014, 2015, 2016, 2017 and 2018. Except for amounts presented in U.S. dollars, the selected historical consolidated statement of financial position data and consolidated statement of profit or loss and other comprehensive income data set forth below are derived from, should be read in conjunction with, and are qualified in their entirety by reference to, our consolidated financial statements and their notes under “Item 18—Financial Statements” and “Item 5—Operating and Financial Review and Prospects” in this annual report. As disclosed above under “Special Note on the Financial Information and Certain Statistical Information Presented in This Annual Report”, our consolidated financial statements have been prepared and presented in accordance with IFRSs.

 

   Year ended December 31,
   2014  2015  2016  2017  2018  2018
   Rmb  Rmb  Rmb  Rmb  Rmb  US$
   (in millions, except per share and per ADS data)
Statement of profit or loss and other comprehensive income data:                  
Operating revenues:                  
Oil and gas sales   218,210  146,597   121,325  151,888  185,872  27,034
Marketing revenues   50,263  21,422   20,310  28,907  35,830  5,211
Other revenue   6,161  3,418  4,855  5,595  5,261  765
Total operating revenues   274,634  171,437  146,490  186,390  226,963  33,010
                   
Expenses:                  
Operating expenses   (31,180)  (28,372)   (23,211)  (24,282)        (24,251)  (3,527)
Taxes other than income tax   (11,842)  (10,770)   (6,941)  (7,210)          (9,127)  (1,327)
Exploration expenses   (11,525)  (9,900)   (7,359)  (6,881)        (12,924)  (1,880)
Depreciation, depletion and amortization   (58,286)  (73,439)   (68,907)  (61,257)        (50,640)  (7,365)
Special oil gain levy   (19,072)  (59)   -  (55)  (2,599)  (378)
Impairment and provision   (4,120)  (2,746)   (12,171)  (9,130)  (567)  (82)
Crude oil and product purchases   (47,912)  (19,840)   (19,018)  (27,643)  (33,558)  (4,881)
Selling and administrative expenses   (6,613)  (5,705)   (6,493)  (6,861)  (7,286)  (1,060)
Others   (3,169)  (3,150)  (4,802)  (6,021)  (5,772)  (840)
Total expenses   (193,719)  (153,981)  (148,902)  (149,340)  (146,724)  (21,340)
                   
Profit/(loss) from operating activities  80,915  17,456  (2,412)  37,050  80,239  11,670
     Interest income   1,073  873   901  653  796  116
     Finance costs   (4,774)  (6,118)  (6,246)  (5,044)  (5,037)  (733)
     Exchange gains /(losses), net   1,049  (143)  (790)  356  (141)  (21)
     Investment income   2,684  2,398  2,774  2,409  3,685  536
     Share of profits/(losses) of associates   232  256  (609)  302  406  59
     Profit/(loss) attributable to a joint venture   774  1,647  533  553  (5,593)  (813)
     Other income, net  560  761  574  78  822  120
                   
Profit/(loss) before tax   82,513  17,130  (5,275)  36,357  75,177  10,934
Income tax (expense)/credit   (22,314)  3,116  5,912  (11,680)  (22,489)  (3,271)

Profit for the year   60,199  20,246  637  24,677  52,688  7,663

  

 

 

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   Year ended December 31,
   2014  2015  2016  2017  2018  2018
   Rmb  Rmb  Rmb  Rmb  Rmb  US$
   (in millions, except per share and per ADS data)
Earnings per share (basic)(2)   1.35  0.45  0.01  0.55  1.18  0.17
Earnings per share (diluted)(3)   1.35  0.45  0.01  0.55  1.18  0.17
Earnings per ADS (basic)(2)   134.83  45.35  1.43  55.40  118.01  17.16
Earnings per ADS (diluted)(3)   134.57  45.31  1.43  55.40  117.99  17.16
                   
Dividend per share                  
Interim   0.198  0.205  0.105  0.170  0.266  0.04
Proposed final   0.254  0.210  0.204  0.243  0.341  0.05

 

   As of December 31,
   2014  2015  2016  2017  2018  2018
   Rmb  Rmb  Rmb  Rmb  Rmb  US$
   (in millions)
Statement of Financial Position Data:                  
Cash and cash equivalents   14,918  11,867  13,735  12,572  14,432  2,099
Available-for sale financial assets(1)   54,030  -  -  -  -  -
Other financial assets(1)   -  71,806  52,889  74,344  125,283  18,222
Current assets   140,708  140,211  122,045  138,838  190,082  27,646
Property, plant and equipment, net   463,222  454,141  432,465  395,868  407,337  59,245
Investments in associates   4,100  4,324  3,695  4,067  4,433  645
Investments in a joint venture   21,150  24,089  26,300  25,079  20,268  2,948
Intangible assets   16,491  16,423  16,644  15,070  15,717  2,286
Available-for-sale financial assets(1)  5,337  -  -  -  -  -
Equity investments(1)   -  3,771  4,266  3,540  4,048  589
Total assets    662,859  664,362  637,681  617,219  678,779  98,724
Current loans and borrowings   31,180  33,585  19,678  13,892  7,042  1,024
Current liabilities   103,498  84,380  67,090  61,412  70,242  10,216
Non-current loans and borrowings   105,383  131,060  130,798  118,358  132,479  19,268
Total non-current liabilities    179,751  193,941  188,220  175,832  191,172  27,805
Total liabilities   283,249  278,321  255,310  237,244  261,414  38,021
Capital stock   43,081  43,081  43,081  43,081  43,081  6,266
Shareholders’ equity   379,610  386,041  382,371  379,975  417,365  60,703

___________________

(1)From January 1, 2015, the Company early adopted IFRS/HKFRS 9 (2009) - Financial Instruments. Certain financial assets have been classified into new categories.

(2)Earnings per share (basic) and earnings per ADS (basic) for each year from 2014 to 2018 have been computed, without considering the dilutive effect of the shares underlying our share option schemes by dividing profit by the weighted average number of shares and the weighted average number of ADSs of 44,647,455,984 and 446,474,560, respectively, for each year from 2014 to 2018, in each case based on a ratio of 100 shares to one ADS.

(3)Earnings per share (diluted) and earnings per ADS (diluted) for each year from 2014 to 2018 have been computed, after considering the dilutive effect of the shares underlying our share option schemes by using 44,734,774,504 shares and 447,347,745 ADSs for 2014, 44,684,819,053 shares and 446,848,191 ADSs for 2015, 44,659,140,488 shares and 446,591,405 ADSs for 2016, and 44,651,557,953 shares and 446,515,580 ADSs for 2017, and 44,656,022,966 shares and 446,560,230 ADSs for 2018.

 

   Year ended December 31,
   2014  2015  2016  2017  2018  2018
   Rmb  Rmb  Rmb  Rmb  Rmb  US$
      (in millions, except percentages and ratios)
Other Financial Data:                  
Capital expenditures paid(1)   95,673  67,674  51,347  47,734  50,411  7,333
Cash provided by/(used for):                  
Operating activities   110,508  80,095  72,863  94,734  123,883  18,018
Investing activities   (90,177)  (76,495)  (27,953)  (64,411)  (94,861)  (13,797)
Financing activities   (19,486)  (6,893)  (43,240)  (31,271)  (27,370)  (3,981)
Gearing ratio(2)   26.5%  29.9%  28.2%  25.8%  25.1%  25.1%

 

____________________

(1)Capital expenditures paid exclude those relating to acquisition of oil and gas properties.

(2)Interest bearing debt divided by the sum of interest bearing debt and equity.

 

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B.Capitalization and Indebtedness

 

Not applicable.

 

C.Reasons for the Offer and Use of Proceeds

 

Not applicable.

 

D.Risk Factors

 

Although we have established the risk management system to identify, analyze, evaluate and respond to risks, our business activities may subject to the following risks, which could have material effects on our strategy, operations, compliance and financial condition. We urge you to carefully consider the risks described below.

 

Our business, cash flows and profits fluctuate with volatility in oil and gas prices.

 

Prices for crude oil, natural gas and oil products may fluctuate widely in response to relative changes in the supply and demand for crude oil and natural gas, market uncertainty and various other factors beyond our control, including, but not limited to overall economic conditions, political instability, armed conflict and acts of terrorism, economic conditions and actions by major oil-producing countries, the price and availability of other energy sources, domestic and foreign government regulations, natural disasters and weather conditions. Changes in oil and gas prices could have a material effect on our business, cash flows and earnings.

 

Oil and gas prices are volatile. A downward trend in oil and gas prices which lasts for a long period may adversely affect our business, revenue and profits, and may also result in write-off of higher cost reserves and other assets, reduction of the amount of oil and natural gas we can produce economically and termination of existing contracts that have become uneconomic. The prolonged slump in oil and natural gas prices may also impact our long-term investment strategy and operation capability for our projects.

 

Our business and strategy may be substantially affected by complex macro economy, political instability, war and terrorism and changes in policy and fiscal and tax regimes.

 

Despite the global economy has been recovering, some of the countries in which we operate may be considered politically and economically unstable. As a result, our financial condition and operating results could be adversely affected by associated international activities, domestic civil unrest and general strikes, political instability, war and acts of terrorism. Any changes in regime or social instability, or other political, economic or diplomatic developments, or changes in fiscal and tax regimes are not within our control. Our operations, existing assets or future investments may be materially and adversely affected by these changes. In addition, our operations and assets may also be subject to potential trade and economic sanctions due to deteriorated relations between different countries.

 

Our financial performance is affected by the tax and fiscal regimes of host countries in which we operate. Any changes in these regimes may result in increased costs, including the potential for additional or double taxation being imposed on our Company in some circumstances. For example, the Organization for Economic Co-operation and Development (OECD)’s “Base Erosion and Profit Shifting Project” (BEPS Project) was initiated to enhance multilateral cooperation and strengthen supervision on global corporate taxation and transfer pricing activities. Numerous countries have responded to the BEPS Project by implementing tax law changes and amending tax treaties at a rapid pace.

 

Oil and natural gas industry are very competitive.

 

We compete in the PRC and international markets with national oil companies, major integrated oil and gas companies and various other independent oil and gas companies for access to oil and gas

 

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resources, products, alternative energy, customers, capital financing, technology and equipment, personnel and business opportunities. Competition may result in shortage of these resources or over-supply of oil and gas, which could increase our cost or reduce our earnings, and adversely impact our business, financial condition and results of operations.

 

In addition to competition, as we need to obtain various approvals from governmental and other regulatory authorities in order to maintain our operations, we may face unfavorable results such as project delays and cost overruns, which may further impact the realization of our strategies and materially and adversely impact our financial condition.

 

Our ability to deliver competitive returns and pursue commercial opportunities depends in part on the robustness and the long-lasting accuracy of our price assumptions.

 

We review the oil and natural gas price assumptions on a periodic basis when evaluating project decisions and business opportunities. We generally test projects and other business opportunities against a long-term price range. While we believe our current long-term price assumptions are prudent, if such assumptions proved to be incorrect, it could have a material adverse effect on our Company. For short-term planning purposes, we stress test the project feasibility against a wider range of prices.

 

Rising climate change concerns could lead to additional regulatory measures that may result in higher costs.

 

It is expected that the CO2 emissions will increase as our production grows. CO2 emissions from flaring will increase if there are no proven and reliable gas gathering systems in place. With the coming into force of the Paris Agreement and the continuing growth of public’s awareness of climate change problems, the carbon emission policies of different countries are gradually enacted. The Company will be supervised by relevant agencies and organizations in the future. If we are unable to find economically viable and publicly acceptable solutions that could reduce our CO2 emissions for new and existing projects, we may experience additional costs and our reputation may be affected.

 

Mergers, acquisitions and divestments may expose us to additional risks and uncertainties, and we may not be able to realize the anticipated benefits from mergers, acquisitions and divestments.

 

Mergers and acquisitions may not succeed due to various reasons, such as difficulties in integrating activities and realizing synergies, outcomes differing from key assumptions, host governments reacting or responding in a different manner from that envisaged, or liabilities and costs being underestimated. Any of these would reduce our ability to realize the anticipated benefits. We may not be able to successfully divest non-core assets at acceptable prices, resulting in increased pressure on our cash position. In the case of divestments, we may be held liable for past acts, or failures to act or perform responsibilities. We may also be subject to liabilities if a purchaser fails to fulfill our commitments. These risks may result in an increase in our costs and inability to achieve our business goals.

 

The nature of our operations exposes us and the communities in which we operate to a wide range of health, safety, security and environment risks.

 

Every aspect of our daily operations exposes us to health, safety, security and environment (“HSSE”) risks given the geographical area, operational diversity and technical complexity of our operations. Our operations include productions and transportations of oil and gas in environmentally sensitive regions and politically unstable areas, such as the basins in Uganda, Iraq, as well as offshore fields far away from land, especially deep-water fields. Our operations expose us and the areas in which we operate to a number of risks, including potential major process safety incidents, natural disasters, social unrest, health and safety lapses and destruction by third party external forces, such as platform destruction caused by typhoon and sea ice, and oil spills and gas leaks caused by external force damage suffered by submarine pipelines. If a major HSSE risk materializes, such as an explosion or hydrocarbon spill, this could result in casualties, environmental damage, disruption of business activities, depending on their cause and severity, material damage to our reputation, exclusion from bidding on mineral rights and

 

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eventually loss of our license to operate. In certain circumstances, liabilities could be imposed without regard to our fault in the matter. Regulatory requirements for HSSE in different countries where we operate change constantly and may become more stringent over time. In the future, we may incur significant additional costs in complying with such requirements or bear liabilities such as fines, penalties, clean-up costs and third-party claims, as a result of breach of HSSE-related laws and regulations.

 

We maintain various insurance policies for our operations against potential losses. However, our ability to insure against our risks is subject to the availability of relevant insurance products in the market. In addition, we cannot ensure you that our insurance coverage is sufficient enough to cover any losses that we may incur, or that we will be able to successfully claim our losses under our existing insurance policies on a timely basis, or at all. If any of our losses are not covered by our insurance coverage, or if the insurance compensation is less than our losses or the claim is not paid on a timely basis, our business, financial condition and results of operations could be materially and adversely affected.

 

Violations of anti-fraud, anti-corruption and corporate governance laws may expose us to various risks.

 

Laws and regulations of the host countries or regions in which we operate, such as laws on anti-corruption, anti-fraud and corporate governance, are constantly changing and strengthening, especially in the United States, the United Kingdom, Canada, Australia, Guyana and China. The compliance with these laws and regulations may increase our cost. If our directors, executives or employees fail to comply with any of such laws and regulations, it may expose us to prosecution or punishment, damage to our brand and reputations, the ability to obtain new resources and/or access to the capital markets, and it may even expose us to civil or criminal liabilities.

 

The activities of our controlling shareholder, CNOOC, or its affiliates in certain countries that are the subject of U.S. sanctions could result in negative media and investor attention and possible sanctions imposed on CNOOC, which could adversely affect our shareholders.

 

U.S. government at federal, state or local levels imposes extensive economic sanctions against certain geographical areas and their populations or against designated governments, organizations, individuals and entities wherever located. In 2018, U.S. government fully re-imposed economic sanctions against Iran that were waived or lifted pursuant to the Joint Comprehensive Plan of Action with Iran. Such changes add uncertainty to the interpretation or implementation of U.S. government with respect to current or future activities by CNOOC or its affiliates (if any) in countries or with individuals or entities that are the subject of U.S. primary and secondary sanctions. If there are any sanctions imposed on CNOOC by U.S. government, we could be prohibited from engaging in business activities in the U.S. or with U.S. individuals or entities, and U.S. transactions in our securities and distributions to U.S. individuals and entities with respect to our securities could also be prohibited. Pension or endowment funds of certain U.S. state and local governments or universities may sell our securities due to certain restrictions on investments in companies that engage in activities in sanctioned countries, such as Iran and Sudan. We may also be subject to negative media or investor attention, which may distract management, consume internal resources and affect investors’ perception of our Company and investment in our Company.

 

As required by the Iran Threat Reduction and Syria Human Rights Act of 2012, which added a disclosure requirement to the Securities Exchange Act of 1934, we are providing certain information regarding our non-controlled affiliate’s activities. To our knowledge, in 2018, China Oilfield Services Limited (COSL), one of our non-controlled affiliates, provided certain drilling services in Iran. We cannot predict at this time whether U.S. sanctions will be imposed on any of our affiliates.

 

Any failure to replace reserves and develop our proved undeveloped reserves could adversely affect our business and our financial position.

 

Our exploration and development activities involve inherent risks, including the risk of not discovering commercially productive oil or gas reservoirs and that the wells we drill may not be able to

 

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commence production or may not be sufficiently productive to generate a return of our partial or full investments. In addition, approximately 58.0% of our proved reserves were undeveloped as of December 31, 2018. Our future success depends on our ability to develop these reserves in a timely and cost-effective manner. There are various risks in developing reserves, mainly including construction, operational, geophysical, geological and regulatory risks.

 

The reliability of reserve estimates depends on a number of factors, including the quality and quantity of technical and economic data, the market prices of our oil and gas products, the production performance of reservoirs, extensive engineering judgments, comprehensive judgement of engineers and the fiscal and tax regime in the countries where we have operations or assets.

 

Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove be incorrect over time. Consequently, the results of drilling, testing, production and changes in the price of oil and gas may require substantial upward or downward revisions to our initial reserve data.

 

If we fail to develop or gain access to appropriate technologies, or to deploy them effectively, the realization of our strategies as well as our competitiveness and ability to operate may be adversely affected.

 

Technology and innovation are vital for us in meeting the global energy demands in a competitive environment and challenges from exploration and development. For example, we strive to rely on technologies and innovations to enhance our competiveness in the development of unconventional oil and gas resources, including heavy oil, oil sands, shale oil and gas and coalbed methane, and deep water exploration and development, offshore enhanced oil recovery. In the context of an operating environment with more stringent environmental compliance standards and requirements, although current knowledge recognize these newly developed technologies as safe to the environment, there still exists unknown or unpredictable elements that may have an impact on the environment. This may in turn harm our reputation and operation, increase our costs or even result in litigations and sanctions.

 

Breach of our cyber security or break down of our IT infrastructure could damage our operations and our reputation.

 

Intentional attacks on our cyber system, negligent management of our cyber security and IT system management and other factors may cause damage or break down to our IT infrastructure, which may disrupt our operations, result in loss or misuse of data or sensitive information, cause injuries, environmental harm or damage in assets, violate laws or regulations and result in potential legal liability. These actions could result in increased costs or damage to our reputation.

 

CNOOC largely controls us and we regularly enter into connected party transactions with CNOOC and its affiliates.

 

Currently, CNOOC indirectly owns or controls 64.44% of our shares. As a result, CNOOC is able to control our board composition, or our Board, determine the timing and amount of dividend payments, and control us in various aspects. In addition, under current PRC laws, CNOOC has the exclusive right to enter into PSCs with foreign enterprises for the petroleum resources exploitation in offshore China. Although CNOOC has undertaken to transfer all of its rights and obligations to us (except for those relating to administrative functions as a state-owned company) under any new PSCs that it enters into, our strategies, results of operations and financial position may be adversely affected in the event CNOOC takes actions that favour its own interests over ours.

 

In addition, we regularly enter into connected transactions with CNOOC and its affiliates. Certain connected transactions require a review by the Hong Kong Stock Exchange and are subject to prior approvals by the independent shareholders. If these transactions are not approved, we may not be able to proceed with these transactions as planned and it may adversely affect our business and financial condition.

 

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Oil and natural gas transportation may expose us to financial loss and reputation harm.

 

Our oil and gas transportation involves marine, land and pipeline transportation, which are subject to hazards such as capsizing, collision, acts of piracy and damage or loss from severe weather conditions, explosions, oil and gas spills and leakages. These hazards could result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations, risk of financial loss and reputation harm. We may not be able to arrange insurance coverage for all of these risks and uninsured losses and liabilities arising from these hazards could reduce the funds available to us for financing, exploration and investment, which may have a material adverse effect on our business, financial condition and results of operations.

 

We face various risks with regard to our business and operations in North America.

 

Transportation and export infrastructure in North America is limited, and without the construction of new transportation and export infrastructure, our oil and natural gas production capacity may be affected. In addition, we may be required to sell our products into the North American markets at lower prices than in other markets, which could materially and adversely affect our financial performance.

 

First Nation in Canada have claimed aboriginal title and rights to the lands and mineral resources in a substantial portion of western Canada. As a result, negotiations with aboriginal people on surface activities are required and may result in timing uncertainties or delays of future development activities. Declaration by the First Nation, if successful, could have a significant adverse effect on our business in Canada.

 

We may have limited control over our investments in joint ventures and our operations with partners.

 

A portion of our operations are conducted in the form of partnerships or in joint ventures in which we may have limited capability to influence and control their operation or future development. Our limited ability to influence and control the operation or future development of such joint ventures could materially and adversely affect the realization of our target returns on capital investment and lead to unexpected future costs.

 

If we depend heavily on key customers or suppliers, our business, results of operations and financial condition could be adversely affected.

 

Key sales customers – if any of our key customers reduced their crude oil or natural gas purchases from us significantly, our results of operation could be adversely affected. In order to reduce reliance on a single customer, in crude oil sales, we adopt measures including signing annual sales contracts, developing sales plans, and participating in market competition so as to maintain a stable cooperation with customers. In natural gas sales, we adopt measures including signing long-term GSA with take or pay clause so as to minimize the risk of impact on our financial condition.

 

Key suppliers – we have strengthened our communication in business with our key suppliers in order to maintain a good working relationship. We have also established strategic partnerships through communications and reached a consensus on corporate cultures and win-win cooperation. Further, we actively explore new suppliers to ensure adequacy and foster competition of supplies.

 

We face currency risks and liquidity risks.

 

Currency risks – Our oil and gas sales are substantially denominated in Renminbi and U.S. dollars. The appreciation of the Renminbi against the U.S. dollar may result in double effects, that it may decrease our revenue in the sales of oil and gas and, decrease our costs of equipment and import of raw materials in the meantime.

 

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Liquidity risks – Certain restrictions on dividend distribution imposed by the laws of the host countries in which we operate may adversely and materially affect our cash flows. For instance, the dividend of our wholly owned subsidiaries in the PRC shall be distributed pursuant to the laws of the PRC and the articles and association, and we may face risks of not obtaining adequate cash flows from such subsidiaries.

 

The audit reports included in this annual report filed with the SEC have been prepared by our auditor, an independent registered public accounting firm, whose work is not inspected by the U.S. Public Company Accounting Oversight Board (the “PCAOB”) and, as such, it is unlikely for the PCAOB to evaluate the effectiveness of our independent registered public accounting firm’s audit procedures and quality control procedures.

 

Our independent registered public accounting firm that issues the audit reports included in our annual report filed with the SEC, as a firm registered with the PCAOB, is required by the laws of the United States to undergo regular inspections by the PCAOB to assess its compliance with the laws of the United States and professional standards.

 

Because we have substantial operations within China and, without the approval of PRC authorities, the PCAOB is currently unable to conduct inspections of the work of our independent registered public accounting firm as it relates to those operations, our independent registered public accounting firm is not currently inspected by the PCAOB. Therefore, it is unlikely for the PCAOB to evaluate the effectiveness of our independent registered public accounting firm’s audit procedures or quality control procedures as compared to auditors outside of China that are subject to the PCAOB inspections.

 

Furthermore, on December 7, 2018, the PCAOB published a list of companies, including us, whose auditors are located in jurisdictions where there are obstacles to the PCAOB inspections. However, it remains unclear what further actions the SEC and the PCAOB will take to address the problem.

 

ITEM 4. INFORMATION ON THE COMPANY

 

A.History and Development

 

We were incorporated with limited liability on August 20, 1999 in Hong Kong under the Companies Ordinance (Chapter 32 of the Laws of Hong Kong, the predecessor to Chapter 622 of the Laws of Hong Kong, or the Hong Kong Companies Ordinance, which came into effect on March 3, 2014). Our Company registration number in Hong Kong is 685974. Under the Hong Kong Companies Ordinance, we have the capacity, rights, powers and privileges of a natural person of full age and may do anything which we are permitted or required to do by our articles of association or any enactment or rule of law. Our registered office is located at 65th Floor, Bank of China Tower, One Garden Road, Central, Hong Kong, and our telephone number is 852-2213-2500.

 

The PRC government established CNOOC, our controlling shareholder, as a state-owned offshore petroleum company in 1982 under the Regulation of the PRC on the Exploitation of Offshore Petroleum Resources in Cooperation with Foreign Enterprises. CNOOC assumed certain responsibility for the administration and development of PRC offshore petroleum operations with foreign oil and gas companies.

 

Prior to CNOOC’s reorganization in 1999, CNOOC and its various subsidiaries performed both commercial and administrative functions relating to oil and natural gas exploration and development in offshore China.

 

In 1999, CNOOC transferred all of its then current operational and commercial interests in its offshore petroleum business, including the related assets and liabilities, to us. As a result and subject to the undertakings below, we and our subsidiaries are the only vehicles through which CNOOC engages in oil and gas exploration, development, production and sales activities both in and outside the PRC.

 

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CNOOC retained its commercial interests in operations and projects not related to oil and gas exploration and production, as well as all of the administrative functions it performed prior to the reorganization.

 

CNOOC has undertaken to us that:

 

·we will enjoy the exclusive right to exercise all of CNOOC’s commercial and operational rights under PRC laws and regulations relating to the exploration, development, production and sales of oil and natural gas in offshore China;

 

·it will transfer to us all of its rights and obligations under any new PSCs and geophysical exploration operations, except those relating to its administrative functions;

 

·it will not engage or be interested, directly or indirectly, in oil and natural gas exploration, development, production and sales in or outside the PRC;

 

·we will be able to participate jointly with CNOOC in negotiating new PSCs and to set out our views to CNOOC on the proposed terms of new PSCs;

 

·we will have unlimited and unrestricted access to all data, records, samples and other original data owned by CNOOC relating to oil and natural gas resources;

 

·we will have an option to invest in LNG projects in which CNOOC invested or proposed to invest, and CNOOC will at its own expense help us to procure all necessary government approvals needed for our participation in these projects; and

 

·we will have an option to participate in other businesses related to natural gas in which CNOOC invested or proposed to invest, and CNOOC will procure all necessary government approvals needed for our participation in such business.

 

The undertakings from CNOOC will cease to have any effect:

 

·if we become a wholly owned subsidiary of CNOOC;

 

·if our securities cease to be listed on any stock exchange or automated trading system; or

 

·12 months after CNOOC or any other PRC government-controlled entity ceases to be our controlling shareholder.

 

For information on our capital expenditures, see “Item 5—Operating and Financial Review and Prospects—Liquidity and Capital Resources—Cash Used in Investing Activities.”

 

B.Business Overview

 

Overview

 

We are an upstream company specializing in oil and natural gas exploration, development and production. We are the dominant oil and natural gas producer in offshore China, and in terms of reserves and production, we are one of the largest independent oil and natural gas exploration and production companies in the world. As of the end of 2018, we had net proved reserves of approximately 4.96 billion BOE (including approximately 0.37 billion BOE in our equity method investees). In 2018, we achieved a total net oil and gas production of 1,301,438 BOE per day (including net oil and gas production of approximately 58,080 BOE per day in our equity method investees).

 

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Competitive Strengths

 

We believe that our historical success and future prospects are directly related to a combination of our strengths, including the following:

 

·large and diversified asset base with significant exploitation opportunities;

 

·sizable operating areas in offshore China with demonstrated exploration potential;

 

·successful independent exploration and development track record;

 

·access to capital and technology and reduced risks through PSCs in offshore China; and

 

·experienced management team and a high level of corporate governance standard.

 

Large and diversified asset base with significant exploitation opportunities

 

We have a large net proved reserve base spread across offshore China and globally. As of December 31, 2018, we had approximately 4.96 billion BOE of net proved reserves. Our core operating area, offshore China, contributed to approximately 56.5% of our net proved reserves, while overseas contributed to the balance of 43.5%.

 

In addition to offshore China, we have a diversified global portfolio which provides us with further exploration and exploitation potential. We have a strong track record of successfully acquiring and operating many quality overseas upstream assets worldwide. Currently, we have assets in resource rich countries such as Indonesia, Australia, Nigeria, Uganda, the United States, Canada, the United Kingdom, Brazil and Guyana.

 

As of December 31, 2018, approximately 58.0% of our net proved reserves were classified as net proved undeveloped. Our large proved reserve base gives us the opportunity to achieve substantial production growth.

 

Sizable operating areas in offshore China with demonstrated exploration potential

 

We are the dominant oil and gas producer in offshore China, a region that we believe has substantial exploration upside. As of December 31, 2018, our total major exploration areas acreage in offshore China was approximately 252 thousand square kilometers. We believe that offshore China is relatively underexplored, compared to other prolific offshore exploration areas such as the shallow water of the U.S. Gulf of Mexico, providing us with substantial exploration upside.

 

We have maintained an active drilling exploration program, which continues to demonstrate the exploration potential of offshore China. During 2018, we and our foreign partners have together drilled a total of 166 exploratory wells in offshore China, of which 67 were wildcat wells. During the same year, we and our foreign partners made 12 new discoveries in offshore China.

 

Successful independent exploration and development track record

 

We have a strong record of growing our reserves base for oil and natural gas, both independently and with our foreign partners through PSCs. In recent years, we have been adding reserves and production mainly through independent exploration and development. As of the end of 2018, in offshore China, approximately 85.0% of our net proved reserves were independent and approximately 78.0% of our production generated from independent projects.

 

In 2018, in offshore China, our independent exploration resulted in 11 new discoveries. We also successfully appraised 16 oil and gas structures. On the development front, our major new development projects progressed smoothly with four new projects on stream in offshore China.

 

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Access to capital and technology and reduced risks through PSCs in offshore China

 

CNOOC holds exclusive right from the PRC government to enter into PSCs with foreign enterprises relating to the petroleum resources exploitation in offshore China. CNOOC assigned us all of its rights and obligations under then-existing PSCs in 1999 and has undertaken to assign to us its future PSCs except for those relating to its administrative functions. PSCs help us minimize our offshore China finding costs, exploration risks and capital requirements because our foreign partners are responsible for all costs associated with exploration under the usual case. Our foreign partners recover their exploration costs only when a commercially viable discovery is made and production begins.

 

For more information about PSC, see “Item 4—Information on the Company—Business Overview—Regulatory Framework in the PRC.”

 

Experienced management team and a high level of corporate governance standard

 

Our senior management team has extensive experience in the oil and gas industry. Most of our executives have extensive experience in the oil and gas industry. Many of our management team and staff members have worked closely with international partners both within and outside China through numerous joint operations.

 

We have always upheld and attained high standard of business ethics, for which our transparency and standard of governance have been recognized by the public and our shareholders. In 2018, we were awarded as the “Best Investor Relations Company (China)” and “Asia’s Best CEO (Investor Relations (China))” by Corporate Governance Asia Magazine, “Top 100 Global Energy Leaders” by Thomson Reuters, “2018 China Securities Golden Bauhinia Awards - Best Listed Companies” and “Best CEO of Listed Companies” by Ta Kung Wen Wei Media Group and “Corporate Awards - Platinum” by The Asset.

 

Business Strategy

 

As one of the largest independent oil and gas exploration and production companies, we mainly engage in the exploration, development, production and sales of oil and natural gas. The principal components of our strategy are as follows:

 

·focus on reserve and production growth;

 

·develop natural gas business; and

 

·maintain a prudent financial policy.

 

Focus on reserve and production growth

 

As an upstream company specializing in the exploration, development, production and sales of oil and natural gas, we consider reserve and production growth as our top priorities. We plan to increase our reserves and production through drill bits and value-driven acquisitions. We will continue to concentrate our independent exploration efforts on major operating areas, especially offshore China. In the meantime, we will continue to cooperate with our partners through production sharing contracts to lower capital requirements and exploration risks.

 

We increase our production primarily through the development of proved undeveloped reserves. As of December 31, 2018, approximately 58.0% of our proved reserves were classified as proved undeveloped, which provides a solid resource base for maintaining increasing production in the future.

 

Develop natural gas business

 

We will continue to develop the natural gas market, and continue to explore and develop natural gas fields. In the event that we invest in businesses and geographic areas where we have limited

 

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experience and expertise, we plan to structure our investments in the form of alliances or partnerships with partners possessing the relevant experience and expertise.

 

We adopt the low-carbon development concept and proactively expands the natural gas business. In 2018, Bozhong 19-6 gas field was successfully appraised and proved to contain proved in-place volume of condensate over 100 million cubic meters and natural gas over 100 billion cubic meters. In addition, Lingshui 17-2 gas field, the first self-operated major deep-water natural gas field discovery in offshore China, entered into its development and construction stage. The project is expected to effectively promote the development of deep-water natural gas in the South China Sea and will be an important growth driver for our natural gas production in the future.

 

Maintain a prudent financial policy

 

We will continue to maintain our prudent financial policy. As an essential part of our corporate culture, we continue to promote cost consciousness among both our management team and employees. Also, in our performance evaluation system, cost control has been one of the most important key performance indicators.

 

In 2018, we continued our efforts to lower costs and enhance efficiency through innovation in technology and management. All-in cost decreased for the fifth consecutive year. Under the environment of oil price fluctuations, we attached more importance to cash flow management and maintained a healthy financial position.

 

Selected Operating and Reserves Data

 

The following table sets forth our operating data and our net proved reserves as of the date and for the periods indicated.

 

Our reserve data were prepared in accordance with the SEC’s final rules on Modernization of Oil and Gas Reporting.

 

  

Year ended December 31,

  

2016

 

2017

 

2018

Net Production(2):         
Oil (daily average bbls/day)   1,083,101  1,064,986  1,050,749
Gas (daily average mmcf/day)   1,276.2  1,300.6  1,452.6
Oil equivalent (BOE/day)   1,302,922  1,288,128  1,301,438
          
Net Proved Reserves (as of the end of period):         
Oil (mmbbls)   2,015.4  2,295.0  2,413.9
Gas (bcf)   7,486.1  7,543.3  7,626.8
Synthetic Oil (mmbbls)   300.5  785.9  796.3
Bitumen (mmbbls)   0.0  118.4  88.1
Total (million BOE)   3,583.4  4,474.1  4,590.0
Total with equity method investees (million BOE)(2)   3,877.6  4,840.8  4,962.1
Annual reserve replacement ratio(1)   6%  297%  126%
Annual reserve replacement ratio(2)   8%  305%  126%
Estimated reserve life (years)   7.8  9.9  10.1
Estimated reserve life (years)(2)   8.1  10.3  10.5
Standardized measure of discounted future net cash
  flow (million Rmb) 		  223,625  241,904   416,075

_________________ 

(1)For the calculation of reserve replacement ratio, see “Terms and Conventions—Glossary of Technical Terms”

(2)Including our interest in equity method investees.

 

For further information regarding our reserves, see “Item 3—Key Information—Risk Factors—Any failure to replace reserves and develop our proved undeveloped reserves could adversely affect our business and our financial position” and “Item 4—Information on the Company—Business Overview—Exploration, Development and Production.”

 

23 

Table of Contents 

Summary of Oil and Gas Reserves

 

The following table sets forth summary information with respect to our estimated net proved reserves of crude oil and natural gas as of the dates indicated.

 

  

Net proved reserves

as of December 31,

   

Net proved reserves

as of December 31, 2018

   2016  2017  Crude Oil  Natural Gas  Synthetic Oil  Bitumen  Total
   (mmboe)  (mmboe)  (mmbbls)  (bcf)  (mmbbls)  (mmbbls)  (mmboe)
Developed                     
Offshore China                     
Bohai   600.8  661.3  612.3  228.6  —  —  650.4
Western South China Sea   165.5  177.4  117.8  452.5  —  —  195.3
Eastern South China Sea   285.2  293.9  166.4  775.7  —  —  295.7
East China Sea   34.9  24.0  5.0  87.1  —  —  19.5
Subtotal   1,086.4  1,156.6  901.5  1,544.0  —  —  1,160.9
Overseas                     
Asia (excluding China)   160.3  133.4  24.6  531.4  —  —  118.9
Oceania   62.1  53.3  8.3  259.7  —  —  59.2
Africa   40.7  36.9  102.3  —  —  —  102.3
North America (excluding Canada)   124.1  169.2  143.0  275.3  —  —  188.9
Canada   155.7  192.0  —  0.2  136.2  —  136.2
South America   1.5  1.3  1.1  —  —  —  1.1
Europe   81.7  84.6  98.1  3.2  —  —  98.6
Subtotal   626.1  670.7  377.5  1,069.7  136.2  —  705.3
Total Developed   1,712.5  1,827.3  1,279.0  2,613.7  136.2  —  1,866.2
                      
Undeveloped                     
Offshore China                     
Bohai   349.4  440.1  491.8  524.8  —  —  579.2
Western South China Sea   653.3  666.7  105.2  3,263.1  —  —  650.5
Eastern South China Sea   220.3  239.8  282.2  127.9  —  —  303.5
East China Sea   111.3  110.2  2.5  648.0  —  —  110.5
Subtotal   1,334.3  1,456.8  881.7  4,563.8  —  —  1,643.7
Overseas                     
Asia (excluding China)   84.7  92.1  29.5  310.2  —  —  84.4
Oceania   15.3  15.7  0.5  19.8  —  —  4.3
Africa   97.3  100.0  11.4  —  —  —  11.4
North America (excluding Canada)   194.4  183.2  120.4  115.7  —  —  139.7
Canada   144.8  716.2  —  —  660.1  88.1  748.2
South America   —  78.4  78.4  —  —  —  78.4
Europe   0.1  4.6  13.1  3.5  —  —  13.7
Subtotal   536.6  1,190.1  253.2  449.3  660.1  88.1  1,080.1
Total Undeveloped   1,870.9  2,646.8  1,134.8  5,013.1  660.1  88.1  2,723.7
TOTAL PROVED   3,583.4  4,474.1  2,413.9  7,626.8  796.3  88.1  4,590.0
Equity method investees   294.2  366.7  258.1  661.5  —  —  372.2
Total with equity method investees   3,877.6  4,840.8  2,672.0  8,288.2  796.3  88.1  4,962.1

 

The following tables set forth net proved crude oil reserves, net proved natural gas reserves and total net proved reserves as of the dates indicated for our independent and non-independent operations in each of our operating areas.

 

24 

Table of Contents 

 

Total Net Proved Crude and Liquids Reserves
(mmbbls)

 

   As of December 31,  As of December 31, 2018
   2016  2017  Developed  Undeveloped  Total
Offshore China               
Bohai   903.8  1050.4  612.3  491.8  1,104.1
Western South China Sea   168.3  196.5  117.8  105.2  223.0
Eastern South China Sea   363.1  371.9  166.4  282.2  448.6
East China Sea   10.6  8.5  5.0  2.5  7.5
Subtotal   1,445.7  1,627.3  901.5  881.7  1,783.2
Overseas               
Asia (excluding China)   77.3  69.9  24.6  29.5  54.1
Oceania   12.0  10.7  8.3  0.5  8.8
Africa   138.0  136.9  102.3  11.4  113.7
North America (excluding Canada)   260.3  282.1  143.0  120.4  263.4
Canada   300.5  904.3  136.2(1)  748.2(2)  884.4
South America   1.5  79.7  1.1  78.4  79.5
Europe   80.6  88.4  98.1  13.1  111.2
Subtotal   870.2  1,571.9  513.7  1,001.4  1,515.1
Total   2,315.9  3,199.3  1,415.2  1,883.1  3,298.3
Equity method entities   195.3  244.8  135.7  122.4  258.1
Total with equity method investees   2,511.2  3,444.1  1,550.9  2,005.5  3,556.4

__________________

(1)Including synthetic oil 136.2 mmbbls

(2)Including synthetic oil 660.1 mmbbls and bitumen 88.1 mmbbls

 

Total Net Proved Natural Gas Reserves
(bcf)

 

   As of December 31,  As of December 31, 2018
   2016  2017  Developed  Undeveloped  Total
Offshore China               
Bohai   278.7  305.7  228.6  524.8  753.4
Western South China Sea   3,896.8  3,880.1  452.5  3,263.1  3,715.6
Eastern South China Sea   854.9  970.5  775.7  127.9  903.7
East China Sea   813.3  754.4  87.1  648.0  735.1
Subtotal   5,843.7  5,910.7  1,544.0  4,563.8  6,107.8
Overseas               
Asia (excluding China)   952.4  885.0  531.4  310.2  841.6
Oceania   333.5  297.2  259.7  19.8  279.5
Africa   —  —  —  —  —
North America (excluding Canada)   349.6  421.5  275.3  115.7  390.9
Canada   —  24.2  0.2  —  0.2
South America   —  —  —  —  —
Europe   6.9  4.8  3.2  3.5  6.7
Subtotal   1,642.4  1,632.6  1,069.7  449.3  1,519.0
Total   7,486.1  7,543.3  2,613.7  5,013.1  7,626.8
Equity method investees   574.0  706.8  490.8  170.6  661.5
Total with equity method investees   8,060.1  8,250.1  3,104.5  5,183.7  8,288.2

  

 

25 

Total Net Proved Reserves
(million BOE)

 

   As of December 31,  As of December 31, 2018
   2016  2017  Developed  Undeveloped  Total
Offshore China               
Bohai   950.2  1,101.4  650.4  579.2  1,229.7
Western South China Sea   818.8  844.1  195.3  650.5  845.8
Eastern South China Sea   505.5  533.7  295.7  303.5  599.2
East China Sea   146.2  134.2  19.5  110.5  130.0
Subtotal   2,420.7  2,613.3  1,160.9  1,643.7  2,804.6
Overseas               
Asia (excluding China)   245.0  225.4  118.9  84.4  203.3
Oceania   77.4  69.0  59.2  4.3  63.6
Africa   138.0  136.9  102.3  11.4  113.7
North America (excluding Canada)   318.6  352.3  188.9  139.7  328.6
Canada   300.5  908.3  136.2  748.2  884.4
South America   1.5  79.7  1.1  78.4  79.5
Europe   81.8  89.2  98.6  13.7  112.3
Subtotal   1,162.7  1,860.8  705.3  1,080.1  1,785.4
Total   3,583.4  4,474.1  1,866.2  2,723.7  4,590.0
Equity method investees   294.2  366.7  220.3  151.9  372.2
Total with equity method investees   3,877.6  4,840.8  2,086.5  2,875.6  4,962.1

 

Proved Reserves

 

As of December 31, 2018, we had proved reserves of 4,962.1 million BOE, including 2,672.0 million barrels of crude oil, 796.3 million barrels of synthetic oil, 88.1 million barrels of Bitumen and 8,288.2 bcf of natural gas, representing an increase of 121.3 million BOE as compared to proved reserves of 4,840.8 million BOE as of December 31, 2017.

 

The changes in our proved reserves mainly include:

 

·An increase of 378.8 million BOE due to new discoveries and extensions, details of which are described below:

 

ØOffshore China: the discoveries and extensions of oil and gas reserves in the amount of 299.6 million BOE, which are primarily attributable to fields such as Bozhong 19-6, Bozhong 29-6 and Lufeng12-3; and

 

ØOverseas: the discoveries and extensions of oil and gas reserves in the amount of 79.2 million BOE, which are primarily attributable to fields such as Buzzard in U.K., OOGC in the United States as well as Long Lake in Canada;

 

·An increase of 211.5 million BOE due to revision of previous estimates, details of which are described below:

 

ØOffshore China: an increase of 199.6 million BOE caused either by technical factors, which were mainly due to better than expected production performance and increased reservoir recoveries from infill drilling, or by changes in economic factors, primarily related to the increase in oil price;

 

Among them, the proved reserves in Bohai increased from 1,101.4 million BOE as of December 31, 2017 to 1,229.7 million BOE as of December 31, 2018, representing an increase of 296.5 million BOE (production in 2018 was 168.2

 

26 

million BOE) or 65% of the total offshore China revision, primarily attributable to fields such as Jinzhou 25-1S, Suizhong 36-1 and Bozhong 34-1;

 

ØOverseas: an increase of 11.9 million BOE caused either by technical factors, which were mainly due to better than expected production performance and increased reservoir recoveries from infill drilling or by changes in economic factors, primarily related to the increase in oil price;

 

·The production of 475.0 million BOE in 2018.

 

As a result of above-mentioned changes in our proved reserves, annual reserve replacement ratio and estimated reserve life as of December 31, 2018 were 126% and 10.5 years, respectively.

 

Proved Undeveloped Reserves (PUD)

 

As of December 31, 2018, we had PUD of 2,875.6 million BOE, including 1,257.3 million barrels of crude oil, 660.1 million barrels of synthetic oil, 88.1 million barrels of Bitumen and 5,183.7 bcf of natural gas, representing an increase of 88.3 million BOE as compared to PUD of 2,787.3 million BOE as of December 31, 2017.

 

The changes in our PUD mainly include:

 

·An increase of 357.2 million BOE due to new discoveries and extensions, details of which are described below:

 

ØOffshore China: the discoveries and extensions of oil and gas reserves in the amount of 290.1 million BOE, which are primarily attributable to fields such as Bozhong 19-6, Bozhong 29-6 and Lufeng 12-3, etc.; and

 

ØOverseas: the discoveries and extensions of oil and gas reserves in the amount of 67.1million BOE which are primarily attributable to Buzzard in U.K., OOGC in the United States and Long Lake in Canada;

 

·A decrease of 282.4 million BOE due to PUD converted to Proved Developed Reserves (“PD”);

 

·An increase of 13.5 million BOE due to revision of previous estimates, details of which are described below:

 

ØOffshore China: an increase of 6.2 million BOE caused either by technical factors, which were mainly due to better than expected production performance and increased reservoir recoveries from infill drilling, or by changes in economic factors, primarily related to the increase in oil price;

 

ØOverseas: an increase of 7.3 million BOE caused either by technical factors, which were mainly due to better than expected production performance and increased reservoir recoveries from infill drilling, or by changes in economic factors, primarily related to the increase in oil price.

 

In 2018, we had in total 282.4 million BOE PUD converted to PD and we spent approximately Rmb 35.9 billion on developing PUD into PD. Rmb 29.6 billion, or 82%, was spent on major development projects in Bohai, Eastern South China Sea, Western South China Sea in offshore China and Canada, Guyana, Nigeria, U.K. and the United States. The remaining 18%, or Rmb 6.3 billion, was spent mainly on the infill drilling programs in offshore China and Nigeria.

 

27 

As of December 31, 2018, 227.6 million BOE of our PUD were first booked before 2013. These PUD were mainly located in Western South China Sea, Bohai and Eastern South China Sea, including (i) 152.2 million BOE of Dongfang 13-2 gas field, or 67% of the total in Western South China Sea, which will be put on stream in 2019; (ii) 38.4 million BOE in Bohai, including Qinhuangdao 33-1S and Luda 6-2 oil fields which are scheduled to come on stream in 2020 and 2021; and (iii) 29.3 million BOE in Eastern South China Sea, including Liuhua 16-2 which is under construction and will be put on stream in 2020. The development of PUD relating to the above projects was not completed within five years from initial booking due to the specific circumstances associated with the relevant development activities and delivery obligations. The Company books proved reserves for which development is scheduled to commence after more than five years only if these proved reserves satisfy the SEC’s standards for attribution of proved status and our management has reasonable certainty that these proved reserves will be produced.

 

Qualifications of Reserve Technical Oversight Group and Internal Controls over Proved Reserves

 

Reserve data contained in this annual report is based on the definitions and disclosure guidelines contained in the SEC Title 17: “Code of Federal Regulations–Modernization of Oil and Gas Reporting–Final Rule” in the Federal Register (SEC regulations), released on January 14, 2009 and related accounting standards. Our proved reserves estimates were prepared using standard geological and engineering methods generally accepted by the petroleum industry, and the definitions and standards of reserves required by the SEC. Generally accepted methods for estimating reserves include volumetric calculations, material balance techniques, production decline curves, pressure transient analysis, analogy with similar reservoirs, and reservoir simulation. The method or combination of methods used is based on professional judgment and experience.

 

For 2016, 2017 and 2018, approximately 60%, 65%, and 69%, respectively, of our reserves were evaluated by our internal reserves evaluation staff, and the remaining were based upon estimates prepared by independent petroleum engineering consulting companies and reviewed by us. Except as otherwise stated, all amounts of reserves in this report include our interests in equity method investees.

 

In 2018, we engaged Ryder Scott Company, L.P., Gaffney, Cline & Associates (Consultants) Pte Ltd. and RPS as independent third party consulting firms to perform annual estimates for our net proved oil and gas reserves under our consolidated subsidiaries. For each independent third party consulting firm, a report of third party letter has been prepared which summarizes the work undertaken, the assumptions, data, methods and procedures they used and provides their reserves estimate. These reports have been included as exhibits to this report on Form 20-F.

 

For overseas assets, approximately 70% of the total net proved oil and gas reserves were evaluated by our internal reserve evaluation staff, which accounted for 30% of our total net proved oil and gas reserves. And we also engaged independent third party consulting firms Ryder Scott Company, L.P., McDaniel & Associates Consultants Ltd. and DeGolyer and MacNaughton to conduct audits for internally evaluated reserves to provide validation of our processes and estimates. For each independent third party consulting firm, a report of third party letter has been prepared which summarizes the work undertaken, the assumptions, data, methods and procedures they used and concludes with their opinion concerning the reasonableness of the estimated reserves quantities or reserves processes. These reports have been included as appendices to this annual report.

 

Approximately 69% of the offshore China and other overseas assets were evaluated by our internal reserves evaluation staff and the remaining 31% net proved oil and gas reserves of the offshore China and other overseas assets were estimated by these independent third party consulting firms.

 

Based on the extent and expertise of our internal reserves evaluation resources, our staff’s familiarity with our properties and the controls applied to the evaluation process, we believe that the reliability of our internally generated estimates of reserves and future net revenue is not materially less than that of reserves estimates conducted by an independent qualified reserves evaluator.

 

28 

Besides engaging third parties to provide annual estimates and audits of our reserves, we also implement rigorous internal control system that monitors the entire reserves estimation process and certain key metrics in order to ensure that the process and results of reserves estimates fully comply with the relevant SEC rules. We established the Reserve Management Committee, or RMC, which is led by one of our Executive Vice Presidents and comprises the general managers of the relevant departments.

 

The RMC’s main responsibilities are to:

 

·review our reserve policies;

 

·review our proved reserves and other categories of reserves; and

 

·select our reserve estimators and auditors.

 

The RMC follows certain procedures to appoint our internal reserve estimators and reserve auditors, who are required to have undergraduate degrees and at least five years and ten years of experience related to reserves estimation, respectively.

 

The reserves estimators and auditors are required to be members of a professional society such as China Petroleum Society (CPS), and are required to take the professional training and examinations as required by the professional society and us.

 

The RMC delegates its daily operation to our Reserves Office, which is led by our Chief Reserves Supervisor. The Reserves Office is mainly responsible for supervising reserves estimates and auditing. It reports to the RMC periodically and is independent from operating divisions such as the exploration, development and production departments. Our Chief Reserve Supervisor has over 35 years’ experience in the oil and gas industry.

 

Exploration, Development and Production

 

Summary

 

In offshore China, we engage in oil and natural gas exploration, development and production in Bohai, Western and Eastern South China Sea, and the East China Sea, either independently or in cooperation with foreign partners through production sharing contracts (“PSCs”). As of the end of 2018, approximately 56.5% of our net proved reserves and approximately 64.9% of our net production were derived from offshore China.

 

For independent operations, we have been adding to our reserves and production mainly through independent exploration and development in offshore China. At the end of 2018, approximately 85% of our net proved reserves and approximately 78% of our net production in offshore China were derived from independent projects.

 

For its PSC operations, China National Offshore Oil Corporation (“CNOOC”), our controlling shareholder, has the exclusive right to explore and develop oil and natural gas in offshore China in cooperation with foreign partners through PSCs. CNOOC has transferred to us all its rights and obligations in regard to the PSCs (except those relating to its management and regulatory function as a state-owned company), including new PSCs that will be signed in the future.

 

After years of hard work, we have established our presence in more than 20 countries and regions. Our overseas assets account for over 50% of our total assets. With our diversified portfolio of high-quality assets, we are an active participant in a number of world-class oil and gas projects and is regarded as a leading industry player. Currently, we hold interests in oil and natural gas blocks in Indonesia, Australia, Nigeria, Uganda, Argentina, the United States, Canada, the United Kingdom, Brazil, Guyana and various other countries. As of the end of 2018, approximately 43.5% of our net proved reserves and approximately 34.9% of our net production were derived from overseas.

 

29 

In 2018, the global economy continued its moderate growth momentum. The U.S. economy remained relatively robust, while slower growth was recorded in the Eurozone and other economies to different extents. The global demand for oil has grown steadily. The international oil price fell deeply after having reached higher grounds but on average, the oil price surged upward extensively during the year. Numerous major geopolitical incidents occurred during the year, imposing great impact on international oil prices.

 

Under the complex and ever-changing external environment, we focused on our own development and adhered to the operating strategies determined at the beginning of the year, which included: steadily increasing our oil and gas reserve and production levels, reinforcing quality and efficiency enhancement, strengthening innovation and technology-driven philosophy, maintaining prudent financial policy and investment decision-making, and pursuing a green, healthy and environment-friendly development model.

 

In 2018, we achieved our production and business targets despite being faced with a number of challenges. We adhered to a value-driven exploration philosophy, targeted mid-to-large sized oil and gas discoveries with enhanced efforts in exploration. 17 new discoveries were made and 17 successful appraisals of oil and gas structures were achieved. Weizhou 6-13 oilfield and Penglai 19-3 oilfield 1/3/8/9 comprehensive adjustment project in offshore China as well as Stampede oilfield in the U.S. Gulf of Mexico came on stream during the year. The production target was met with a net production of 475.0 million BOE. To ensure our continuing sustainable development, we pushed ahead steadily with the construction of new projects. Notwithstanding the pressure of rebounding oil prices and rising costs, all-in cost per BOE decreased for five consecutive years to US$30.39. We maintained a healthy financial position with net profit of Rmb 52.7 billion for the year. Meanwhile, our performance in the areas of health, safety and environmental protection remained stable.

 

Looking forward to 2019, the global economy will continue its slow recovery. The movement of international oil prices and the external environment are filled with uncertainties. To this end, we remain confident of our prospects. We will further strengthen our operating strategies, which mainly include: steadily increasing oil and gas reserve and production levels, promoting high-quality development, improving core business enhancement with digital transformation, maintaining prudent financial policy and investment decision-making, and pursuing a green, low-carbon and environmentally-friendly development model.

 

In 2019, our capital expenditure is anticipated to reach Rmb 70 to 80 billion, and our production target is 480 to 490 million BOE with six new projects to commence production. Our target for the reserve replacement ratio is 120%. Meanwhile, we will maintain our high standards of health, safety and environmental protection.

 

Exploration

 

In 2018, we devoted greater efforts in our oil and gas exploration, and amount of our exploration activities reached a record high. Adhering to value-driven and business exploration and anchoring on our exploration and discoveries of mid-to-large sized oil and gas fields, several major discoveries were made. This continuously maintained a good development momentum of oil and gas exploration. Various exploration breakthroughs were achieved in new frontier areas in offshore China, and a strategic core exploration area was gradually formed on both sides of the Atlantic Ocean. Our management capability and technological innovation capability have been further enhanced, and the efficiency of exploration operations has been significantly improved. In addition, we continued to maintain a reasonable proportion of exploration investment and a relatively high level of exploration activities so as to ensure mid-to-long term sustainable development. In 2018, our reserve replacement ratio was 126%, and the reserve life further increased to 10.5 years.

 

In offshore China, our exploration activities remained at a high level. A total of 166 exploration wells were drilled, 10 of which were drilled through PSC. A total of 11,534 kilometers of 2D seismic data and 14,653 square kilometers of 3D seismic data were acquired independently and through PSC. We

 

30 

made 12 new discoveries and successfully appraised 16 oil and gas structures in offshore China. The success rate for independent exploration wells in offshore China was 53% to 63%.

 

In 2018, we continued to follow a value-driven exploration strategy in offshore China, resulting in outstanding achievement. Notable achievements include the following:

 

·First, four mid-to-large sized oil and gas fields, namely Bozhong 19-6, Bozhong 29-6, Bozhong 13-1 South and Ledong 10-1, were successfully appraised.

 

·Secondly, exploration breakthroughs were achieved in the South China Sea. The newly discovered Lufeng 12-3 is the largest commercial PSC discovery in recent years, and has the potential to be developed into a mid-sized oilfield. The new discoveries of Enping 10-2 and Enping 15-2 confirmed the exploration potential of the northern belt of Enping Sag, and are expected to be jointly developed with Enping 15-1 to create a mid-sized oilfield.

 

·Thirdly, the rolling exploration in the Bohai and Beibu Gulf areas continued to improve. Proved crude oil geological reserves will contribute to our production capacity in 2019.

 

·Fourthly, progress was made in risk exploration in new areas. The Songnan Baodao Sag in the Qiongdongnan Basin and the Yangjiang Sag in the Pearl River Mouth Basin have opened up new areas for reserve growth.

 

Overseas, we drilled eight exploration wells, made five new discoveries and successfully appraised one oil and gas structure. Major achievements include the following:

 

·First, five more new discoveries were made in Stabroek block in Guyana. A total of 12 discoveries were made in the block.

 

·Secondly, we focused on our overseas strategic planning and obtained three new blocks in Brazil and the U.K. North Sea, which further optimized our overseas exploration assets.

 

Our major exploration activities in 2018 are set out in the table below:

 

   Exploration Wells  New Discoveries  Successful Appraisal Wells  Seismic Data
   Independent  PSC              2D (km) 

3D (km2)

   Wildcat  Appraisal  Wildcat  Appraisal  Independent  PSC  Independent  PSC  Independent  PSC  Independent  PSC
Offshore China                                    
Bohai   22  58  0  1  6  0  48  0  0  0  776  0
Eastern South China Sea   20  10  4  4  3  1  4  2  3,744  2,199  5,040  835
Western South China Sea   16  24  1  0  2  0  19  0  3,073  0  7,088  0
East China Sea   4  2  0  0  0  0  0  0  2,518  0  914  0
Subtotal   62  94  5  5  11  1  71  2  9,335  2,199  13,818  835
Overseas   0  0  6  2  0  5  0  2  0  0  0  0
Total   62  94  11  7  11  6  71  4  9,335  2,199  13,818  835

 

In 2019, we will continue to follow a value-driven exploration philosophy and target mid-to-large size oil and gas discoveries offshore China. We will make efforts on both oil and gas exploration and strengthen gas exploration activities. We will strengthen exploration in new area and frontier area and adhere to optimal exploration investment to support our sustainable development. Overseas, we will also develop proactive planning to accelerate the progress of the existing projects, promptly acquire high-quality new projects and continuously expand the scope of exploration.

 

Engineering Construction, Development and Production

 

In 2018, we successfully met our operational targets, with oil and gas production in line with

 

31 

expectations. We carefully organized our operational resources and made smooth progress in engineering construction. More than 20 projects were under construction throughout the year.

 

In 2018, our net oil and gas production reached 475.0 million BOE, representing a slight increase year-on-year, fulfilling the production target set at the beginning of the year. Weizhou 6-13 oilfield and Penglai 19-3 oilfield 1/3/8/9 comprehensive adjustment project in offshore China as well as Stampede oilfield in the U.S. Gulf of Mexico came on stream during the year.

 

In 2018, our development and production were driven by intensive and streamline management with emphasis on cost savings and efficiency enhancement, technology-driven strategy and sustainable development. Achievements mainly include:

 

·First, we ensured base production level and laid a solid foundation for production profile of existing oilfields through refined management.

 

·Secondly, we strictly controlled costs, encouraged conservation and improved efficiency, and all-in cost per BOE decreased for five consecutive years.

 

·Thirdly, we coordinated and adjusted the workload of infill drillings, which reached to a record high.

 

·Fourthly, we devoted great efforts in promoting the “Year of Water Injection” program of Bohai oilfield in order to further tap the potential of producing oilfields.

 

In 2019, a total of six new projects are expected to commence production, including Bozhong 34-9 oilfield, Caofeidian 11-1/11-6 oilfield comprehensive adjustment project, Wenchang 13-2 oilfield comprehensive adjustment project and Huizhou 32-5 oilfield comprehensive adjustment/Huizhou 33-1 oilfield joint development project in offshore China, as well as Egina oilfield in Nigeria and Appomattox project in the U.S. Gulf of Mexico. Among them, Huizhou 32-5 oilfield comprehensive adjustment/ Huizhou 33-1 oilfield joint development project and Egina oilfield have commenced production in January 2019.

 

In addition, we will continue to optimize the development plan of producing oil and gas fields to control natural decline and guarantee base production level. Implementation of new development wells will be accelerated to commence production as soon as possible. We will also continue to optimize the infill drilling program to ensure the record high workload be achieved. Meanwhile, we will pursue technological innovation in our production measures to achieve great stimulation effects.

 

Regional Overview

 

Offshore China

 

Bohai

 

Bohai is the most important crude oil producing area for us. The crude oil produced in this region is mainly heavy oil. The operational area in Bohai is mainly shallow water with a depth of 10 to 30 meters. As of the end of 2018, the reserve and daily production volume in Bohai were 1,229.7 million BOE and 460,822 BOE/day, respectively, representing approximately 24.8% of our total reserves and 35.4% of our daily production.

 

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With rich oil and gas resources, Bohai is one of our primary areas for exploration and development. In 2018, we made six successful discoveries in Bohai, namely Luda 10-6, Luda 4-3, Luda 6-2 South, Bozhong 13-2, Longkou 19-1 North and Kenli 5-1. We also successfully appraised five oil and gas structures, including Bozhong 19-6, Bozhong 29-6, Bozhong 13-1 South, Kenli 4-1 and Longkou 7-6. Material progress has been made in the appraisal of Bozhong 19-6 gas field, proving that Bozhong 19-6 is a large gas field with proved in-place volume of condensate more than 100 million cubic meters and nature gas more than 100 billion cubic meters. Bozhong 29-6 oilfield is expected to become a hundred-million-ton class oilfield. These new discoveries and successful appraisals further demonstrated Bohai’s potential as core region for us.

 

For development and production, we launched a major technology campaign in 2018 to ensure stable production of Bohai oilfield of 30 million tons for another 10 years. Penglai 19-3 oilfield 1/3/8/9 comprehensive adjustment project commenced production during the year. Bozhong 34-9 oilfield and Caofeidian 11- 1/11-6 oilfields comprehensive adjustment project are expected to come on stream in 2019. More new projects in Bohai are under construction, which will strongly support our future production growth.

 

Western South China Sea

 

Western South China Sea is one of our important natural gas production areas. Currently, the typical water depth of our operational area in the region ranges from 40 to 120 meters. As of the end of 2018, the reserves and daily production volume in Western South China Sea reached 845.8 million BOE and 154,248 BOE/ day, respectively, representing approximately 17.0% of our total reserves and 11.9% of our daily production.

 

In 2018, we made two successful discoveries in Western South China Sea, namely Wushi 23-5 North and Weizhou 10-3 East. The discovery in Wushi 23-5 North has expanded new formations and will boost the development of Wushi oilfields. We also achieved six successful appraisals, namely Ledong 10-1, Weizhou 11-2 East, Wushi 16-1, Weizhou 11-12, Wushi 16-1 West and Wenchang 19-9. The successful appraisal of Ledong 10-1 obtained significant progress in the high temperature and ultra-high pressure sector, making Ledong area the new battlefield of continuous reserves expansion.

 

For development and production, Weizhou 6-13 oilfield commenced production during the year. In addition, Wenchang 13-2 oilfield comprehensive adjustment project is expected to start production in 2019.

 

In 2018, Lingshui 17-2, the first independent deepwater gas field in offshore China, entered the construction stage, which will promote the development of deepwater natural gas resources in South China Sea and become an important growth point for our natural gas production in the future.

 

Eastern South China Sea

 

Eastern South China Sea is another important crude oil and natural gas producing area for us. Currently, the typical water depth of our operational area in the region ranges from 100 to 1,500 meters. The crude oil produced is mostly of light to medium gravity. As of the end of 2018, reserves and daily production volume in Eastern South China Sea reached 599.2 million BOE and 216,877 BOE/day, respectively, representing 12.1% of our total reserves and 16.7% of our daily production.

 

In 2018, new discoveries of Lufeng 12-3, Enping 10-2, Enping 15-2 and Enping 20-4 were made in Pearl River Mouth Basin. Lufeng 12-3 oilfield has been the largest commercial PSC discovery in recent years and is expected to be developed to a mid-sized oilfield. The discoveries of Enping 10-2 and Enping 15-2 proved the exploration potential of the northern belt of Enping Sag and are expected to be jointly developed with Enping 15-1 to a mid-sized oilfield. Furthermore, five oil and gas structures, namely Lufeng 14-8, Lufeng 14-4, Lufeng 22-1, Enping 18-1 and Xijiang 34-3, were successfully appraised.

 

33 

For development and production, Huizhou 32-5 oilfield comprehensive adjustment/Huizhou 33-1 oilfield joint development project commenced production in January 2019. New projects such as Liuhua 16-2/20-2 oilfield joint development are currently under construction.

 

East China Sea

 

The typical water depth of our operational area in the East China Sea region is approximately 90 meters. As of the end of 2018, reserves and daily production volume in the region represented 2.6% and 1.0% of our total reserves and daily production, respectively.

 

In 2018, we continued with the regional development of certain gas fields in the East China Sea, which would help us optimize the energy structure, target on both oil and gas exploration, devote more effort to natural gas development and achieve “stable oil production and increased gas production.”

 

Others

 

We responded to the global trend of low carbon development for energy industry. Taking advantage of offshore operation strength, we have actively explored the opportunities of renewable clean energy development. In January 2019, we participated in an offshore wind power project in Jiangsu province.

 

Overseas

 

Asia (excluding China)

 

Asia (excluding China) was the first overseas region that we entered into, and it has become one of our major overseas oil and gas producing areas. Currently, we hold oil and gas assets mainly in Indonesia and Iraq. As of the end of 2018, reserves and daily production volume derived from Asia (excluding China) reached 203.3 million BOE and 88,662 BOE/day, respectively, representing 4.1% of our total reserves and 6.8% of our daily production.

 

Indonesia

 

At the end of 2018, our asset portfolio in Indonesia comprised mainly two development and producing blocks, namely Madura Strait and Tangguh. Among these, the Madura Strait PSC was a joint operation block, in which the production of BD gas field maintained stable, and other gas fields were under appraisal and construction.

 

We own an interest of approximately 13.90% in the Tangguh LNG Project in Indonesia. In 2018, production volume of Phase I of the project remained stable with a daily net production of approximately 22,000 BOE/day. Currently, construction of the third LNG train of Phase II is in progress as planned, and is expected to reach completion and commence production in 2020.

 

In 2018, we had withdrawn from the Southeast Sumatra block due to the expiration of the contract. The working interest in Malacca PSC was transferred and is pending for government approval and settlement.

 

Iraq

 

We hold a 63.75% participating interest in the technical service contract of Missan oilfields in Iraq and acts as the oilfields’ lead contractor.

 

In 2018, we continuously drilled development wells and devoted more efforts to production enhancement measures of Missan oilfields, resulting in a steady increase in daily net production of the project to approximately 49,000 barrels per day. The investment of the project over the past years was fully recovered and we started to recover foregone remuneration. The gross production target of 250,000 barrels per day was achieved as of the end of 2018.

 

34 

Oceania

 

Currently, our oil and gas assets in Oceania are mainly located in Australia and Papua New Guinea. As of the end of 2018, reserves and daily production volume derived from Oceania reached 63.6 million BOE and 26,034 BOE/day, respectively, representing approximately 1.3% of our total reserves and 2.0% of our daily production.

 

Australia

 

We own a 5.3% interest in the Australian North West Shelf LNG Project. The project has commenced production and is currently supplying gas to end-users including the Dapeng LNG Terminal in Guangdong, China.

 

In 2018, the North West Shelf LNG Project maintained stable production and achieved favorable economic returns.

 

Other Regions in Oceania

 

We owned interests in three blocks which are still under exploration in Papua New Guinea.

 

Africa

 

Africa is a relatively large oil and gas reserve and production base for us. Our assets in Africa are primarily located in Nigeria and Uganda. As of the end of 2018, reserves and daily production volume in Africa reached 113.7 million BOE and 59,844 BOE/day, respectively, representing approximately 2.3% of our total reserves and 4.6% of our daily production.

 

Nigeria

 

We own a 45% interest in the OML130 block in Nigeria. The OML130 block is a deepwater project comprising four oilfields, namely Akpo, Egina, Egina South and Preowei.

 

In 2018, the Akpo oilfield maintained stable production, with daily net production reaching approximately 46,000 barrels per day. The Egina oilfield commenced production in January 2019 and our production increased steadily. In 2018, the Preowei oilfield development plan was completed and submitted to the government for approval.

 

We also hold a 20% non-operating interest in Usan oilfield in the OML138 block in offshore Nigeria, and an 18% non-operating interest in the OPL 223 and OML 139 PSC. In 2018, the daily net production of Usan oilfield was approximately 13,000 BOE/day.

 

We will continue to further integrate the OML130, OML 138, OML 139 and OPL 223 projects to establish an oil and gas production base in west Africa centered in Nigeria.

 

Uganda

 

We own one-third of the interest in each of EA 1, EA 2 and EA 3A in Uganda. EA 1, EA 2 and EA 3A are located at the Lake Albert Basin, one of the most promising basins for oil and gas resources in onshore Africa.

 

In 2018, the front end engineering design (FEED) for drilling in EA 3A block was fully completed. The tender process and tender evaluation process for engineering procurement and construction (EPC) firms was basically completed as well. The Phase II of FEED was completed in EA 1 and EA 2 blocks. We were actively initiating the negotiation for crude oil pipeline for the project.

 

Other Regions in Africa

 

35 

Apart from Nigeria and Uganda, we own interests in several blocks in Senegal, Republic of the Congo, Algeria and the Gabonese Republic.

 

North America

 

North America has become our largest overseas reserves and production region. We hold interests in oil and gas assets in the U.S., Canada and Trinidad and Tobago, as well as shares in MEG Energy Corporation in Canada. As of the end of 2018, our reserves and daily production volume in North America reached 1,213.0 million BOE and 143,967 BOE/ day, respectively, representing 24.4% of our total reserves and 11.1% of our daily production.

 

United States

 

Currently, we own interests in two onshore shale oil and gas projects in the U.S. and two offshore deepwater development projects in the Gulf of Mexico.

 

The onshore shale oil and gas projects are Eagle Ford and Niobrara. CNOOC holds 27% and 12% interests in the two projects, respectively. In 2018, the daily net production of the Eagle Ford project remained stable, which was approximately 54,000 BOE/day.

 

We own interests in two major deepwater development projects, Stampede and Appomattox, and numbers of other exploration blocks in the Gulf of Mexico. Among these, Stampede commenced production in February 2018. Appomattox is currently undergoing pipeline installation and offshore test and is expected to commence production in the second half of 2019.

 

Canada

 

Canada is one of the world’s richest places of oil sands resources, and participation in the country’s oil sands development will make a major contribution to our sustainable growth. We own a 100% working interest in Long Lake oil sands project, as well as three other oil sands projects in the Athabasca region of north eastern Alberta. In 2018, the daily net production of Long Lake project ramped up to approximately 42,000 BOE/day.

 

We hold a 7.23% interest in the Syncrude project and our daily net production in 2018 was approximately 17,000 BOE/day. We also hold a 25% interest in the Hangingstone oil sands project and non-operating interests in several other exploration and development leases.

 

We hold a 100% interest in two exploration blocks in offshore Newfoundland.

 

In 2018, we made the final investment decision on the Long Lake Southwest (LLSW) oil sands project and the KIA production resumption project. Both projects are expected to commence production in 2020.

 

In addition, we hold approximately 12.39% of shares in MEG Energy Corporation, a company listed on the Toronto Stock Exchange.

 

Other Regions in North America

 

We own 12.5% interest in the 2C block and a 17.12% interest in the 3A block in Trinidad and Tobago, respectively, of which the 2C block is in production. Phase III of the natural gas project in 2C block yielded stable production and achieved favorable economic returns. We also own a 100% exploration interest in the deepwater exploration block 1 and block 4 of the Cinturon Plegado Perdido in Mexico, respectively.

 

South America

 

In South America, we hold a 50% interest in BC Energy Investments Corp. (“BC”) and a 10%

 

36 

interest in the PSC for the Libra oilfield in Brazil. Our 50% interest in BC is accounted for by equity methods. As of the end of 2018, our reserves and daily production volume derived from South America reached 450.3 million BOE and 59,640 BOE/day, respectively, representing approximately 9.1% of our total reserves and 4.6% of our daily production.

 

Argentina

 

We hold a 50% interest in BC which it makes joint management decisions. BC holds a 50% interest in Pan American Energy Group (“PAEG”) in Argentina.

 

In 2018, we strived to enhance our operating efficiency, optimize operating plans and create innovative development plans. Daily net production for BC averaged approximately 57,000 BOE/day.

 

Brazil

 

We hold a 10% interest in Libra PSC, a deepwater pre-salt project in Brazil. The oilfield is located in the Santos Basin, with a block area of about 1,550 square kilometers and a water depth of approximately 2,000 meters.

 

The Mero oilfield in the northwest area includes 4 production units of Mero 1, Mero 2, Mero 3 and Mero 4. The daily net production of the extended well trial project in Mero 2 and Mero 3 in 2018 reached approximately 2,200 BOE/day. As for development, the operator Petróleo Brasileiro S.A. (“Petrobras”) has submitted an overall development proposal for the Libra project southwest block to the Brazil government on behalf of its partners, and entered into a joint development agreement on cross boundary structures outside the contract blocks.

 

Brazil is one of the world’s most important deepwater oil and gas development regions. We will fully leverage on the development opportunities of the Libra project to seek new drivers for production growth.

 

We also hold a 100% interest in the 592 block in offshore Brazil and a 20% interest in the ACF Oeste block. Additionally, we obtained a 30% interest in the Pau Brasil block in 2018.

 

Guyana

 

We hold a 25% interest in the Stabroek block in offshore Guyana. In 2018, the Liza oilfield Phase I construction was in good progress and is expected to commence production in 2020. The Field Development Proposal (FDP) design of Liza oilfield Phase II was finished and pending for government approval. The final investment decision is planned to be made in 2019.

 

In 2018, the Liza reservoir in the block was further successfully appraised. Five new successful discoveries, including Ranger, Pacora, Longtail, Hammerhead and Pluma, were made, which has further expanded the scale of reserve.

 

Other Regions in South America

 

We also hold interests in several exploration and production blocks in Colombia.

 

Europe

 

We hold interests in oil and gas fields such as Buzzard and Golden Eagle in the U.K. North Sea. As of the end of 2018, our reserves and daily production volume derived from Europe reached 112.3 million BOE and 76,615 BOE/day, respectively, representing approximately 2.3% of our total reserves and 5.9% of our daily production.

 

United Kingdom

 

37 

Our asset portfolio in the North Sea includes projects under production, development and exploration, mainly comprising: 43.2% interest in the Buzzard oilfield, one of the largest oilfields in the North Sea, and a 36.5% interest in the Golden Eagle oilfield. These make us the largest crude oil operator in the North Sea.

 

The United Kingdom is one of our key overseas development areas, with key projects such as Buzzard and Golden Eagle contributing substantially to our production. In 2018, the Buzzard oilfield’s daily net production reached approximately 50,000 BOE/day. As for development, the final investment decision on Buzzard oilfield Phase II was made in 2018 and the oilfield is expected to commence production in 2020.

 

Furthermore, we hold interests in three blocks in the United Kingdom, and has obtained a 30% interest in the P2414 block and P2415 block in West of Shetland Basin in 2018.

 

Other Regions in Europe

 

We hold a 50% interest in the FEL 3/18 block, a 80% interest in LO 16/23 block and exploration interests in other five blocks in offshore Ireland.

 

Other Oil and Gas Data

 

Oil and Gas Production, Production Prices and Production Costs

 

The following table sets forth our net production, average sales price and average production cost (excluding ad valorem and severance taxes) in the years of 2016, 2017 and 2018.

 

   Net Production  Average Sales Price  Average Production Cost
   Total  Crude and Liquids  Gas  Crude and Liquids  Gas   
   (BOE/day)  (Bbls/day)  (Mmcf/day)  (US$/bbl)  (US$/Mmcf)  (US$/BOE)
2018                  
Offshore China                  
Bohai   460,822  433,325  165.0  —  —  —
Western South China Sea   154,248  109,381  265.2  —  —  —
Eastern South China Sea   216,877  159,312  345.4  —  —  —
East China Sea   11,580  3,347  49.4  —  —  —
Subtotal   845,171 (1)  705,366  825.0  70.79  7,207  7.01
Overseas                  
Asia (excluding China)   88,662  59,240  164.2  65.60  8,067  9.37
Oceania   26,034  4,251  111.1  73.31  3,245  6.74
Africa   59,844  59,844  —  69.44  —  6.22
North America (excluding Canada)  74,184  53,120  126.4  59.39  3,080  6.55
Canada   69,783  64,026  34.5  29.98  1,222  18.20
South America   3,066  3,066  —  62.22  —  24.81
Europe   76,615  73,678  17.6  70.37  6,700  6.89
Subtotal   398,187  317,224  453.9  59.30  4,934  9.39
Total   1,243,357  1,022,589  1,278.9  67.22  6,408  7.77
Equity method investees   58,080  28,159  173.7  —  —  —

 

  

 

38 

   Net Production  Average Sales Price  Average Production Cost
   Total  Crude and Liquids  Gas  Crude and Liquids  Gas   
2017                  
Offshore China                  
Bohai  458,473  433,591  149.3  —  —  —
Western South China Sea   142,870  96,543  273.5  —  —  —
Eastern South China Sea   212,895  173,192  238.2  —  —  —
East China Sea   13,016  3,629  56.3  —  —  —
Other   688  —  4.1  —  —  —
Subtotal   827,941  706,955  721.4  55.04  6,810  7.57
Overseas                  
Asia (excluding China)   82,958  57,395  141.4  47.83  6,658  12.19
Oceania   22,598  3,691  96.5  58.39  3,167  8.61
Africa   73,625  73,625  —  53.32  —  5.90
North America (excluding Canada)  68,507  46,785  130.3  45.99  2,995  6.27
Canada   64,167  57,711  38.7  32.56  1,702  20.08
South America   929  929  —  43.70  —  10.63
Europe   100,046  95,750  25.8  52.57  4,757  5.89
Subtotal   412,832  335,887  432.8  47.63  4,220  9.59
Total   1,240,773  1,042,842  1,154.2  52.65  5,838  8.24
Equity method investees   47,355  22,144  146.4  —  —  —
                   
2016                  
Offshore China                  
Bohai   477,380  455,002  134.3  —  —  —
Western South China Sea   144,835  98,351  273.9  —  —  —
Eastern South China Sea   213,835  182,848  185.9  —  —  —
East China Sea   12,273  3,177  54.6  —  —  —
Subtotal   848,322  739,378  648.7  42.88  6,663  6.36
Overseas                  
Asia (excluding China)   75,780  48,577  150.2  33.17  6,243  11.45
Oceania   26,107  4,278  111.4  40.97  3,176  7.57
Africa   80,297  80,297  —  42.90  —  5.72
North America (excluding Canada)  69,290  48,078  127.3  34.81  2,390  4.63
Canada   48,448  40,304  48.9  28.24  1,345  24.24
South America   926  926  —  32.48  —  8.14
Europe   104,473  98,672  34.8  41.78  4,061  6.83
Subtotal   405,320  321,131  472.5  38.00  3,815  9.23
Total   1,253,643  1,060,509  1,121.2  41.40  5,463  7.29
Equity method investees   49,280  22,592  155.0  —  —  —

____________________

(1)Includes other production from onshore China, which was approximately 1,644 BOE/day in 2018.

 

 

Drilling and Other Exploratory and Development Activities

 

The following table sets forth our net exploratory wells and development wells drilled in the years of 2016, 2017 and 2018.

 

39 

   Net Exploratory Wells Drilled  Net Development Wells Drilled
   Total  Productive  Dry  Total  Productive  Dry
2018                  
Offshore China                  
Independent                  
Bohai   80  54  26  36  36  —
Western South China Sea   40  22  18  36  36  —
Eastern South China Sea   30  7  23  9  9  —
East China Sea   6  —  6  —  —  —
Subtotal   156  83  73  81  81  —
PSCs                  
Bohai   1  —  1  13.8  13.8  —
Western South China Sea   1  —  1  —  —  —
Eastern South China Sea   8  3  5  —  —  —
East China Sea   —  —  —  —  —  —
Subtotal   10  3  7  13.8  13.8  —
Overseas                  
Asia (excluding China)   —  —  —  23.8  23.8  —
Oceania   —  —  —  —  —  —
Africa   —  —  —  1.4  1.4  —
North America   —  —  —  63  63  —
South America   1.85  1.60  0.25  2.3  2.3  —
Europe   —  —  —  —  —  —
Subtotal   1.85  1.60  0.25  90.5  90.5  —
                   
2017                  
Offshore China                  
Independent                  
Bohai   60  37  21  33  33  —
Western South China Sea   28  13  11  22  22  —
Eastern South China Sea   23  5  18  12  12  —
East China Sea   3  —  3  —  —  —
Subtotal   114  55  53  67  67  —
PSCs                  
Bohai   1  —  1  8.7  8.7  —
Western South China Sea   —  —  —  —  —  —
Eastern South China Sea   1  —  1  —  —  —
East China Sea   —  —  —  0.5  0.5  —
Subtotal   2  —  2  9.2  9.2  —
Overseas                  
Asia (excluding China)   —  —  —  16.5  16.5  —
Oceania   —  —  —  —  —  —
Africa   0.5  0.5  —  3.6  3.6  —
North America   0.2  —  0.2  67.3  67.3  —
South America   1.6  1.6  0.1  —  —  —
Europe   0.6  —  0.6  —  —  —
Subtotal   2.9  2.1  0.9  87.4  87.4  —

  

 

40 

2016                  
Offshore China                  
Independent                  
Bohai   56  41  15  87  87  —
Western South China Sea   27  9  18  24  24  —
Eastern South China Sea   24  7  17  22  22  —
East China Sea   4  1  3  —  —  —
Subtotal   111  58  53  133  133  —
PSCs                  
Bohai   1  —  1  1.5  1.5  —
Western South China Sea   3  —  3  —  —  —
Eastern South China Sea   1  1  —  —  —  —
East China Sea   —  —  —  6.5  6.5  —
Subtotal   5  1  4  8.0  8.0  —
Overseas                  
Asia (excluding China)   —  —  —  10.5  10.5  —
Oceania   —  —  —  —  —  —
Africa   0.9  0.9  —  4.0  4.0  —
North America   0.3  —  0.3  55.66  55.66  —
South America   1.3  0.9  0.4  0.25  0.25  —
Europe   0.4  —  0.4  2.19  2.19  —
Subtotal   2.9  1.8  1.0  72.6  72.6  —

 

 

Present Activities

 

The following tables set forth our present activities as of December 31, 2018.

 

   Wells Being Drilled  Waterfloods Being Installed
   Gross  Net  Gross  Net
Offshore China            
Bohai   30  23.2  791  714.7
Western South China Sea   8  5.2  51  51
Eastern South China Sea   2  2  —  —
East China Sea   —  —  —  —
Subtotal   40  30.4  842  765.7
Overseas            
Asia (excluding China)   8  6.8  3  3
Oceania   —  —  —  —
Africa   1  0.5  2  0.9
North America   3  3  2  0.5
South America   3  0.8  26  6.5
Europe   —  —  —  —
Subtotal   15  11.1  33  10.9

 

Oil and Gas Properties, Wells, Operations, and Acreage

 

The following table sets forth our productive wells, developed acreage and undeveloped acreage as of December 31, 2018.

 

41 

   Productive Wells 

Developed Acreage (km2)

 

Undeveloped Acreage (km2)

   Crude and Liquids  Natural Gas            
   Gross  Net  Gross  Net  Gross  Net  Gross  Net
Offshore China                        
Bohai   2,209  1,929.8  28  28  2,636  2,636  42,794  42,794
Western South China Sea   350  330.2  103  98.5  1,941  1,941  72,778  72,778
Eastern South China Sea   446  400.7  43  38.1  2,652  2,652  51,379  51,379
East China Sea   20  7.6  72  33.3  85  85  85,141  85,141
Subtotal   3,025  2,668.2  246  197.9  7,314  7,314  252,092  252,092
Overseas                        
Asia (excluding China)   136  136  19  3.4  869  619  14,334  5,670
Africa   23  10.4  —  —  880  352  22,919  8,509
Oceania   —  —  66  3.0  3,240  172  27,343  4,114
North America   3,592  954.3  335  116.5  1,087  369  7,045  6,925
South America   4,918  1,209.8  560  140  2,997  695  32,199  8,436
Europe   59  25  2  1  89  38  10,751  6,865
Subtotal   8,727.9  2,335.4  982  263.9  9,163  2,245  114,591  40,519
Total   11,753  5,004  1,228  462  16,477  9,559  366,683  292,611

 

The gross acreage disclosed above includes the total number of acres in major blocks that we own an interest. The net acreage includes our wholly owned interests and the sum of our fractional interests in gross acreage.

 

Delivery Commitment

 

We have certain delivery commitments under the take-or-pay contracts for sales of natural gas. In 2018, the annual sales from our largest gas contract contributed to only approximately 2.4% of our total oil and gas sales and the total revenues from gas sales accounted for approximately 8.8% of our total revenues in 2018. Moreover, the total gas quantities that are subject to delivery commitments under existing contracts or agreements are not significant to us. Therefore, we believe that we did not have any material delivery commitment as of the end of 2018.

 

Sales and Marketing

 

Sales of Crude Oil

 

We sell crude oil produced in offshore China to the PRC market mainly through CNOOC China Limited, our wholly owned subsidiary. We sell crude oil produced overseas to international and domestic markets mainly through another wholly-owned subsidiary, China Offshore Oil (Singapore) International Pte Ltd.

 

Our crude oil sales prices are mainly determined by the prices of international benchmark crude oil of similar quality, with certain premiums or discounts subject to prevailing market conditions. Although the prices are quoted in U.S. dollars, customers in China usually paid in Renminbi. We currently sell three types of crude oil in China: heavy crude, medium crude and light crude. The benchmark price for crude oil is Brent. Our major customers in China are CNOOC, PetroChina and Sinopec. Crude oil produced overseas is benchmarked at the Brent and WTI prices and sold on international markets.

 

In 2018, as a result of the increase in international oil prices, our realized oil prices picked up. Our average realized oil price was US$67.22/barrel, representing a year-on-year increase of 27.7%.

 

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The table below sets forth the sales and marketing volumes in offshore China for each of these types of crude oil for the periods indicated.

 

   Year ended December 31,
   2016  2017  2018
Sales and Marketing Volumes (mmbbls)(1)         
Light Crude   20.8  26.3  23.6
Medium Crude   162.6  147.4  148.4
Heavy Crude   122.4  112.3  106.8

___________________

(1)Includes the sales volumes of us and our foreign partners under production sharing contracts.

 

Sales of Natural Gas

 

Our natural gas sales prices are mainly determined by negotiation with customers. Its natural gas sales agreements are generally long-term contracts, and contract terms normally include a price review mechanism. Our natural gas customers are primarily located in the southeastern coast of China and include CNOOC Gas and Power Group, China BlueChemical Ltd, Hong Kong Castle Peak Power Company Limited and others.

 

Sales of LNG sourced by us from the North West Shelf LNG Project in Australia and the Tangguh LNG Project in Indonesia are mainly based on long-term supply contracts with various customers in the Asia-Pacific region, including Guangdong Dapeng LNG Terminal and Fujian Putian LNG Terminal in China.

 

The economy in China was stable in 2018 and the supply tension of natural gas was eased. Driven by the clean winter heating and changing fuel from coal to gas policy in northern China, the demand for natural gas continued to grow. Prior to the winter, the upstream gas suppliers reserved sufficient resources to meet the gas demand in northern China during winter. Based on the market condition, we gradually adjusted the sale prices for natural gas in northern China through negotiation. In addition, the production of gas field with higher prices increased. In 2018, our average realized natural gas price was US$6.41/mcf, representing a 9.8% year-on-year increase.

 

The table below sets forth the average realized prices for our crude oil and natural gas for the periods indicated.

 

   Year ended December 31,
   2016  2017  2018
Average Realized Prices         
Crude and Liquids (US$/bbl)   41.40  52.65  67.22
Natural Gas (US$/mcf)   5.46  5.84  6.41
West Texas Intermediate (US$/bbl)   43.35  50.80  64.95

 

The international benchmark crude oil price, West Texas Intermediate, was US$45.41 per barrel as of December 31, 2018 and US$60.14 per barrel as of March 29, 2019.

 

The following table presents, for the periods indicated, our revenues sourced in and outside the PRC:

 

  

   Year ended December 31,
   2016  2017  2018
   (Rmb in millions, except percentages)
Revenues sourced in the PRC   102,861  121,740  154,181
Revenues sourced outside the PRC   43,629  64,650  72,782
Total revenues   146,490  186,390  226,963
% of revenues sourced outside the PRC   29.8%  34.7%  32.1%

 

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Procurement of Services

 

We usually outsource work in connection with the acquisition and processing of seismic data, well drilling, well logging and perforating services and well control and completion service to independent third parties, or CNOOC and its affiliates.

 

Besides building floating production storage and offloading, or FPSO, with our partners, we employ independent third parties or CNOOC and/or its affiliates for FPSO services and other services.

 

We conduct a bidding process to determine who we employ to construct platforms, terminals and pipelines, to drill production wells and to install offshore production facilities. Both independent third parties and CNOOC affiliates participate in the bidding process. We are closely involved in the design and management of services by contractors and exercise extensive control over their performance, including their costs, schedule, quality and health, safety, and environment measures.

 

Research and Development

 

In 2018, we proactively implemented our “innovation-driven” strategy, deepened the reform of the technology system, increased the investment in science and technology research, established major projects, strengthened the fundamental forward-looking technological research, set up platforms for research and strived to ensure reserve and production growth with efficiency enhancement. Our capabilities of innovation continued to be enhanced with the new progress being made in core technological research. We also actively promoted our digital transformation, and commenced the research and development in this aspect.

 

Major Scientific and Technological Project Development

 

In 2018, we focused on core business needs and continued to carry out critical core technology such as development of deepwater oil and gas fields, offshore heavy oil fields and fields with low porosity and permeability. A number of technological achievements were made, including metamorphic rock reservoir evaluation technology, recovery enhancement technology by controlling injection and production and technologies of accelerating and facilitating medium and deep drilling. These notable developments have provided vital technical support for our sustainable development.

 

Development of Major Technological Innovation

 

Our research and development platform construction project progressed smoothly. The heavy oil fire flooding experimental platform and the offshore multi-source multi-thermal fluid heavy oil thermal recovery experimental platform, with comprehensive simulation experimental capabilities such as simulations for thermal recovery and displacement, effectively support the research of major scientific and technological projects. Major progresses have also been made in “Pre-stack seismic inversion and oil and gas identification driven by rock physics”, “key technologies and industrial applications of marine complex rock formations and deepwater drilling fluids”, and “real-time optimization of reservoir production and intelligent control technology and industrial applications”.

 

Health, Safety and Environmental Protection (“HSE”)

 

As always, we take “safety and environmental protection come first, people oriented and well-equipped facilities” as top priority in our works, which have been regarded as the core values of HSE. We constantly improve the systematic management of HSE and promotes the cultivation of safety culture by focusing on “people, execution and intervention” in order to provide a safe working environment for us and contractors and establish first class management capability in safe production.

 

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In 2018, we further standardized the systematic management of safe production. We completed the HSE management system framework with our own characteristics on the basis of summarizing the previous management experience. We have selected some affiliated units to carry out the pilot scheme and further improve such management system. With key focus placed on the “implementation of safe production responsibility system for all employees” across the overall work for the year, the requirements of “one enterprise with one standard, one post with one checklist” were effectively performed.

 

In 2018, we further improved the supervising review of our HSE system, improved the effectiveness of the review, strengthened special operations, special processes and special audits during exceptional periods, and improved risk assessment and prevention. We also closely monitored key areas such as operation permits, underwater operations, atmospheric storage and hazardous chemicals, strengthened the management and control measures, as well as improved management and control capability.

 

We have further strengthened the building of safety leadership, adhering to the substantial measures, significant identification and appropriate implementation to further promote the cultivation of a safety culture, and promote the continuous improvement of safety management. During the year, we issued the “Implementation Opinions on Promoting the Cultivation of Safety Culture”, our senior executives took the lead in practicing the safety measures and conducted on-site special inspections and safety lectures for the subordinate units during the “Safe Production Month”. Each affiliated unit took the opportunities of “Safe Production Month”, “Quality Month”, “Environment Day” and “Energy Saving Week” and so on to carry out a series of promotional and educational activities to enhance the safety awareness and safety skills of the employees. Thus, a good atmosphere for high quality development of the Company was created.

 

Overseas, we continued to improve the HSE management system, enhanced the supervision and management functions on our overseas business, organized the HSE due diligence investigation before withdrawing from the Indonesia SES oilfield project, conducted safety emergency and security inspection and research on our business in Mexico; and conducted special safety inspection for completion operations in the Misan oilfields in Iraq. At the same time, we organized self-inspection work on safe production for our overseas business, and the completion rate of improving various types of safety hazards discovered during the inspection reached 98%.

 

In 2018, we held an eco-environmental protection work conference to map out a clear direction of our eco-environmental protection work, formulate and implement a green development action plan, actively coordinate the classification of main function areas, promote the environmental impact assessment, carry out environmental risk investigation, progressively eliminate hidden dangers as well as improve supervision and inspection. We have also fully explored the potential of energy conservation, promoted the implementation of technological improvement projects and developed green factories to continuously enhance energy efficiency.

 

During 2018, we maintained our good performance in safety management and upheld consistently high HSE standards. OSHA (Occupational Safety and Health Administration) statistics for the year are shown below.

 

   Gross Man-hours (million)  Number of Recordable Cases  Rate of Recordable Cases  Number of Lost Workdays Cases  Rate of Lost Workdays Cases  Fatal Cases
Company staff  40  16  0.08  10  0.05  1
Staff of the Company and direct contractors   111  44  0.08  22  0.04  2

 

 

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Operating Hazards and Uninsured Risks

 

Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and natural gas, including pipeline ruptures and spills, fires, explosions, encountering formations with abnormal pressures, blowouts, cratering and natural disasters, any of which can result in loss of hydrocarbons, environmental pollution and other damage to our properties and the properties of operators under PSCs. In addition, certain of our crude oil and natural gas operations are located in areas that are subject to tropical weather disturbances such as typhoons, some of which can be severe enough to cause substantial damage to facilities and interrupt production.

 

We further strengthened safety in production, such as intensifying our efforts to identify and eliminate potential risks, and giving special attention to preventing operational accidents in key and high-risk areas. We also improved the implementation of safety standards and deepened safety awareness across all levels of the organization. In 2018, we completed full system safety inspections, including the special safety supervision, a special safety check on storage tank fields and a year-end major safety inspection. For HSE risks in particular operating units, we organized special examinations. Through examinations and inspections, we effectively met our management requirements, urged affiliated units to act in accordance with the law, and promoted the continuous improvement of HSE management.

 

Based on an in-depth analysis of the causes for major accidents and the key links in offshore production, we implemented risk-level-based management of offshore production facilities in accordance with relevant laws and regulations. We also promoted the construction of risk-level-based management information systems in downstream enterprises and established and improved risk monitoring indicators, including, among others, well-control event monitoring, major operation risk monitoring in engineering constructions. Moreover, We established a list of post responsibilities, improved the site tour inspection system, and improved onsite safety management capabilities.

 

To better handle the major risks involved in our daily operations, we continued to improve our crisis management mechanisms according to the updated requirements from reorganized authorities. In 2018, we have successfully combined the international incident management system into our incident management plan, which could keep the same pace with international companies while fulfill all the requirements of the local authorities. In 2018, we have also tested the coordination mechanism amongst CNPC, Sinopec and CNOOC in the annual exercise conducted in Bohai. All three companies activated emergency response teams and vessels to deal with potential oil spills. The mechanism functioned well and the exercise also proved that the combination of the emergency response plan worked well.

 

As part of the protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses, including the loss of wells, blowouts, pipeline leakage or other damage, certain costs of pollution control and physical damages on certain assets. Our insurance coverage includes offshore oil and gas field properties all risks insurance and construction insurance, protection and indemnity insurance, operator extra expenses insurance, marine cargo insurance and third party liabilities and comprehensive general liability insurance. The operators of the projects in which we participate overseas are required by local law to purchase insurance policies customarily taken out by international oil and gas companies.

 

We also carry third-party liability insurance policies to cover (i) claims made against us by or on behalf of individuals who are not our employees in the event of personal injury or death and (ii) legal liabilities for environmental damages resulting from our onshore and offshore activities, including oil spills. In addition, we impose contractual requirements upon our contractors to purchase insurance policies that cover their liabilities for the personal injuries of their own employees. Our contractors are obligated to indemnify us against such claims.

 

As of December 31, 2018, we have purchased a number of insurance policies with varying policy coverage and limits to meet our risk management requirements and cover our potential liabilities arising from accidents at any of our offshore and onshore locations. We maintain insurance for costs relating to property damage to our facilities, control of well including drilling relief wells, removal of wreck, pollution clean-up, liability for bodily injury and property damage to third parties. The policy limits and other terms and conditions of these insurance policies comply with all applicable laws and regulations in

 

46 

the PRC and other relevant jurisdictions. However, we may not have sufficient coverage for some of the risks we face, either because insurance is not available or because of high premium costs. See “Item 3—Key Information—Risk Factors—Oil and natural gas transportation may expose us to financial loss and reputation harm” and See “Item 3—Key Information—Risk Factors—The nature of our operations exposes us and the communities in which we operate to a wide range of health, safety, security and environment risks.”

 

We have maintained insurance policies for our domestic assets and operational insurance policies and construction insurance policies, with various policy limits and deductibles. We also purchase operator’s extra expense insurance up to US$ 100 million and third-party liabilities insurance up to US$200 million. As for deep-water wells, we are insured up to US$250 million for costs related to control of the well. The deductible for each insurance policy mainly ranges from US$2 million to US$5 million for different types of insurance policies. For overseas operations and assets, we are insured for amounts up to the replacement cost value of our assets for property damage and up to US$925 million in 2018 for operators extra expense. Additionally, we purchase insurance covering liability for bodily injury and property damage to third parties with limits of up to US$1,055 million in 2018. This cover protects against liability that arises from sudden and accidental pollution or from other causes.

 

For all of our offshore operations, we have 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 our offshore operations in the PRC have been reviewed and approved by the industry experts and have been filed with the PRC government. The evaluations and plans for our offshore operations overseas have complied with the legal and regulatory requirements of the relevant local jurisdictions.

 

In addition, we currently have seven oil spill emergency response bases, to which we have contributed land and funds for construction, separately located in six cities in the PRC, namely Suizhong, Tanggu, Longkou, Huizhou, Zhuhai and Weizhou Island. All the oil spill emergency response bases are close to our workplaces of operations, and in the event of any oil spill, explosion or other similar events, they can react promptly and assist us in coping with such accidents effectively. We have developed and established a “four-in-one” emergency management system to support our worldwide business, which includes a crisis management plan, an emergency commanding system, an emergency information system and an emergency rescue team. Through constant trainings and exercises, we have comprehensively enhanced our ability to defend risks, minimize the impact of emergency events and maintain our sustainable development.

 

Competition

 

Domestic Competition

 

The oil and gas industry is very competitive. We compete in the PRC and in international markets for customers as well as capital to finance our exploration, development and production activities. Our principal competitors in the PRC are PetroChina and Sinopec.

 

We price our crude oil on the basis of comparable crude oil prices in the international market. The majority of our customers for crude oil are refineries affiliated with CNOOC, PetroChina and Sinopec to which we have been selling crude oil, from time to time. Based on our past experiences with these refineries, we believe that we have established stable business relationships with them.

 

We are the dominant player in the oil and gas industry offshore China and, through CNOOC, are the only company permitted to engage in oil and gas exploration and production in offshore China with foreign parties under PSCs. We may face increasing competition in the future from other oil and gas companies in obtaining new PRC offshore oil and gas properties, or, as a result of changes in current PRC laws or regulations permitting an expansion of existing companies’ activities or new entrants into the industry.

 

47 

As part of our business strategy, we intend to expand our natural gas business to meet rapidly increasing domestic demand. Our principal competitors in the PRC natural gas market are PetroChina and Sinopec.

 

Foreign Competition

 

Imports of crude oil are subject to import licenses, handling fees and other restrictions. The PRC government also restricts the availability of foreign exchange with which the imports must be purchased. The combination of licenses and restrictions on foreign exchange has, to some extent, limited the competition from imported crude oil.

 

As a result of China joining the World Trade Organization as a full member on December 11, 2001, it is required to further reduce its import tariffs and other trade barriers over time, including with respect to certain categories of petroleum and crude oil. At present, CNOOC, Sinopec, PetroChina and several other domestic state-owned enterprises have received permission to import crude oil on their own. Foreign owned or foreign invested entities and other non-state-owned enterprises are subject to certain import quotas.

 

Segment Information

 

The following table shows the breakdown of our total consolidated operating revenues for each of the periods indicated and the percentage contribution of each revenue component to our total operating revenues:

 

   Year ended December 31,
   2016  2017  2018
   Rmb in millions  %  Rmb in millions  %  Rmb in millions  %
Exploration and production   125,611   85.7  157,166  84.3  190,728  84.0
Trading businesses   20,310   13.9  28,881  15.5  35,805  15.8
Corporate and elimination   569  0.4  343  0.2  430  0.2
Total operating revenues   146,490  100.0  186,390  100.0  226,963  100.0

 

We mainly engage in the exploration, development, production and sale of crude oil and natural gas in offshore China and overseas including Canada, the United States, the United Kingdom, Nigeria, Argentina, Indonesia, Uganda, Iraq, Brazil, Australia and Guyana. For the year ended December 31, 2018, approximately 67.9% of our total revenue was sourced in the PRC.

 

Regulatory Framework in the PRC

 

Government Control

 

All of China’s petroleum resources are owned by the PRC government which exercises regulatory control over oil exploration and production activities in China. We are required to obtain various governmental approvals, including those from the Ministry of Natural Resources, the Ministry of Ecology and Environment, the National Development and Reform Commission and the Ministry of Emergency Management before we are permitted to conduct production activities. Our sales are coordinated by the National Development and Reform Commission. For independent operations and joint exploration and production with foreign enterprises, we are required to obtain various governmental approvals, through CNOOC, including permits for exploration blocks, approval of a reserve report, environmental impact reports submitted through CNOOC, extraction permits and work safety permits. Moreover, for joint exploration and production, we are required, through CNOOC, to file overall development plan with the National Development and Reform Commission, and to report the circumstances and situation of the PSCs or other cooperation contracts between CNOOC and the foreign enterprises to the Ministry of Commerce.

 

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We explore and develop our offshore China reserves under exploration and production licenses granted by the PRC government. Exploration licenses, which are generally granted for individual blocks, require holders to make an annual minimum exploration investment and pay an annual exploration license fee. The annual minimum investment and license fees are based on the area under license and increase over the life of the exploration license. Production licenses, which are generally granted for individual fields, require holders to pay an annual production right usage fee based on the area under license. All of our proved reserves in offshore China are under production licenses granted by the PRC government.

 

Since the early 1980s, the PRC government has adopted policies and measures to encourage the development of the offshore petroleum industry. These policies and measures, which were applicable to CNOOC’s operations prior to the reorganization, became applicable to our operations in accordance with an undertaking agreement between us and CNOOC. As approved by the PRC government, these policies and measures have provided us with benefits mainly including the exclusive right to explore for, develop and produce petroleum in designated areas in offshore China in cooperation with foreign enterprises and to sell petroleum in China, and the flexibility to set our prices in accordance with international market prices and determine where to sell our crude oil.

 

Although we historically have benefited from the foregoing special policies, we cannot assure that such policies will continue in the future.

 

Fiscal Regimes for Independent Operations

 

Taxation

 

We are subject to income taxes on an entity basis on profits arising in or derived from the tax jurisdictions in which we and each of our subsidiaries are domiciled and operate. Our profits arising in or derived from Hong Kong are subject to profits tax at a rate of 16.5%.

 

We received a formal approval from the State Administration of Taxation of the PRC on October 19, 2010, confirming that we are regarded as a Chinese Resident Enterprise, or CRE. According to the formal approval, we are subject to the PRC corporate income tax at a rate of 25% starting from January 1, 2008. The corporate income tax we pay in Hong Kong can be credited against our PRC corporate income tax liability.

 

We are required to withhold 10% corporate income tax when we make dividend distributions to our non-Chinese resident enterprise shareholders.

 

Our PRC subsidiary, CNOOC China Limited, as a wholly foreign-owned enterprise, is subject to an enterprise income tax rate of 25% under the prevailing tax rules and regulations. Our indirect wholly-owned PRC subsidiary, CNOOC Deepwater Development Limited, is subject to corporate income tax at the rate of 15% from 2018 to 2020 after being re-assessed as a high and new technology enterprise.

 

The PRC corporate income tax is levied based on taxable income, including income from both operations and other components of earnings, as determined in accordance with the generally accepted accounting principles in the PRC, or PRC GAAP.

 

Besides income taxes, our PRC subsidiary also pays certain other taxes, including:

 

·production tax at the rate of 5% on production under production sharing contracts;

 

·Value added tax (“VAT”) at the rates from 13% to 17% on taxable sales under independent oil and gas fields before July 1, 2017. According to “Notice on Simplifying the Relevant Policies on Value-added Tax Rates” (Cai Shui [2017] No.37), with effect from July 1, 2017, the VAT rate of 13% had been removed and gas sales had been subject to the VAT rate of 11%. VAT rates of 17% and 11% have been adjusted to 16% and 10% respectively since May 1, 2018 according to “Notice on adjustment on Value-added Tax Rates” (Cai Shui [2018] No.32”);

 

49 

·the VAT payable is calculated using the taxable sales amount multiplied by the applicable tax rate less relevant deductible input VAT;

 

·Resource tax at the rate of 6% (reduced tax rates may apply to specific products and fields) on the oil and gas sales revenue (excluding production tax) derived by oil and gas fields under production sharing contracts signed after November 1,2011 and independent offshore oil and gas fields, except for those under production sharing contracts signed before November 1, 2011 which will be subject to related resource tax requirement after the expiration of such production sharing contracts;

 

·export tariff at the rate of 5% on the export value of petroleum oil;

 

·city construction tax at the rates of 1% or 7% on the production tax and VAT paid;

 

·educational surcharge at the rate of 3% on the production tax and VAT paid; and

 

·local educational surcharge at the rate of 2% on the production tax and VAT paid.

 

We calculate our deferred tax to account for the losses available for offsetting against future taxable profit and the temporary differences between our tax base, which is used for income tax reporting and prepared in accordance with applicable tax guidelines, and our accounting base, which is prepared in accordance with applicable financial reporting requirements. The temporary differences include accelerated amortization allowances for oil and gas properties, which are partially offset by provisions for dismantlement and for impairment of property, plant and equipment and write-off of unsuccessful exploratory drilling. As of December 31, 2016, 2017 and 2018, we had Rmb 19,174 million, Rmb 22,206 million and Rmb 24,234 million (US$3,525 million), respectively, in net deferred tax assets/ (liabilities). See note 10 to our consolidated financial statements included elsewhere in this annual report.

 

Royalty

 

Royalties paid to the PRC government are based on our gross production from both independent operations and oil and gas fields under PSCs. The amount of the royalties varies up to 12.5% based on the annual production of the relevant property. The PRC government has provided us, among other companies, with a royalty exemption in each field for up to one million tons, or approximately seven million BOE, per year for our crude oil production and for up to two billion cubic meters (approximately 70.6 billion cubic feet or 11.8 million BOE) per year for our natural gas production. The limits in these exemptions apply to our total production from both independent properties and properties under PSCs.

 

In 2011, the State Council of the PRC amended the Provisional Regulation of PRC Resource Tax. As a result, since November 1, 2011, the royalties payable to the PRC government have been replaced by resource tax, currently at 6% (5% before December 1, 2014) of the sales revenues from crude oil and natural gas. The PSCs that were signed before November 1, 2011 are not affected by the amendment of the Provisional Regulation of PRC Resource Tax and we continue to pay royalties to the PRC government for these PSCs.

 

Special Oil Gain Levy

 

In March 2006, the PRC government imposed a special oil gain levy at progressive rates from 20% to 40% on the portion of the monthly weighted average sales price of the crude oil lifted in the PRC exceeding US$40 per barrel. In December 2011, the PRC government increased the threshold of the special oil gain levy from US$40 per barrel to US$55 per barrel, with effect from November 1, 2011. In December 2014, the PRC government decided to increase the threshold of the special oil gain levy from US$55 per barrel to US$65 per barrel, with effect from January 1, 2015. The special oil gain levy is collected on a monthly basis. For the years ended December 31, 2016, 2017 and

 

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2018 we incurred approximately nil, Rmb 55 million and Rmb 2,599 million for the Special Oil Gain Levy, respectively.

 

As international oil prices, the exchange rate of Renminbi and our crude oil production fluctuate, we cannot ascertain the full impact of the special oil gain levy in the future.

 

The current rates of the special oil gain levy are shown in the table below:

 

Realized Oil Price (US$/bbl) Rate of the Levy
65-70 (Include 70) 20%
70-75 (Include 75) 25%
75-80 (Include 80) 30%
80-85 (Include 85) 35%
Above 85 40%

 

Fiscal Regimes for PSC Operations

 

The PRC government encourages foreign participation in offshore oil and gas exploitation. Currently, foreign enterprises can only undertake offshore oil and gas exploitation activities in China after they have entered into a PSC with CNOOC.

 

Under our PSCs, production of crude oil and gas is allocated among us, the foreign partners and the PRC government according to a formula contained in the contracts. Under this formula, a percentage of production under our PSCs is allocated to the PRC government as its share oil.

 

When exploitation operations in offshore China are conducted through a PSC, the operator of the oil or gas fields must submit a detailed evaluation report and an overall development program to a joint management committee established under the PSC upon the discovery of commercially viable oil or gas reserves. The program must be subsequently confirmed by CNOOC and filed with the PRC regulatory authorities before the parties to the PSC begin the commercial development of the oil and gas fields.

 

Under PRC law, only a state-owned company, such as CNOOC, may negotiate a PSC with foreign enterprises. CNOOC assigned to us all of its rights and obligations under then-existing PSCs in 1999 and has undertaken to assign to us its future PSCs except for those relating to CNOOC’s administrative functions as a state-owned oil company.

 

Bidding Process

 

CNOOC and foreign enterprises enter into new PSCs primarily through bidding process organized by CNOOC and direct negotiation. During a typical bidding process, CNOOC determines which blocks are open for bidding and invites foreign enterprises to bid. Potential bidders are required to provide information, including minimum work commitments, exploration expenditures and percentages of share oil payable to the PRC government; and CNOOC evaluates each bid and negotiates a PSC with the successful bidder. CNOOC has agreed to allow us to participate in all negotiations for new PSCs.

 

Terms of PSCs

 

Term of Length. PSCs typically last for 30 years: (1) the exploration period is generally divided into three phases, with three years, two years and two years, respectively. During the exploration period, exploratory and appraisal work is conducted in order to discover petroleum and to enable the parties to determine the commercial viability of any petroleum discovery; (2) the development period begins on the date of approval of the environmental impact statements for any oilfield and/or gas field by the competent authorities of the Chinese government and ends when the design, construction, installation, drilling and related research work for the realization of petroleum production as planned have been completed; and (3)

 

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the production period begins when commercial production commences and usually lasts for 15 years for oil and 20 years for natural gas.

 

Minimum Work Commitment. The foreign partners must complete a minimum amount of work during the exploration period, generally including: drilling a minimum number of wildcat(s); acquiring a fixed amount of seismic data; and incurring a minimum amount of exploration expenditures. Foreign partners may be required to pay all exploration costs, which can be recovered according to the production sharing formula after commercial discoveries are made and production begins. Foreign partners are required to relinquish 25% of the contract area, excluding the development and production areas, to CNOOC at the end of each phase of the exploration period and to relinquish all areas, excluding the development areas, production areas and areas under evaluation, to CNOOC at the end of the exploration period.

 

Participating Interests. We have the right to take participating interests up to 51% in any oil or gas field discovered in the contract area and may exercise this right after the foreign partners have made commercially viable discoveries. The foreign partners retain the remaining participating interests.

 

Production Sharing Formula. A chart illustrating the production sharing formula under our PSCs is shown below.

 

Percentage of annual gross production

Allocation

5.0% Production tax payable to the PRC government(1)
62.5%

For the payment of resource tax and recovery: 

 

1. Resource tax(2) payable to the PRC government 

 

2. Cost recovery oil allocated according to the following priority:

 

(1) recovery of current year operating costs by us and foreign partner(s); 

(2) recovery of current year abandonment costs accrued by us and foreign partner(s) ; 

(3) recovery of earlier exploration costs by foreign partner(s) or us (if any); and 

(4) recovery of development costs and deemed interest by us and foreign partner(s) based on participating interests. 

 

3. Any excess after the payment of resource tax and recovery of costs mentioned above allocated to the remainder oil. 

32.5%(3)

Remainder oil allocated according to the following formula:

 

1. (1-X) multiplied by 32.5% represents share oil payable to the PRC government; and 

2. X multiplied by 32.5% represents remainder oil distributed according to each partner’s participating interest. 

________________

(1)In this annual report and in our consolidated financial statements included elsewhere in this annual report, references to production tax on oil and gas produced offshore China are the value-added tax set out in our PSCs offshore China.

(2)For PSCs that came into effect prior to November 1, 2011, instead of resource tax, royalties (with the rate ranging from 0.0%-12.5% of the annual gross production, depending on the annual gross production of the oilfield) shall be paid to the PRC government.

(3)The ratio “X” is agreed in each PSC based on commercial considerations and ranges from 8% to 100%.

 

We calculate and pay oil and gas production tax and royalty (or resource tax) to the PRC government on a monthly basis and make adjustments for any overpayment or underpayment at the end of the year. The foreign partners have the right to either take possession of their allocable remainder oil for sale in the international market, or entrust us to sell such crude oil on their behalf in the PRC market.

 

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Management and Operator. A party will be designated as the operator to undertake the execution work of the petroleum operations, including preparing work programs and budgets, procuring equipment and materials relating to operations, establishing insurance programs, and issuing cash-call notices to the parties to the PSC to raise funds.

 

A joint management committee will be set up to perform supervisory functions. Each of us and the foreign partners has the right to appoint an equal number of representatives to form the joint management committee. We designate the chairman of the committee and the foreign partners as a group designate the vice chairman. The joint management committee has the authority to make decisions on matters including reviewing and approving operational and budgetary plans, determining the commercial viability of each petroleum discovery, reviewing and adopting the overall development program, and approving significant procurements and expenditures as well as insurance coverage.

 

After the full recovery of the exploration and development costs under PSCs in accordance with the overall development plan of any oilfield and / or gas field within the contract area in which the foreign partner is the operator, we have the right to take over the operation of the particular oil and/ or gas field. With the consent of the foreign partner, we may also take over the operation before the full recovery of the exploration and development costs.

 

Ownership of Data and Assets. All data, records, samples, vouchers and other original information obtained by foreign partners in the process of exploring, developing and producing offshore petroleum become the property of CNOOC as a state-owned oil company under PRC law. Through CNOOC, we have unlimited and unrestricted access to such information.

 

We and our foreign partners have joint ownership in all of the assets purchased, installed or constructed under the PSCs until either the foreign partners have fully recovered their development costs, or upon the expiration of the production period under the PSCs. After that, CNOOC will assume ownership of all of the assets under the PSCs, and our foreign partners and we retain the exclusive right to use the assets during the production period.

 

Abandonment Costs. Any party to our PSCs shall monthly pay the abandonment cost to the designated bank accounts managed by the operator and jointly owned by the parties in proportion to their participating interests in the development of such oil field and/or gas field in accordance with relevant laws, decrees, and other rules and regulations then existing with respect to the abandonment of offshore facilities of the PRC.

 

Regulatory Framework Overseas

 

We are subject to other fiscal regimes in the foreign countries and regions where we conduct operations, including Indonesia, Iraq, Australia, Nigeria, Uganda, Argentina, the United States, Canada, United Kingdom, Brazil, Guyana and certain other countries. See “Item 4—Information on the Company—Business Overview—Regional Overview—Overseas.”

 

In countries including Indonesia, Nigeria, Trinidad and Tobago and certain other countries, we conduct our operations through PSCs. For example, the OML130 block in Nigeria involves a production sharing arrangement. We and other partners to overseas PSCs are required to bear all exploration, development and operating costs according to our respective participating interests. Exploration, development and operating costs which qualify for recovery can be recovered according to the production sharing formula after commercial discoveries are made and production begins.

 

Our net interest in the PSCs overseas consists of our participating interest in the properties covered under the relevant PSCs, less oil and gas distributed to the local government and/or the domestic market obligation, as applicable.

 

In Australia, the United States, Canada, United Kingdom, Argentina and certain other countries, we conduct our operations through exploration and production permits, licenses or leases. We, as one of

 

53 

the title owners under these permits, licenses or leases, are required to bear all exploration, development and operating costs together with other co-owners. Once production begins, a certain percentage of the annual production or revenue will first be distributed to the landowner, in most of cases in the form of royalty, severance tax and other payments, and the rest of the annual production or revenue will be allocated among the co-owners. Exploration, development and operating costs are deductible for the purpose of income tax calculation in accordance with local tax regulations.

 

In Iraq, we operate our project under a technical service contract. We provide technology of developing oil and gas and invest capital to assist the host country to achieve the production goals. According to the technical service contract, we have the rights to recover all the investments and receive remuneration fee as defined in the contract as a return from the incremental production.

 

Taxation

 

Taxes paid and payable by our non-PRC subsidiaries and jointly controlled entities include royalties, duties and export tariffs, as well as taxes levied on petroleum related income, profits and budgeted operating and capital expenditures.

 

Our subsidiaries domiciled outside of the PRC are subject to income tax rates ranging from 10% to 50%. The U.S. government enacted comprehensive tax legislation in December 2017 that took effect as of January 1, 2018. A one-time non-cash deferred tax charge was recorded due to the impact of the reduction of U.S. federal corporate income tax rate from 35% to 21%.

 

Environmental Regulation

 

Our operations are required to comply with various applicable environmental laws and regulations, including PRC laws and regulations administered by the Ministry of Ecology and Environment and national and local environmental protection agencies for our operations in China. The Marine Environment Protection Law of PRC was amended and came into effect on November 7, 2016. Such amended Marine Environment Protection Law strengthens the marine environment protection regulation system including but not limited to the regional restricted approval system of environmental impact assessment, provides marine ecological protection compensation system. We therefore face more stringent environmental supervision and law enforcement environment.

 

Government agencies set national or local environmental protection standards. The relevant State Oceanic Administration and/or environmental protection agencies must approve or review each stage of a project. We must file an environmental impact statement or, in some cases, an environmental impact assessment outline before an approval can be issued. The filing must demonstrate that the project conforms to applicable environmental standards. The Ministry of Ecology and Environment and/or relevant environmental protection agencies generally issue approvals and permits for projects using modern pollution control measurement technology.

 

Pursuant to the Environmental Protection Tax Law of PRC which came into effect on January 1, 2018, enterprises, public institutions and other producers/operators that discharge taxable pollutants directly to the environment within the territorial areas of PRC and other sea areas under the jurisdiction of PRC are required to pay environmental protection tax in accordance with the provisions of such law. The Ministry of Ecology and Environment or national and local environmental protection agencies may at their own discretion close or suspend any facility which fails to comply with orders requiring it to cease or cure operations causing environmental damage.

 

The PRC and overseas environmental laws require offshore petroleum investors to pay abandonment costs. Our financial statements include provisions for costs associated with the dismantlement of oil and gas fields as of December 31, 2016, 2017 and 2018 of approximately Rmb 50,888 million, Rmb 54,073 million and Rmb 54,834 million (US$7,975 million), respectively.

 

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According to the Notice of the National Development and Reform Commission, the National Energy Administration, the Ministry of Finance, the State Administration of Taxation, and the State Oceanic Administration on Issuing the Interim Provisions on Administration over the Abandonment and Disposal of Offshore Oil and Gas Production Facilities, investors of the offshore oil and gas fields are required to take responsibility for abandonment of the offshore oil and gas production facilities and perform the obligation in relation to environmental protection and ecological restoration, and must provide and allocate special fund for the aforesaid purpose in accordance with the relevant laws and regulations. The investors include us and the foreign parties to our PSCs.

 

Environmental protection and prevention costs and expenses in connection with the operation of offshore petroleum exploitation are covered either under PSCs, or by us for independent operations. Each platform has its own environmental protection and safety staff responsible for monitoring and operating the environmental protection equipment. However, no assurance can be given that the PRC government will not impose new or more stringent regulations which would require additional environmental protection expenditures.

 

We are also subject to the environmental laws and regulations in jurisdictions where our logistical support facilities are located.

 

We believe that our environmental protection systems and facilities comply with applicable national and local environmental protection laws and regulations.

 

Patents and Trademarks

 

We have licenses to use trademarks which are of value in the conduct of our business. CNOOC is the owner of relevant trademarks. Under the non-exclusive license agreement between CNOOC and us, we have obtained the right to use the trademarks for a nominal consideration.

 

Employees and Employee Benefits

 

As of December 31, 2016, 2017 and 2018, we had 19,718 employees, 19,030 employees and 18,312 employees, respectively. Among the 18,312 employees as of December 31, 2018, approximately 82.6% were involved in oil exploration, development and production activities, approximately 4.3% were involved in accounting and finance work and the remainder were senior management and others. A portion of the workers for the operation of the oil and gas fields, maintenance and ancillary service are hired on a contract basis.

 

We have a union that protects employees’ rights, organizes educational programs, encourages employee participation in management decisions, and assists in mediating disputes between us and individual employees.

 

We have not been subject to any strikes or other labor disturbances and believe that our relations with our employees are good.

 

The total remuneration for an employee includes salary, bonuses and allowances. Bonus for any given period is based primarily on individual and our performance. Employees also receive health benefits and other miscellaneous subsidies.

 

We have implemented an occupational health and safety program similar to that employed by other international oil and gas companies. Under this program, we closely monitor and record health and safety incidents and promptly report them to government agencies and organizations. We believe this program is broadly in line with the U.S. government’s Occupational Safety & Health Administration guidelines.

 

All full-time employees in the PRC are covered by a government-regulated pension plan and are entitled to an annual pension at their retirement dates. The actual pension payable to each retiree is subject

 

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to a formula based on the status of the individual pension account, general salary and inflation movements. We are required to make annual contributions to the government pension plan at rates ranging from 11% to 22% of our employees’ salaries, with each employee contributing 8% of his or her salary for retirement. The contributions vary based on the requirements of local governments.

 

For further details regarding retirement benefits, see note 30 to our consolidated financial statements included elsewhere in this annual report.

 

As an oil and gas exploration and production company operating in highly competitive markets, we depend in large part on our employees for effective and efficient operations. We devote significant resources to train our employees. During 2018, we held 57 core training workshops, which were attended by approximately 2,400 person-times of participants. To ensure smooth implementation of our overseas strategy, we have established an international human resource system to attract and retain talent in the international market. In order to enhance the planning and budget control of our labor costs, we have installed target benchmarks in performance appraisals to guide various business units to cut their labor costs and to increase the accuracy of their budgets.

 

C. Organizational Structure

 

CNOOC indirectly owned or controlled an aggregate of approximately 64.44% of our shares as of March 29, 2019. Accordingly, CNOOC continues to be able to exercise all the rights of a controlling shareholder, including electing our directors and voting to amend our articles of association. Although CNOOC has retained a controlling interest in us, the management of our business will be our directors’ responsibility.

 

The following chart sets forth our controlling entities and our directly wholly-owned subsidiaries as of March 29, 2019 and notes our significant indirectly-held subsidiaries.

 

 

  

 

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__________________ 

(1)Overseas Oil & Gas Corporation, Ltd. also directly owns five shares of our Company.

(2)Owner of our overseas interests in oil and gas exploration and production businesses and operations, including our indirect wholly-owned subsidiaries CNOOC Southeast Asia Limited, CNOOC SES Ltd. , CNOOC Muturi Limited, CNOOC NWS Private Limited, CNOOC Exploration & Production Nigeria Limited, CNOOC Iraq Limited, CNOOC Canada Energy Ltd., CNOOC Uganda Ltd, CNOOC Petroleum North America ULC (formerly known as Nexen Energy ULC), CNOOC Petroleum Europe Limited (formerly known as Nexen Petroleum U.K. Limited), Nexen Petroleum Nigeria Limited, CNOOC Energy U.S.A. LLC (the entity surviving from the merger of Nexen Energy Services U.S.A. Inc. and OOGC America LLC), CNOOC Petroleum Offshore U.S.A. Inc. (formerly known as Nexen Petroleum Offshore U.S.A. Inc.), CNOOC Oil Sands Canada (formerly known as Nexen Oil Sands Partnership) , CNOOC PETROLEUM BRASIL LTDA, CNOOC Nexen Finance (2014) ULC, CNOOC Finance (2015) U.S.A. LLC and CNOOC Finance (2015) Australia Pty Ltd.

(3)Owner of substantially all of our PRC oil and gas exploration and production businesses, operations and properties, including our indirect wholly-owned subsidiary CNOOC Deepwater Development Limited.

(4)Business vehicle through which we engage in sales and marketing activities in the international markets.

(5)Includes CNOOC Finance (2003) Limited, CNOOC Finance (2011) Limited, CNOOC Finance (2012) Limited and CNOOC Finance (2013) Limited, all of which are our financing vehicles. These finance companies are our wholly owned subsidiaries with the Company as their sole corporate director.

 

D.Property, Plants and Equipment

 

For our property, plants and equipment relating to our business activities, see “Item 4—Information on the Company—Business Overview.” We also have some other real properties, including land, buildings and facilities in our onshore processing plants for our oil and gas fields, oil and gas pipelines in both offshore China and overseas, and the upgrader facilities for our oil sands projects in Canada.

 

ITEM 4A. unresolved staff comments

 

None.

 

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

 

A.Operating Results

 

You should read the following discussion and analysis in conjunction with our consolidated financial statements, selected historical consolidated financial data and operating and reserves data, in each case together with the accompanying notes, contained in this annual report. Certain statements set forth below constitute “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995. See “Forward-Looking Statements.”

 

Overview

 

Our revenues and profitability are largely determined by our production volume and the prices we realize on our crude oil and natural gas, as well as the costs of our exploration and development activities. Although crude oil prices depend on various market factors and have been volatile historically, our total net production volume displayed a trend of growth in 2018.

 

Factors Affecting Our Results of Operations

 

There are many factors that affect our results of operations and financial condition, mainly including the following:

 

Oil and Gas Prices

 

Substantially all of our revenues are from the sales of oil and natural gas. Therefore, one of the primary factors affecting our revenues is the prices for crude oil and natural gas. Crude oil prices are subject to fluctuations due to market uncertainty and various other factors that are beyond our control, including, but not limited to overall economic conditions, supply and demand dynamics for crude oil and natural gas, political developments, the ability of petroleum producing nations to set and maintain production levels and prices, the price and availability of other energy sources and weather conditions.

 

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In addition, our typical contracts with natural gas buyers include provisions for periodic resets and adjustment formulas which may result in selling price fluctuations.

 

In addition to directly affecting our revenues and earnings, declines in crude oil and/or natural gas prices may also result in the write-off of higher cost reserves and other assets. Furthermore, decreases in crude oil and natural gas prices may reduce the amount of crude oil and natural gas we can produce economically and make our performance of existing contracts that we have entered into uneconomical.

 

Sustained lower commodity prices may reduce revenue, earnings and liquidity, negatively impact the economics of estimated proved reserves quantities, and result in impairment. When the oil price forecasts of authoritative and independent institutions are revised to a significantly lower level than our projection, our oil and gas properties may face the risk of impairment. If oil and natural prices did not rise to the prices used in our internal price forecasts, there would be potential impact on the economics of the estimated proved reserves. Since the negative effect of lower oil price may be partially or completely offset by effective cost controls and efficiency enhancement, the estimated proved reserves quantities may not decrease proportionately with the decline in commodity prices. However, the price is not the sole or determining factor affecting our liquidity, capital resources and operating results. In particular, we believe that we have adequate resources of short- and long-term funding because (i) we have sufficient cash and cash equivalents, readily disposable financial assets and time deposits on hand, and (ii) we enjoy a sound credit rating and has the ability to access financing.

 

The following table sets forth our average net realized prices for crude oil and natural gas for the periods indicated:

 

   Year ended December 31,
   2016  2017  2018
Average realized prices:         
Crude oil (US$ per bbl)   41.40  52.65  67.22
Natural gas (US$ per mcf)   5.46  5.84  6.41

 

Production and Sales Volumes

 

Our revenues are also greatly affected by our production and sales volume as well as our product mix. Our crude oil and natural gas production volumes depend primarily on our ability to keep a high reserve replacement ratio and to develop currently undeveloped reserves in a timely and cost-effective manner.

 

We produce and sell different mixes of crude oil and natural gas, each having different market prices. Therefore, in any given period, our product mix is subject to change, which will also affect our results of operations.

 

The following table sets forth our average daily net production of crude oil and natural gas for the periods indicated.

 

   Year ended December 31,
   2016  2017  2018
Net production of crude oil (bbl/day)(1)   1,083,101  1,064,986  1,050,749
Net production of natural gas (mmcf/day)(1)    1,276.2  1,300.6  1,452.6

_______________

(1)Including our interest in equity method investees.

 

For a description of other factors affecting our results of operations, see “Item 3—Key Information—Risk Factors.”

 

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Critical Accounting Policies

 

We prepare our consolidated financial statements in accordance with IFRSs issued by the IASB and HKFRSs issued by the HKICPA. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of our assets and liabilities, the disclosure of our contingent assets and liabilities as of the date of our financial statements, if any, and the reported amounts of our revenues and expenses during the periods reported. Management makes these estimates and judgments based on historical experience and other factors that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe that the following significant accounting policies may involve a higher degree of judgment in the preparation of our consolidated financial statements. For additional discussion of our significant accounting policies, see note 3 to our consolidated financial statements included elsewhere in this annual report.

 

Oil and Gas Properties

 

For oil and gas exploration, we have adopted the successful efforts method of accounting. As a result, we capitalize initial acquisition costs of oil and gas properties. Impairment of initial acquisition costs is recognized as exploration expenses based on exploratory experience and management judgment which includes, but is not limited to, that any dry hole has been drilled on the property; that the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale; and that the period during which we have the right to explore in the specific area has expired or will expire in the near future and is not expected to be renewed. Upon discovery of commercial reserves, we transfer acquisition costs to proved properties and capitalize the costs of drilling and equipping successful exploratory wells, all development expenditure on construction, installation or completion of infrastructure facilities such as platforms, pipelines, processing plants and the drilling of development wells, and the building of enhanced recovery facilities, including those renewals and betterments that extend the economic lives of the assets, and the related borrowing costs.

 

The costs incurred in installing enhanced recovery facilities are capitalized together with the development costs of the relevant oil and gas properties. We treat the costs of unsuccessful exploratory wells and all other exploration costs as expenses when incurred. Productive oil and gas properties and other tangible and intangible costs of producing properties are depreciated using the unit-of-production method on a property-by-property basis under which the ratio of produced oil and gas to the estimated remaining proved developed reserves is used to determine the provision of depreciation, depletion and amortization. Common facilities that are built specifically to service production directly attributed to designated oil and gas properties are amortized based on the proved developed reserves of the respective oil and gas properties on a pro-rata basis. Common facilities that are not built specifically to service identified oil and gas properties are depreciated using the straight-line method over their estimated useful lives. Costs associated with significant development projects are not depreciated until commercial production commences and the reserves related to those costs are excluded from the calculation of depreciation. We amortize capitalized acquisition costs of proved properties by the unit-of-production method on a property-by-property basis based on the total estimated proved reserves.

 

We recognized the amount of the estimated cost of dismantlement discounted to its present value using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Changes in the estimated timing of dismantlement or dismantlement cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment. We included the unwinding of the discount on the dismantlement provision as a finance cost.

 

Reserves Estimation

 

Oil and gas properties are depreciated on a unit-of-production basis at a rate calculated by reference to proved reserves. Commercial reserves are determined using estimates of oil in place, recovery factors and future oil prices, the latter having an impact on the proportion of the gross reserves which are attributable to the host government under the terms of the production sharing contracts. The

 

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level of estimated commercial reserves is also a key determinant in assessing whether the carrying value of any of our oil and gas properties have been impaired.

 

Pursuant to the oil and gas reserve estimation requirements under U.S. SEC rules, we use the average, first-day-of-the-month oil price during the 12-month period before the ending date of the period covered by the consolidated financial statements to estimate our proved oil and gas reserves.

 

Impairment of Non-Financial Assets other than Goodwill

 

We make an assessment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, or when there is any indication that an impairment loss previously recognized for an asset in prior years may no longer exist or may have decreased. In any event, we would make an estimate of the asset’s recoverable amount, which is calculated as the higher of the asset’s value in use or our fair value less costs to sell. We recognize an impairment loss only if the carrying amount of an asset exceeds its recoverable amount. We charge an impairment loss to the consolidated statement of profit or loss and other comprehensive income in the period in which it arises. A reversal of an impairment loss is credited to the consolidated statement of profit or loss and other comprehensive income in the period in which it arises.

 

The calculations of the recoverable amount of assets require the use of estimates and assumptions. The key assumptions include, but are not limited to, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating expenses and the discount rate.

 

Changes in the key assumptions used, which could be significant, include updates to future pricing estimates, updates to future production estimates to align with our anticipated drilling plan, changes in our capital costs and operating expense assumptions, and the discount rate. There is a significant degree of uncertainty with the assumptions used to estimate future cash flows due to, but are not limited to, the risk factors referred to in “Item 3.D. Risk Factors.” The complex economic outlook may also materially and adversely affect our key assumptions. Changes in economic conditions can also affect the discount rates applied in assessments of impairment.

 

Although it is not reasonably practicable to quantify the impact of future impairment charges at this time, our results of operations could be materially and adversely affected for the period in which impairment charges are incurred.

 

The sensitivity analysis for the impairment testing involves estimates and judgments to consider numerous assumptions comprehensively. Those assumptions interact on each other and interrelate with each other complexly and do not have fixed patterns along with the changes in price. Accordingly, we believe that the preparation of the sensitivity analysis for the impairment testing will be impracticable. Changes in assumptions could affect impairment charges and reversals in income statement, and the carrying amounts of assets in balance sheet.

 

In the calculations of the recoverable amount of the oil and gas properties in a joint venture, we use the approach above. 

 

Business Combinations and Goodwill

 

Business combinations, other than business combinations under common control, are accounted for using the acquisition method. The consideration transferred is measured at acquisition date fair value which is the sum of the acquisition date fair values of assets transferred by us, liabilities assumed by us from the former owners of the acquiree and the equity interests issued by us in exchange for control of the acquiree. For each business combination, we elect whether we measure the non-controlling interests in the acquiree either at fair value or at the proportionate share of the acquiree’s identifiable net assets. All other components of non-controlling interests are measured at fair value. Acquisition costs incurred are included in profit or loss.

 

Goodwill is initially measured at cost, being the excess of the aggregate of the purchase consideration, the amount recognized for non-controlling interests and any fair value of our previously held equity interests in the acquiree over the identifiable net assets acquired and liabilities assumed. If the sum

 

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of this consideration and other items is lower than the fair value of the net assets of the subsidiary acquired, the difference is recognized in profit or loss as a gain on bargain purchase.

 

Joint Arrangements

 

Certain of our activities are conducted through joint arrangements. Joint arrangements are classified as either a joint operation or joint venture, based on the rights and obligations arising from the contractual obligations between the parties to the arrangement.

 

Joint Operations

 

Some arrangements have been assessed by us as joint operations as both parties to the contract are responsible for the assets and obligations in proportion to their respective interest, whether or not the arrangement is structured through a separate vehicle. This evaluation applies to both our interests in production sharing arrangements and certain jointly-controlled entities.

 

Joint Venture

 

A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement.

 

Our investments in joint ventures are stated in the consolidated statement of financial position at our share of net assets under the equity method of accounting, less any impairment losses.

 

Fair Value

 

The fair value of financial instruments that are traded in active markets at each reporting date is determined by reference to quoted market prices or dealer price quotations, without any deduction for transaction costs.

 

For financial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques. Such techniques may include using recent arm’s length market transactions; reference to the current fair value of another instrument that is substantially the same; a discounted cash flow analysis or other valuation models.

 

Provisions

 

We recognize a provision when a present obligation (legal or constructive) has arisen as a result of a past event and it is probable that a future outflow of resources will be required to settle the obligation provided that a reliable estimate can be made of the amount of the obligation. When the effect of discounting is material, the amount recognized for a provision is the present value at the reporting date of the future expenditures expected to be required to settle the obligation. The increase in the discounted present value amount arising from the passage of time is included in profit or loss.

 

We make provisions for dismantlement based on the present value of our future costs expected to be incurred, on a property-by-property basis, in respect of our expected dismantlement and abandonment costs at the end of the related oil exploration and recovery activities.

 

The ultimate dismantlement costs are uncertain and cost estimates can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing and amount of expenditure can also change, for example, in response to changes in reserves or changes in laws and regulations or their interpretation. As a result, there could be significant adjustments to the provisions established which would affect future financial results.

 

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Deferred Tax

 

Deferred tax is provided, using the balance sheet liability method, on all temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.

 

Deferred tax liabilities are recognized for all taxable temporary differences, except:

 

·when the deferred tax liability arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit or loss nor taxable profit or loss; and

 

·in respect of taxable temporary differences associated with investments in subsidiaries, associates and interests in a joint venture, when the timing of the reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future.

 

A typical example of transactions that are not business combinations and, at the time of the transaction, affect neither accounting profit or loss nor taxable profit or loss is the acquisition of an asset, such as an exploration license or concession, where no previous activity has taken place, whereby the consideration paid is higher than its tax base.

 

Recognition of Revenue from Oil and Gas Sales and Marketing

 

Under IFRS 15/HKFRS 15,we recognize revenue when (or as) a performance obligation is satisfied, i.e. when "control" of the goods or services underlying the particular obligation is transferred to the customer.

 

For oil and gas sales, our revenues represent the sales of oil and gas, net of royalties and obligations to governments and other mineral interest owners. Revenue from the sales of oil and gas is recognized at a point in time when oil and gas has been delivered to the customer, which is when the customer obtains the control of oil and gas, and we have present right to payment and collection of the consideration is probable. Oil and gas lifted and sold by us above or below our participating interests in any PSC result in overlifts and underlifts. From January 1, 2018 we have ceased recording these transactions in accordance with the entitlement method. We recognize revenues when sales are made to customers. Settlement will be in kind or in cash when the liftings are equalized or in cash when production ceases. We have entered into gas sales contracts with customers which often contain take-or-pay clauses. Under these contracts, we make a long term supply commitment in return for a commitment from the customer to pay for minimum quantities, whether or not the customer takes delivery. These commitments contain protective provisions, such as force majeure provision, and adjustment provisions. If a customer has a right to get a “make up” delivery at a later date, revenue recognition is deferred and payments received from the customers for natural gas not yet taken are recorded as contract liabilities. If no such option exists according to the contract terms, revenue is recognized when the take-or-pay penalty is triggered.

 

Our marketing revenues principally represent the sales of oil and gas belonging to the foreign partners under our PSCs and revenues from the trading of oil and gas through our subsidiaries, which is recognized at a point in time when oil and gas has been delivered to the customer, which is when the customer obtains the control of oil and gas, and we have present right to payment and collection of the consideration is probable. The cost of the oil and gas sold is included in crude oil and product purchases.

  

Results of Operations

 

Overview

 

The following table summarizes the components of our revenues and net production as percentages of our total revenues and total net production for the periods indicated:

 

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   Year ended December 31,
   2016  2017  2018
   (Rmb in millions, except percentages and production data )
Revenues:                  
Oil and gas sales:                  
Crude oil   106,448  72.7%  135,256  72.6%  165,939  73.1%
Natural gas   14,877  10.1%  16,632  8.9%  19,933  8.8%
Total oil and gas sales   121,325  82.8%  151,888  81.5%  185,872  81.9%
                   
Marketing revenues   20,310  13.9%  28,907  15.5%  35,830  15.8%
Other revenue   4,855  3.3%  5,595  3.0%  5,261  2.3%
Total revenues   146,490  100.0%  186,390  100.0%  226,963  100.0%
                   
Net production (million BOE)(1):                  
Crude oil   396.4  83.1%  388.7  82.7%  383.5  80.7%
Natural gas   80.5  16.9%  81.5  17.3%  91.5  19.3%
Total net production   476.9  100.0%  470.2  100.0%  475.0  100.0%

__________________ 

(1)Including our interest in equity method investees.

 

The following table sets forth, for the periods indicated, certain income and expense items in our consolidated statement of profit or loss and other comprehensive income as a percentage of total revenues:

 

   Year ended December 31,
   2016  2017  2018
Operating Revenues:         
Oil and gas sales   82.8%  81.5%  81.9%
Marketing revenues   13.9%  15.5%  15.8%
Other revenue   3.3%  3.0%  2.3%
Total revenues   100.0%  100.0%  100.0%
Expenses:         
Operating expenses   (15.8)%  (13.0)%  (10.7)%
Taxes other than income tax   (4.7)%  (3.9)%  (4.0)%
Exploration expenses   (5.0)%  (3.7)%  (5.7)%
Depreciation, depletion and amortization   (47.0)%  (32.9)%  (22.3)%
Special oil gain levy   0.0%  0.0%  (1.1)%
Impairment and provision   (8.3)%  (4.9)%  (0.2)%
Crude oil and product purchases   (13.0)%  (14.8)%  (14.8)%
Selling and administrative expenses   (4.4)%  (3.7)%  (3.2)%
Others   (3.3)%  (3.2)%  (2.5)%
Total expenses   (101.6)%  (80.1)%  (64.6)%
          
Interest income   0.6%  0.4%  0.4%
Finance costs   (4.3)%  (2.7)%  (2.2)%
Exchange gain, net   (0.5)%  0.2%  (0.1)%
Investment income   1.9%  1.3%  1.6%
Share of profits of associates   (0.4)%  0.2%  0.2%
Profit/(loss) attributable to a joint venture   0.4%  0.3%  (2.5)%
Other income, net   0.4%  0.0%  0.4%
Profit before tax   (3.6)%  19.5%  33.1%
Income tax expense   4.0%  (6.3)%  (9.9)%
Profit for the year   0.4%  13.2%  23.2%

 

Calculation of Revenues

 

China

 

We report total revenues, which consist of oil and gas sales, marketing revenue and other revenue, in our consolidated financial statements included elsewhere in this annual report. With respect to revenues

 

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derived from our offshore China operations, oil and gas sales represent gross oil and gas sales less royalties and share oil payable to the PRC government.

 

Revenue from the sales of oil and gas is recognized at a point in time when oil and gas has been delivered to the customer, which is when the customer obtains the control of oil and gas, and we have present right to payment and collection of the consideration is probable.

  

Marketing revenues represent our sales of our foreign partners’ oil and gas produced under our PSCs. Our foreign partners have the right to either take possession of their oil and gas for sale in the international market or to sell their oil and gas to us for resale in the PRC market.

  

Indonesia

 

The oil and gas sales from our subsidiaries in Indonesia represent our sales of oil and gas derived from the relevant joint operation projects, less adjustments for oil and gas distributable to the Indonesian government under our Indonesian PSCs and for a domestic market obligation under which the contractor must sell a specified percentage of its crude oil to the local Indonesian market at a reduced price.

 

Iraq

 

The oil sales from Iraq represent our sales of oil derived from the Missan project.

 

Australia

 

The oil and gas sales from our subsidiaries in Australia represent our sales of oil and gas derived from the North West Shelf project.

 

Nigeria

 

The oil and gas sales from our subsidiaries in Nigeria represent our sales of oil and gas derived from relevant joint operation projects, net of the rental concession, royalty, and oil and gas distributable to the host country. The royalty rates applicable to deepwater properties are zero. We record revenue when oil and gas has been delivered to the customer.

 

Trinidad and Tobago

 

The oil and gas sales from our subsidiaries in Trinidad and Tobago represent our sales of oil and gas derived from relevant joint operation projects.

 

The United States and Canada

 

The oil and gas sales from the United States represent our sales of oil and gas derived from the Eagle Ford project, Niobrara project and properties in the Gulf of Mexico.

 

The revenue is calculated net of royalties and is recognized when oil and gas has been delivered to the customer.

 

United Kingdom

 

The oil and gas sales from the United Kingdom represent our sales of oil and gas derived from the Buzzard, Scott/Telford/Rochelle, Golden Eagle and Farragon properties.

 

Unconsolidated Investees

 

Our share of the oil and gas sales of unconsolidated investees is not included in our revenues, but our share of the profits or losses of these investees is included as part of our share of profits or losses of associates and profit/loss attributable to a joint venture as shown in our consolidated statements of profit or loss and other comprehensive income.

 

 

64 

 

2018 versus 2017

 

Consolidated net profit

 

Our consolidated net profit increased 113.5% to Rmb 52,688 million (US$ 7,663.2 million) in 2018 from Rmb 24,677 million in 2017, primarily as a result of the increase in profitability under the higher international oil price environment, at the same time, the cost control through taking efficient measures brings about the increase in profitability.

 

Revenues

 

Our oil and gas sales, realized prices and sales volume in 2018 are as follows:

 

  

2018

 

2017

 

Amount

 

Change (%)

Oil and gas sales (Rmb million)   185,872  151,888  33,984  22.4%
Crude and liquids   165,939  135,256  30,683  22.7%
Natural gas   19,933  16,632  3,301  19.8%
Sales volume (million BOE)*  453.4  452.4  1.0  0.2%
Crude and liquids (million barrels)   372.9  380.1  (7.2)  (1.9%)
Natural gas (bcf)   469.9  421.5  48.4  11.5%
Realized prices             
Crude and liquids (US$/barrel)   67.22  52.65  14.57  27.7%
Natural gas (US$/mcf)   6.41  5.84  0.57  9.8%
Net production (million BOE)   475.0  470.2  4.8  1.0%
China   309.0  302.8  6.2  2.0%
Overseas   166.0  167.4  (1.4)  (0.8%)

 

* Excluding our interest in equity-accounted investees.

 

In 2018, our net production was 475.0 million BOE (including our interest in equity-accounted investees), representing an increase of 1.0% from 470.2 million BOE in 2017. The increase in crude and liquids sales was primarily due to higher international oil price in 2018. The increase in natural gas sales was primarily due to the gradual release of production capacity of high-priced gas fields arising from natural gas demand growth in China, which pulled up the gas price and sales volume simultaneously.

 

Operating expenses

 

Our operating expenses decreased 0.1% to Rmb 24,251 million (US$3,527.2 million) in 2018 from Rmb 24,282 million in 2017, the operating expenses per BOE decreased 0.4% to Rmb 53.4 (US$ 7.77) per BOE in 2018 from Rmb 53.6 (US$8.24) per BOE in 2017. Operating expenses per BOE offshore China decreased 2.0% to Rmb 48.2 (US$7.01) per BOE in 2018 from Rmb 49.2 (US$7.57) per BOE in 2017. Overseas operating expenses per BOE increased 3.4% to Rmb 64.5 (US$ 9.39) per BOE in 2018 from Rmb 62.4 (US$9.59) per BOE in 2017. Through refined management, strict costs control and enhancing conservation, our operating expenses per BOE remained stable.

 

65 

Taxes other than income tax

 

Our taxes other than income tax increased 26.6% to Rmb 9,127 million (US$1,327.5 million) in 2018 from Rmb 7,210 million in 2017, mainly due to the increase in oil and gas sales.

 

Exploration expenses

 

Our exploration expenses increased 87.8% to Rmb 12,924 million (US$ 1,879.7 million) in 2018 from Rmb 6,881 million in 2017, mainly because of impairment provision of Rmb 5,387 million related to certain exploration and evaluation assets in North America, resulting from its further development uncertainty. Please refer to Note 13 to the Consolidated Financial Statement of this annual report.

 

Depreciation, depletion and amortization

 

Our total depreciation, depletion and amortization decreased 17.3% to Rmb 50,640 million (US$7,365.3 million) in 2018 from Rmb 61,257 million in 2017.

 

The dismantlement-related depreciation, depletion and amortization costs increased 237.6% to Rmb 1,293 million (US$188.1 million) in 2018 from Rmb 383 million in 2017. Our average dismantling costs per BOE increased 235.3% to Rmb 2.85 (US$0.41) per BOE in 2018 from Rmb 0.85 (US$0.13) per BOE in 2017, primarily due to the increase of the present value of asset retirement obligations brought by the decrease of U.S. bond interest rate in the international market.

 

Our depreciation, depletion and amortization, excluding the dismantlement-related depreciation, depletion and amortization, decreased 18.9% to Rmb49,347 million (US$7,177.2 million) in 2018 from Rmb 60,874 million in 2017. Our average depreciation, depletion and amortization per BOE, excluding the dismantlement-related depreciation, depletion and amortization, decreased 19.1% to Rmb 108.7 (US$15.81) per BOE in 2018 from Rmb 134.4 (US$20.66) per BOE in 2017, primarily due to the increase of reserve by optimizing the development plan of producing oil and gas fields to control natural decline and improve production performance.

 

Impairment and provision

 

Our impairment and provision decreased 93.8% to Rmb 567 million (US$82.5 million) in 2018 from Rmb 9,130 million in 2017. The vast majority of impairment and provision in 2018 was related to raw material inventory provision, while Rmb 8,639 million of oil and gas assets impairment was recognized in 2017.

 

Selling and administrative expenses

 

Our selling and administrative expenses increased 6.2% to Rmb 7,286 million (US$1,059.7 million) in 2018 from Rmb 6,861 million in 2017. Our selling and administrative expenses per BOE increased 5.9% to Rmb 16.05 (US$ 2.34) per BOE in 2018 from Rmb 15.15 (US$2.33) per BOE in 2017, due to the increase of scientific research expenses, arising from the active implementation of the “innovation-driven” strategy, the reform of science and technology system, which increased the technological investment.

 

Finance costs/Interest income

 

Our finance costs were Rmb 5,037 million (US$732.6 million) in 2018 and in line with Rmb 5,044 million in 2017. Our interest income increased 21.9% to Rmb 796 million (US$115.8 million) in 2018 from Rmb 653 million in 2017, primarily due to the higher proportion of long-term deposits in China.

 

Exchange losses/gains, net

 

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Our net exchange losses changed to Rmb 141 million (US$20.5 million) in 2018, while there was net exchange gains of Rmb 356 million in 2017, primarily arising from Rmb fluctuation against the U.S. dollars and Hong Kong dollars.

 

Investment income

 

Our investment income increased 53.0% to Rmb 3,685 million (US$ 536.0 million) in 2018 from Rmb 2,409 million in 2017, primarily attributable to the higher interest rates and increased average stock of corporate wealth management products.

 

Share of losses/profits of associates and a joint venture

 

Our share of losses of associates and a joint venture changed to Rmb 5,187 million (US$754.4 million) in 2018, while in 2017 our shared profits was Rmb 855 million, mainly due to depreciation of the value of the assets in Argentina owned by the joint venture, BC Energy Investments Corp., as a result of the huge depreciation of the Argentina peso against the U.S. dollar and the sharp increase of interest rate.

 

Income tax expense

 

Our income tax expense increased 92.5% to Rmb 22,489 million (US$3,270.9 million) in 2018 from Rmb 11,680 million in 2017, mainly because our overall profitability increased in 2018.

 

2017 versus 2016

 

Consolidated net profit

 

Our consolidated net profit increased significantly to Rmb 24,677 million in 2017 from Rmb 637 million in 2016, primarily as a result of the increase in profitability due to higher international oil price environment, as well as the combined effects of increased reserve and reduced costs as a result of adoption of efficient measures by us.

 

Revenues

 

Our oil and gas sales, realized prices and sales volume in 2017 are as follows:

 

   2017  2016  Amount  Change (%)
Oil and gas sales (Rmb million)   151,888  121,325  30,563  25.2%
Crude and liquids   135,256  106,448  28,808  27.1%
Natural gas   16,632  14,877  1,755  11.8%
Sales volume (million BOE)*  452.4  458.3  (5.9)  (1.3%)
Crude and liquids (million barrels)   380.1  387.6  (7.5)  (1.9%)
Natural gas (bcf)   421.5  410.5  11.0  2.7%
Realized prices             
Crude and liquids (US$/barrel)   52.65  41.40  11.25  27.2%
Natural gas (US$/mcf)   5.84  5.46  0.38  7.0%
Net production (million BOE)   470.2  476.9  (6.7)  (1.4%)
China   302.8  311.1  (8.3)  (2.7%)
Overseas   167.4  165.8  1.6  1.0%

 

* Excluding our interest in equity-accounted investees.

 

In 2017, our net production was 470.2 million BOE (including our interest in equity-accounted investees), representing a decrease of 1.4% from 476.9 million BOE in 2016. The increase in crude and liquids sales was primarily due to higher realized oil prices in 2017. The increase in natural gas sales was primarily due to the gradual release of production capacity of high-priced gas fields arising from natural gas demand growth in China, which pulled up the gas price and sales volume simultaneously.

 

67 

Operating expenses

 

Our operating expenses increased 4.6% to Rmb 24,282 million in 2017 from Rmb 23,211 million in 2016, the operating expenses per BOE increased 6.0% to Rmb 53.6 per BOE in 2017 from Rmb 50.6 per BOE in 2016, Operating expenses per BOE offshore China increased 11.6% to Rmb 49.2 per BOE in 2017 from Rmb 44.1 per BOE in 2016, mainly attributable to the increase in workload as the result of the Company adopting optimisation measures to increase production efficiency, as well as prices of refined oil, chemicals and other materials rose with oil price. Overseas operating expenses per BOE decreased 2.7% to Rmb 62.4 per BOE in 2017 from Rmb 64.1 per BOE in 2016.

 

Taxes other than income tax

 

Our taxes other than income tax increased 3.9% to Rmb 7,210 million in 2017 from Rmb 6,941 million in 2016, mainly due to the increase in oil and gas sales.

 

Exploration expenses

 

Our exploration expenses decreased 6.5% to Rmb 6,881 million in 2017 from Rmb 7,359 million in 2016, mainly because of less costs of uncertain wells from previous years being written off according to subsequent reserve evaluation as well as the decrease in write-off of expired leases in North American.

 

Depreciation, depletion and amortization

 

Our depreciation, depletion and amortization decreased 11.1% to Rmb 61,257 million in 2017 from Rmb 68,907 million in 2016.

 

The dismantlement-related depreciation, depletion and amortization costs decreased 75.6 % to Rmb 383 million in 2017 from Rmb 1,569 million in 2016. Our average dismantling costs per BOE decreased 75.1% to Rmb 0.85 per BOE in 2017 from Rmb 3.42 per BOE in 2016, primarily due to the decrease of the present value of asset retirement obligations brought by the increase of interest rate in the China market. Our depreciation, depletion and amortisation, excluding the dismantlement-related depreciation, depletion and amortization, decreased 9.6% to Rmb 60,874 million in 2017 from Rmb 67,338 million in 2016. Our average depreciation, depletion and amortization per BOE, excluding the dismantlement-related depreciation, depletion and amortization, decreased 8.4% to Rmb 134.4 per BOE in 2017 from Rmb 146.8 per BOE in 2016, primarily due to the increase of reserve in producing oil and gas fields by taking effective measures to improve production performance and recovery rate as well as the decrease in amortization rate resulting from the recognized impairment of oil and gas assets in 2016.

 

Impairment and provision

 

Our impairment and provision decreased 25.0% to Rmb 9,130 million in 2017 from Rmb 12,171 million in 2016, mainly due to the decrease of oil and gas assets impairment. The impairment loss of oil and gas assets recognized in 2017 mainly related to oil and gas fields located in China, Africa and North America and it was primarily due to the revision of the oil and gas price forecast and revision of reserve. In 2016, certain oil and gas properties located in North America, Europe and Africa were impaired, which was reflected by the revision of the oil price forecast and the adjustment in operating plan for the oil sand assets in Canada. Please refer to Note 13 to the Consolidated Financial Statement of this annual report.

 

Selling and administrative expenses

 

Our selling and administrative expenses increased 5.7% to Rmb 6,861 million in 2017 from Rmb 6,493 million in 2016. Our selling and administrative expenses per BOE increased 7.1% to Rmb 15.15 per BOE in 2017 from Rmb 14.15 per BOE in 2016, due to the increase in transportation costs in Canada resulting from increased production and sales volume.

 

Finance costs/Interest income

 

68 

Our finance costs decreased 19.2% to Rmb 5,044 million in 2017 from Rmb 6,246 million in 2016, primarily due to the increased capitalized interest cost arising from the increase in the scale of oil and gas assets under construction. Our interest income decreased 27.5% to Rmb 653 million in 2017 from Rmb 901 million in 2016, primarily due to the decreased proportion of deposits with higher interest rates.

 

Exchange gains/losses, net

 

Our net exchange gains changed to Rmb 356 million in 2017, while accounted net exchange losses of Rmb 790 million in 2016, primarily as a result of the increase in exchange gains arising from Rmb fluctuation against the U.S. dollars and Hong Kong dollars.

 

Investment income

 

Our investment income decreased 13.2% to Rmb 2,409 million in 2017 from Rmb 2,774 million in 2016, primarily attributable to the decreased proportion of corporate wealth management products with higher interest rates.

 

Share of profits/losses of associates and a joint venture

 

Our share of profits of associates and a joint venture changed to Rmb 855 million in 2017, while in 2016 we shared losses of Rmb 76 million, primarily attributable to losses from the sale of shares of Northern Cross (Yukon) Limited located in Canada in 2016.

 

Income tax expense/credit

 

Our income tax expense changed to Rmb 11,680 million in 2017, while accounted income tax credit of Rmb 5,912 million in 2016, mainly because income tax expense increased as Company’s profitability increased in 2017, in addition, the U.S. government decreased the federal corporate income tax rate from 35% to 21% and resulted in a one-time write-off of net deferred tax asset and increased income tax expense.

 

B.Liquidity and Capital Resources

 

Our primary source of cash during 2018 was cash flows from operating activities. We used cash primarily to fund capital expenditure and dividends. The following table summarizes our cash flows for the periods presented:

 

   Year ended December 31,
   2016  2017  2018
   (Rmb in millions)
Cash generated from (used in):         
Operating activities   72,863  94,734  123,883
Investing activities   (27,953)  (64,411)  (94,861)
Financing activities   (43,240)  (31,271)  (27,370)
Net increase/(decrease) in cash and cash equivalents   1,670  (948)  1,652

 

Cash Generated from Operating Activities

 

The cash inflow from operating activities increased 30.8% to Rmb 123,883 million (US$18,018.0 million) in 2018 from Rmb 94,734 million in 2017, primarily attributable to the increase of oil and gas sales cash inflows caused by the increase of international oil price for the current period.

 

69 

Cash Used in Investing Activities

 

In 2018, our capital expenditure payment increased 5.6% to Rmb 50,411 million (US$7,332.0 million) from 2017. Our development expenditures in 2018 were primarily related to the capital expenditure of OML130 project, Iraq technical service contract project, deep-water Gulf of Mexico and shale oil and gas in the United States, as well as the expenses incurred for improving recovery factors of the oil and gas fields in production. We had no significant acquisition during the year.

 

In addition, our cash used in investing activities was also attributable to the purchase of corporate wealth management products and money market funds of Rmb 178,100 million (US$25,903.6 million) this year. Our cash generated from investing activities was mainly from the proceeds from the sales of corporate wealth management products and money market funds in the amount of Rmb 127,903 million (US$18,602.7 million), and the decrease in our time deposits with maturity over three months in the amount of Rmb 1,620 million (US$235.6 million).

 

Cash Used in Financing Activities

 

In 2018, the net cash outflow from financing activities was mainly due to the repayment of bank loans of Rmb 5,888 million (US$856.4 million), repayment of guaranteed notes of Rmb 4,976 million (US$750.0 million) and the payment of dividends of Rmb 23,523 million (US$3,421.3 million), partially offset by the issuance of guaranteed notes of Rmb 9,952 million (US$1,450.0 million) and the proceeds of bank loans of Rmb 2,212 million (US$321.7 million).

 

At the end of 2018, our total interest-bearing outstanding debt was Rmb 139,521 million (US$20,292.5 million), compared to Rmb 132,250 million at the end of 2017. The increase in debt in 2018 was primarily attributable to the issuance of guaranteed notes and impact of changes in the exchange rate of the U.S. dollar and Rmb. Our gearing ratio, which is defined as interest-bearing debts divided by the sum of interest-bearing debts plus equity, was 25.1%, lower than that of 25.8% in 2017. The main reason was the increased scale of equity.

 

   Debt maturities (principal only)
Due by December 31, 

Original currency

US$

  Total Rmb equivalents  Total US$ equivalents
   (in millions, except percentages)
2019   331.8  2,281.5  331.8
2020-2021   3,048.8  20,962.3  3,048.8
2022-2023   3,985.7  27,404.0  3,985.7
2024 and beyond   11,452.5  78,741.4  11,452.5
Total   18,818.8  129,389.2  18,818.8
Percentage of total debt   96.5%  96.5%  96.5%

 

As of December 31, 2018, we had total foreign currency debt of US$19,546 million, all of which was in U.S. dollars. As of March 29, 2019, we had total foreign currency debt of US$19,573 million, all of which was in U.S. dollars.

 

As of December 31, 2018, we had unutilized banking facilities amounting to approximately Rmb 55,289 million (US$8,041 million) as compared to Rmb 53,749 million as of December 31, 2017.

 

In 2016, 2017 and 2018, we paid dividends totaling Rmb 14,245 million, Rmb 16,448 million and Rmb 23,523 million (US$3,421 million) (before PRC withholding tax deducted), respectively. The payment and the amount of any dividends in the future will depend on our results of operations, cash flows, financial condition, the payment by our subsidiaries of cash dividends to us, future prospects and other factors which our directors may consider relevant. The amount of dividends we paid historically is not indicative of the dividends that we will pay in the future.

 

70 

We believe our future cash flows from operations, borrowing capacity and funds raised from our debt offerings will be sufficient to fund planned capital expenditures and investments, debt maturities and working capital requirements through at least 2019. However, our ability to obtain adequate financing to satisfy our capital expenditures and debt service requirements may be limited by our financial condition and results of operations and the liquidity of international and domestic financial markets.

 

Capital Expenditures

 

For 2019, we have budgeted Rmb 70 to 80 billion for capital expenditures for exploration and development. The following table sets forth our actual or budgeted capital expenditures on an accrual basis for the periods indicated.

 

   Year ended December 31,
  

2016(1)

 

2017(1)

 

2018(1)

 

2019(2)

 

2018(1)

   (Rmb million)  (US$ million)
China               
Development(3)   15,048  16,762  26,212  36,784  3,812
Exploration   6,205  7,978  9,995  12,349  1,454
Subtotal   21,253  24,740  36,207  49,133  5,266
Overseas               
Development(3)   24,516  21,891  23,564  27,073  3,427
Exploration   2,964  3,085  2,331  3,864  339
Subtotal   27,480  24,976  25,895  30,937  3,766
Total   48,733  49,716  62,102  80,070  9,032

___________________

(1)Capitalized interests were not included, and it was Rmb 1,430 million, Rmb 2,495 million and Rmb 2,838 million in 2016, 2017 and 2018, respectively.

(2)Numbers for 2019 represent our budgeted capital expenditures.

(3)Including production expenditures.

 

In addition to the budgeted development and exploration expenditures relating to the oil and gas properties described above, we may make additional capital expenditures and investments consistent with our business strategy. See “Item 4—Information on the Company—Business Overview—Business Strategy.” We expect to fund our capital expenditures with our cash flows from operations and external financing.

 

Our ability to maintain and grow our revenues, profit and cash flows depends upon continued capital spending. Generally, we adjust our capital expenditure and investment budget on an annual basis. Our capital expenditure plans are subject to a number of risks, contingencies and other factors, some of which are beyond our control. Therefore, our actual future capital expenditures and investments will likely be different from our current planned amounts, and such differences may be significant.

 

Holding Company Structure

 

We are a holding company. Our entire oil and gas exploration, development, production and sales business in the PRC is owned and conducted by CNOOC China Limited, our wholly owned subsidiary in the PRC. Our oil and gas exploration, development and production business outside the PRC is owned and conducted by CNOOC International Limited, our wholly owned subsidiary incorporated in the British Virgin Islands, or owned and conducted by CNOOC Petroleum North America ULC, a wholly-owned subsidiary of us located in Canada, or directly owned by us. International sales of crude oil and natural gas are conducted by China Offshore Oil (Singapore) International Pte Ltd, our wholly owned subsidiary incorporated in Singapore. CNOOC Petroleum North America ULC, sells its crude oil and synthetic oil to international markets separately. Accordingly, our future cash flows will consist principally of dividends from our subsidiaries. The subsidiaries’ ability to pay dividends to us is subject to various restrictions, including legal restrictions in their jurisdictions of incorporation. For example, legal restrictions in the PRC permit payment of dividends only out of profit determined in accordance with PRC accounting

 

71 

standards and regulations. In addition, under PRC law, CNOOC China Limited should set aside a portion of its profit each year to fund certain reserve funds until the total amount of such funds is up to 50% of the registered capital of CNOOC China Limited. These reserves are not distributable as cash dividends.

 

Inflation/Deflation

 

According to the China Statistical Bureau, as represented by the general consumer price index, China experienced an overall inflation rate of 2.0%, 1.6% and 2.1% in 2016, 2017 and 2018, respectively. Neither deflation nor inflation has had a significant impact on our results of operations in the respective years.

 

Impact of Recently Issued Accounting Standards

 

IFRSs and HKFRSs

 

We have adopted the IFRSs as issued by the IASB since January 1, 2008. Therefore, our consolidated financial statements for 2018 have been prepared in due compliance with both IFRSs and HKFRSs. The accounting policies adopted are consisted with those of the year ended December 31, 2017, except for the first time adoption of the new and amendments to IFRSs/HKFRSs effective for the Company's financial year beginning on January 1, 2018. Except as described in note 2.2 to our consolidated financial statements included elsewhere in this annual report, the adoption of those new amendments to IFRSs/HKFRSs in the current year had no material impact on the accounting policies, the disclosures or the amounts recognized in the consolidated financial statements of us.

 

Besides, a number of new and revised IFRSs and HKFRSs have been issued and would become effective for annual periods beginning on or after January 1, 2018. For details, please refer to notes 2.1 and 2.2 to our consolidated financial statements included elsewhere in this annual report.

 

C.Research and Development, Patents and Licenses, etc.

 

See “Item 4—Information on the Company—Business Overview—Research and Development”, “Item 4—Information on the Company—Business Overview—Patents and Trademarks”.

 

D.Trend Information

 

Looking forward to 2019, the global economy will continue its slow recovery. Despite a recovery in international oil prices, the external operating environment is filled with uncertainties. To this end, we remain confident of our prospects. We will further strengthen our operating strategies, which mainly include: (i) steadily increase oil and gas reserves and production levels, (ii) promote high-quality development of the Company, (iii) digital transformation helps improve core businesses, (iv) maintain prudent financial policy and investment decision-making, and (v) pursue a green, Low-carbon and environment-friendly development model.

 

In 2019, our capital expenditure is anticipated to reach Rmb 70 to 80 billion. Our production target for 2019 is 480 to 490 million BOE, with six new projects to commence production. Meanwhile, we will maintain our high standards of health, safety and environmental protection.

 

As an upstream company specializing in the exploration, development, production and sales of oil and natural gas, we consider reserve and production growth as our top priorities. We plan to increase our reserves and production through drill bits and value-driven acquisitions. We will continue to concentrate our independent exploration efforts on major operating areas, especially offshore China. In the meantime, we will continue to cooperate with our partners through production sharing contracts to lower capital requirements and exploration risks.

 

We will continue to develop the natural gas market, and continue to explore and develop natural gas fields. In the event that we invest in businesses and geographic areas where we have limited

 

72 

experience and expertise, we plan to structure our investments in the form of alliances or partnerships with partners possessing the relevant experience and expertise.

 

We will continue to maintain our prudent financial policy. As an essential part of our corporate culture, we continue to promote cost consciousness among both our management team and employees. Also, in our performance evaluation system, cost control has been one of the most important key performance indicators.

 

Other than as disclosed in the paragraphs above under Item 5.D, we are not aware of any trends that are reasonably likely to have a material effect on our net sales or revenues, income from continuing operations, profitability, liquidity or capital resources, or that would cause reported financial information not necessarily to be indicative of future operating results or financial conditions. You are urged to read the forward-looking statements contained elsewhere in this annual report, the cautionary statement on page 10 and the risk factors on pages 14, which describe the risks and uncertainties that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements. We provide no commitment to update the forward-looking statements or to publish financial projections for forward-looking statements in the future.

 

E.Off-Balance Sheet Arrangements

 

None.

 

F.Tabular Disclosure of Contractual Obligations

 

The following table sets forth information regarding our contractual obligations as of December 31, 2018.

 

   Payments due by period
Contractual Obligations  Total  Less than 1 year  1-3 years  3-5 years  More than 5 years
   Rmb million  Rmb million  Rmb million  Rmb million  Rmb million
Long-term debt obligations(1)   129,388  2,281  20,962  27,404  78,741
Operating lease obligations   16,372  3,141  3,472  2,437  7,322
Provision for dismantlement(2)   54,834  675  —  —  54,159
Total   200,594  6,097  24,434  29,841  140,222

 _______________

(1)The amount of long-term debt obligations represents the principal of the long-term debt obligations.

(2)Provision for dismantlement represents the discounted present value of retirement obligations in connection with upstream assets, which primarily relate to asset removal costs at the completion date of the relevant project.

 

As of December 31, 2016, 2017 and 2018, we had the following capital commitments, principally for the construction and purchase of property, plant and equipment:

 

Capital Commitments  2016  2017  2018
   Rmb million  Rmb million  Rmb million
Contracted, but not provided for   46,515  46,704  55,538

 

G.Safe Harbor

 

The safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act, or the statutory safe harbors, shall apply to forward-looking information provided pursuant to Item 5.F above. For our cautionary statement on the forward looking statement in this annual report, see the section “Forward-Looking Statements” on page 10 of this annual report.

 

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ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

 

A.Directors and Senior Management

 

In accordance with Hong Kong law and our articles of association, our affairs are managed by our Board, which has eight members, including two executive directors, two non-executive directors and four independent non-executive directors as of March 29, 2019.

 

The table below sets forth information about our directors and senior officers:

 

Name

Year of Birth

Position

Guangyu Yuan 1959 Executive Director and Chief Executive Officer
Keqiang Xu 1971 Executive Director and President
Hua Yang 1961 Chairman of the Board and Non-executive Director

Dongjin Wang

1962 Vice Chairman and Non-executive Director (effective December 5, 2018 and April 27, 2018, respectively)
Jian Liu 1958 Vice Chairman and Non-executive Director (resigned as Vice Chairman and Non-executive Director effective from August 16, 2018)
Guangqi Wu 1957 Non-executive Director (resigned as non-executive director effective April 27, 2018)
Sung Hong Chiu 1947 Independent Non-executive Director
Lawrence J. Lau 1944 Independent Non-executive Director
Aloysius Hau Yin Tse 1948 Independent Non-executive Director
Kevin G. Lynch 1951 Independent Non-executive Director
Yuhong Xie 1961 Executive Vice President and General Manager of Exploration Department
Xinjian Cao 1966 Executive Vice President and General Manager of CNOOC China Limited Tianjin Branch
Weizhi Xie 1964 Chief Financial Officer
Guohua Zhang 1960 Senior Vice President and General Manager of CNOOC China Limited Zhanjiang Branch
Yunhua Deng 1963 Deputy Chief Exploration Engineer and Deputy Director of Beijing Research Center of CNOOC China Limited
Zaisheng Liu 1962 Vice President
Xiaonan Wu 1967 Joint Company Secretary and General Counsel and Compliance Officer (effective November 19, 2018 and August 2018, respectively) 
Jiewen Li 1965

Joint Company Secretary and General Manager (Director) of Investor Relations Department (Office for the Board of Directors) (resigned as Joint Company Secretary effective November 19, 2018) 

May Sik Yu Tsue 1973 Joint Company Secretary

 

We have a management team with extensive experience in the oil and gas industry. As a result of our cooperation with international oil and gas companies, the management team and staff have had the opportunities to work closely with foreign partners both within and outside China. Such opportunities, in

 

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conjunction with management exchange programs with foreign partners, have provided valuable training to our personnel in international management practices. A description of the business experience and present position of each director and senior officer is provided below. Our registered office is located at 65th Floor, Bank of China Tower, One Garden Road, Central, Hong Kong.

 

Executive Directors

 

Guangyu Yuan Born in 1959, Mr. Yuan is a professor-level senior engineer. He graduated from China University of Petroleum with a bachelor’s degree in drilling engineering. He graduated from the EMBA program of China Europe International Business School in 2007 with an MBA degree. Mr. Yuan joined China National Offshore Oil Corporation (“CNOOC”) in 1982 and has over 30 years of experience in the oil and gas industry. From February 1993 to October 2001, Mr. Yuan served as Deputy Manager of CNOOC Bohai Drilling Company, Deputy General Manager of CNOOC China Offshore Oil Northern Drilling Company, Deputy General Manager of the Operational Department of CNOOC, General Manager of CNOOC China Offshore Oil Northern Drilling Company. From October 2001 to January 2009, Mr. Yuan served as General Manager and President of CNOOC Services, and Vice Chairman of the Board of Directors, Chief Executive Officer and President of China Oilfield Services Limited (a company listed on The Stock Exchange of Hong Kong Limited and Shanghai Stock Exchange). From November 2006 to May 2016, Mr. Yuan served as the Assistant President of CNOOC. Since July 2016, Mr. Yuan was appointed as the Vice President of CNOOC. In January 2009, Mr. Yuan was appointed as the Executive Vice President of the Company. From April 2013 to June 2016, Mr. Yuan was appointed as Director of Bohai Petroleum Administrative Bureau of CNOOC and General Manager of CNOOC China Limited Tianjin Branch, a subsidiary of the Company. He served as a Director of CNOOC International Limited, a subsidiary of the Company, from July 31, 2009 to May 5, 2017 and as the Chairman of such company from June 15, 2016 to May 5, 2017. Since March 31, 2009, Mr. Yuan served as a Director of CNOOC China Limited, a subsidiary of the Company, and as the General Manager of such company from June 15, 2016 to May 21, 2018, then he was appointed as the Chairman of such company on May 21, 2018. From June 15, 2016 to April 18, 2017, Mr. Yuan served as President of the Company and Mr. Yuan was appointed as an Executive Director of the Company with effect from June 15, 2016. Mr. Yuan was appointed as the Chief Executive Officer of the Company with effect from April 18, 2017.

 

Keqiang Xu Born in 1971, Mr. Xu is a professor-level senior engineer. He graduated from Northwest University with a Bachelor of Science degree in Oil and Gas Geology. He received a master’s degree in Coalfield Oil and Gas Geology from Northwest University in 1996. Mr. Xu joined China National Petroleum Corporation in 1996 and served different positions. From April 2003 to April 2005, he served as Deputy General Manager of Sinopetro Investment Company Ltd. From April 2005 to September 2008, he served as Deputy General Manager of CNPC International (Kazakhstan) Ltd. and concurrently General Manager of CNPC Ai-Dan Munai Joint Stock Company. From September 2008 to March 2014, he served as Deputy General Manager of CNPC International (Kazakhstan) Ltd. and concurrently General Manager of Joint Stock Company CNPC International Aktobe Petroleum. From March 2014 to March 2017, he served as General Manager of PetroChina Tuha Oilfield Company, and Director of Tuha Petroleum Exploration & Development Headquarters. In March 2017, Mr. Xu was appointed as a Vice President of CNOOC. From April 2017 to June 2018, Mr. Xu served as the Chairman of Nexen Energy ULC, a subsidiary of the Company. In between May 2017 and June 2018, he served as the Chairman of a subsidiary of the Company-CNOOC International Limited. In May 2017, Mr. Xu was appointed as a Director of CNOOC China Limited, a subsidiary of the Company. Mr. Xu was appointed as the General Manager of CNOOC China Limited with effect from May 21, 2018. Mr. Xu was appointed as an Executive Director and the President of the Company with effect from April 18, 2017.

 

Non-executive Directors

 

Hua Yang Born in 1961, Mr. Yang is a professor-level senior economist and graduated from China University of Petroleum with a B.S. degree in petroleum engineering. He also received an MBA degree from the Sloan School of Management at MIT as a Sloan Fellow. Mr. Yang joined CNOOC in 1982 and has over 30 years of experience in petroleum exploration and production. From 1982 to 1992,

 

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Mr. Yang served in a number of positions in CNOOC Research Center including the Director of Field Development Department, the Manager of Reservoir Engineering Department and the Project Manager. Thereafter, Mr. Yang was mainly involved in international business, M&A, corporate finance and capital market operations. From 1993 to 1999, he served as the Deputy Chief Geologist, the Deputy Director and the Acting Director for Overseas Development Department of CNOOC and the Vice President of CNOOC International Limited. From 1999 to 2011, Mr. Yang served in a number of positions in the Company including Senior Vice President, Chief Financial Officer, Executive Vice President, President and Chief Executive Officer. Mr. Yang also served as an Assistant President of CNOOC from November 2006 to April 2010 and as Vice President of CNOOC from April 2010 to August 2011. Mr. Yang served as Director and President of CNOOC from August 2011 to April 2015. He was appointed as Chairman of CNOOC in April 2015. From June 15, 2016 to April 18, 2017, he was appointed as the Chairman and a Director of Nexen Energy ULC, a subsidiary of the Company. He also served as Chairman, Director and President of CNOOC Southeast Asia Limited, Chairman, Director and General Manager of CNOOC China Limited and Chairman and Director of CNOOC International Limited, all being subsidiaries of the Company. He also served as Director of CNOOC Finance Corporation Limited, a subsidiary of CNOOC. Mr. Yang was appointed as an Executive Director of the Company with effect from August 31, 2005 and was the Vice Chairman of the Board of the Company from September 16, 2010 to May 19, 2015, and was re-designated from an Executive Director to a Non-executive Director of the Company with effect from November 23, 2011. Mr. Yang was appointed as Chairman of the Board and Chairman of the Nomination Committee of the Company with effect from May 19, 2015. From June 15, 2016 to April 18, 2017, Mr. Yang was re-designated from a Non-executive Director to an Executive Director and served as the Chief Executive Officer of the Company. Mr. Yang was re-designated from an Executive Director to a Non-executive Director with effect from April 18, 2017.

 

Dongjin Wang Born in 1962, Mr. Wang is a professor-level senior engineer and received a Bachelor of Science degree in Petroleum Drilling from Development Department of China University of Petroleum and a Doctor of Science degree in Petroleum Engineering Management from China University of Petroleum-Beijing in 2012. From July 1995 to December 1997, he was appointed as Deputy Director-General of Jiangsu Petroleum Exploration Bureau. From December 1997 to October 2002, he was appointed as Vice President of China National Oil & Gas Exploration and Development Corporation (“CNODC”). From December 2000 to October 2002, he also served as President of CNPC International (Kazakhstan) Ltd. and President of Aktobe Munai Gas Corp. From October 2002 to September 2008, he served as President of CNODC. From January 2004 to September 2008, he was appointed as Assistant President of China National Petroleum Corporation (“CNPC”) and Vice Chairman of CNODC. From September 2008 to March 2018, he served as Vice President of CNPC. From May 2011 to May 2014, he was concurrently appointed as Director of PetroChina Company Limited (“PetroChina”). From July 2013 to March 2018, he was concurrently appointed as President of PetroChina. From May 2014 to March 2018, he served as Vice Chairman of PetroChina. In March 2018, Mr. Wang was appointed as a Director of CNOOC. In October 2018, Mr. Wang was appointed as President of CNOOC. On April 27, 2018, Mr. Wang was appointed as a Non-executive Director and a member of the Remuneration Committee of the Company. Mr. Wang has been appointed as the Vice Chairman of the Company with effect from December 5, 2018.

 

Jian Liu Born in 1958, Mr. Liu is a professor-level senior engineer. He graduated from Huazhong University of Science and Technology with a Bachelor degree and he received his MBA degree from Tianjin University. Mr. Liu first joined CNOOC in 1982 and has over 35 years of experience in the oil and gas industry. He served as the manager of CNOOC Bohai Corporation Oil Production Company, a subsidiary of CNOOC, Deputy General Manager of the Tianjin Branch and the General Manager of the Zhanjiang Branch of CNOOC China Limited, a subsidiary of the Company. From 2003 to 2009, Mr. Liu served as Senior Vice President and General Manager of the Development and Production Department and Executive Vice President of the Company, primarily responsible for the offshore oil and gas fields development and production of the Company. Mr. Liu served as an Assistant President of CNOOC from November 2006 to April 2010 and as a Vice President of CNOOC from April 2010 to

 

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August 2015. In August 2015, Mr. Liu was appointed as the President of CNOOC. Mr. Liu also served as the Director of CNOOC China Limited, CNOOC International Limited and CNOOC Southeast Asia Limited, all being subsidiaries of the Company. Besides, Mr. Liu served as the Chief Executive Officer, Vice Chairman and Chairman of China Oilfield Services Limited (a company listed on The Stock Exchange of Hong Kong Limited and Shanghai Stock Exchange) from March 2009 to December 2016 and Chairman of Offshore Oil Engineering Co. Ltd. (a company listed on the Shanghai Stock Exchange) from December 2010 to November 2016. During February 2017 and May 2018, Mr. Liu served as Chairman and Director of CNOOC China Limited, a subsidiary of the Company. Mr. Liu served as the Vice Chairman and a Non-executive Director of the Company from December 20, 2016 to August 16, 2018.

 

Guangqi Wu Born in 1957, Mr. Wu is a geologist, professor-level senior economist, Certified Senior Enterprise Risk Manager and Certified Internal Auditor and graduated with a B.S. degree from the Ocean University of China, majoring in Marine Geology. He also holds a master degree in Management from China University of Petroleum and a doctor degree in Management from Huazhong University of Science and Technology. Mr. Wu joined CNOOC in 1982. From 1994 to 2001, he served as the Deputy General Manager of CNOOC Oil Technical Services Company, a subsidiary of CNOOC, the Director of the Administration Department of CNOOC and the Director of the Ideology Affairs Department of CNOOC successively. Mr. Wu was appointed as an Assistant President of CNOOC in 2003, and has been the Vice President of CNOOC since 2004. Mr. Wu also serves as the Chairman of CNOOC Marine Environment and Ecology Protection Foundation, and served as the Vice Chairman of China Association of Risk Professionals, the Vice Chairman of China Association of Oceanic Engineering, the Director-General of National Energy Deepwater Oil & Gas Engineering Technology Research Centre Council. Mr. Wu served as an Independent Non-executive Director of China Yangtze Power Limited, a company listed on the Shanghai Stock Exchange, from May 2003 to July 2010. Mr. Wu has served as the Compliance Officer of the Company from June 1, 2005 to June 15, 2016. Since June 2005 to August 2018, he served as a Director of CNOOC International Limited and once as a Director of CNOOC China Limited, all being the subsidiaries of the Company. Mr. Wu was appointed as an Executive Director of the Company with effect from June 1, 2005. Mr. Wu has been re-designated from an Executive Director to a Non-executive Director of the Company with effect from June 15, 2016. Mr. Wu resigned as a Non-executive Director and a member of the Remuneration Committee of the Company with effect from April 27, 2018.

 

Independent Non-executive Directors

 

Sung Hong Chiu Born in 1947, Mr. Chiu received an LL.B. degree from the University of Sydney. He was admitted as a solicitor of the Supreme Court of New South Wales and the High Court of Australia. He has over 30 years’ experience in legal practice and had been a director of a listed company in Australia. Mr. Chiu was the founding member of the Board of Trustees of the Australian Nursing Home Foundation and a senior research fellow of Centre for Law & Globalization of Renmin University of China since 2016. He also served as the General Secretary of the Australian Chinese Community Association of New South Wales. Mr. Chiu is also an independent non-executive director of Tianda Pharmaceuticals Limited (formerly Yunnan Enterprises Holdings Limited, Tianda Holdings Limited) since April 2008, a company listed on The Stock Exchange of Hong Kong Limited. Mr. Chiu is also an independent non-executive director of Bank of China (Australia) Limited (a wholly subsidiary of Bank of China Limited). Mr. Chiu was appointed as an Independent Non-executive Director of the Company with effect from September 7, 1999.

 

Lawrence J. Lau Born in 1944, Professor Lau graduated with a B.S. (with Great Distinction) in Physics from Stanford University in 1964, and received his M.A. and Ph.D. degrees in Economics from the University of California at Berkeley in 1966 and 1969 respectively. He joined the faculty of the Department of Economics at Stanford University in 1966, becoming Professor of Economics in 1976, the first Kwoh Ting Li Professor in Economic Development in 1992, and Kwoh-Ting Li Professor in Economic Development, Emeritus in 2006. From 2004 to 2010, Professor Lau served as the Vice-chancellor (President) of The Chinese University of Hong Kong. From September 2010 to September 2014, Professor Lau served as Chairman of CIC International (Hong Kong) Co., Limited. From March

 

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2008 to February 2018, Professor Lau served as a member of the 11th and 12th National Committee of the Chinese People’s Political Consultative Conference (and a Vice Chairman of its Economics Subcommittee). Professor Lau specializes in economic development, economic growth, and the economies of East Asia, including that of China. He has authored, co-authored, or edited 13 books, including The China-U.S. Trade War and Future Economic Relations, and published 190 articles and notes in professional journals. Professor Lau serves as a member of the Hong Kong Special Administrative Region Exchange Fund Advisory Committee and Chairman of its Governance Sub-Committee, and member of its Currency Board Subcommittee and Investment Sub-Committee, and a member of the Hong Kong Trade Development Council (HKTDC) Belt and Road Committee. In addition, he also serves as the Chairman of the Board of Directors of the Chinese University of Hong Kong (Shenzhen) Advanced Finance Institute, aka Shenzhen Finance Institute, a member and Chairman of the Prize Recommendation Committee of the LUI Che Woo Prize Company, as well as a Vice-Chairman of Our Hong Kong Foundation. He was appointed a Justice of the Peace in Hong Kong in July 2007. He currently serves as the Ralph and Claire Landau Professor of Economics at the Lau Chor Tak Institute of Global Economics and Finance, The Chinese University of Hong Kong, an independent non-executive director of AIA Group Limited, Hysan Development Company Limited and Semiconductor Manufacturing International Corporation, all listed on the Hong Kong Stock Exchange, and an independent non-executive director of Far EasTone Telecommunications Company Limited, Taipei, which is listed on the Taiwan Stock Exchange. Professor Lau was appointed as an Independent Non-executive Director of the Company with effect from August 31, 2005.

 

Aloysius Hau Yin Tse Born in 1948, Mr. Tse is a fellow of The Institute of Chartered Accountants in England and Wales, and the Hong Kong Institute of Certified Public Accountants (“HKICPA”). Mr. Tse is a past president and a former member of the Audit Committee of the HKICPA. He joined KPMG in 1976, became a partner in 1984 and retired in March 2003. Mr. Tse was a non-executive Chairman of KPMG’s operations in the PRC and a member of the KPMG China advisory board from 1997 to 2000. Mr. Tse is currently an independent non-executive director of China Telecom Corporation Limited, SJM Holdings Limited, Sinofert Holdings Limited and China Huarong Asset Management Company, Limited, companies listed on The Stock Exchange of Hong Kong Limited. From 2004 to 2010, he was an independent non-executive director of China Construction Bank Corporation, which is listed on the HKSE Main Board. From 2005 to 2016, Mr. Tse was also an independent non-executive director of Daohe Global Group Limited (formerly known as Linmark Group Limited), which is listed on the HKSE Main Board, Mr. Tse is currently an independent non-executive director of CCB International (Holdings) Limited, a wholly owned subsidiary of China Construction Bank Corporation and OCBC Wing Hang Bank Limited (formerly named as Wing Hang Bank Limited whose shares were delisted from The Stock Exchange of Hong Kong Limited with effect from October 16, 2014). Mr. Tse is also a member of the International Advisory Council of the People’s Municipal Government of Wuhan. Mr. Tse was appointed as an Independent Non-executive Director of the Company with effect from June 8, 2005.

 

Kevin G. Lynch Born in 1951, Mr. Lynch obtained a B.A. degree from Mount Allison University, a M.A. degree in Economics from the University of Manchester, and a doctorate degree in Economics from McMaster University. He also holds 11 honorary degrees. Mr. Lynch was made a life Member of the Privy Council for Canada, and an Officer of the Order of Canada. He is the Vice Chairman of BMO Financial Group and also a distinguished former public servant with 33 years of service with the Government of Canada. Mr. Lynch served as Deputy Minister of Industry of Canada from 1995 to 2000, Deputy Minister of Finance of Canada from 2000 to 2004, Executive Director at the International Monetary Fund from 2004 to 2006 and was appointed as Clerk of the Privy Council for Canada, Secretary to the Cabinet and Head of the Public Service from 2006 to 2009. Mr. Lynch is the Senior Fellow of Massey College, former Chancellor of the University of King’s College, former Chair of the Board of Governors of the University of Waterloo, former Chair of the Canadian Ditchley Foundation, and past Chair of the World Economic Forum’s Global Policy Council on the Global Financial System. He also serves on other boards including the Killam Trusts, Communitech, the Governor General’s Rideau Hall Foundation, the Asia Pacific Foundation of Canada. Mr. Lynch is currently a director of Canadian National Railway Company listed on the Toronto Stock Exchange and New York Stock Exchange, and a

 

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director and chairman of the Board of Directors of SNC Lavalin Group Inc. listed on the Toronto Stock Exchange. Mr. Lynch was appointed as an Independent Non-executive Director of the Company on November 27, 2013, and such appointment took effect from March 1, 2014.

 

Other Members of Senior Management

 

Yuhong Xie Born in 1961, Mr. Xie is an Executive Vice President and General Manager of Exploration Department of the Company as well as a professor-level senior engineer. Mr. Xie obtained a Ph.D. degree from China University of Geosciences in 2005. From 1982 to 1995, Mr. Xie served as an engineer of Research Institute and Exploration Department of CNOOC Naihai West Corporation. From 1995 to 1996, he served as the Deputy Manager of Exploration Department of CNOOC Naihai West Corporation. From 1996 to 1999, he served as Manager of Tepu Company of CNOOC Naihai West Corporation, Deputy Chief Earth Physicist and Manager of Exploration Department of Naihai West Corporation. From 2001 to 2005, he was Deputy Chief Manager of CNOOC China Limited Zhanjiang Branch. From 2005 to 2013, he served as the Chief Manager of CNOOC China Limited Zhanjiang Branch. From 2013 to 2015, he was appointed as the Director of Naihai West Petroleum Administrative Bureau of CNOOC. In July 2015, he was appointed as Deputy Chief Geologist of CNOOC, Deputy Chief Geologist and General Manager of Exploration Department of the Company. From 2016 to 2018, he was appointed as the Chief Geologist of CNOOC, an Executive Vice President and General Manager of Exploration Department of the Company. In May 2018, he was appointed as the Chief Geologist of CNOOC, an Executive Vice President and the Chief Safety Officer of the Company.

 

Xinjian Cao Born in 1966, Mr. Cao is an Executive Vice President and the General Manager of CNOOC China Limited Tianjin Branch as well as a professor-level senior economist. Mr. Cao obtained a master degree of Business Administration from the University of Wales in 2003. From 1989 to 1999, Mr. Cao served as a geological delegate of the Contract Area of CNOOC Donghai Company & Caltex and the deputy manager of Exploration Department of CNOOC Donghai Company. From 1999 to 2004, he served as Exploration Manager of Exploration Department, Assistant Manager, Acting Manager and Manager of Human Resources Department of CNOOC China Limited Shanghai Branch. From 2004 to 2006, he served as Deputy Director of the CNOOC Talent Work Leading Group’s Office. From 2006 to 2013 he served as Deputy General Manager of CNOOC China Limited Shanghai Branch. From 2009 to 2013, he also served as Deputy Director of Donghai Petroleum Administration Bureau of CNOOC. From 2013 to 2017, he served as Deputy General Manager and General Manager of Human Resources Department of CNOOC and the Company. From March 2017, he has served as the Director of Bohai Petroleum Administration Bureau of CNOOC and General Manager of CNOOC China Limited Tianjin Branch. From August 2017, he was appointed as an Executive Vice President of the Company. In September 2017, he was appointed as Assistant President of CNOOC.

 

Weizhi Xie Born in 1964, Mr. Xie is the Chief Financial Officer of the Company. Mr. Xie is a Senior Accountant. He graduated from Guanghua School of Management of Peking University with a master’s degree in Business Administration. Mr. Xie joined CNOOC in 1986. Mr. Xie served as Deputy Manager of Finance Department of CNOOC Nanhai West Corporation, Deputy Manager and Manager of Controllers’ Department and General Manager of Treasury Department of CNOOC. From January 2002 to February 2011, Mr. Xie served as General Manager of CNOOC Finance Corporation Ltd. From February 2011 to May 2016, Mr. Xie served as Assistant President of CHINALCO, Executive Director of CHINALCO Finance Company Limited, President of CHINALCO Offshore Holding Company, Vice President& CFO of CHALCO, President of CHALCO (Hong Kong), Chairman of CHINALCO Finance Company Limited, General Auditor & Director of Audit Department CHINALCO. From 2016 to 2017, Mr. Xie was appointed as General Manager of Finance Department of CNOOC. From August 2017, Mr. Xie was appointed as the Chief Financial Officer of the Company.

 

Guohua Zhang Born in 1960, Mr. Zhang is a Senior Vice President of the Company and the General Manager of CNOOC China Limited Zhanjiang Branch. He is a professor-level senior engineer. He graduated from Shandong Oceanographic Institute (now Ocean University of China) with a bachelor degree. He studied in the Business Institute of University of Alberta in Canada in 2001. He joined

 

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CNOOC in 1982 and served as Deputy Chief Geologist and Manager of Exploration Department of CNOOC Naihai West Corporation, a subsidiary of CNOOC, Chief Geologist of CNOOC Research Center, Assistant to General Manager of CNOOC China Limited and the General Manager of Exploration Department of the Company. In March 2003, he was appointed as Senior Vice President of the Company. In October 2005, Mr. Zhang was appointed as Senior Vice President of the Company and General Manager of CNOOC China Limited Shanghai Branch. In July 2009, he was appointed as Director of Donghai Petroleum Administrative Bureau of CNOOC. In July 2015, he was appointed as Director of Nanhai West Petroleum Administrative Bureau of CNOOC and General Manager of CNOOC China Limited Zhanjiang Branch.

 

Yunhua Deng Born in 1963, Mr. Deng is an academician of the Chinese Academy of Engineering and the Deputy Chief Exploration Engineer of the Company. Mr. Deng graduated from the Scientific Research Institute of Petroleum Exploration and Development with a major in Petroleum Geology and Exploration and received a master’s degree in Engineering in 1988. He was assistant geologist and then geologist in the Exploration Department of CNOOC Bohai Corporation Institute from 1988 to 1989; and served as the Team Leader of the Comprehensive Petroleum Geological Research Team, Project Manager, Deputy Principal of Geologist, Deputy Principal Geologist and Director of the Exploration Department and Deputy Chief Geologist in the CNOOC Bohai Corporation Institute from 1989 to 1999. Mr. Deng became Deputy Chief Geology Engineer and Deputy General Manager of CNOOC China Limited Tianjian Branch from 1999 to 2005. He was Deputy Director of CNOOC Research Center from 2005 to 2006. He served as the Deputy Chief Exploration Engineer of the Company and the Deputy Director of CNOOC Research Center from 2006 to 2007. Mr. Deng served as Deputy Chief Geology Engineer of CNOOC, Deputy Chief Exploration Engineer of the Company and Deputy Director of CNOOC Research Center from 2007 to 2009; and Deputy Chief Geology Engineer of CNOOC, Deputy Chief Exploration Engineer of the Company and Deputy General Director of CNOOC Research Institute from 2009 to 2015. In November 2015, he was appointed as the Deputy Chief Geology Engineer of CNOOC, Deputy Chief Exploration Engineer of the Company and Deputy Director of Beijing Research Center of CNOOC China Limited.

 

Zaisheng Liu Born in 1962, Mr. Liu is a Vice President of the Company and Director of Beijing Research Center of CNOOC China Limited, General Manager of CNOOC China Limited Beijing Branch, Director of CNOOC Energy Technology Development Research Institute and General Manager of CNOOC Energy Technology Development Research Institute Company Limited. Mr. Liu graduated from Southwest Petroleum Institute (now Southwest Petroleum University) with a bachelor’s degree. From 1983 to 1994, he served as Deputy Manager of District Research First Team of Exploration and Development Department Research Institute of Nanhai East Oil Corporation of CNOOC. From 1994 to 1997, he served as Principal of Seismic Engineer and Principal of Geologist of Exploration and Development Department of Nanhai East Oil Corporation of CNOOC. From 1997 to 1999, he served as Deputy Manager of Exploration and Development Department of Nanhai East Oil Corporation of CNOOC. From1997 to 2001, he served as Deputy Director of Scientific and Technology Research Institute of Nanhai East Oil Corporation of CNOOC. From 2001 to 2004, he served as Director of Nanhai East Institute of the Research Center of CNOOC China Limited. From 2004 to 2009, he served as Manager, Assistant to General Manager, Deputy General Manager and Acting General Manager of Technology Department of CNOOC China Limited Shenzhen Branch respectively. From 2009 to 2016, he served as General Manager of CNOOC China Limited Shenzhen Branch and Director of Nanhai East Petroleum Administrative Bureau of CNOOC and General Manager of CNOOC Deepwater Development Limited respectively. From April to November 2016, he served as Director of Beijing Research Center of CNOOC China Limited, General Manager of CNOOC China Limited Beijing Branch, and General Director of CNOOC Energy Technology Development Research Institute and General Manager of CNOOC Energy Technology Development Research Institute Company Limited. In February 2017, Mr. Liu was appointed as a Vice President of the Company.

 

Xiaonan Wu Born in 1967, Ms. Wu Xiaonan is the General Counsel, the Compliance Officer and Joint Company Secretary of the Company. Ms. Wu is an Enterprise Legal Adviser (註 冊 企 業 法 律 顧 問) and Certified Senior Enterprise Risk Manager ( 註 冊 高 級 企 業 風 險 管 理 師). Ms. Wu received a bachelor

 

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of laws degree from China University of Political Science and Law in 1990. Ms. Wu has been working in the oil and gas industry for over 19 years. From September 1999 to June 2002, Ms. Wu successively worked in the Regulatory and Legislative Division of the Legal Department of CNOOC and the Company. From June 2002 to February 2012, Ms. Wu served as the Manager of the Regulatory and Legislative Division of the Legal Department of the Company. From February 2012 to May 2016, she served as the Deputy General Manager of the Legal Department of the Company and was promoted as the General Manager of the Legal Department of the Company in May 2016. In August 2018, Ms. Wu was appointed as the Vice General Counsel of CNOOC and the General Counsel and the Compliance Officer of the Company. In September 2018, Ms. Wu was appointed as the Director of the Legal Support Center of CNOOC. Ms. Wu was appointed as a Joint Company Secretary of the Company with effect from November 19, 2018.

 

Joint Company Secretaries

 

Xiaonan Wu

 

See “Item 6— Directors, Senior Management and Employees—A. Directors and Senior Management— Other Members of Senior Management —Xiaonan Wu.”

 

Jiewen Li Born in 1965, Ms. Li Jiewen was the Joint Company Secretary and the General Manager (Director) of the Investor Relations Department (Office for the Board of Directors). Ms. Li is a senior economist and Certified Senior Enterprise Risk Manager and a member of CPA Australia. Ms. Li graduated from Shanghai Jiao Tong University with a bachelor’s degree in Naval Architecture and Ocean Engineering in 1987. She received a master’s degree in Management from Zhejiang University in 2001. Ms. Li joined CNOOC in 1987 and has been working in the oil and gas industry for over 30 years. From 1987 to 1989, Ms. Li was an Assistant Engineer in Nanhai East Oil Corporation of CNOOC. From 1990 to 2003, she worked as the Assistant Engineer, Budget and Planning Engineer, Budget Supervisor, Assistant Finance Manager of CACT (CNOOC-AGIPChevron-Texaco) Operators Group. From February 2004 to October 2006, she served as the Finance Manager of CNOOC China Limited Shenzhen Branch. From October 2006 to November 2010, Ms. Li was the Deputy General Manager of the Controllers Department of the Company. Ms. Li served as the General Manager of the Controllers Department of the Company from November 2010 to June 2016. Ms. Li also served as the Director of Nexen Energy ULC, a subsidiary of the Company. Ms. Li has been also appointed as the General Manager (Director) of the Investor Relations Department (Office for the Board of Directors) of the Company since October 2015. From November 2015 to November 2018, Ms. Li Jiewen served as a Joint Company Secretary of the Company.

 

May Sik Yu Tsue Born in 1973, Ms. Tsue Sik Yu, May is the Joint Company Secretary of the Company. She graduated from Curtin University of Technology in Australia with a bachelor of commerce in accounting. Ms. Tsue furthered her education at The Hong Kong Polytechnic University in Master of Corporate Governance from 2004 to 2006, and MBA from The University of Hong Kong from 2014 to 2016. She is a fellow member of both the Institute of Chartered Secretaries and Administrators and the Hong Kong Institute of Chartered Secretaries since 2012 and became a member of Company Secretaries Panel and Advisor for Academy of Professional Certification in the same year, and became a member of ACCA since 2016. She is also a fellow member and certified risk trainer of the Institute of Crisis and Risk Management and an associate member of CPA Australia. Furthermore, she was granted a Practitioner’s Endorsement (PE) since 2017/2018 under The Hong Kong Institute of Chartered Secretaries and accredited a General Mediator under Hong Kong Mediation Accreditation Association Limited (HKMAAL) since August 2017. From August 1998 to March 1999, Ms. Tsue worked in LG International (HK) Ltd. as a senior accounts clerk. Ms. Tsue joined China Ocean Oilfield Services (HK) Limited in 1999 as an accountant. She helped to manage the finance of the CNOOC Insurance Limited since 2000 and became its employee in 2004 as a manager of finance department. She serves as company secretary of CNOOC Insurance Limited since March 2007. Ms. Tsue gained The Chartered Governance Professional (CGP) qualification of The Institute of Chartered Secretaries and Administrators and The Hong Kong Institute of Chartered Secretaries on September 30, 2018. She volunteered on Hong Kong Management

 

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Association (HKMA) of Panel of Adjudicators on 2018 HKMA Best Annual Reports Awards. Ms. Tsue was appointed as a Joint Company Secretary of the Company with effect from November 25, 2008.

 

B.       Compensation

 

The aggregate amount of fees, salaries, bonus, housing allowances, other allowances and benefits in kind paid to our directors for the year ended December 31, 2018 was Rmb 4,972,182 (US$723,174), while the amount paid to our other senior management for the same period was Rmb 9,070,176 (US$1,319,202). In addition, under our pension plan for 2018, we set aside an aggregate amount of Rmb 1,154,807 (US$167,960) for pension and similar benefits for our directors (other than independent non-executive directors) and senior management. Our directors (other than independent non-executive directors) and senior management contributed an additional Rmb 362,915 (US$52,784) to the pension plan for 2018. Each director’s annual compensation, including fees, salaries, allowances, benefits in kind, pension benefits and share option benefits, is disclosed in note 8 to our consolidated financial statements included elsewhere in this annual report. Note 9 to our consolidated financial statements included elsewhere in this annual report discloses our five highest paid employees during 2018. For further details regarding share options granted to our directors, officers and employees, see “Item 6—Directors, Senior Management and Employees—E. Share Ownership.” For further details regarding our employee compensation, see “Item 4—Information on the Company—Business Overview—Employees and Employee Benefits.”

 

C.Board Practice

 

Committees

 

We have established an audit committee, a remuneration committee and a nomination committee. Our audit committee meets at least twice a year and is responsible for reviewing the completeness, accuracy and fairness of our accounts, evaluating our auditing scope (both internal and external) and procedures as well as the effectiveness of our risk management and internal control systems. Our audit committee together with senior management and the external auditors, review the accounting principles and practices adopted by us and discuss the risk management and internal control and financial reporting matters. Our audit committee is also responsible for overseeing the operation of the internal monitoring systems, so as to ensure our Board is able to monitor our overall financial position, to protect our assets, and to prevent major errors or omissions resulting from financial reporting. In addition, our audit committee reviews our Company’s business ethics and compliance policies, related reports and performs other corporate governance functions. Our Board is responsible for these systems and appropriate delegations and guidance have been made. Our audit committee regularly reports to our Board. Our audit committee consists of Aloysius Hau Yin Tse as the audit committee financial expert for the purposes of U.S. securities laws and chairman of the audit committee, Sung Hong Chiu and Professor Lawrence J. Lau. Our audit committee charter is available on our website, www.cnoocltd.com.

 

The main responsibilities and authorities of our remuneration committee include making recommendations to our Board on our policy and structure of the remuneration of our directors and senior management and on the establishment of a formal and transparent procedure for developing remuneration policy, determining the service contracts and specific remuneration packages for all executive directors and senior management, such as benefits in kind, pension rights and compensation payments, including any compensation payable for loss or termination of their office or appointment, reviewing and approving the compensation arrangements relating to dismissal or removal of directors for misconduct to ensure consistency with contractual terms, and making recommendations to our Board on the remuneration of non-executive directors and independent non-executive directors. Our remuneration committee consisted of two independent non-executive directors (Sung Hong Chiu as chairman and Aloysius Hau Yin Tse) and one non-executive director (Dongjin Wang). Our remuneration committee charter is available on our website, www.cnoocltd.com.

 

The main authorities and responsibilities of our nomination committee include nominating candidates to serve as our directors and senior management for approval by our Board, reviewing the

 

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structure and composition of our Board, and evaluating the leadership abilities of our executive directors so as to ensure our competitive position, determine the policy and establish proper procedures for the selection of our leadership positions. Our nomination committee is also responsible for reviewing and monitoring the training and continuous professional development of directors and senior management and make recommendations to our Board in this regard. Our nomination committee consists of Hua Yang as chairman, Professor Lawrence J. Lau and Kevin G. Lynch. Our nomination committee charter is available on our website, www.cnoocltd.com.

 

For information on our audit committee financial expert and our code of ethics, see “Item 16A—Audit Committee Financial Expert,” and “Item 16B—Code of Ethics.”

 

Directors Service Contracts

 

Our executive directors and non-executive directors have entered into director’s service contracts with us and the terms of appointment of our independent non-executive directors are governed by appointment letters. There is no severance pay arrangement for our directors.

 

Summary of Significant Differences in Corporate Governance Practices for Purposes of Section 303A.11 of the New York Stock Exchange Listed Company Manual

 

We are incorporated under the laws of Hong Kong. The principal trading market for our shares is the Hong Kong Stock Exchange. In addition, because our shares are registered with the United States Securities and Exchange Commission and are listed on the New York Stock Exchange, or the NYSE, we are subject to certain corporate governance requirements. However, many of the corporate governance rules in the NYSE Listed Company Manual, or the NYSE Standards, do not apply to us as a “foreign private issuer” and we are permitted to follow the corporate governance practices in Hong Kong in lieu of most corporate governance standards contained in the NYSE Standards. Section 303A.11 of the NYSE Standards requires NYSE-listed foreign private issuers to describe the significant differences between their corporate governance practices and the corporate governance standards applicable to U.S. domestic companies listed on the NYSE, or U.S. domestic issuers. We set forth below a brief summary of such significant differences.

 

1. Board and Committee Independence

 

While NYSE Standards require U.S. domestic issuers to have a majority of independent directors, we are not subject to this requirement. Four of our eight directors are independent non-executive directors.

 

NYSE Standards require U.S. domestic issuers to schedule regular executive sessions of non-management directors, or regular executive sessions of independent directors only. NYSE Standards also require that, if a U.S. domestic issuer chooses to hold regular meetings of all non-management directors, it should hold an executive session at least once a year to be attended by only independent directors. We are not subject to such requirements and our independent directors attend all board meetings where possible. We also schedule meetings between our chairman and our independent non-executive directors.

 

NYSE Standards require U.S. domestic issuers to disclose a method for interested parties to communicate directly with the presiding director of the executive sessions, or with the non-management or independent directors as a group. We are not subject to such requirement and we have not adopted such a method yet.

 

2. Audit Committee

 

If an audit committee member simultaneously serves on the audit committees of more than three public companies, and the listed company does not limit the number of audit committees on which its audit committee members serve to three or less, then in each case, the board of directors of the U.S. domestic issuer is required to determine that such simultaneous service would not impair the ability of such member to effectively serve on its audit committee and disclose such determination on or through

 

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the U.S. domestic issuer’s website or in its annual proxy statement or annual report. We are not subject to such requirement and we have not addressed this in our audit committee charter.

 

NYSE Standards require audit committees of U.S. domestic issuers to discuss guidelines and policies that govern the process by which risk assessment and risk management are handled and include such responsibilities in their audit committee charters. We are not subject to such requirement and our audit committee charter does not have such provision. Our audit committee charter only provides that our audit committee shall review with our external auditors and the general managers of internal audit and risk management departments the scope, adequacy and effectiveness of our corporate accounting and financial controls, internal control and risk management systems, and any related significant findings regarding risks or exposures and consider recommendations for improvement of such controls.

 

NYSE Standards require audit committees of U.S. domestic issuers to produce an audit committee report annually and include such report in their annual proxy statements. We are not subject to such requirement and we have not addressed this in our audit committee charter.

 

3. Remuneration Committee

 

NYSE Standards require U.S. domestic issuers to have a compensation committee composed entirely of independent directors. We are not subject to such requirement and have a remuneration committee that consists of two independent non-executive directors and one non-executive director. NYSE Standards also require the board of directors of U.S. domestic issuers to consider additional factors in evaluating the independence of compensation committee members, including the source of compensation of the director, including any consulting, advisory or other compensatory fee paid by the issuer to such director and whether such director is affiliated with the issuer, a subsidiary of the issuer or an affiliate of a subsidiary of the issuer. We are not subject to such requirement and we have not considered such additional factors in evaluating the independence of compensation committee members.

 

NYSE Standards require U.S. domestic issuers to address in their compensation committee charters matters regarding committee member removal and committee structure and operations (including authority to delegate to subcommittees). We are not subject to such requirement and we have not addressed this in our remuneration committee charter.

 

NYSE Standards require compensation committees of U.S. domestic issuers to produce a compensation committee report annually and include such report in their annual proxy statements or annual reports on Form 10-K. We are not subject to such requirement and we have not addressed this in our remuneration committee charter. We disclose the amounts of compensation of our directors on a named basis, senior management by band and the five highest paid employees in our annual reports according to the requirements of the Hong Kong Stock Exchange Listing Rules.

 

NYSE Standards require compensation committees of U.S. domestic issuers may, in its sole discretion, retain or obtain the advice of compensation consultants or other advisers, only after taking into consideration all factors relevant to such advisers’ independence from management, including the various factors as specified in the NYSE Standards, and issuers must provide funding for the retention of such advisers. Also, compensation committees shall be directly responsible for the appointment, compensation and oversight of the advisers they retain. We are not subject to these requirements and we have not applied such requirements and addressed them in our remuneration committee charter.

 

4. Nomination Committee

 

While NYSE Standards require U.S. domestic issuers to have only independent directors on their nomination committee, we are not subject to such requirement and our nomination committee consists of two independent non-executive directors and one non-executive director.

 

NYSE Standards require U.S. domestic issuers to address in their nomination committee charters matters regarding committee member removal and committee structure and operations (including

 

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authority to delegate to subcommittees). We are not subject to such requirement and we have not addressed this in our nomination committee charter.

 

5. Corporate Governance Guidelines

 

NYSE Standards require U.S. domestic issuers to adopt and disclose corporate governance guidelines. They must state in their annual proxy statements or annual reports that such corporate governance guidelines are available on their websites and provide the website addresses. We are not subject to such requirement. We have adopted a set of corporate governance guidelines in accordance with the Hong Kong Stock Exchange Listing Rules, including the CNOOC Limited Code of Ethics for Directors and Senior Officers (the “Code of Ethics”), to govern various aspects of our corporate governance. We have posted the Code of Ethics on our website, www.cnoocltd.com. See “Item 16B—Code of Ethics.”

 

D.Employees

 

See “Item 4—Information on the Company—Business Overview—Employees and Employee Benefits.”

 

E.Share Ownership

 

As of March 29, 2019, our directors and employees had the following personal interests in options to subscribe for shares granted under our share option schemes:

 

Name of Grantee  Number of shares involved in the options outstanding as of January 1, 2018  Number of shares involved in the options outstanding as of March 29, 2019  Date of Grant 

Date of Expiration(1) 

  Closing price per share immediately before the date of grant (HK$)  Exercise Price (HK$)
                   
Executive Director:                  
                   
Guangyu Yuan  1,857,000  1,857,000  May 27, 2009  May 27, 2019  9.33  9.93
   1,899,000  1,899,000  May 20, 2010  May 20, 2020  12.22  12.696

Non-executive Directors: 

                  
                   
Hua Yang  1,857,000  —  May 29, 2008  May 29, 2018  14.20  14.828
   2,835,000  2,835,000  May 27, 2009  May 27, 2019  9.33  9.93
   2,000,000  2,000,000  May 20, 2010  May 20, 2020  12.22  12.696
                   
Other Employees In Aggregate(2):                  
                   
   33,423,000  —  May 29, 2008  May 29, 2018  14.20  14.828
   39,408,000  25,158,000  May 27, 2009  May 27, 2019  9.33  9.93
   46,640,000  32,022,000  May 20, 2010  May 20, 2020  12.22  12.696
Total  129,919,000  65,771,000            

_________________

(1)Except for share options granted under the Pre-Global Offering Share Option Scheme, all share options granted are subject to a vesting schedule pursuant to which one third of the options granted vest on the first, second and third anniversaries of the date of grant, respectively, such that the options granted are fully vested on the third anniversary of the date of grant.

 

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(2)With effect from April 27, 2018, Mr. Wu Guangqi resigned as a Non-executive Director and a member of the Remuneration Committee of the Company. Information on Mr. Wu’s share options outstanding at the beginning of the reporting period is included in the category of “Other Employees.”

 

For the year ended December 31, 2018, no share options granted under our share option schemes were exercised. For the period from January 1, 2018 to March 29, 2019, no share options were exercised.

 

As of December 31, 2018, we had 67,907,000 share options outstanding under our share option schemes, which represented approximately 0.15% of our shares in issue as of that date.

 

For further details about our share option schemes, see notes 9 and 27 to our consolidated financial statements included elsewhere in this annual report.

 

As of March 29, 2019, none of our directors or employees owned 1% or more of our shares including the shares underlying the share options granted as of that date.

 

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

 

A.Major Shareholders

 

The following table sets forth information regarding the ownership of our outstanding shares by major shareholders as of March 29, 2019.

 

Shareholder  Number of Shares Owned  Percentage
CNOOC(1)   28,772,727,273  64.44%

_________________

(1)CNOOC owns our shares indirectly through its wholly owned subsidiaries, CNOOC (BVI) Limited and Overseas Oil & Gas Corporation, Ltd.

 

Our major shareholder listed above does not have voting rights different from our other shareholders. Except as set forth in the above table, we are not aware of any shareholders that hold more than 5% of our shares. Except as disclosed above, we are not aware of any significant changes in the percentage ownership of our major shareholder over the course of the past three years. To our knowledge, no arrangements are currently in place that could lead to a change of control of our Company.

 

As of March 29, 2019, 10,221,385 ADSs, representing approximately 2.3% of our then outstanding shares, were held of record in the form of ADSs. At such date, the number of registered ADS holders in the United States was 54.

 

B.Related Party Transactions

 

Overview

 

We regularly enter into transactions with related parties, including CNOOC and its associates. Since CNOOC indirectly owns an aggregate of approximately 64.44% of our outstanding shares, some of these transactions constitute connected transactions under the Hong Kong Stock Exchange Listing Rules, and are regulated by the Hong Kong Stock Exchange.

 

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;

 

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·purchases of assets, goods and services;

 

·leases of assets; and

 

·bank deposits.

 

These transactions are conducted in the normal course of business on terms comparable to those with other non-state-owned enterprises.

 

Categories of Continuing Connected Transactions

 

As we are controlled by CNOOC, transactions with CNOOC, its subsidiaries and associates are deemed to be related party transactions. The continuing connected transactions defined in Chapter 14A of the Hong Kong Stock Exchange Listing Rules in respect of items listed below also constitute related party transactions. We entered into a comprehensive framework agreement with CNOOC on November 15, 2016 for the provision (1) by us to CNOOC and/or its associates and (2) by CNOOC and/or its associates to us, of a range of products and services which may be required and requested from time to time by either party and/or its associates in respect of the continuing connected transactions. The term of the comprehensive framework agreement is for a period of three years from January 1, 2017. The comprehensive framework agreement is substantially on the same terms as the terms contained in the comprehensive framework agreement entered into by the Company on November 6, 2013, with more details about the pricing principles. The continuing connected transactions under such comprehensive framework agreement and the relevant annual caps for the three years from January 1, 2017 were approved by our independent shareholders on December 1, 2016. The approved continuing connected transactions are as follows:

 

1.Provision of exploration, oil and gas development, oil and gas production as well as marketing, management and ancillary services by CNOOC and/or its associates to us:

 

(a)Provision of exploration and support services

 

(b)Provision of oil and gas development and support services

 

(c)Provision of oil and gas production and support services

 

(d)Provision of marketing, management and ancillary services

 

(e)FPSO vessel leases

 

2.Provision of management, technical, facilities and ancillary services, including the supply of materials by us to CNOOC and/or its associates

 

3.Sales of petroleum and natural gas products by us to CNOOC and/or its associates

 

(a)Sales of petroleum and natural gas products (other than long term sales of natural gas and liquefied natural gas)

 

(b)Long-term sales of natural gas and liquefied natural gas

 

Pricing principles

 

The basic pricing principle for the continuing connected transactions between the Company and CNOOC is based on arm’s length negotiations, on normal commercial terms or better and with reference to the prevailing local market conditions (including the volume of sales, length of contracts, the volume of services, overall customer relationship and other market factors).

 

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On the basis of the above basic pricing principle, each type of products or services must be charged in accordance with the following pricing mechanism and in the following sequential order:

 

(a) government-prescribed price; or

 

(b) where there is no government-prescribed price, in accordance with market prices, including the local, national or international market prices.

 

The continuing connected transactions referred to in paragraph 1(a)-1(b) above provided by CNOOC to the Company and 3(a)-3(b) above provided by the Company to CNOOC, on the basis of the above pricing principle, are determined through arm's length negotiations based on market prices (as defined in the comprehensive framework agreement).

 

The continuing connected transactions referred to in paragraph 1(c)-1(d) above provided by CNOOC to the Company, on the basis of the above pricing principle, are based on government-prescribed price or market prices.

 

The continuing connected transactions referred to in paragraph 1(e) on the basis of the above pricing principle, are unanimously determined with the subsidiaries of CNOOC which provides the FPSO vessel leases after arm’s length negotiation in accordance with normal commercial terms.

 

The continuing connected transactions referred to in paragraph 2 above provided by the Company to CNOOC on the basis of the above pricing principle, are determined through arm’s length negotiation between both parties with reference market price.

 

Disclosure and/or Independent Shareholders’ Approval Requirements

 

Under the Hong Kong Stock Exchange Listing Rules, the following categories of continuing connected transactions are exempted from the independent shareholders’ approval requirement but are subject to the announcement, annual report and annual review requirements set out in the Hong Kong Stock Exchange Listing Rules, because each of the percentage ratios for these categories under the Hong Kong Stock Exchange Listing Rules (other than the profits ratio) , where applicable, is expected to be less than 5% on an annual basis:

 

(a)Provision of marketing, management and ancillary services by CNOOC and/or its associates to us;

 

(b)Provision of management, technical, facilities and ancillary services, including the supply of materials from us to CNOOC and/or its associates; and

 

(c)FPSO vessel leases from CNOOC and/or its associate to us.

 

Under the Hong Kong Stock Exchange Listing Rules, the following categories of continuing connected transactions, or the non-exempt continuing connected transactions, are subject to the connected transaction requirements:

 

(a)Provision of exploration and support services;

 

(b)Provision of oil and gas development and support services;

 

(c)Provision of oil and gas production and support services;

 

(d)Sales of petroleum and natural gas products (other than long-term sales of natural gas and liquefied natural gas); and

 

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(e)Long term sales of natural gas and liquefied natural gas.

 

We obtained independent shareholders’ approval at the extraordinary general meetings held on December 1, 2016 for the non-exempt continuing connected transactions and relevant annual caps for the period from January 1, 2017 to December 31, 2019, respectively. The annual caps for our continuing connected transactions with CNOOC and/or its associates are specified as follows:

 

Categories of Continuing Connected Transactions

 Relevant Annual Caps
Provision of exploration, oil and gas development, oil and gas production as well as marketing, management and ancillary services by CNOOC and/or its associates to us
(a) Provision of exploration and support services

For the three years ending December 31, 2019,

Rmb 9,969 million,

Rmb 10,579 million and

Rmb 11,590 million respectively

(b) Provision of oil and gas development and support services

For the three years ending December 31, 2019,

Rmb 31,670 million,

Rmb 38,289 million and

Rmb 43,745 million, respectively

(c) Provision of oil and gas production and support services

For the three years ending December 31, 2019,

Rmb 12,625 million,

Rmb 14,678 million and

Rmb 16,877 million, respectively

(d) Provision of marketing, management and ancillary services

For the three years ending December 31, 2019,

Rmb 1,620 million,

Rmb 1,786 million and

Rmb 1,970 million, respectively

(e) FPSO vessel leases

For the three years ending December 31, 2019,

Rmb 2,880 million,

Rmb 3,120 million and

Rmb 3,360 million, respectively

Provision of management, technical, facilities and ancillary services, including the supply of materials from us to CNOOC and/or its associates
Provision of management, technical, facilities and ancillary services, including the supply of materials to CNOOC and/or its associates

For the three years ending December 31, 2019,

Rmb 100 million,

Rmb 100 million and

Rmb 100 million, respectively

Sales of petroleum and natural gas products by us to CNOOC and/or its associates

(a) Sales of petroleum and natural gas products (other than long-term sales of natural gas and liquefied natural gas)

For the three years ending December 31, 2019,

Rmb 263,893 million,

Rmb 314,371 million and

Rmb 437,773 million , respectively

(b) Long-term sales of natural gas and liquefied natural gas

For the three years ending December 31, 2019,

Rmb 25,654 million,

Rmb 33,386 million and

Rmb 43,649 million, respectively

 

A detailed discussion of significant connected transactions entered into in the ordinary course of business between us and our related parties during 2018 and the balances arising from connected

 

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transactions at the end of 2018 is included in note 29 to our consolidated financial statements included elsewhere in this annual report.

 

The non-exempt continuing connected transactions for the year ended December 31, 2018 to which any member of us was a party were entered into by us:

 

(i)in the ordinary and usual course of our business;

 

(ii)on normal commercial terms or better; and

 

(iii)in accordance with the relevant agreements (including pricing principles and guidelines set out therein) governing the transactions on terms that were fair and reasonable and in the interests of the shareholders of our Company as a whole.

 

We confirmed that the annual amount of each category of the non-exempt continuing connected transactions for the year ended December 31, 2018 did not exceed the applicable annual caps; and we have complied with other relevant provisions of the Hong Kong Stock Exchange Listing Rules in relation to each category of the non-exempt continuing connected transactions.

 

Transactions with CNOOC Finance Corporation Limited

 

On December 1, 2016, we entered into a financial services framework agreement (“Financial Services Framework Agreement”) with CNOOC Finance Corporation Limited (“CNOOC Finance”), our 31.8% owned affiliate and a subsidiary of CNOOC, pursuant to which CNOOC Finance provides a range of financial services as may be required and requested by the Company, for a term of three years from January 1, 2017 to December 31, 2019. Apart from the duration of the Financial Services Framework Agreement, more details about the pricing policy for the depositary services and update of the address and relevant dates, the Financial Services Framework Agreement is substantially on the same terms as the terms contained in the financial services framework agreement (as renewed on August 20, 2010 and November 27, 2013) entered into by the Company on October 14, 2008. The continuing connected transactions in respect of the depositary services under the Financial Services Framework Agreement are exempted from independent shareholders’ approval requirement, but subject to the annual reporting, annual review and announcement requirements. In August 2018, the Board expected that the existing annual cap for the depositary services under the Financial Services Framework Agreement for its remaining term will not fully satisfy the demands of business of us and resolved to revise the annual cap for the depositary services for the period from August 23, 2018 to December 31, 2019.