20-F

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

ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017

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)

Jiewen Li

65^th 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	New York Stock Exchange, Inc. New York Stock Exchange, Inc.(1)

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 ¨     No ý

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 

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

Table of Contents

Page

TERMS AND CONVENTIONS	5
SPECIAL NOTE ON THE FINANCIAL INFORMATION AND CERTAIN STATISTICAL INFORMATION PRESENTED IN THIS ANNUAL REPORT	10
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS	11
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE	11
ITEM 3. KEY INFORMATION	11
A.   Selected Financial Data	11
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	18
A.   History and Development	18
B.   Business Overview	20
C.   Organizational Structure	53
D.   Property, Plants and Equipment	54
ITEM 4A. unresolved staff comments	54
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS	54
A.  Operating Results	54
B.   Liquidity and Capital Resources	66
C.   Research and Development, Patents and Licenses, etc.	69
D.   Trend Information	69
E.   Off-Balance Sheet Arrangements	70
F.   Tabular Disclosure of Contractual Obligations	70
G.   Safe Harbor	70
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	71
A.   Directors and Senior Management	71
B.   Compensation	79
C.   Board Practice	80
D.   Employees	82
E.   Share Ownership	82
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	83
A.   Major Shareholders	83
B.   Related Party Transactions	84
C.   Interests of Experts and Counsel	88
ITEM 8. FINANCIAL INFORMATION	88
A.   Consolidated Statements and Other Financial Information	88
B.   Significant Changes	90
ITEM 9. THE OFFER AND LISTING	90
ITEM 10. ADDITIONAL INFORMATION	91
A.   Share Capital	91
B.   Memorandum and Articles of Association	91
C.   Material Contracts	94
D.   Exchange Controls	94
E.   Taxation	94
F.   Dividends and Paying Agents	99
G.   Statement by Experts	99
H.   Documents on Display	99
I.   Subsidiary Information	99
ITEM 11. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK	99
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	100
A.   Debt Securities	100
B.   Warrants and Rights	100
C.   Other Securities	100
D.   American Depositary Shares	100
PART II	102
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	102

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ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	102
A.   Material Modifications to the Instruments Defining the Rights of Security Holders	102
B.   Material Modifications to the Rights of Registered Securities by Issuing or Modifying any Other Class of Securities	102
C.   Withdrawal or Substitution of a Material Amount of the Assets Securing any Registered Securities	102
D.   Change of Trustees or Paying Agents for any Registered Securities	103
E.   Use of Proceeds	103
ITEM 15. CONTROLS AND PROCEDURES	103
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT	103
ITEM 16B. CODE OF ETHICS	103
ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES	104
ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	105
ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	105
ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT	105
ITEM 16G. CORPORATE GOVERNANCE	105
ITEM 16H. MINE SAFETY DISCLOSURE	105
PART III	105
ITEM 17. FINANCIAL STATEMENTS	105
ITEM 18. FINANCIAL STATEMENTS	105
ITEM 19. EXHIBITS	105

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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;

· “Our company”, “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;

· “HKFRS” 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;

· “IFRS” 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; and

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

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

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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 29, 2017 of US$1.00=Rmb 6.5063. 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, 2017 of US$1.00=HK$ 7.8128. 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, 2017 of US$1.00=Cdn$1.2517. 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, 2017, 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 2015, 2016 and 2017, approximately 62%, 60% and 65% 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 2015, 2016 and 2017 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 and Tangguh projects in Indonesia in Asia and Yacheng 13-1/13-4 gas fields in the Western South China Sea, where we have used energy equivalence 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.

· “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

6 

methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available 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.”

· “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.

(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.

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(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 its 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 economical recovery.

· “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.

8 

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.

9 

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, 2015, 2016 and 2017 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, 2013, 2014, 2015, 2016 and 2017. 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 as of and for the years ended December 31, 2013, 2014, 2015, 2016 and 2017 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 as of and for the years ended December 31, 2013, 2014, 2015, 2016 and 2017 have been prepared and presented in accordance with IFRS.

	Year ended December 31,
	2013			2014			2015			2016			2017			2017
	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		226,445			218,210			146,597			121,325			151,888			23,345
Marketing revenues		55,495			50,263			21,422			20,310			28,907			4,443
Other income		3,917			6,161			3,418			4,855			5,595			860
Total operating revenues		285,857			274,634			171,437			146,490			186,390			28,648
Expenses:
Operating expenses		(30,014	)		(31,180	)		(28,372	)		(23,211	)		(24,282	)		(3,732	)
Taxes other than income tax		(15,937	)		(11,842	)		(10,770	)		(6,941	)		(7,210	)		(1,108	)
Exploration expenses		(17,120	)		(11,525	)		(9,900	)		(7,359	)		(6,881	)		(1,058	)
Depreciation, depletion and amortization		(56,456	)		(58,286	)		(73,439	)		(68,907	)		(61,257	)		(9,415	)
Special oil gain levy		(23,421	)		(19,072	)		(59	)		-			(55	)		(8	)
Impairment and provision		45			(4,120	)		(2,746	)		(12,171	)		(9,130	)		(1,403	)
Crude oil and product purchases		(53,386	)		(47,912	)		(19,840	)		(19,018	)		(27,643	)		(4,249	)
Selling and administrative expenses		(7,859	)		(6,613	)		(5,705	)		(6,493	)		(6,861	)		(1,055	)
Others		(3,206	)		(3,169	)		(3,150	)		(4,802	)		(6,021	)		(925	)
Total expenses		(207,354	)		(193,719	)		(153,981	)		(148,902	)		(149,340	)		(22,953	)
Profit/(loss) from operating activities		78,503			80,915			17,456			(2,412	)		37,050			5,695
Interest income		1,092			1,073			873			901			653			100
Finance costs		(3,457	)		(4,774	)		(6,118	)		(6,246	)		(5,044	)		(775	)
Exchange gains /(losses), net		873			1,049			(143	)		(790	)		356			55
Investment income		2,611			2,684			2,398			2,774			2,409			370
Share of profits/(losses) of associates		133			232			256			(609	)		302			46
Share of (losses)/ profits of a joint venture		762			774			1,647			533			553			85
Non-operating income, net		334			560			761			574			78			12
Profit/(loss) before tax		80,851			82,513			17,130			(5,275	)		36,357			5,588
Income tax (expense)/credit		(24,390	)		(22,314	)		3,116			5,912			(11,680	)		(1,795	)
Profit for the year		56,461			60,199			20,246			637			24,677			3,793
Earnings per share (basic)(2)		1.26			1.35			0.45			0.01			0.55			0.09
Earnings per share (diluted) (3)		1.26			1.35			0.45			0.01			0.55			0.09
Earnings per ADS (basic) (2)		126.46			134.83			45.35			1.43			55.40			8.51
Earnings per ADS (diluted) (3)		126.07			134.57			45.31			1.43			55.40			8.51
Dividend per share
Interim		0.198			0.198			0.205			0.105			0.170			0.03
Proposed final		0.252			0.254			0.210			0.204			0.243			0.04

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	As of December 31,
	2013		2014		2015		2016		2017		2017
	Rmb		Rmb		Rmb		Rmb		Rmb		US$
			(in millions)
Statement of Financial Position Data:
Cash and cash equivalents		14,318		14,918		11,867		13,735		12,572		1,932
Available-for sale financial assets(1)		51,103		54,030		-		-		-		-
Other financial assets(1)		-		-		71,806		52,889		74,344		11,426
Current assets		146,552		140,708		140,211		122,045		138,838		21,339
Property, plant and equipment, net		419,102		463,222		454,141		432,465		395,868		60,844
Investments in associates		4,094		4,100		4,324		3,695		4,067		625
Investments in a joint venture		20,303		21,150		24,089		26,300		25,079		3,855
Intangible assets		17,000		16,491		16,423		16,644		15,070		2,316
Available-for-sale financial assets		6,798		5,337		-		-		-		-
Equity investments(1)		-		-		3,771		4,266		3,540		544
Total assets		621,473		662,859		664,362		637,681		617,219		94,865
Current loans and borrowings		49,841		31,180		33,585		19,678		13,892		2,136
Current liabilities		128,948		103,498		84,380		67,090		61,412		9,439
Long term loans and borrowings		82,011		105,383		131,060		130,798		118,358		18,191
Total non-current liabilities		150,905		179,751		193,941		188,220		175,832		27,025
Total liabilities		279,853		283,249		278,321		255,310		237,244		36,464
Capital stock		43,081		43,081		43,081		43,081		43,081		6,621
Shareholders’ equity		341,620		379,610		386,041		382,371		379,975		58,401

(1) From January 1, 2015, the Company early adopted IFRS/HKFRS 9 (2009) - Financial Instruments. Certain financial assets have been classified into new categories. For details, please refer to notes 2.2 to our consolidated financial statements included elsewhere in this annual report.

(2) Earnings per share (basic) and earnings per ADS (basic) for each year from 2013 to 2017 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 44,646,825,847 and 446,468,258, respectively, for 2013, and 44,647,455,984 and 446,474,560, respectively, for 2014, 44,647,455,984 and 446,474,560, respectively, for 2015, 44,647,455,984 and 446,474,560, respectively, for 2016, and 44,647,455,984 and 446,474,560, respectively, for 2017, 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 2013 to 2017 have been computed, after considering the dilutive effect of the shares underlying our share option schemes by using 44,787,119,089 shares and 447,871,191 ADSs for 2013, 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.

				Year ended December 31,
	2013			2014			2015			2016			2017			2017
	Rmb			Rmb			Rmb			Rmb			Rmb			US$
				(in millions, except percentages and ratios)
Other Financial Data:
Capital expenditures paid(1)		79,716			95,673			67,674			51,347			47,734			7,337
Cash provided by/(used for):
Operating activities		110,891			110,508			80,095			72,863			94,734			14,561
Investing activities		(170,032	)		(90,177	)		(76,495	)		(27,953	)		(64,411	)		(9,901	)
Financing activities		18,601			(19,486	)		(6,893	)		(43,240	)		(31,271	)		(4,806	)
Gearing ratio(2)		27.8	%		26.5	%		29.9	%		28.2	%		25.8	%		25.8	%

(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

12 

The following table sets forth the noon buying rates between U.S. dollars and Renminbi as set forth in the H.10 weekly statistical release of the Federal Reserve Board for the periods indicated:

	Noon Buying Rate
Period	End		Average(1)		High		Low
	(Rmb per US$1.00)
2013		6.0537		6.1412		6.2438		6.0537
2014		6.2046		6.1704		6.2591		6.0402
2015		6.4778		6.2869		6.4896		6.1870
2016		6.9430		6.6549		6.9580		6.4480
2017		6.5063		6.7350		6.9575		6.4773
October 2017		6.6328		—		6.6533		6.5712
November 2017		6.6090		—		6.6385		6.5967
December 2017		6.5063		—		6.6210		6.5063
January 2018		6.2841		—		6.5263		6.2841
February 2018		6.3280		—		6.3471		6.2649
March 2018		6.2726		—		6.3565		6.2685

(1) Determined by averaging the noon buying rates on the last business day of each month during the relevant period.

On March 30, 2018, the noon buying rate between U.S. dollars and Renminbi as set forth in the H.10 weekly statistical release of the Federal Reserve Board was Rmb 6.2726 to US$1.00.

The following table sets forth the noon buying rates between U.S. dollars and Hong Kong dollars as set forth in the H.10 weekly statistical release of the Federal Reserve Board for the periods indicated.

	Noon Buying Rate
Period	End		Average(1)		High		Low
	(HK$ per US$1.00)
2013		7.7539		7.7565		7.7654		7.7503
2014		7.7531		7.7554		7.7669		7.7495
2015		7.7507		7.7529		7.7686		7.7495
2016		7.7534		7.7618		7.8270		7.7505
2017		7.8128		7.7950		7.8267		7.7540
October 2017		7.8015		—		7.8106		7.7996
November 2017		7.8093		—		7.8118		7.7955
December 2017		7.8128		—		7.8228		7.8050
January 2018		7.8210		—		7.8230		7.8161
February 2018		7.8262		—		7.8267		7.8183
March 2018		7.8484		—		7.8486		7.8275

(1) Determined by averaging the noon buying rates on the last business day of each month during the relevant period.

On March 30, 2018, the noon buying rate between U.S. dollars and Hong Kong dollars as set forth in the H.10 weekly statistical release of the Federal Reserve Board was HK$7.8484 to US$1.00.

The following table sets forth the noon buying rates between U.S. dollars and Canadian dollars as set forth in the H.10 weekly statistical release of the Federal Reserve Board for the periods indicated.

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	Noon Buying Rate
Period	End		Average(1)		High		Low
	(Cdn$ per US$1.00)
2013		1.0637		1.0347		1.0697		0.9839
2014		1.1601		1.1083		1.1644		1.0612
2015		1.3839		1.2906		1.3989		1.1725
2016		1.3426		1.3229		1.4592		1.2544
2017		1.2517		1.2963		1.3745		1.2131
October 2017		1.2894		—		1.2894		1.2470
November 2017		1.2884		—		1.2890		1.2693
December 2017		1.2517		—		1.2900		1.2517
January 2018		1.2293		—		1.2534		1.2293
February 2018		1.2806		—		1.2806		1.2280
March 2018		1.2891		—		1.3096		1.2822

(1) Determined by averaging the noon buying rates on the last business day of each month during the relevant period.

On March 30, 2018, the noon buying rate between U.S. dollars and Canadian dollars as set forth in the H.10 weekly statistical release of the Federal Reserve Board was Cdn$1.2891 to US$1.00.

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 be 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 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.

Despite the mild recovery of international oil prices, low oil and natural gas prices may adversely affect our business, revenue and earnings. Lower oil and natural gas prices may result in the 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, politically 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 regime are not within our control. Our operations, existing assets or future investments may be materially and adversely affected by these changes as well as potential trade and economic sanctions due to deteriorated relations between different countries.

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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 in 2015 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. Most recently, the U.S. has promulgated a significant tax reform with effect from January 1, 2018.

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 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 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. 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 project delays and higher costs.

It is expected that the CO₂ emissions will increase as our production grows. CO₂ emissions from flaring will increase as long as 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 the 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, project delays, reduced production and reduced demand for the Company’s products.

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

Mergers and acquisitions may not succeed due to various reasons, such as difficulties in integrating activities and realising 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 realise 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 fulfil all of its 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 work to a wide range of health, safety, security and environment risks.

15 

Every aspect of our daily operations exposes us to health, safety, security and environmental (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 difficult geographic or climate zones, as well as environmentally sensitive regions, such as Canada, the basins in Uganda or offshore, especially in deep water area. Our operations expose us and the areas in which we operate to a number of risks, including major process safety incidents, natural disasters, earthquakes, social unrest, health and safety lapses and crimes. If a major HSSE risk materialises, such as an explosion or hydrocarbon spill, this could result in casualties, environmental damage disruption of business activities and, depending on their cause and severity, material damage to our reputation, exclusion from bidding on mineral rights and eventually loss of our licence to operate. In certain circumstances, liabilities could be imposed without regard to our fault in the matter. Regulatory requirements for HSSE 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 laws and regulations relating to HSSE matter.

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 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 U.S., United Kingdom, Canada, Australia, Guyana and China. The compliance with these laws and regulations may increase our cost. If the Company, 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 current or future 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 imposition of sanctions on CNOOC, which could materially and adversely affect our shareholders.

We cannot predict the interpretation or implementation of government policies at the U.S. federal, state or local levels with respect to any current or future activities by CNOOC or its affiliates in countries or with individuals or entities that are the subject of U.S. sanctions. As a result of such activities by CNOOC, 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 affiliates’ activities. To our knowledge, in 2017, China Oilfield Services Limited (COSL), one of our non-controlled affiliates, provided certain drilling and other related 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 commence production or may not be sufficiently productive to generate a return of our partial or full investments. In addition, approximately

16 

57.6% of our proved reserves were undeveloped as of 31 December 2017. 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 stricter environmental compliance standards and requirements, although current knowledge recognise 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 damages in assets, violate laws or regulations and result in potential legal liability. These actions could result in significant costs or damage to our reputational.

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 controls us in various aspects. 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 under any new PSCs that it enters into to us (except for those relating to administrative functions as a state-owned company), 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, the Company may not be able to proceed with these transactions as planned and it may adversely affect our business and financial condition.

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

17 

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.

The 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 aboriginal people, 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 purchases from us significantly, our results of operation could be adversely affected. In order to reduce reliance on a single customer, 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.

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 a consensus in corporate cultures and win-win cooperation. Further, we actively explore new suppliers to ensure adequacy and foster competition.

We face currency risks and liquidity risks.

Currency risks – The Company’s 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. The depreciation of the U.S. dollar against the Renminbi may decrease the Company’s revenue in the sales of oil and gas, but it may decrease our costs of equipment and import of raw materials in the meantime.

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. In addition, a ratings downgrade could potentially increase financing costs and adversely impact our ability to access financing, which could put pressure on the Company’s liquidity.

The audit reports included in this annual report have been prepared by our independent registered public accounting firm whose work are not be inspected by the Public Company Accounting Oversight Board and, as such, you are deprived of the benefits of such inspection.

 Our independent registered public accounting firm that issues the audit reports included in our annual report filed with the SEC, as auditors of companies that are traded publicly in the United States and a firm registered with the U.S. Public Company Accounting Oversight Board, or 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. This lack of PCAOB inspections in China prevents the PCAOB from regularly evaluating our independent registered public accounting firm’s audits and its quality control procedures. As a result, investors may be deprived of the benefits of PCAOB inspections.

Inspections of other firms that the PCAOB has conducted outside China have identified deficiencies in those firms’ audit procedures and quality control procedures, which may be addressed as part of the inspection process to improve future audit quality. The inability of the PCAOB to conduct inspections of auditors in China makes it more difficult 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 PCAOB inspections. Investors may lose confidence in our reported financial information and procedures and the quality of our financial statements.

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

18 

articles of association or any enactment or rule of law. Our registered office is located at 65^th 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.

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.”

19 

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 2017, we had net proved reserves of approximately 4.84 billion BOE (including approximately 0.37 billion BOE in our equity method investees). In 2017, we achieved a total net oil and gas production of 1,288,128 BOE per day (including net oil and gas production of approximately 47,355 BOE per day in our equity method investees).

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, 2017, we had approximately 4.84 billion BOE of net proved reserves. Our core operating area, offshore China, contributed to approximately 54.0% of our net proved reserves, while overseas contributed to the balance of 46.0%.

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 and Brazil.

As of December 31, 2017, approximately 57.6% 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, 2017, our total major exploration areas acreage in offshore China was approximately 257 thousand km². 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 2017, we and our foreign partners have together drilled a total of 116 exploratory wells in offshore China, of which 58 were wildcat wells. During the same year, we and our foreign partners made 17 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

20 

independent exploration and development. As of the end of 2017, in offshore China, approximately 84.1% of our net proved reserves were independent and approximately 76.0% of our production came from independent projects.

In 2017, in offshore China, our independent exploration resulted in 17 new discoveries. We also successfully appraised 14 oil and gas structures. On the development front, our major new development projects progressed smoothly with four new projects on stream in offshore China.

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 been with CNOOC, our controlling shareholder, since its inception in 1982. Many of our management team and staff members have worked closely with international partners both within and outside China through numerous joint operations.

The Company has always upheld and attained high standard of business ethics, for which its transparency and standard of governance have been recognized by the public and its shareholders. In 2017, we were awarded the “Best Investor Relations Company (China)” and “Asia’s Best CEO (Investor Relations (China))” by “Asian Excellence Award” organized by Corporate Governance Asia magazine and “2017 China Securities Golden Bauhinia Awards – Best Board Secretary of Listed Companies” by Ta Kung Wen Wei Media Group.

Business Strategy

We intend to continue expanding our oil and gas exploration and production activities. 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, 2017, approximately 57.6% of our proved reserves were classified as proved undeveloped, which provides a solid resource base for maintaining stable production in the future.

Develop natural gas business

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

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 2017, we continued our efforts to lower costs and enhance efficiency through innovation in technology and management. All-in cost decreased for the fourth consecutive year. Under low oil price environment, 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 for 2015, 2016 and 2017 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.

	Year ended December 31,
	2015			2016			2017
Net Production(2):
Oil (daily average bbls/day)		1,124,047			1,083,101			1,064,986
Gas (daily average mmcf/day)		1,363.6			1,276.2			1,300.6
Oil equivalent (BOE/day)		1,358,022			1,302,922			1,288,128
Net Proved Reserves (end of period):
Oil (mmbbls)		2,015.0			2,015.4			2295.0
Gas (bcf)		6,992.9			7,486.1			7543.3
Synthetic Oil (mmbbls)		815.3			300.5			785.9
Bitumen (mmbbls)		0.0			0.0			118.4
Total (million BOE)		4,016.0			3,583.4			4474.1
Total with equity method investees (million BOE)(2)		4,315.5			3,877.6			4840.8
Annual reserve replacement ratio(1)		65	%		6	%		297	%
Annual reserve replacement ratio(2)		67	%		8	%		305	%
Estimated reserve life (years)		8.4			7.8			9.9
Estimated reserve life (years)(2)		8.7			8.1			10.3
Standardized measure of discounted future net cash flow (million Rmb)		185,251			223,625			241,904

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

(2) Including our interest in equity method investees.

For further information regarding our reserves, see “Item 3—Key Information—Risk Factors—Risks Relating to Our Operations—The oil and gas reserve estimates in this annual report may require substantial revision as a result of future drilling, testing, production and oil and gas price changes” and “Item 4—Information on the Company—Business Overview—Exploration, Development and Production.”

Summary of Oil and Gas Reserves

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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 at December 31,						Net proved reserves at December 31, 2017
	2015		2016		Crude Oil		Natural Gas		Synthetic Oil		Bitumen		Total
	(mmboe)		(mmboe)		(mmbbls)		(bcf)		(mmbbls)		(mmbbls)		(mmboe)
Developed
Offshore China
Bohai		603.1		600.8		623.9		224.0		—		—		661.3
Western South China Sea		169.0		165.5		99.0		465.1		—		—		177.4
Eastern South China Sea		299.9		285.2		164.1		778.8		—		—		293.9
East China Sea		30.9		34.9		6.2		106.4		—		—		24.0
Subtotal		1,102.9		1,086.4		893.3		1,574.3		—		—		1,156.6
Overseas
Asia (excluding China)		118.8		160.3		35.3		557.9		—		—		133.4
Oceania		63.3		62.1		8.3		229.5		—		—		53.3
Africa		52.7		40.7		36.9		0.0		—		—		36.9
North America (excluding Canada)		112.6		124.1		122.8		278.3		—		—		169.2
Canada		216.6		155.7		0.0		24.2		141.8		46.2		192.0
South America		1.6		1.5		1.3		—		—		—		1.3
Europe		95.8		81.7		83.8		4.6		—		—		84.6
Subtotal		661.4		626.1		288.5		1,094.4		141.8		46.2		670.7
Total Developed		1,764.3		1,712.5		1,181.7		2,668.7		141.8		46.2		1,827.3
Undeveloped
Offshore China
Bohai		368.7		349.4		426.5		81.7		—		—		440.1
Western South China Sea		503.6		653.3		97.5		3,415.0		—		—		666.7
Eastern South China Sea		215.7		220.3		207.8		191.7		—		—		239.8
East China Sea		133.4		111.3		2.2		648.0		—		—		110.2
Subtotal		1,221.5		1,334.3		734.0		4,336.4		—		—		1,456.8
Overseas										—		—
Asia (excluding China)		90.1		84.7		34.7		327.1		—		—		92.1
Oceania		27.5		15.3		2.4		67.6		—		—		15.7
Africa		113.9		97.3		100.0		—		—		—		100.0
North America (excluding Canada)		172.1		194.4		159.3		143.2		—		—		183.2
Canada		618.6		144.8		—		—		644.1		72.1		716.2
South America						78.4								78.4
Europe		8.0		0.1		4.5		0.2		—		—		4.6
Subtotal		1,030.3		536.6		379.2		538.2		644.1		72.1		1,190.1
Total Undeveloped		2,251.7		1,870.9		1,113.3		4,874.6		644.1		72.1		2,646.8
TOTAL PROVED		4,016.0		3,583.4		2,295.0		7,543.3		785.9		118.4		4,474.1
Equity method investees		299.5		294.2		244.8		706.8		—		—		366.7
Total with equity method investees		4,315.5		3,877.6		2,539.8		8,250.1		785.9		118.4		4,840.8

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.

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Total Net Proved Crude and Liquids Reserves
(mmbbls)

	As of December 31,				As of December 31, 2017
	2015		2016		Developed			Undeveloped			Total
Offshore China
Bohai		908.3		903.8		623.9			426.5			1050.4
Western South China Sea		149.3		168.3		99.0			97.5			196.5
Eastern South China Sea		357.0		363.1		164.1			207.8			371.9
East China Sea		16.1		10.6		6.2			2.2			8.5
Subtotal		1,430.6		1,445.7		893.3			734.0			1,627.3
Overseas
Asia (excluding China)		59.8		77.3		35.3			34.7			69.9
Oceania		14.5		12.0		8.3			2.4			10.7
Africa		166.6		138.0		36.9			100.0			136.9
North America (excluding Canada)		239.5		260.3		122.8			159.3			282.1
Canada		815.3		300.5		188.0	(1)		716.2	(2)		904.3
South America		1.6		1.5		1.3			78.4			79.7
Europe		102.3		80.6		83.8			4.5			88.4
Subtotal		1,399.6		870.2		476.5			1,095.5			1,571.9
Total		2,830.2		2,315.9		1,369.8			1,829.5			3,199.3
Equity method entities		200.1		195.3		133.3			111.5			244.8
Total with equity method investees		3,030.3		2,511.2		1,503.1			1,941.0			3,444.1

(1) Including Synthetic oil 141.8 mmbbls and Bitumen 46.2 mmbbls.

(2) Including Synthetic oil 644.1 mmbbls and Bitumen 72.1 mmbbls.

Total Net Proved Natural Gas Reserves
(bcf)

	As of December 31,				As of December 31, 2017
	2015		2016		Developed		Undeveloped		Total
Offshore China
Bohai		381.4		278.7		224.0		81.7		305.7
Western South China Sea		3,132.6		3,896.8		465.1		3,415.0		3,880.1
Eastern South China Sea		951.6		854.9		778.8		191.7		970.5
East China Sea		889.0		813.3		106.4		648.0		754.4
Subtotal		5,354.6		5,843.7		1,574.3		4,336.4		5,910.7
Overseas
Asia (excluding China)		845.8		952.4		557.9		327.1		885.0
Oceania		389.2		333.5		229.5		67.6		297.2
Africa		—		—		—		—		—
North America (excluding Canada)		275.2		349.6		278.3		143.2		421.5
Canada		119.3		—		24.2		—		24.2
South America		—		—		—		—		—
Europe		8.8		6.9		4.6		0.2		4.8
Subtotal		1,638.3		1,642.4		1,094.4		538.2		1,632.6
Total		6,992.9		7,486.1		2,668.7		4,874.6		7,543.3
Equity method investees		576.9		574.0		538.8		168.0		706.8
Total with equity method investees		7,569.8		8,060.1		3,207.5		5,042.5		8,250.1

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 Total Net Proved Reserves
(million BOE)

	As of December 31,				As of December 31, 2017
	2015		2016		Developed		Undeveloped		Total
Offshore China
Bohai		971.8		950.2		661.3		440.1		1101.4
Western South China Sea		672.6		818.8		177.4		666.7		844.1
Eastern South China Sea		515.6		505.5		293.9		239.8		533.7
East China Sea		164.2		146.2		24.0		110.2		134.2
Subtotal		2,324.3		2,420.7		1,156.6		1,456.8		2,613.3
Overseas
Asia (excluding China)		208.9		245.0		133.4		92.1		225.4
Oceania		90.8		77.4		53.3		15.7		69.0
Africa		166.6		138.0		36.9		100.0		136.9
North America (excluding Canada)		284.8		318.6		169.2		183.2		352.3
Canada		835.2		300.5		192.0		716.2		908.3
South America		1.6		1.5		1.3		78.4		79.7
Europe		103.8		81.8		84.6		4.6		89.2
Subtotal		1,691.7		1,162.7		670.7		1,190.1		1,860.8
Total		4,016.0		3,583.4		1,827.3		2,646.8		4,474.1
Equity method investees		299.5		294.2		226.2		140.5		366.7
Total with equity method investees		4,315.5		3,877.6		2,053.5		2,787.3		4,840.8

Proved Reserves

As of December 31, 2017, we had proved reserves of 4,840.8 million BOE, including 2,539.8 million barrels of crude oil, 785.9 million barrels of synthetic oil, 118.4 million barrels of Bitumen and 8250.1 bcf of natural gas, representing an increase of 963.2 million BOE as compared to proved reserves of 3,877.6 million BOE as of December 31, 2016.

The changes in our proved reserves mainly include:

· An increase of 881.5 million BOE due to revision of previous estimates, details of which are described below:

Ø Offshore China: an increase of 338.6 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 950.2 million BOE as of December 31, 2016 to 1,101.4 million BOE as of December 31, 2017, representing an increase of 318.5 million BOE (production in 2017 was 167.3 million BOE) or 73% of the total offshore China revision, such as Jinzhou 25-1, Suizhong 36-1 and Qinhuangdao 32-6, etc.;

Ø Overseas: an increase of 542.9 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;

Among them, the proved reserves in Canada increased from 300.5 million BOE as of December 31, 2016 to 908.3 million BOE as of December 31, 2017, representing an increase of 631.2 million BOE (production in 2017 was 23.4 million BOE) or 85% of the total overseas revision, such as re-booked oil sand assets in Long Lake and Hangingstone, shale gas in Horn River, etc.;

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· An increase of 470.4 million BOE due to new discoveries and extensions, details of which are described below:

Ø Offshore China: the discoveries and extensions of oil and gas reserves in the amount of 153.6 million BOE, which are primarily attributable to fields such as Kenli16-1, Wushi23-5, Wenchang9-3S, Liuhua29-1 and Lufeng14-8, etc.; and

Ø Overseas: the discoveries and extensions of oil and gas reserves in the amount of 316.9 million BOE, which are primarily attributable to Guyana, Brazil and onshore fields in the United States as well as K1C and KEN areas of re-booked Long Lake in Canada, etc.;

· An increase of 75.9 million BOE due to purchases, which are primarily attributable to Bridas and Caofeidian 11-6/12-1S assets;

· The production of 469.9 million BOE in 2017.

According to above, annual reserve replacement ratio and estimated reserve life were 305% (if excluding purchases, 289%; and if excluding purchases and re-booked reserves, 138%) and 10.3 years (if excluding purchases, 10.1 years; and if excluding purchases and re-booed reserves, 8.6 years) respectively.

Proved Undeveloped Reserves (PUD)

As of December 31, 2017, we had proved undeveloped reserves of 2,787.3 million BOE, including 1,224.8 million barrels of crude oil, 644.1 million barrels of synthetic oil, 72.1 million barrels of Bitumen and 5,042.5 bcf of natural gas, representing an increase of 800.2 million BOE as compared to proved undeveloped reserves of 1,987.1 million BOE as of December 31, 2016.

The changes in our proved undeveloped reserves mainly include:

· A decrease of 174.2 million BOE due to PUD converted to Proved Developed reserves (PD);

· An increase of 502.7 million BOE due to revision of previous estimates, details of which are described below:

Ø Offshore China: an increase of 74.1 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 PUD reserves in Bohai increased from 349.4 million BOE as of December 31, 2016 to 440.1 million BOE as of December 31, 2017, representing an increase of 90.7 million BOE or 103% of the total offshore China revision, such as Kenli 16-1 and re-booked Jinzhou 20-2N, Luda 5-2N, Kenli 9-1, etc.;

Ø Overseas: an increase of 428.6 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 PUD reserves in Canada increased from 144.8 million BOE as of December 31, 2016 to 716.2 million BOE as of December 31, 2017, representing an increase of 571.5 million BOE or 93% of the total overseas revision, such as re-booked oil sand assets in Long Lake and Hangingstone, etc.;

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· An increase of 440.2 million BOE due to new discoveries and extensions, details of which are described below:

Ø Offshore China: the discoveries and extensions of oil and gas reserves in the amount of 135.4 million BOE, which are primarily attributable to fields such as Kenli16-1, Wushi23-5, Wenchang9-3S, Liuhua29-1 and Lufeng14-8, etc.; and

Ø Overseas: the discoveries and extensions of oil and gas reserves in the amount of 304.8 million BOE which are primarily attributable to onshore fields in the United States, Guyana and Brazil as well as K1C and KEN areas of re-booked Long Lake in Canada, etc.;

· An increase of 29.6 million BOE due to purchases, which are primarily attributable to Bridas and Caofeidian 11-6/12-1S assets.

In 2017, we had in total 174.2 million BOE PUD reserves converted to PD and we spent approximately Rmb 32.8 billion on developing proved undeveloped reserves into proved developed reserves. Rmb 26.1 billion, or 80%, were spent on major development projects in Bohai, Eastern South China Sea, Western South China Sea in offshore China and Canada, Iraq, Nigeria, the United Kingdom and the U.S., etc. The remaining 20% was spent mainly on the infill drilling programs in offshore China, etc.

As of December 31, 2017, 191.8 million BOE of our proved undeveloped reserves were first booked before 2012. These proved undeveloped reserves were mainly located in East China Sea, Bohai and Western South China Sea, including (i) 7.7 million BOE in East China Sea, which are under construction; (ii) 6.9 million BOE in Bohai, including Qinhuangdao 33-1S oil field which is scheduled to come on stream in 2019; and (iii) 177.2 million BOE in Western South China Sea, including Wenchang 9-2/9-3/10-3 and Dongfang 13-2 gas fields which will be put on stream in 2018. The development of proved undeveloped reserves 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 the Company’s 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 disclosure 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 2015, 2016 and 2017, approximately 62%, 60%, and 65% 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 2017, 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 appendices to this document.

For Nexen-managed assets, all of the total net proved oil and gas reserves were evaluated by our internal reserve evaluation staff, which accounted for 29% of the company 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

27 

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 document. Approximately 35% net proved oil and gas reserves of the Domestic China and other overseas assets were estimated by these independent third party consulting firms and the remaining 36% of the Domestic China and other overseas assets were evaluated by our internal reserves evaluation staff.

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.

Besides engaging third parties to provide annual estimates and audits of our reserves, we also implement rigorous internal control systems that monitor the entire reserves estimation procedures and certain key metrics in order to ensure that the process and results of reserves estimates fully comply with the relevant SEC rules. As part of our efforts to improve the evaluation and oversight of our reserves, 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 30 years’ experience in the oil and gas industry.

Exploration, Development and Production

Summary

In offshore China, the Company engages 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 2017, approximately 54.0% of the Company’s net proved reserves and approximately 64.4% of its net production were derived from offshore China.

In its independent operations, the Company has been adding to its reserves and production mainly through independent exploration and development in offshore China. At the end of 2017, approximately 84.1% of the Company’s net proved reserves and approximately 76.0% of its net production in offshore China were derived from independent projects.

In its PSC operations, China National Offshore Oil Corporation (“CNOOC”), the Company’s controlling shareholder, has the exclusive right to explore and develop oil and natural gas in offshore China in cooperation with

28 

foreign partners through PSCs. CNOOC has transferred to the Company 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 the Company’s total assets. With its diversified portfolio of high-quality assets, the Company is an active participant in a number of world-class oil and gas projects and is regarded as a leading industry player. Currently, the Company holds interests in oil and natural gas blocks in Indonesia, Australia, Nigeria, Uganda, Argentina, the U.S., Canada, the United Kingdom, Brazil, Guyana and various other countries. As of the end of 2017, approximately 46.0% of the Company’s net proved reserves and approximately 35.6% of its net production were derived from overseas.

In 2017, the recovery of the global economy remained stable on the whole. The U.S. economy recovery momentum was strong. The Eurozone economy continued to improve, and emerging markets saw rapid overall economic growth. International oil prices surged upward following initial decline. The entire oil and gas industry as well as oil and gas companies still faced an uncertain operating environment.

In 2017, the Company persisted with the operating strategies it formulated at the beginning of the year, which include balancing short-term and mid-to-long term development; maintaining a prudent financial policy and improving capital efficiency; and optimizing the assets portfolio and focusing more on assets return.

In 2017, the Company achieved its production and business targets despite being faced with a variety of challenges. The Company managed to maintain appropriate exploration expenditures and carry out an intensive exploration program, and obtained successful results while continuing to control total capital expenditure. 19 new discoveries were made and 16 successful appraisals of oil and gas structures were achieved. Five new projects planned in early 2017 all came on stream. The production target was met with a net production volume of 470.2 million BOE. To ensure its continuing sustainable development, the Company pushed ahead steadily with the construction of new projects. All-in cost per BOE was US$32.54. The Company maintained a healthy financial position with a net profit of RMB24.7 billion for the year. Meanwhile, its performance in the areas of health, safety and environmental protection remained stable.

Looking forward to 2018, 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, the Company remains confident of its prospects. We will further strengthen our operating strategies, which mainly include steadily increasing the Company’s oil and gas reserve and production levels, continuing to reinforce 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, the Company’s capital expenditure is anticipated to reach RMB 70-80 billion. To maintain its competitive financial position, the Company will continue to stress efficiency, enhance investment return, strengthen cost controls and focusing on cash flow management. Our production target for 2018 is 470-480 million BOE, with five new projects to commence production. Meanwhile, the Company will maintain its high standards of health, safety and environmental protection.

Exploration

In 2017, the Company continued to reinforce the integration of exploration and development and enhance the ability of and shorten the cycle of reserve monetization. For offshore China, it further prioritized investment in mature areas while continuing to explore frontier areas. For overseas exploration, with its foothold on existing core projects, the Company sought to maintain a “rolling” pattern of development. It continued to maintain a reasonable proportion of exploration investment in total capital expenditure and to ensure mid-to-long term sustainable development with a relatively high level of exploration activity. In 2017, the reserve replacement ratio for the Company was 305%. Reserve life as the end of 2017 was back to over ten years.

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In offshore China, the Company’s exploration activities remained at a high level. A total 116 exploration wells were drilled, two of which were drilled through PSC. A total of 4,417 kilometers of 2D seismic data and 11,063 square kilometers of 3D seismic data were acquired independently and through PSC. The Company made 17 new discoveries and successfully appraised 14 oil and gas structures in offshore China. The success rate for independent exploration wells in offshore China was 48-61%.

In 2017, the Company continued to follow a value-driven exploration strategy in offshore China, resulting in outstanding achievement. Meanwhile, the Company intensified natural gas exploration and achieved breakthroughs in various fields. Notable achievements include:

Firstly, we effectively completed the appraisal of four mid-to-large size oilfields, including Bozhong 36-1, Kenli 6-4/5/6, Longkou 7-6 and Wushi 16-1 West/Wushi 23-5.

Secondly, key breakthroughs were achieved in deep formation natural gas exploration in Bohai. New discovery Bozhong 19-6 is expected to be the largest gas discovery in Bohai Basin in history.

Thirdly, breakthroughs were achieved in natural gas exploration with high temperature and ultra-high pressure in South China Sea, proving the exploration potential of Ledong 10 area in Yinggehai Basin.

Fourthly, new discoveries of Lufeng 14-8 and Lufeng 8-1 South were made in Pearl River Mouth Basin, significantly increased the reserve scale of Lufeng area.

Overseas, the Company drilled 12 exploration wells and acquired approximately 3,163 square kilometers of 3D seismic data. During its overseas explorations, the Company made two new discoveries and successfully appraised two oil and gas structures. Major achievements include the following:

Firstly, successive new discoveries were made in Stabroek block in Guyana, which became one of the Company’s most successful overseas exploration projects.

Secondly, Libra project in Brazil was successfully appraised, with reserve in line with expectation.

Thirdly, following the significant discovery of Owowo, the Preowei-3 well in Nigeria was successfully appraised, and reserve scale substantially increased.

In 2017, the Company focused on its overseas strategic layout and obtained new quality projects in Senegal and Brazil.

The Company’s major exploration activities in 2017 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	38	1	0	9	0	28	0	0	0	742	0
Eastern South China Sea	16	7	1	0	2	0	3	1	2,248	2,169	3,545	683
Western South China Sea	16	12	0	0	6	0	7	0	0	0	3,131	1,028
East China Sea	2	1	0	0	0	0	0	0	0	0	1,934	0
Subtotal	56	58	2	0	17	0	38	1	2,248	2,169	9,352	1,711
Overseas	0	0	5	7	0	2	0	6	0	0	0	3,163
Total	56	58	7	7	17	2	38	7	2,248	2,169	9,352	4,874

In 2018, the Company will continue to follow a value-driven exploration philosophy and target mid-to-large size oil and gas discoveries offshore China. It will make efforts on both oil and gas exploration and strengthen gas exploration activities. It will strengthen exploration in new areas to

30 

support the Company’s sustainable development. Overseas, the Company will focus on strategic core areas, actively obtain quality blocks, continue to target mid-to-large size discoveries, and expand reserve base.

Engineering Construction, Development and Production

In 2017, the Company successfully met its operational targets, with oil and gas production exceeding the target set early in the year. The Company carefully organized its operational resources and made smooth progress in engineering construction.

In 2017, while ensuring safety, the Company achieved its development and production targets for the year through consistently maintaining high operational efficiency, refined adjustment of liquid structures, optimizing water injection and lowering the decline of oilfields. The Company’s net oil and gas production reached 470.2 million BOE, fulfilling the production target of 450-460 million BOE set at the beginning of the year. The five new projects planned for 2017, namely Penglai 19-9 oilfield comprehensive adjustment, Enping 23-1 oilfields, Weizhou 12-2 oilfield phase II, BD gas field and the Hangingstone project, all came on stream during the year.

In 2017, the Company’s 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 in these areas included the following:

Firstly, we ensured base production level and laid solid foundation for future production profile of oilfields through refined management.

Secondly, we strictly controlled the operating cost of existing fields and encouraged conservation to improve efficiency, and further lowered the all-in cost per BOE.

Thirdly, we actively implemented infill drillings to contribute to production.

Fourthly, we strengthened technology-driven development, breaking technology bottlenecks, and promoted heavy oil thermal recovery in Bohai.

Looking forward to 2018, the workload of onshore construction and offshore installations will increase. A total of five new projects are expected to commence production, including Weizhou 6-13 oilfield, Penglai 19-3 oilfield 1/3/8/9 comprehensive adjustment project, Dongfang 13-2 gas fields and Wenchang 9-2/9-3/10-3 gas fields in offshore China, and Stampede oilfield of U.S. in the Gulf of Mexico. Among these, the Stampede oilfield commenced production in February 2018 and the Weizhou 6-13 oilfield commenced production in March 2018. It is expected that more than 20 new projects will be under construction in 2018, supporting the Company’s future sustainable growth.

In 2018, the Company will promote the construction of key projects, optimize development plans of producing fields, strengthen comprehensive management and lower the decline of reserve to ensure base production level. It will arrange infill drillings based on economic evaluation and increase the contribution to production. Meanwhile, it will continue to intensify quality and efficiency enhancement and consolidate its cost competitiveness.

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Regional Overview

Offshore China

Bohai

Bohai is the most important crude oil producing area for the Company. The crude oil produced in this region is mainly heavy oil. As of the end of 2017, the reserve and daily production volume in Bohai were 1,101.4 million BOE and 458,473 BOE/day, respectively, representing approximately 22.8% of the Company’s total reserves and 35.6% of its daily production. The operational area in Bohai is mainly shallow water with a depth of 10 to 30 meters.

Bohai has rich oil and gas resources and has been one of the Company’s primary areas for exploration and development. In 2017, the Company made nine successful discoveries in Bohai, namely Bozhong 19-6, Bozhong 29-6, Bozhong 29-6 South, Bozhong 13-1 South, Penglai 19-1, Bozhong 29-1 East, Bozhong 26-3 West, Kenli 3-2 South and Kenli 4-1. The Company also successfully appraised eight oil and gas structures, including Bozhong 36-1/36-2, Bozhong 19-6, Bozhong 29-6 South, Bozhong 26-3, Longkou 7-6, Kenli 6-4/6-5, Bozhong 29-1 and Luda 27-2 South. Among these, three mid- to-large size oilfields, namely Bozhong 36-1, Kenli 6-4/5/6 and Longkou 7-6, were successfully appraised, laying reserve foundations for the sustainable development of Bohai. The newly discovered Bozhong 19-6 marks a significant breakthrough in the natural gas exploration in deep formation in Bohai. The rolling exploration in Bohai also made some remarkable achievements.

These new discoveries and successful appraisals further demonstrated Bohai’s potential as a core production region for the Company.

For development and production, Penglai 19-9 comprehensive adjustment project commenced production during the year. Penglai 19-3 oilfield 1/3/8/9 comprehensive adjustment project is expected to commence production in 2018. Currently a number of new projects are under construction, including Luda 16-3 oilfield, Caofeidian 6-4 oilfield and Qinhuangdao 33-1 South oilfield.

Western South China Sea

Western South China Sea is one of the Company’s most important natural gas production areas. Currently, the typical water depth of the Company’s operational area in the region ranges from 40 to 120 meters. As of the end of 2017, the reserves and daily production volume in Western South China Sea reached 844.1 million BOE and 142,870 BOE/day, respectively, representing approximately 17.4% of the Company’s total reserves and 11.1% of its daily production.

In 2017, the Company made six successful discoveries in Western South China Sea, namely Weizhou 11-2 East, Weizhou 11-12, Wenchang 9-3 South, Wenchang 19-9, Wushi 22-8, Wushi 23-5/23-5 South. Four successful appraisals were made, namely Weizhou 11-12, Wushi 16-1 West, Wushi 22-8, Wushi 23-5/23-5 South. Among these, the mid-to-large size oil and gas fields Wushi 16-1 West and Wushi 23-5 were successfully appraised, which will greatly promote the Phase II development of Wushi oilfields. Breakthroughs were made in high temperature and ultra-high pressure natural gas exploration, which proved the exploration potential of Ledong 10 area in Yinggehai Basin. The concept of integrated exploration and development was further developed in the Weixinan oilfields and many new discoveries were obtained.

For development and production, Weizhou 12-2 oilfield Phase II commenced production during the year. Weizhou 6-13 oilfield commenced production in March 2018. Dongfang 13-2 gas fields and Wenchang 9-2/9-3/10-3 gas fields are planned to commence production in 2018. Wenchang 13-2 comprehensive adjustment and other new projects are under construction.

32 

Eastern South China Sea

Eastern South China Sea is the Company’s another important crude oil producing area. Currently, the typical water depth of the Company’s operational area in the region ranges from 100 to 300 meters. The crude oil produced is mostly of light to medium gravity. As of the end of 2017, reserves and daily production volume in Eastern South China Sea reached 533.7 million BOE and 212,895 BOE/day, respectively, representing approximately 11.0% of the Company’s total reserves and 16.5% of its daily production.

In 2017, new discoveries of Lufeng 14-8 and Lufeng 8-1 South were made in Pearl River Mouth basin, significantly increased the reserve scale of Lufeng area. Two oil and gas structures, namely Lufeng 8-1 and Lufeng 14-8, were successfully appraised.

For development and production, Enping 23-1 oilfields commenced production during the year. Currently, Huizhou 32-5 comprehensive adjustment and other new projects are under construction.

East China Sea

The typical water depth of the Company’s operational area in the East China Sea region is approximately 90 meters. As of the end of 2017, reserves and daily production volume in the region represented approximately 2.8% and 1.0% of the Company’s total reserves and daily production, respectively

Others

In 2017, integrated model of “exploration, development, production and sale” was successfully implemented in 8/9 Area of Shanxi Linxing Block. Drilling, testing, construction and startup of tight gas project was completed within the same year and achieved first production.

Overseas

Asia (excluding China)

Asia (excluding China) was the first overseas region entered into by the Company, and it has become one of its major overseas oil and gas producing areas. Currently, the Company holds oil and gas assets mainly in Indonesia and Iraq. As of the end of 2017, reserves and daily production volume derived from Asia (excluding China) reached 225.4 million BOE and 82,958 BOE/day, respectively, representing approximately 4.7% of the Company’s total reserves and 6.4% of its daily production.

Indonesia

At the end of 2017, the Company’s asset portfolio in Indonesia consisted of four development and production blocks. Among these, the Company acted as the operator for the Southeast Sumatra block, the Madura Strait PSC was a joint operation block, in which the BD gas field commenced production in 2017, and other gas fields were under appraisal and construction. The Company, as a non-operator, also holds working interests in the production sharing contracts of Malacca PSC.

The Company owns an interest of approximately 13.90% in the Tangguh LNG Project in Indonesia. In 2017, production volume of Phase I of the Project remained stable. 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.

Iraq

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

In 2017, the Company continuously drilled development wells and adopted production enhancement measures of Missian project, resulting in a steady increase in daily net production to approximately 42,000 barrels per day.

Oceania

Currently, the Company’s oil and gas assets in Oceania are mainly located in Australia and Papua New Guinea. As of the end of 2017, reserves and daily production volume derived from Oceania reached 69.0 million BOE and 22,598 BOE/day, respectively, representing approximately 1.4% of the Company’s total reserves and 1.8% of its daily production.

Australia

The Company owns 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 2017, the North West Shelf LNG Project generated stable production and achieved favorable economic returns.

The Company also owns one exploration block in Australia which is currently under appraisal.

Other Regions in Oceania

The Company owns interests in four blocks which are still under exploration in Papua New Guinea.

Africa

Africa is a relatively large oil and gas reserve and production base for the Company. The Company’s assets in Africa are primarily located in Nigeria and Uganda. As of the end of 2017, reserves and daily production volume in Africa reached 136.9 million BOE and 73,625 BOE/day, respectively, representing approximately 2.8% of the Company’s total reserves and 5.7% of its daily production.

Nigeria

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

In 2017, the Akpo oilfield maintained stable production, with net production reaching approximately 56,000 barrels per day. The Egina project is in the engineering construction stage. During the year, the Preowei-3 well was successfully appraised.

The Company also holds 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 respectively.

We will continue to utilize the synergy of Usan and OML130 projects to establish an oil and gas production base in west Africa.

Uganda

34 

The Company owns 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 Africa.

In 2017, the Company, as the operator of EA 3A, completed the front end engineering design (FEED) for ground construction and drilling.

In 2017, development and production licenses for eight oilfields in the EA1 and EA2 blocks were issued by the government and the FEED initiated. The intergovernmental agreement (IGA) for an oil pipeline was signed and the FEED was completed.

Other Regions in Africa

Apart from Nigeria and Uganda, the Company owns interests in several blocks in the Republic of the Congo, Algeria and the Gabonese Republic. In 2017, the Company also obtained a 65% operating interest in AGC Profond block in offshore Senegal and Guinea-Bissau.

North America

North America has become the Company’s largest overseas reserves and production region. The Company holds 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 2017, the Company’s reserves and daily production volume in North America reached 1,260.6 million BOE and 132,675 BOE/day, respectively, representing approximately 26.0% of the Company’s total reserves and 10.3% of its daily production.

The U.S.

The Company currently holds an average of 27% and 12% interests in the Eagle Ford and Niobrara shale oil and gas projects in the U.S. respectively.

In 2017, net production of the Eagle Ford project remained stable and averaged 53,000 BOE/day.

Additionally, the Company owns interests in two major deepwater development projects, Stampede and Appomattox, and a number of other exploration blocks in the US Gulf of Mexico through its wholly-owned subsidiary, Nexen Energy ULC (“Nexen”). Among these, Stampede commenced production in February 2018.

Canada

Canada is one of the world’s richest place of oil sands resources, and participation in the country’s oil sands development will make a major contribution to the Company’s sustainable growth. Through its Nexen subsidiary, the Company owns a 100% working interest in the oil sands project located at Long Lake, as well as three other oil sands leases in the Athabasca region of northeastern Alberta. In 2017, the production of Long Lake project ramp up to approximately 40,000 BOE/day.

The Company holds a 25% interest in the Hangingstone oil sands project. The project commenced production in 2017. We also hold a 7.23% interest in the Syncrude project and non-operating interests in several other exploration and development leases.

The Company holds a 100% interest in two exploration blocks in offshore Newfoundland.

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

35 

Other Regions in North America

The Company owns 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 yielded stable production and achieved favorable economic returns. The Company also owns 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, the Company’s major holdings consist of a 50% interest in the Bridas Corporation (“Bridas”) and a 10% interest in the PSC for the Libra oilfield in Brazil. The Company’s 50% interest in Bridas is accounted for by equity methods. As of the end of 2017, the Company’s reserves and daily production volume derived from South America reached 444.8 million BOE and 46,770 BOE/day, respectively, representing approximately 9.2% of the Company’s total reserves and 3.6% of its daily production.

Argentina

The Company holds a 50% interest in Bridas and makes joint management decisions. Bridas holds a 40% interest in Pan American Energy (“PAE”) in Argentina and a 100% interest in AXION Refinery. In December 2017, Bridas exchanged the 10% interest in PAE held by BP with the 50% interest in AXION. After the settlement of the upstream and downstream asset swap, Bridas holds 50% interest in PAE and AXION respectively.

Under the low oil price environment in 2017, the Company sought to strike a balance between production and return, enhanced its operating efficiency, optimized operating plans and created innovative development plans. Daily net production for Bridas averaged approximately 46,000 BOE/day.

Brazil

The Company holds 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.

Ten appraisal wells have been drilled as of the end of 2017 under the Libra project. In November 2017, the Libra Consortium declared the commerciality of the northwest area and named it as the Mero field, which includes 4 production units of Mero 1, Mero 2, Mero 3 and Mero 4. Extended well test has been implemented to test Mero 2 and Mero 3 and started production. Final Investment Decision (FID) of Mero 1 has been approved and it has entered the construction phase.

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

The Company additionally holds a 100% interest in the 592 block and a 20% interest in the ACF Oeste block.

Guyana

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The Company holds a 25% interest in Stabroek block in offshore Guyana. Seven exploration discoveries have been made in the block. In 2017, the Liza and Payara reservoirs were successfully appraised and two new discoveries, namely Snoek and Turbot, were obtained, which further confirmed the reserve scale. FID was approved for Liza oilfield Phase I and production is planned to commence in 2020.

Other Regions in South America

The Company also holds interests in several exploration and production blocks in Colombia.

Europe

The Company holds interests in several oil and gas fields such as Buzzard and Golden Eagle in the North Sea. As of the end of 2017, the Company’s reserves and daily production volume derived from Europe reached 89.2 million BOE and 100,046 BOE/day, respectively, representing approximately 1.8% of the Company’s total reserves and 7.8% of its daily production.

United Kingdom

The Company’s asset portfolio in the North Sea includes projects under production, development and exploration, mainly including: 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 the Company the largest crude oil operator in the North Sea.

The United Kingdom is one of the Company’s key overseas development areas, with key projects such as Buzzard and Golden Eagle substantially contributing to the Company’s production. In 2017, the Buzzard oilfield’s net production averaged approximately 63,000 barrels per day. We will continue to intensify our oil and gas development efforts in the UK, and actively seek out exploration and development blocks with potential in order to achieve stable and sustainable development in the region.

Other Regions in Europe

The Company holds a licence issued by the government of Iceland for undertaking oil exploration operations in the Norwegian Sea, northeast Iceland. In addition, the Company holds several frontier exploration licenses 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 2015, 2016 and 2017.

	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)
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		—		—		—

37 

2015
Offshore China
Bohai	500,719	477,904	136.9	—	—	—
Western South China Sea	143,676	89,958	314.3	—	—	—
Eastern South China Sea	229,679	190,525	234.9	—	—	—
East China Sea	10,271	2,632	45.8	—	—	—
Subtotal	884,346	761,019	731.9	53.05	8,175	7.64
Overseas
Asia (excluding China)	70,987	45,640	140.0	46.82	7,615	15.19
Oceania	21,673	3,350	93.5	53.40	3,166	8.19
Africa	83,677	83,677	—	51.01	—	6.42
North America (excluding Canada)	76,915	54,692	134.6	34.92	272	5.74
Canada	58,115	46,712	68.4	45.14	1,704	30.96
South America	1,110	1,110	—	40.81	—	10.73
Europe	110,842	103,258	45.5	51.61	5,843	10.62
Subtotal	423,319	338,440	482.1	47.21	3,704	12.38
Total	1,307,664	1,099,459	1,214.0	51.27	6,395	9.18
Equity method investees	50,357	24,588	149.6	—	—	—

Drilling and Other Exploratory and Development Activities

The following table sets forth our net exploratory wells and development wells drilled in the years of 2015, 2016 and 2017.

	Net Exploratory Wells Drilled						Net Development Wells Drilled
	Total		Productive		Dry		Total		Productive		Dry
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		0		3		0		0		—
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		—
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		—

38 

2015
Offshore China
Independent
Bohai	50	35	15	129	129	—
Western South China Sea	31	12	19	32	32	—
Eastern South China Sea	27	4	23	40	39	—
East China Sea	6	4	2	—	—	—
Subtotal	114	55	59	201	200	—
PSCs
Bohai	3	—	3	40.0	40.0	—
Western South China Sea	3	—	3	0.6	0.6	—
Eastern South China Sea	1	—	1	3.0	3.0	—
East China Sea	2	—	2	4.0	4.0	—
Subtotal	9	—	9	47.6	47.6	—
Overseas
Asia (excluding China)	—	—	—	20.4	20.4	—
Oceania	—	—	—	—	—	—
Africa	1.2	1.2	—	5.9	5.9	—
North America	0.5	—	0.5	174.4	174.4	—
South America	0.6	0.6	—	0.4	0.4	—
Europe	0.7	—	0.7	4	3	1
Subtotal	2.9	1.7	1.1	205.1	204.1	1

Present Activities

The following tables set forth our present activities as of December 31, 2017.

	Wells Being Drilled				Waterfloods Being Installed
	Gross		Net		Gross		Net
Offshore China
Bohai		2		2		758		686.9
Western South China Sea		8		8		38		38
Eastern South China Sea		2		2		—		—
East China Sea		0		0		—		—
Subtotal		12		12		796		724.9
Overseas
Asia (excluding China)		9		7.7		4		4
Oceania		—		—		—		—
Africa		0		0		2		0.9
North America		78		16.4		2		0.5
South America		—		—		25		5
Europe		—		—		—		—
Subtotal		87		24.1		33		10.4

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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, 2017.

	Productive Wells								Developed Acreage (km2)				Undeveloped Acreage (km2)
	Crude and Liquids				Natural Gas
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Offshore China
Bohai		2,150		1,871.7		27		27		2,636		2,636		43,068		43,068
Western South China Sea		327		319.2		89		84.5		1,941		1,941		73,388		73,388
Eastern South China Sea		435		390.2		39		34.1		2,652		2,652		55,424		55,424
East China Sea		21		10.5		72		36.1		85		85		85,413		85,413
Subtotal		2,933		2,591.5		227		181.7		7,314		7,314		257,292		257,292
Overseas		—		—		—		—		—		—		—		—
Asia (excluding China)		571		539.5		31		25		1,566		1204		14,334		5,670
Africa		45		14.8		—		—		909		358		25,587		9,016
Oceania		—		—		66		3		3,240		172		41,766		25,140
North America		3,013		847.1		415		144		3,023		797		8,257		7,276
South America		4,706		929.4		496		99		2,505		500		29,503		7,860
Europe		74		32.4		1		0.4		359		154		18,993		13,285
Subtotal		8,409.3		2,363.2		1,008.7		271.4		11,602		3,185		138,440		68,247
Total		11,342.3		4,954.7		1,235.7		453.1		18,916		10,499		395,732		325,539

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 2017, the annual sales from our largest gas contract contributed to only approximately 4.7% of our total oil and gas sales and the total revenues from gas sales accounted for approximately 8.9% of our total revenues in 2017. Moreover, the total gas quantities that are subject to delivery commitments under existing contracts or agreements are not significant to the Company. Therefore, we believe that we did not have any material delivery commitment as of the end of 2017.

Sales and Marketing

Sales of Crude Oil

The Company sells crude oil produced in offshore China to the PRC market mainly through CNOOC China Limited,its wholly-owned subsidiary. The Company sells crude oil produced overseas to international and domestic markets mainly through another wholly-owned subsidiary, China Offshore Oil (Singapore) International Pte Ltd. Nexen Energy ULC, a wholly-owned subsidiary of the Company, sells its crude oil and synthetic oil to international markets separately.

The Company’s 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 pay by Renminbi. The Company currently sells three types of crude oil in China: heavy crude, medium crude and light crude.

Beginning in 2017, the benchmark price for crude oil is Dated Brent. The Company’s major customers in China are Sinopec, PetroChina and CNOOC. Crude oil produced overseas and sold on international markets is benchmarked at the Brent and WTI prices. In 2017, as a result of the increase in international oil prices, the Company’s realized oil prices picked up. In 2017, the Company’s average realized oil price was US$52.65/barrel, representing a year-on-year increase of 27.2%.

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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,
	2015		2016		2017
Sales and Marketing Volumes (mmbbls)(1)
Light Crude		22.9		20.8		26.3
Medium Crude		162.4		162.6		147.4
Heavy Crude		138.2		122.4		112.3

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

Sales of Natural Gas

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

Sales of LNG sourced by the Company 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 LNG Terminals in Dapeng, Guangdong and Putian, Fujian, China.

In 2017, stable and positive economic performance in China, the impact from the clean winter heating policy in northern China, as well as the policy of changing fuel from coal to gas, resulted in natural gas demand growth in China, which drove sales volume growth of high-priced natural gas. In addition, based on market condition, the Company gradually adjusted sale prices for natural gas users in certain areas through negotiation. In 2017, the Company’s average realized natural gas price was US$5.84/mcf, representing a 7.0% 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,
	2015		2016		2017
Average Realized Prices
Crude and Liquids (US$/bbl)		51.27		41.40		52.65
Natural Gas (US$/mcf)		6.39		5.46		5.84
West Texas Intermediate (US$/bbl)		48.68		43.35		50.80

The international benchmark crude oil price, West Texas Intermediate, was US$60.46 per barrel as of December 29, 2017 and US$ 64.94 per barrel as of March 29, 2018.

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

	Year ended December 31,
	2015			2016			2017
	(Rmb in millions, except percentages)
Revenues sourced in the PRC		124,427			102,861			121,740
Revenues sourced outside the PRC		47,010			43,629			64,650
Total revenues		171,437			146,490			186,390
% of revenues sourced outside the PRC		27.4	%		29.8	%		34.7	%

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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 2017, the Company continued to implement its “technology-driven” strategy, focused on strengthening the management of key research and development projects, continued to improve its systems and mechanisms of technological innovation, and promoted construction of research and development platform. It continued to implement systems for research collaboration and strengthened joint project developments of core technologies of different research institutes of the Company. The Company actively carried out the “Quality and Efficiency Year 4.0” program. Through technological innovation, the Company was able to establish a solid foundation for reserve and production growth. A series of research findings have been applied to increase production efficiency.

Major Scientific and Technological Project Development

In 2017, the Company focused on core business needs and continued to carry out critical core technological projects such as deepwater oil and gas fields, offshore heavy oil fields and fields with low porosity and permeability. It made a number of technological achievements including fracture system and hydrocarbon accumulation control research in the western Bohai, and key technologies for oil and gas geology and exploration in the deepwater areas in the epicontinental region of the Pearl River Mouth Basin. These notable developments have provided vital technical support for the sustainable development of the Company.

Construction of Scientific and Technological Innovative System

The Company established platforms for research and development which include an offshore low-permeability reservoir exploration and development laboratory and an unconventional oil and gas exploration and development laboratory. The “Key technologies in drilling and completion of wells in South China Sea under high temperature and high pressure and their industrial application” project won first prize at the National Science and Technology Progress Awards. The Company also led the drafting of “ISO18647, Petroleum and Natural Gas Industries – Modular Drilling Rigs for Offshore Fixed Platforms, an International Standard”, which has since been formally published.

Health, Safety and Environmental Protection (“HSE”)

As always, the Company takes safety as top priority in its works. “Safety and environmental protection come first, people oriented and well-equipped facilities” have been regarded as the core values of health, safety and environmental protection (HSE). The Company constantly improves the systematic management of HSE work and nourishes a safety culture with characteristics of the Company, striving to provide a safe working environment for the Company and contractors and establishing first class management capability in safe production.

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In 2017, as the Company continued to improve its HSE internal control system, it adjusted the HSE management of its construction projects in accordance with new government regulatory requirements. It continued to supervise and encourage the implementation of various management requirements by adopting management audits and reviews to control HSE risks. The Company successively organized management audits to Nexen UK and the Shenzhen and Zhanjiang branches, completed special audits on high-risk contractors in relation to diving and helicopters, organized a three-month safety production inspection, and urged the prompt rectification to the problems identified.

The Company improved its safety performance, actively conducted international benchmarking, and built a HSE management system framework which is in line with international principles of industry risk management and continuous improvement and with distinct characteristics of CNOOC Limited. As the first PRC member of the Oil Companies International Marine Forum (OCIMF), the Company actively participated marine safety management activities organized by OCIMF, developed the Maritime Safety Management Measures, launched a marine management information system, and strove to improve its marine safety management and control abilities.

The Company continued to improve its implementation of safety management. It organized a series of activities with the theme of “Last centimeter for safety management”, fostered the development of a safety culture. Mr. Hua Yang, Chairman of the Company, wrote a letter titled “YOUR SAFETY, WE CARE” to employees. The Company’s management recorded a promotional video talking about safety, and taught safety classes in order to strengthen safety leadership. Employees at base-level units actively participated in HSE knowledge quiz, essay competition and safety video making.

In China, the Company further extended its safety management risk control to front-line operation by organizing examinations on working permit to ensure that all operations are under control and effectively avoid operational risks. On drilling rigs, it vigorously rectified security risks and conducted special inspections to identify the risks relating to high falling objects and falls from height. These measures generally improved the safety management of drilling rigs.

In Overseas, the Company continued to strengthen HSE supervision and management functions for its overseas operations. It improved the safety leadership of overseas management as well as their ability to set a good example through their own conduct, arranged HSE audits of its project companies in the United Kingdom and Indonesia, and organized joint emergency drills, publicity and training aimed at improving the safety culture among employees. All these initiatives significantly contributed to a strong overseas HSE performance.

The Company kept a close eye on the impacts of international political and social changes on its overseas operations. By combining its overseas safety management and good industry practices, the Company established and improved its overseas security management mechanism and information collection channel, further clarified its requirements for security management of overseas projects, obtained the security updates of overseas staff in a timely manner, and provided strong support of the security of its overseas operations.

In 2017, the Company acted in compliance with the climate compact advocated by the Paris Agreement. With the objective of reducing carbon emissions and energy consumption, the Company continued to push for cost reductions and efficiency improvement campaign, organized carbon investigation on domestic units, improved its carbon emissions management rules and systems, actively participated in the establishment of national low carbon-emission standards, and conducted assessments of the impact of carbon emissions on fixed assets investment projects.

During 2017, the Company maintained its good performance in safety management and upheld consistently high HSE standards. OSHA (Occupation Safety and Health Administration) statistics for the year are shown below.

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	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		41		12		0.06		6		0.03		0
Staff of the Company and direct contractors		109		48		0.08		17		0.03		2

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.

The Company further strengthened safety in production, intensifying its efforts to identify and eliminate potential risks, giving special attention to preventing operational accidents in key and high-risk areas. It also improved the implementation of safety standards and deepened safety awareness across all levels of the organization. In 2017, the Company completed full system safety inspections, including the special supervision of safety production, a special safety check on storage tank fields and a year-end major check on safety production. For HSE risks in particular operating units, the Company organized special examinations. Through examinations and inspections, the Company effectively met CNOOC Limited’s 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, the Company implemented risk-level-based management of offshore production facilities in accordance with relevant laws and regulations. It also promoted the construction of risk-level-based management information systems in downstream enterprises and established and improved risk monitoring indicators, including well-control event monitoring, major operation risk monitoring in engineering constructions, etc. Moreover, it established a list of post responsibilities, improved the site tour inspection system, and improved onsite safety production capabilities.

Based on hazard identification and risk analysis, the Company continued to improve its emergency management mechanisms. In 2017, the Company further refined the crisis management plan, integrated emergency management information systems, developed a mobile application for emergency management, improved the ICS system, and strengthened emergency drills to improve the system’s risk resistance and reduce the effect of emergencies to the greatest extent possible.

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, 2017, 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,

44 

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 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—Risks Relating to Our Operations—Extreme weather conditions may have a material adverse impact on us and could result in losses that are not covered by insurance.”

We have maintained varied insurance policies for our domestic assets and operational insurance policies and construction insurance policies, with different policy limits and deductibles. We also purchase operator’s extra-expense 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 operation and assets, we are insured for amounts up to the replacement cost value of our assets for property damage and up to US$525 in 2017 million 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 billion in 2017. 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 eight cities in the PRC, namely Suizhong, Tanggu, Longkou, Huizhou, Shenzhen, Zhuhai, Weizhou and Gaolan. 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 would 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, Sinopec and PetroChina 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 in 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.

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.

45 

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,
	2015				2016				2017
	Rmb in millions		%		Rmb in millions		%		Rmb in millions		%
Exploration and production		149,582		87.3		125,611		85.7		157,166		84.3
Trading businesses		21,438		12.5		20,310		13.9		28,881		15.5
Corporate and elimination		417		0.2		569		0.4		343		0.2
Total operating revenues		171,437		100.0		146,490		100.0		186,390		100.0

We are mainly engaged in the exploration, development, production and sales of crude oil and natural gas primarily in offshore China. For the year ended December 31, 2017, approximately 65.3% of our total revenue was sourced in the PRC. Our overseas activities are mainly conducted in Canada, the United States of America, United Kingdom, Nigeria, Argentina, Indonesia, Uganda, Iraq, Brazil and Australia, etc.

Regulatory Framework in the PRC

Government Control

All of China’s petroleum resources are owned by the PRC state. The PRC government 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 State Oceanic Administration, the National Development and Reform Commission and 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.

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.

46 

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 income 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 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. CNOOC Deepwater Development Limited is subject to corporate income tax at the rate of 15% for the three years ending December 31, 2017, after being assessed as a high and new technology enterprise. The Company is in the process of re-applying to be assessed as a high and new technology enterprise from 2018 to 2020.

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;

· VAT at the rates from 13% to 17% on taxable sales under independent oil and gas fields since May 1, 2016 under “Provisional Regulations on VAT of the PRC” and relevant detailed rules according to the “Circular on Certain Policies on the Pilot Program of the Collection of Value-added Tax in Lieu of Business Tax” (Cai Shui [2016] No.39), which replaced the production tax at the rate of 5% on production under independent oil and gas fields before May 1, 2016. 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 13% VAT rate shall be removed and gas sales shall be subject to the 11% tax rate;

· VAT at the rates from 3% to 17% on other income since May 1, 2016, which were subject to the business tax at rates from 3% to 5% or VAT at the rates from 3% to 17% before May 1, 2016.

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

47 

· Resource tax (reduced tax rates may apply to specific products and fields) on the oil and gas sales revenue (excluding production tax) derived from oil and gas fields under production sharing contracts signed after November 1, 2011 and independent offshore oil and gas fields starting from November 1, 2011, which replaced the royalties for 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. The resource tax rate was changed from 5% to 6% since December 1, 2014;

· 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, business tax and VAT paid;

· Educational surcharge at the rate of 3% on the production tax, business tax and VAT paid; and

· Local educational surcharge at the rate of 2% on the production tax, business 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, 2015, 2016 and 2017, we had Rmb 1,948 million, Rmb 19,174 million and Rmb 22,206 million (US$3,413 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 2 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 any income derived from sales of locally produced crude oil by an oil exploration and production company at a price that exceeds 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 has 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 quarterly basis. For the years ended December 31, 2015, 2016 and 2017 we incurred approximately Rmb 59 million, nil and Rmb 55 million for the Special Oil Gain Levy.

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 going forward.

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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 approved by 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 when the relevant PRC regulatory authorities have approved the overall development program 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) 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.

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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.

Management and Operator. A party will be designated as the operator to undertake the execution of the petroleum operations which includes 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.

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After the foreign partner has fully recovered its exploration and development costs under PSCs in which the foreign partner is the operator, we have the right to take over the operation of the particular oil or gas field. With the consent of the foreign partner, we may also take over the operation before the foreign partner has fully recovered its 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 and certain other countries. See “Item 4—Information on the Company—Business 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 the 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 U.S., Canada, United Kingdom, Argentina and certain other countries, we conduct our operations through exploration and production permits, licenses or leases. We, as one of 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 occurs, 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 & 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.

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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 State Oceanic Administration 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 State Oceanic Administration and/or relevant environmental protection agencies generally issues 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 shall pay environmental protection tax in accordance with the provisions of such law.State Oceanic Administration 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, 2015, 2016 and 2017 of approximately Rmb 50,063 million, Rmb 50,888 million and Rmb 54,073 million (US$8,311 million), respectively.

According to the Notice of the National Development and Reform Commission, National Energy Administration, Ministry of Finance, State Administration of Taxation, and 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 shall 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 shall 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 stricter regulations which would require additional environmental protection expenditures.

We are also subject to the environmental rules introduced by governments in whose jurisdictions our logistical support facilities are located.

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

Patents and Trademarks

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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

During the years ended December 31, 2015, 2016 and 2017, we employed 20,585 persons, 19,718 persons and 19,030 persons, respectively. Of the 19,030 employees we employed as of December 31, 2017, approximately 82.7% were involved in oil exploration, development and production activities, approximately 5.5% were involved in accounting and finance work and the remainder were senior management and others. Part 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, assists in the fulfillment of economic objectives, 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 relations with our employees are good.

The total remuneration of employees 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 United States government’s Occupational Safety & Health Administration guidelines.

All full-time employees in the PRC are covered by a government-regulated pension and are entitled to an annual pension at their retirement dates. The PRC government is responsible for the pension liabilities to these retired employees under this government pension plan. The actual pension payable to each retiree is subject to a formula based on the status of the individual pension account, general salary and inflation movements. We are required to make monthly contributions to the government pension plan at rates ranging from 15% to 20% of our employees’ salaries, with each employee contributing 8% of his or her salary for retirement. The contributions vary from region to region.

We are required to make monthly contributions to the government pension plan at rates ranging from 15% to 20% of our employees’ salaries, with each employee contributing 8% of his or her salary for retirement. The contributions vary from region to region.

For further details regarding retirement benefits, see note 29 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 2017, we held 40 core training workshops, which were attended by approximately 1,680 person-times of participants. To ensure smooth implementation of our overseas strategy, we have established an international human resources 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 31, 2018. 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.

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The following chart sets forth our controlling entities and our directly wholly-owned subsidiaries as of March 31, 2018 and notes our significant indirectly-held subsidiaries.

________

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

(2) Owner of our overseas interests in oil 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, Nexen Energy ULC, Nexen Petroleum U.K. Limited, Nexen Petroleum Nigeria Limited, OOGC America LLC, Nexen Petroleum Offshore U.S.A. Inc., 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 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 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

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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 has increased over the past few years.

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.

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, lower crude oil and natural gas prices may reduce the amount of crude oil and natural gas we can produce economically and render 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 the Company’s projection, the Company’s oil and gas properties may face the risk of impairment. If oil and natural prices did not rise to the prices used in the Company’s 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 the liquidity, capital resources and operating results of the Company. In particular, the Company believes that it has adequate resources of short- and long-term funding because (i) the Company has sufficient cash and cash equivalents, readily realizable financial assets and time deposits on hand, and (ii) the Company also enjoys 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,
	2015		2016		2017
Average net realized prices:
Crude oil (US$ per bbl)		51.27		41.40		52.65
Natural gas (US$ per mcf)		6.39		5.46		5.84

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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,
	2015		2016		2017
Net production of crude oil (bbl/day)(1)		1,124,047		1,083,101		1,064,986
Net production of natural gas (mmcf/day)(1)		1,363.6		1,276.2		1,300.6

(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.”

Critical Accounting Policies

We prepare our consolidated financial statements in accordance with IFRS issued by the IASB and HKFRS 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

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

Pursuant to the oil and gas reserve estimation requirements under US SEC rules, the Company uses 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 its 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 its 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 the Company’s 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, the Company believes that the

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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.

Business Combinations and Goodwill

Business combinations 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 the Company, liabilities assumed by the Company to the former owners of the acquiree and the equity interests issued by the Company in exchange for control of the acquiree. For each business combination, the Company elects whether it measures 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 consideration transferred, the amount recognised for non-controlling interests and any fair value of the Company’s previously held equity interests in the acquiree over the identifiable net assets acquired and liabilities assumed. If the sum of this consideration and other items is lower than the fair value of the net assets of the subsidiary acquired, the difference is recognised in profit or loss as a gain on bargain purchase.

Joint Arrangements

Certain of the Company’s 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 the Company 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 the Company’s 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.

The Company’s investments in joint ventures are stated in the consolidated statement of financial position at the Company’s 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.

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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.

Deferred Tax

Deferred tax is provided, using the 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

We recognize revenue when it is probable that the economic benefits will flow to us and when the revenue can be measured reliably. For oil and gas sales, our revenues represent the invoiced value of sales of oil and gas attributable to our interests, net of royalties and obligations to governments and other mineral interest owners. We have adopted a net basis of reporting for royalties and government share oil when we have no legal rights to the underlying reserves. As such, we act as an agent for the relevant governments or royalty holders when we sell the portion of oil and gas on their behalves. Sales are recognized when the significant risks and rewards of ownership of oil and gas have been transferred to customers. Oil and gas lifted and sold by us above or below our participating interests in any PSC result in overlifts and underlifts. We record these transactions in accordance with the entitlement method under which overlifts are recorded as liabilities and underlifts are recorded as assets at year-end oil prices. Settlement will be in kind or in cash when the liftings are equalized or in cash when production ceases. We enter 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 buyer to pay for minimum quantities, whether or not it takes delivery. These commitments contain protective provisions, such as force majeure provision, and adjustment provisions. If a buyer has a right to get a “make up” delivery at a later date, revenue recognition is deferred. 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 from the foreign partners under our PSCs and revenues from the trading of oil and gas through our subsidiaries. The cost of the oil and gas sold is included in crude oil and product purchases.

59 

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:

	Year ended December 31,
	2015				2016				2017
	(Rmb in millions, except percentages and production data )
Revenues:
Oil and gas sales:
Crude oil		128,929	75.2	%		106,448	72.7	%		135,256	72.6	%
Natural gas		17,668	10.3	%		14,877	10.1	%		16,632	8.9	%
Total oil and gas sales		146,597	85.5	%		121,325	82.8	%		151,888	81.5	%
Marketing revenues		21,422	12.5	%		20,310	13.9	%		28,907	15.5	%
Other income		3,418	2.0	%		4,855	3.3	%		5,595	3.0	%
Total revenues		171,437	100	%		146,490	100	%		186,390	100.0	%
Net production (million BOE)(1):
Crude oil		410.3	82.8	%		396.4	83.1	%		388.7	82.7	%
Natural gas		85.4	17.2	%		80.5	16.9	%		81.5	17.3	%
Total net production		495.7	100	%		476.9	100	%		470.2	100	%

(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,
	2015			2016			2017
Operating Revenues:
Oil and gas sales		85.5	%		82.8	%		81.5	%
Marketing revenues		12.5	%		13.9	%		15.5	%
Other income		2.0	%		3.3	%		3.0	%
Total revenues		100.0	%		100.0	%		100.0	%
Expenses:
Operating expenses		(16.5	)%		(15.8	)%		(13.0)	%
Taxes other than income tax		(6.3	)%		(4.7	)%		(3.9)	%
Exploration expenses		(5.8	)%		(5.0	)%		(3.7)	%
Depreciation, depletion and amortization		(42.8	)%		(47.0	)%		(32.9)	%
Special oil gain levy		0.0	%		0.0	%		0.0	%
Impairment and provision		(1.6	)%		(8.3	)%		(4.9)	%
Crude oil and product purchases		(11.6	)%		(13.0	)%		(14.8)	%
Selling and administrative expenses		(3.3	)%		(4.4	)%		(3.7)	%
Others		(1.8	)%		(3.3	)%		(3.2)	%
Total expenses		(89.8	)%		(101.6	)%		(80.1)	%
Interest income		0.5	%		0.6	%		0.4	%
Finance costs		(3.6	)%		(4.3	)%		(2.7)	%
Exchange gain, net		(0.1	)%		(0.5	)%		0.2	%
Investment income		1.4	%		1.9	%		1.3	%
Share of profits of associates		0.1	%		(0.4	)%		0.2	%
Share of profits/(losses) of a joint venture		1.0	%		0.4	%		0.3	%
Non(operating income/(expenses), net		0.4	%		0.4	%		0.0	%
Profit before tax		10.0	%		(3.6	)%		19.5	%
Income tax expense		1.8	%		4.0	%		(6.3)	%
Profit for the year		11.8	%		0.4	%		13.2	%

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Calculation of Revenues

China

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

The gross oil and gas sales consist of our percentage interest in total oil and gas sales, comprised of (i) a 100% interest in our independent oil and gas properties and (ii) our participating interest in the properties covered under our PSCs, less an adjustment for production allocable to foreign partners under our PSCs as reimbursement for exploration costs attributable to our participating interest.

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.

Other income mainly represents project management fees charged to foreign partners, handling fees charged to customers, the sales of diluents to third parties and gains from disposal of oil and gas properties and is recognised when the services have been rendered or the properties have been disposed of. Reimbursement of insurance claims is recognised when the compensation becomes receivable.

Indonesia

The oil and gas sales from our subsidiaries in Indonesia consist of our participating interest in the properties covered under the relevant PSCs, 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 consist of our participating interest in the Missan project.

Australia

The oil and gas sales from our subsidiaries in Australia consist of our participating interest in the North West Shelf project.

Nigeria

The oil and gas sales from our subsidiaries in Nigeria consist of our participating interest in the properties covered under the relevant PSCs. We record revenue from oil sales in accordance with the entitlement method. The revenue is calculated based on our participating interest less the rental concession, royalty, and oil and gas distributable to the host country. The royalty rates applicable to deepwater properties are zero.

Trinidad and Tobago

61 

The oil and gas sales from our subsidiaries in Trinidad and Tobago consist of our participating interest in the properties covered under the relevant PSCs.

The U.S. and Canada

The oil and gas sales from the U.S. consist of our participating interest in the properties of the Eagle Ford project, Niobrara project and properties in the Gulf of Mexico.

In respect of oil and gas products derived from Canada, our share of sales is primarily recognized when the ownership of products is transferred at the delivery point of the pipeline. The revenue is calculated net of royalties.

United Kingdom

The oil and gas sales from the United Kingdom consist of our participating interests in the Buzzard, Scott/Telford/Rochelle and Ettrick/Blackbird 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 a joint venture as shown in our consolidated statements of profit or loss and other comprehensive income.

2017 versus 2016

Consolidated net profit

Our consolidated net profit increased significantly to Rmb 24,677 million (US$3,792.8 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 the Company.

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 realised 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.

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Operating expenses

Our operating expenses increased 4.6% to Rmb 24,282 million (US$3,732.1 million) in 2017 from Rmb 23,211 million in 2016, the operating expenses per BOE increased 6.0% to Rmb 53.6 (US$8.24) per BOE in 2017 from Rmb 50.6 (US$7.29) per BOE in 2016, Operating expenses per BOE offshore China increased 11.6% to Rmb 49.2 (US$7.57) per BOE in 2017 from Rmb 44.1 (US$6.36) 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 (US$9.59) per BOE in 2017 from Rmb 64.1 (US$9.23) per BOE in 2016.

Taxes other than income tax

Our taxes other than income tax increased 3.9% to Rmb 7,210 million (US$1,108.2 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 (US$1,057.6 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 (US$ 9,415.0 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 (US$58.9 million) in 2017 from Rmb 1,569 million in 2016. Our average dismantling costs per BOE decreased 75.1% to Rmb 0.85 (US$ 0.13) per BOE in 2017 from Rmb 3.42 (US$0.49) 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 (US$9,356.2 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 (US$20.66) per BOE in 2017 from Rmb 146.8 (US$21.14) 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 (US$1,403.3 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 (US$1,054.5 million) in 2017 from Rmb 6,493 million in 2016. Our selling and administrative expenses per BOE increased 7.1% to Rmb 15.15 (US$2.33) per BOE in 2017 from Rmb 14.15 (US$2.04) per BOE in 2016, due to the increase in transportation costs in Canada resulting from increased production and sales volume.

Finance costs/Interest income

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Our finance costs decreased 19.2% to Rmb 5,044 million (US$775.2 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 (US$100.4 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 (US$54.7 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 (US$370.3 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 (US$131.4 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 (US$1,795.2 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.

2016 versus 2015

Consolidated net profit

Our consolidated net profit decreased 96.9% to Rmb 637 million in 2016 from Rmb 20,246 million in 2015, primarily as a result of the decrease in profitability under the low international oil price environment and impairment charge.

Revenues

Our oil and gas sales, realized prices and sales volume in 2016 are as follows:

	2016		2015		Amount			Change (%)
Oil and gas sales (Rmb million)		121,325		146,597		(25,272	)		(17.2	)%
Crude and liquids		106,448		128,929		(22,481	)		(17.4	)%
Natural gas		14,877		17,668		(2,791	)		(15.8	)%
Sales volume (million BOE)*		458.3		480.1		(21.8	)		(4.5	)%
Crude and liquids (million barrels)		387.6		404.0		(16.4	)		(4.1	)%
Natural gas (bcf)		410.5		444		(34	)		(7.5	)%
Realized prices
Crude and liquids (US$/barrel)		41.40		51.27		(9.87	)		(19.3	)%
Natural gas (US$/mcf)		5.46		6.39		(0.93	)		(14.6	)%
Net production (million BOE)		476.9		495.7		(18.8	)		(3.8	)%
China		311.1		323.4		(12.3	)		(3.8	)%
Overseas		165.8		172.3		(6.5	)		(3.8	)%

* Excluding our interest in equity-accounted investees.

64 

In 2016, our net production was 476.9 million BOE (including our interest in equity-accounted investees), representing a decrease of 3.8% from 495.7 million BOE in 2015, mainly due to the quality improvement and efficiency enhancement, and the optimization of production plan under the low oil price environment. In addition, the wildfire in Canada caused production suspension brought further decrease in production. The decrease in crude and liquids sales was primarily due to lower realized oil prices and sales volume in 2016 compared to 2015. The decrease in natural gas sales was primarily due to lower China government state-prescribed price and decrease in downstream demand.

Operating expenses

Our operating expenses decreased 18.2% to Rmb 23,211 million in 2016 from Rmb 28,372 million in 2015, attributable from effective cost control. The operating expenses per BOE decreased 14.9% to Rmb 50.6 per BOE in 2016 from 59.4 per BOE in 2015. Operating expenses per BOE offshore China decreased 10.9% to Rmb 44.1 per BOE in 2016 from Rmb 49.5 per BOE in 2015. Overseas operating expenses per BOE decreased 20.1% to Rmb 64.1 per BOE in 2016 from Rmb 80.2 per BOE in 2015.

Taxes other than income tax

Our taxes other than income tax decreased 35.6% to Rmb 6,941 million in 2016 from Rmb 10,770 million in 2015. The decrease was mainly due to the decrease in oil and gas revenue. In addition, the transfer from 5% production tax to regular VAT in independent oil and gas fields in China brought further decrease.

Exploration expenses

Our exploration expenses decreased 25.7% to Rmb 7,359 million in 2016 from Rmb 9,900 million in 2015, due to the dry hole expense decreased significantly compared to 2015 under strengthening intensify of exploration appraisal during the year and reducing the proportion of high risk and high cost wells. Meanwhile, the seismic expense decreased as compared to 2015 under the circumstance of increasing workload of 3D seismic data collection, resulting from continued strengthening of geological research and improvement in the operation standards.

Depreciation, depletion and amortization

Our depreciation, depletion and amortization decreased 6.2% to Rmb 68,907 million in 2016 from Rmb 73,439 million in 2015, resulting from the decrease of production volume. Our average depreciation, depletion and amortization per BOE, excluding the dismantlement-related depreciation, depletion and amortization, increased 0.2% to Rmb 146.8 per BOE in 2016 from Rmb 146.4 per BOE in 2015.

The dismantlement-related depreciation, depletion and amortization costs decreased 55.7 % to Rmb 1,569 million in 2016 from Rmb 3,545 million in 2015. Our average dismantling costs per BOE decreased 54.0% to Rmb 3.42 per BOE in 2016 from Rmb 7.43 per BOE in 2015, primarily due to the fact that the expected dismantlement costs in independent oil and gas fields no longer included the relevant taxes after the replacement of business tax with VAT in China.

Impairment, provision and write off

Our impairment and provision increased 343.2% to Rmb 12,171 million in 2016 from Rmb 2,746 million in 2015. In 2016, certain oil and gas properties located in North America, Europe and Africa were impaired, which was reflected by the revision of the estimation for the oil price forecast and the adjustment in operating plan for oil sand assets in Canada. Meanwhile, the Company wrote off certain oil and gas assets in North America due to the expired lease contracts. Approximately Rmb 823 million was included in the exploration expenses, and Rmb 605 million was included in the depreciation, depletion and amortization charge, respectively. Please refer to Note 14 to the Consolidated Financial Statement of this annual report. In addition, the Company had an approximately Rmb 1,403 million bad debt provision, which was classified as impairment and provision due to risk associated with the collection of Nigeria trade receivable. Please refer to Note 7 to the Consolidated Financial Statement of this annual report.

65 

Selling and administrative expenses

Our selling and administrative expenses increased 13.8 % to Rmb 6,493 million in 2016 from Rmb 5,705 million in 2015 due to the increasing of transportation costs in North America resulting from technology improvement of some production facilities. Our selling and administrative expenses per BOE increased 18.4% to Rmb 14.15 per BOE in 2016 from 11.95 per BOE in 2015.

Exchange losses, net

Our net exchange losses increased 452.4% to Rmb 790 million in 2016 from Rmb 143 million in 2015, primarily as a result of the increase in exchange losses as a result of Rmb, GBP and CAD fluctuation against the U.S. dollars.

Investment income

Our investment income increased 15.7% to Rmb 2,774 million in 2016 from Rmb 2,398 million in 2015, primarily attributable to the increase in return on corporate wealth management products and money market funds held by the Company.

Share of (losses)/profits of associates and a joint venture

Our share of losses of associates and a joint venture changed 104.0% to Rmb 76 million in 2016, while in 2015 we shared profits of Rmb 1,903 million, primarily attributable to losses from sales of shares of Northern Cross (Yukon) Limited located in Canada and decreases in profitability of some associates and a joint venture due to continuous decline in oil price.

Income tax credit

Our income tax credit increased 89.7% to Rmb 5,912 million in 2016 from Rmb 3,116 million in 2015, mainly because of an increase in deferred tax credit recognized on temporary differences and tax losses in overseas and a decrease in income tax expense due to decreased profit in China. In addition the UK government reduced the combined income tax rate on North Sea oil and gas activities from 50% to 40% and resulted in a one-time reversal of net deferred tax liability.

B. Liquidity and Capital Resources

Our primary source of cash during 2017 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,
	2015			2016			2017
	(Rmb in millions)
Cash generated from (used for):
Operating activities		80,095			72,863			94,734
Investing activities		(76,495	)		(27,953	)		(64,411	)
Financing activities		(6,893	)		(43,240	)		(31,271	)
Net increase/(decrease) in cash and cash equivalents		(3,293	)		1,670			(948	)

Cash Generated from Operating Activities

The cash inflow from operating activities increased 30.0% to Rmb 94,734 million (US$14,560.3 million) in 2017 from Rmb 72,863 million in 2016, primarily attributable to the increase in oil and gas sales cash inflows caused by the increase in international oil price partially offset by the increase in the income tax expense for the current period.

66 

Cash Used in Investing Activities

In 2017, our capital expenditure payment (excluding acquisition) decreased 7.0% to Rmb 47,734 million (US$7,336.6 milion) from 2016. Our development expenditures in 2017 were primarily related to the capital expenditure of OML130 project, deep-water Gulf of Mexico and shale oil and gas in U.S., as well as the expenses incurred for improving recovery factors of the oil and gas fields in production. The Company had no significant expenditure incurred for acquisition during the year.

In addition, our cash used in investing activities was also attributable to the purchase of other financial assets of Rmb 122,267 million (US$18,792.1 million) this year. Our cash generated from investing activities was mainly from the proceeds from the sales of other financial assets in the amount of Rmb 101,396 million (US$15,584.3 million), and the decrease in our time deposits with maturity over three months in the amount of Rmb 1,450 million (US$222.9million).

Cash Used in Financing Activities

In 2017, the increase in net cash outflow from financing activities was mainly due to the repayment of bank loans of Rmb 13,052 million (US$2,006.1 million), repayment of financial notes of Rmb 8,869 million (US$1,363.1 million) and the cash outflow of the distribution of dividends of Rmb 16,448 million (US$2,528.0 million), partially offset by the proceeds of bank loans of Rmb 12,252 million (US$1,883.1 million).

At the end of 2017, our total interest-bearing outstanding debt was Rmb 132,250 million (US$20,326.5 million), compared to Rmb 150,476 million at the end of 2016. The decrease in debt in 2017 was primarily attributable to the repayment of financial 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 25.8%, lower than that of 28.2% in 2016. The main reason was the decreased scale of interest-bearing debts.

We have debt service obligations consisting of principal and interest payments on our outstanding indebtedness. The following table summarizes the maturities of our long-term debt (including the current portion) outstanding as of December 31, 2017.

	Debt maturities (principal only)
	Original currency			Total Rmb equivalents			Total US$ equivalents
Due by December 31,	US$
	(in millions, except percentages)
2018		785.8			5,112.5			785.8
2019-2020		1,872.8			12,185.2			1,872.8
2021-2022		3,038.9			19,772.2			3,038.9
2023 and beyond		12,438.9			80,931.3			12,438.9
Total		18,136.4			118,001.2			18,136.4
Percentage of total debt		93.5	%		93.5	%		93.5	%

As of December 31, 2017, we had total foreign currency debt of US$19,403million, all of which is in U.S. dollars. As of March 31, 2018, we had total foreign currency debt of US$19,579 million, all of which is in U.S. dollars.

As of December 31, 2017, we had unutilized banking facilities amounting to approximately Rmb 53,749 million (US$8,261 million) as compared to Rmb 60,697 million as of December 31, 2016.

In 2015, 2016 and 2017, we paid dividends totaling Rmb 20,419 million, Rmb 14,245 million and Rmb 16,448 million (US$2,528 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.

67 

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 2018. 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. See “Item 3—Key Information—Risk Factors—Risks Relating to Our Operations—Our future prospects largely depend on our capital expenditures, which are subject to various risks.”

Capital Expenditures

For 2018, we have budgeted Rmb 70-80 billion for capital expenditures for exploration and development. The following table sets forth the Company’s actual or budgeted capital expenditures on an accrual basis for the periods indicated.

	Year ended December 31,
	2015 (1)		2016(1)		2017(1)		2018(1) (2)		2017(1)
	(Rmb million)								(US$ million)
China
Development		25,187		15,048		16,762		32,815	2,576
Exploration		9,515		6,205		7,978		9,979	1,226
Subtotal		34,702		21,253		24,740		42,794	3,802
Overseas
Development		25,957		24,516		21,891		32,095	3,365
Exploration		5,201		2,964		3,085		3,921	474
Subtotal		31,158		27,480		24,976		36,051	3,839
Total		65,860		48,733		49,716		78,845	7,641

(1) Capitalized interests were not included, and it was Rmb 1,385 million, Rmb 1,430 million and Rmb2,495 million in 2015, 2016 and 2017, respectively.

(2) Figures for 2018 represent our budgeted capital 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. See “Item 3—Key Information—Risk Factors—Risks Relating to Our Operations—Our future prospects largely depend on our capital expenditures, which are subject to various risks.”

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 Nexen Energy ULC, a wholly-owned subsidiary of the Company located in Canada, or directly owned by our company itself. International sales of crude oil and natural gas are conducted by China Offshore Oil

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(Singapore) International Pte Ltd, our wholly owned subsidiary incorporated in Singapore. Nexen Energy 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 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 1.4%, 3.0% and 1.6% in 2015, 2016 and 2017, 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

IFRS and HKFRS

We have adopted the IFRS as issued by the IASB since January 1, 2008. Therefore, our consolidated financial statements for 2017 have been prepared in due compliance with both IFRS and HKFRS. The accounting policies adopted are consisted with those of the year ended December 31, 2016, except for the first time adoption of the amendments to IFRS/HKFRS effective for the Company's financial year beginning on January 1, 2017 (the “Amendments”). The adoption of those Amendments upon their effective dates has had no material impact on the accounting policies, the disclosures or the amounts recognized in the consolidated financial statements of the Company.

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 2018, 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, the Company remains confident of its prospects. We will further strengthen our operating strategies, which mainly includes: steadily increase the Company’s oil and gas reserve and production levels, continue to reinforce quality and efficiency enhancement, strengthen innovation and technology-driven philosophy, maintain prudent financial policy and investment decision making, and pursue a green, healthy and environment friendly development model.

In 2018, the Company’s capital expenditure is anticipated to reach RMB 70-80 billion. To maintain its competitive financial position, the Company will continue to stress efficiency, enhance investment return, strengthen cost controls and focus on cash flow management. Our production target for 2018 is 470-480 million BOE, with five new projects to commence production. Meanwhile, the Company will maintain its 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.

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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 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 9 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. The Company provides 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, 2017.

	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)		118,001		5,113		12,185		19,772		80,931
Operating lease obligations		12,895		2,902		3,217		1,596		5,180
Provision for dismantlement(2)		54,073		1,180		-		-		52,893
Total		184,969		9,195		15,402		21,368		139,004

(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, 2015, 2016 and 2017, we had the following capital commitments, principally for the construction and purchase of property, plant and equipment:

Capital Commitments	2015		2016		2017
	Rmb million		Rmb million		Rmb million
Contracted, but not provided for		51,296		46,515		46,704

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 9 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 nine members, including two executive directors, three non-executive directors and four independent non-executive directors as of March 31, 2018. Hua Yang was re-designated from an Executive Director to a Non-executive Director and resigned as the Chief Executive Officer with effect from April 18, 2017. Guangyu Yuan was appointed as the Chief Executive Officer and resigned as the President with effect from April 18, 2017. Keqiang Xu was appointed as an Executive Director and the President of the Company with effect from April 18, 2017.

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 (appointed as Chief Executive Officer and resigned as President effective April 18, 2017)
Keqiang Xu	1971	Executive Director and President (effective April 18, 2017)
Hua Yang	1961	Chairman of the Board and Non-executive Director (re-designated as Non-executive Director and resigned as Chief Executive Officer effective April 18, 2017)
Jian Liu	1958	Vice Chairman and Non-executive Director
Guangqi Wu	1957	Non-executive Director
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
Wei Chen	1958	Executive Vice President, General Counsel and Compliance Officer (retired as Executive Vice President, the General Counsel and Compliance Officer of the Company effective March 2018)
Yuhong Xie	1961	Executive Vice President and General Manager of Exploration Department (effective May 2016)
Yong Li	1963	Executive Vice President and General Manager of CNOOC China Limited Tianjin Branch (effective June 2016)
Xinjia Cao	1966	Executive Vice President and General Manager of CNOOC China Limited Tianjin Branch (appointed as Executive Vice President effective August 2017 and served as General Manager of CNOOC China Limited Tianjin Branch effective March 2017)
Weizhi Xie	1964	Chief Financial Officer (effective August 2017)
Guohua Zhang	1960	Senior Vice President and General Manager of CNOOC China Limited Zhanjiang Branch

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Name  Year of Birth  Position 

Hua Zhong	1960	Chief Financial Officer (ceased to be Chief Financial Officer effective August 2017)
Yunhua Deng	1963	Deputy Chief Exploration Engineer and Deputy Director of Beijing Research Center of CNOOC China Limited
Lisong Song	1957	Chief Safety Official and General Manager of the Quality, Health, Safety and Environmental Protection Department (retired as Chief Safety Official effective April 2017)
Zaisheng Liu	1962	Vice President (effective February 2017); 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 (from April 2016 to November 2016)
Zongjie Qiu	1958	Vice President and General Manager of Development and Production Department (retired as Vice President and General Manager of Development and Production Department effective March 2018)
Jiewen Li	1965	Joint Company Secretary and General Manager (Director) of Investor Relations Department (Office for the Board of Directors)
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 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 65^th 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

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Executive Vice President of the Company. In April 2013, Mr. Yuan was appointed as Director of Bohai Petroleum Administrative Bureau of CNOOC and General Manager of CNOOC China Limited Tianjian Branch, a subsidiary of the Company. Mr. Yuan also serves as the Director and General Manager of CNOOC China Limited and the Director of CNOOC International Limited, both subsidiaries of the Company. From June 15, 2016 to May 5, 2017, he was appointed as the Chairman of CNOOC International Limited. 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. In April 2017, Mr. Xu was appointed as the Chairman of Nexen Energy ULC, a subsidiary of the Company. He was appointed as the Chairman of CNOOC International Limited and as a Director of CNOOC China Limited, both subsidiaries of the Company, with effect from May 2017. 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, 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

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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 with effect from April 18, 2017.

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 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. He was appointed as Chairman and Director of CNOOC China Limited, a subsidiary of the Company, with effect from February 28, 2017. Mr. Liu was appointed as the Vice Chairman and a Non-executive Director of the Company with effect from December 20, 2016.

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 and since June 1, 2005 he also serves as a Director of CNOOC International Limited and served 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.

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 served as the General Secretary of the Australian Chinese Community Association of New South Wales. Mr. Chiu is also an Independent

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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 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 twelve books 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 Sub-committee 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 and Hysan Development Company Limited, both 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.

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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 Chancellor of the University of King’s College, Senior Fellow of Massey 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 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

Wei Chen Born in 1958, Mr. Chen is an Executive Vice President, the General Counsel and Compliance Officer of the Company. He is a professor-level senior engineer. He received his B.S. degree from East China Petroleum Institute (now China University of Petroleum) and MBA degree from Tsinghua University. He has over 30 years of experience in the oil and gas industry. Mr. Chen joined CNOOC in 1984 and previously served as the Deputy Manager for the Development Department of CNOOC Exploration and Development Research Center, the Deputy Manager of the Overseas Research Department, the Manager of the Information Department, and the Deputy Director of CNOOC Research Center. He has also served as General Manager of Human Resources Department and General Manager of Science and Technology Development Department of CNOOC, and a Senior Vice President of the Company and General Manager of Administration Department of the Company. In July 2003, Mr. Chen was appointed as the Director of CNOOC Research Center (later became President of CNOOC Research Institute). In February 2012, Mr. Chen was appointed as the Worker’s Director of CNOOC. In March 2013, Mr. Chen was appointed as the Assistant President of CNOOC and the Executive Vice President of the Company. In May 2016, Mr. Chen was appointed as the General Counsel of CNOOC, the General Counsel and Compliance Officer of the Company. In March 2018, Mr. Chen retired as Executive Vice President, the General Counsel and Compliance Officer of the Company.

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. In May 2016, he was appointed as the Chief Geologist of CNOOC, an Executive Vice President and General Manager of Exploration Department of the Company.

Yong Li Born in 1963, Mr. Li is an Executive Vice President of the Company and General Manager of CNOOC China Limited Tianjin Branch. He is a senior engineer. He received his B.S. degree from Southwest Petroleum University, master of Petroleum Economics from Scuola E Mattei of Italy and MBA from Peking University. He has over 30 years of experience in the oil and gas industry. Mr. Li joined CNOOC in 1984 and previously served as Comprehensive Technology Manager and Drilling Manager of Exploration Department of CNOOC, Director of Drilling Office of Exploration and Development Department of the Company. In April 2003, he was appointed as Deputy General Manager of Tianjin Branch of CNOOC (China) Limited. In October 2005, he was appointed as Executive Vice President and Chief Operating Officer of COSL. In April 2009, he was appointed

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as Executive Director and President of COSL. In September 2010, he served as Executive Director, Chief Executive Officer and President of COSL. From June 2016 to August 2017, he served as Assistant President of CNOOC, Executive Vice President of the Company, Director of CNOOC Bohai Petroleum Administration Bureau and General Manager of CNOOC China Limited Tianjin Branch.

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 Finance 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, Controller General & Director of Audit Department CHINALCO. From May 2016, 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 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.

Hua Zhong Born in 1960, Mr. Zhong is Chief Financial Officer of the Company. Mr. Zhong is a professor-level senior economist and senior engineer and graduated from Southwest Petroleum Institute (now Southwest Petroleum University) with a bachelor’s degree in Oil Exploitation. He received a master’s degree in Petroleum Engineering from Heriot-Watt University in the United Kingdom. He joined CNOOC in 1982, and has been working in the oil and gas industry for over 30 years. From 1982 to 1999, Mr. Zhong served as Petroleum Engineer of China Offshore Oil Nanhai West Corporation (“COONWC”), Expro Northsea Staff in UK, Deputy Manager of Downhole Services Company of Oil Production Company of COONWC, Manager of Wei 10-3 Oilfield, Oilfield Superintendent of CNOOC Indonesia Project, Supervisor of Ya 2-1-3 HTHP Well Testing Project, Deputy Manager of Drilling and Exploitation Institute, Manager of Science and Technology Development Department and Manager of Administration Department of COONWC. From September 1999 to October 2005, Mr. Zhong was General Manager of Administration Department and General Manager and Director of Development and Planning Department of the Company. From August 2005 to September 2010, Mr. Zhong served as Vice President,

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Executive Vice President and Chief Financial Officer of China Oilfield Services Limited, a company listed on The Stock Exchange of Hong Kong Limited and Shanghai Stock Exchange, a subsidiary of CNOOC. On September 16, 2010, Mr. Zhong was appointed as Chief Financial Officer of the Company. From March 2012 to November 2015, Mr. Zhong served as Joint Company Secretary of the Company. In August 2017, Mr. Zhong ceased to serve as Chief Financial Officer of the Company.

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.

Lisong Song Born in 1957, he is a professor-level senior engineer. He graduated in 1982 with a bachelor’s degree from the Department of Petroleum Development of East China Petroleum Institute (now China University of Petroleum), majoring in Drilling Engineering. In 1999, he graduated with a master’s degree in management from Department of Economic Management of School of Management, TianJin University. From 1982 to 1994, he served as Supervisor and Platform Manager for Bohai Oil Corporation, and a staff member of the offshore division of the Technology Safety Department and the head of the offshore safety division of the Technical Safety and Environmental Protection Department respectively. From 1994 to 1999, Mr. Song served as Director of the Safety Production Division and head of the Safety Office of the HSE Department of CNOOC. From 1999 to 2001, he served as Deputy Manager of the HSE Department of the Company. From 2001 to 2003, he served as Director of operational safety of the HSE Department of CNOOC. From 2003 to 2013, he served as the General Manager of the HSE Department of CNOOC and the Company. From March 2013 to September 2016, he served as the Deputy Chief Safety Official of CNOOC, the Chief Safety Official and General Manager of the QHSE Department of the Company. From September 2016 to now, he has been serving as the Deputy Chief Safety Official of CNOOC and the Chief Safety Official of the Company. In April 2017, Mr. Song retired as the Chief Safety Official of the Company.

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.

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Zongjie Qiu Born in 1958, Mr. Qiu is a Vice President and General Manager of Development and Production Department of the Company. He graduated from China University of Petroleum with a master’s degree. From 1982 to 1993, he served as Cadre and Deputy Manager of Oil Testing Company of CNOOC Nanhai West Corporation Oil Production Company. From 1993 to 1999, he served as Manager of Weizhou 11-4 oilfield, head of the operation division, Principal Engineer, Deputy Manager, Manager (and Manager of Oilfield Development Department) of CNOOC Nanhai West Corporation Oil Production Company respectively. From 1999 to 2001, he served as Manager of Petroleum Production Department of CNOOC Nanhai West Corporation. From 2001 to 2005, he served as Deputy General Manager of CNOOC China Limited Zhanjiang Branch. From 2005 to 2007, he served as Deputy General Manager of CNOOC China Limited Shenzhen Branch. From 2007 to 2016, he served as General Manager of Development and Production Department of the Company. In February 2017, Mr. Qiu was appointed as Vice President and General Manager of Development and Production Department of the Company. In May 2017, he was appointed as Vice President, Chief Safety Official, and General Manager of Development and Production Department of the Company. In March 2018, Mr. Qiu retired as Vice President, Chief Safety Official and General Manager of Development and Production Department of the Company.

Joint Company Secretaries

Jiewen Li Born in 1965, Ms. Li Jiewen is 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 a 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-AGIP-Chevron-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. Ms. Li was appointed as Joint Company Secretary of the Company with effective from November 27, 2015.

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) 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 was appointed as 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, 2017 was Rmb 4,552.000 (US$699,630), while the amount paid to our other senior management for the same period was Rmb 8,851,515 (US$1,360,453). In addition, under our pension plan for 2017, we set aside an aggregate amount of Rmb 1,159,398 (US$178,196) for pension and

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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 174,166 (US$57,508) to the pension plan for 2017. Each director’s annual compensation, including fees, salaries, allowances, benefits in kind, pension benefits and share option benefits, is disclosed in note 9 to our consolidated financial statements included elsewhere in this annual report. Note 10 to our consolidated financial statements included elsewhere in this annual report discloses our five highest paid employees during 2017. For further details regarding share options granted to our directors, officers and employees, see “Item 6—Directors, Senior Management and Employees—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 its internal control systems. 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, 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, 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 (Guangqi Wu). 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 structure and composition of our Board, and evaluating the leadership abilities of our executive directors so as to ensure our competitive position. 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

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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 nine 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 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

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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 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 31, 2018, our directors and employees had the following personal interests in options to subscribe for shares granted under our share option schemes:

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Name of Grantee	Number of shares involved in the options outstanding as of January 1, 2017		Number of shares involved in the options outstanding as of March 1, 2018		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(2)		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(2)		1,857,000		-		May 25, 2007		May 25, 2017		7.43		7.29
		1,857,000		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
Guangqi Wu		1,857,000		-		May 25, 2007		May 25, 2017		7.43		7.29
		1,857,000		1,857,000		May 29, 2008		May 29, 2018		14.20		14.828
		1,857,000		1,857,000		May 27, 2009		May 27, 2019		9.33		9.93
		1,857,000		1,857,000		May 20, 2010		May 20, 2020		12.22		12.696
Other Employees In Aggregate:
		31,390,000		-		May 25, 2007		May 25, 2017		7.43		7.29
		38,226,000		28,251,000		May 29, 2008		May 29, 2018		14.20		14.828
		44,823,000		34,236,000		May 27, 2009		May 27, 2019		9.33		9.93
		53,357,000		41,355,000		May 20, 2010		May 20, 2020		12.22		12.696
Total		187,529,000		119,861,000

(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.

(2) With effect from April 18, 2017, Mr. Hua Yang was re-designated from an Executive Director to a Non-executive Director of the Company and resigned as the Chief Executive Officer of the Company. Mr. Guangyu Yuan was appointed as the Chief Executive Officer of the Company and resigned as the President of the Company.

For the year ended December 31, 2017, no share options granted under our share option schemes were exercised. For the period from January 1, 2017 to March 31, 2018, no share options were exercised.

As of December 31, 2017, we had 129,919,000 share options outstanding under our share option schemes, which represented approximately 0.29% 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 April 19, 2018, 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 31, 2018.

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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 1, 2018, 10,429,785 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 59.

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;

· 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 connected transactions or 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:

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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).

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 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 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

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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

(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,  Rmb12,625 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

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(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,  Rmb263,893 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 2017 and the balances arising from connected transactions at the end of 2017 is included in note 28 to our consolidated financial statements included elsewhere in this annual report.

The non-exempt continuing connected transactions for the year ended December 31, 2017 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, 2017 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

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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.

The maximum daily outstanding balance of deposits (including accrued interest) (excluding funds placed for the purpose of extending entrustment loans pursuant to the entrustment loan services) placed by the Company with CNOOC Finance should not exceed Rmb19.5 billion for the period from January 1, 2017 to December 31, 2019.

We confirmed that the maximum daily outstanding balance of deposits (including accrued interests but excluding funds placed for the purpose of extending entrustment loans pursuant to the entrustment loan services) placed by us with CNOOC Finance did not exceed Rmb 19.5 billion from January 1, 2017 to December 31, 2017.

Borrowings from CNOOC

In September 2014, CNOOC provided CNOOC International Limited, a wholly-owned subsidiary of us a five-year uncommitted revolving loan facility for general purposes, with the principal amount of US$ 135 million of 0.95% per annum. As at March 31, 2018, the withdrawal amount of the loan was US$ 130 million; In December 2014, CNOOC provided us a five-year uncommitted revolving loan facility for general purposes, with the principal amount of US$ 600 million of 0.95% per annum. As at March 31, 2018, the withdrawal amount of the loan was US$ 564 million. All the loans above are unsecured.

C. Interests of Experts and Counsel

Not applicable.

ITEM 8. FINANCIAL INFORMATION

A. Consolidated Statements and Other Financial Information

See pages beginning on page F-1 following Item 19.

Legal Proceedings

As at December 31, 2017, the Company was not involved in any material litigation or arbitration and no material litigation or arbitration were pending or threatened or made against the Company so far as the Company is aware.

Dividend Distribution Policy

The payment of any future dividends will be determined by our Board, subject to shareholders’ approval for all dividends other than interim dividends, based upon, among other things, our future earnings, capital requirements, financial conditions, future prospects and other factors which our Board may consider relevant. Our ability to pay dividends will also depend on the cash flows determined by the dividends, if any, received by us from our subsidiaries and associates. Holders of our shares will be entitled to receive such dividends declared by our Board pro rata according to the amounts paid up or credited as paid up on the shares. Subject to the factors described above, we currently intend to pursue a dividend policy consistent with other international oil and gas exploration and production companies.

Dividends may be paid only out of our distributable profits as permitted under Hong Kong law, which does not restrict the payment of dividends to nonresident holders of our securities. To the extent profits are distributed as dividends, such portion of profits will not be available to be reinvested in our operations.

Holders of our ADSs will be entitled to receive dividends, subject to the terms of the deposit agreement, to the same extent as holders of our shares, less the fees and expenses payable under the deposit agreement and withholding taxes of 10%. Cash dividends will be paid to the depositary in Hong Kong dollars and will be converted by the depositary into U.S. dollars and paid to holders of ADSs. Stock dividends, if any, will be distributed to the depositary and will be distributed by the depositary, in the form of additional ADSs, to holders of the ADSs.

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In 2015, we declared and paid dividends totaling Rmb 20,419 million. In 2016, we declared and paid dividends totaling Rmb 14,244 million. In 2017, we declared and paid dividends totaling Rmb16,449 million (US$2,528 million). The amount of dividends we paid historically is not indicative of the dividends that we will pay in the future.

Substantially all our dividend payments result from dividends paid to us by CNOOC China Limited. CNOOC China Limited must follow the laws and regulations of the PRC and its articles of association in determining its dividends. As a wholly foreign owned enterprise in China, CNOOC China Limited has to provide for a reserve fund and staff and workers’ bonus and welfare fund, each of which is appropriated from net profit after taxation but before dividend distribution according to the prevailing accounting rules and regulations in the PRC. The general reserve fund, which is determined at the discretion of the board of directors of CNOOC China Limited, can only be used, upon approval by the relevant authority, to offset against accumulated losses or to increase capital. Appropriations to the staff and workers’ bonus and welfare fund, which are determined at the discretion of the directors of CNOOC China Limited, are charged to expense as incurred in our consolidated financial statements, which were prepared under IFRS. In accordance with the “Temporary Regulation for Safety Expense Financial Management of High Risk Industry” and the implementation guidance issued by the Ministry of Finance of the PRC, a safety fund has been accrued for our oil and gas exploration and production activities within the PRC. The accrued safety fund will be utilized for improving the safety conditions of our production. None of the contributions of CNOOC China Limited to these statutory funds may be used for dividend purposes.

For the years ended December 31, 2015, 2016 and 2017, CNOOC China Limited made the following appropriations to the statutory reserves:

	For the year ended   December 31, 2015					For the year ended   December 31, 2016					For the year ended   December 31, 2017
	Percentage of Net Profits			Rmb (in millions)		Percentage   of Net Profits			Rmb (in millions)		Percentage of Net Profits			Rmb (in millions)
Reserve fund		—			—		—			—		202.6	%		50,000.0
Staff and workers’ bonus and welfare fund		—			—		—			—		—			—
Safety fund		3.6	%		733.7		110.7	%		705.1		2.7	%		670.4

Contingencies

(a) Two oil spill accidents ( the “Penglai 19-3 Oilfield Oil Spill Accidents”) occurred on June 4 and June 17, 2011 respectively at Platforms B and C of Penglai 19-3 oilfield, which is being operated under a production sharing contracts (the “PSC”) among CNOOC China Limited, a subsidiary of the Company, and two subsidiaries of ConocoPhillips, a US based oil company, among which ConocoPhillips China Inc. (the “COPC”) was the operator and responsible for the daily operations of the oilfield when the Penglai 19-3 Oilfield Oil Spill Accidents occurred.

On August 10, 2015, the Company received a Notice Calling for Responses from the Qingdao Maritime Court of the People’s Republic of China （the “Qingdao Maritime Court”）for a public interest action filed by China Biodiversity Conservation and Green Development Foundation (the “Plaintiff”) in relation to the Penglai 19-3 Oilfield Oil Spill Accidents (the “Lawsuit”). The Lawsuit is lodged against COPC and CNOOC China Limited. On February 2, 2018, CNOOC China Limited received a ruling dated 28 December 2017 issued by Qingdao Maritime Court (the “Ruling”). Pursuant to the Marine Environment Protection Law of the People’s Republic of China amended in 2016, Qingdao Maritime Court ruled that the Plaintiff was not an appropriate entity to file the Lawsuit, and rejected it. As none of the parties to the Lawsuit appealed within the time limit, the Ruling came into effect. Therefore, CNOOC China Limited bears no liability for the Lawsuit.

The Company is of the view that there was no material impact of the Penglai 19-3 Oilfield Oil Spill Accidents on the Company.

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(b) As a Chinese Resident Enterprise, the Company may be liable to pay taxes on the deemed interest income for the funding provided to its overseas subsidiaries starting from January 1, 2008. The Company has prepared contemporaneous documentation in accordance with applicable PRC tax laws and regulations and is currently awaiting confirmation from its in-charge tax authority.

The Company is subject to tax in numerous jurisdictions around the world. There are audits in progress and items under review. Difference in positions taken by taxation authorities over the interpretation and application of tax laws and regulations may increase the Company’s tax liability. Management has assessed the possible future outcome of matters that are currently under dispute. The Company believes that an adequate provision for future tax liability has been included in the consolidated financial statements based on available information.

In addition to the matters mentioned above, the Company is dealing with a number of other lawsuits and arbitrations that arise in the ordinary course of business. While the results of these legal proceedings cannot be ascertained at this stage, the Company believes these proceedings are not expected to have a material effect on the consolidated financial statements.

B. Significant Changes

The Company has no other subsequent events needed to be disclosed except those disclosed in note 37 to our consolidated financial statements included elsewhere in this annual report.

ITEM 9. THE OFFER AND LISTING

Not applicable, except for Item 9.A.4 and Item 9.C.

We listed our shares on the Hong Kong Stock Exchange and our ADSs on the New York Stock Exchange in February 2001. Our shares are listed on the Hong Kong Stock Exchange under the stock code “00883” and our ADSs are listed on the New York Stock Exchange under the symbol “CEO.” Pursuant to certain undertakings in connection with our acquisition of Nexen, we listed our ADSs on the Toronto Stock Exchange in September 2013 under the symbol “CNU”. The listing of our ADSs on the Toronto Stock Exchange is not a new issuance of equity securities and does not generate additional funds for us. The following table sets forth, for the periods indicated, the high and low closing prices per share, as reported on the Hong Kong Stock Exchange and adjusted retroactively to reflect the stock split, and per ADS, as reported on the New York Stock Exchange and the Toronto Stock Exchange.

Period	Hong Kong Stock Exchange		New York Stock Exchange		Toronto Stock Exchange
	High	Low	High	Low	High	Low
	(HK$ per share)		(US$ per ADS)		(Cdn$ per ADS)
2013	17.34	11.54	226.60	159.19	217.78	196.50
2014	15.68	9.80	201.50	126.70	219.15	151.57
2015	13.42	7.44	174.88	98.91	210.01	135.00
2016	10.7	6.42	138.11	85.34	168.95	137.00
2017	11.3	8.5	144.51	108.48	182.74	138.61
2016 Financial Quarter
1st Quarter	9.26	6.42	121.86	85.34	157.50	139.00
2nd Quarter	10.18	8.59	129.94	110.58	159.00	150.00
3rd Quarter	9.96	8.85	128.35	115.23	163.00	150.00
4th Quarter	10.70	9.51	138.11	121.64	183.15	164.00
2017 Financial Quarter
1st Quarter	10.04	8.81	129.00	113.25	169.78	160.00
2nd Quarter	9.54	8.5	122.44	108.48	161.43	145
3rd Quarter	10.08	8.52	129.7	109.08	147	138.61
4th Quarter	11.3	9.89	144.51	126.4	182.74	144.6
2018 Financial Quarter
1st Quarter	12.9	10.82	165.85	140.41	199.5	175.97
Last Six Months
October 2017	10.62	9.89	134.3	126.4	172.47	144.6
November 2017	11.14	10.56	143.36	134.48	182.74	172.22
December 2017	11.3	10.48	144.51	133.02	181.33	172
January 2018	12.9	11.22	165.85	143.56	199.5	181.33
February 2018	12.66	10.92	158.06	140.41	199.5	175.97
March 2018	11.74	10.82	152.86	140.54	192.85	183.74

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ITEM 10. ADDITIONAL INFORMATION

A. Share Capital

Not applicable.

B. Memorandum and Articles of Association

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 the Hong Kong Companies Ordinance). 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.

The following are summaries of provisions of our articles of association and the Hong Kong Companies Ordinance. By operation of this Ordinance, provisions that were previously contained in our memorandum of association are deemed to be incorporated into our articles of association except for those provisions which conflict with the Hong Kong Companies Ordinance. For further details, you should read our memorandum of association, which was filed as an exhibit to our registration statement on Form F-1 (Registration No.333-10862) and our articles of association, as amended, which was filed as an exhibit to our annual report on Form 20-F for the fiscal year of 2010. We are required by the Hong Kong Stock Exchange Listing Rules to upload, among other things, our memorandum and articles of association on our website and on the website of the Hong Kong Stock Exchange. We have complied with such requirement and as such, our memorandum and articles of association were further filed as an exhibit to the Form 6-K filed with the SEC on March 30, 2012 (File Number: 1-14966).

Issue of Shares

Under the Hong Kong Companies Ordinance, our directors may, without obtaining the prior approval of our shareholders, offer to allot new shares in our company to existing shareholders on a pro rata basis. Our directors may not allot new shares of our company or grant rights to subscribe for, or to convert any security into, shares of our company in any other manner without the prior approval of our shareholders at a general meeting. Any approval given at a general meeting granting our directors power to allot shares or securities convertible into shares or to grant rights to subscribe for shares generally shall continue in force from the date of the passing of the resolution until the earlier of:

· the conclusion of the next annual general meeting following the passing of the resolution; and

· the date on which the authority given under the resolution is revoked or varied by an ordinary resolution of our shareholders in a general meeting.

If such an approval for a general mandate to issue shares is given, our Board shall have the discretion to issue such number of shares as are approved pursuant to such general mandate, and our directors may offer, allot, grant options or other rights of subscription or conversion over, or otherwise issue, such number of shares to persons at such times and for such consideration and upon such terms and conditions as our directors may determine, subject to the restrictions under the Hong Kong Stock Exchange Listing Rules.

In accordance with Hong Kong Stock Exchange Listing Rules, any such approval of the shareholders must be limited to shares not exceeding 20% of our total number of shares in issue as of the date of granting such approval plus the number of shares repurchased by us since the granting of such approval.

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Dividends

Subject to the Hong Kong Companies Ordinance, the shareholders at a general meeting may declare dividends to be paid to shareholders. However, under our articles of association, dividends cannot be declared in excess of the amount recommended by our Board. Further, all dividends unclaimed for one year after having become payable may be invested or otherwise made use of by the directors for the benefit of our company until claimed, and all dividends unclaimed for six years after having become payable may be forfeited by the directors and shall revert to our company.

In addition to dividends declared at a general meeting, our Board may declare and pay to the shareholders interim dividends as our Board deems justified by our financial position. Our Board may also pay any fixed dividend on any shares of our company semi-annually or at other suitable intervals, whenever our financial position, in their opinion, justifies such payment.

Winding Up

If we are wound up, the surplus assets remaining after payment to all creditors are to be divided among our shareholders in proportion to the amount paid on the shares held by them respectively, and if such surplus assets are insufficient to repay the whole of the paid-up share capital, they are to be distributed so that the losses are borne by our shareholders in proportion to the amount paid up on the shares held by them respectively. The liquidator may, with the sanction of a special resolution, divide among our shareholders in specie or in kind the whole or any part of our assets or vest any part of our assets in trustees upon such trusts for the benefit of our shareholders or any of them as the resolution shall provide.

Voting Rights

Under the Hong Kong Companies Ordinance, any action to be taken by the shareholders at a general meeting requires the affirmative vote of either an ordinary or a special resolution passed at such meeting.

· An ordinary resolution is a resolution passed by a majority of shareholders that are entitled to, and do, vote in person or by proxy at a general meeting;

· A special resolution is a resolution passed by not less than 75% of shareholders that are entitled to, and do, vote in person or by proxy at a general meeting.

Generally, resolutions of shareholders are passed by ordinary resolution. However, the Hong Kong Companies Ordinance provides that certain specified matters may only approved by shareholders by way of special resolutions. These matters include, for example:

· alteration of the articles;

· change of a company’s name;

· reduction of share capital; and

· voluntary winding up.

The Hong Kong Stock Exchange Listing Rules require that voting at any general meeting must be taken by way of poll, except where the chairman, in good faith, decides to allow a resolution which relates purely a procedural or administrative matter to be voted on by a show of hands. On a poll, every shareholder who is present in person or by proxy has one vote for every share held or represented by him or her.

Any action to be taken by the shareholders requires the affirmative vote of the requisite majority of the shares at a general meeting. There are no cumulative voting rights. Accordingly, the holders of a majority of the shares voting for the election of directors can elect all the directors if they choose to do so.

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Under Hong Kong law and our articles of association, shareholders who are not residents of Hong Kong may hold, vote and transfer their shares in our company in the same manner as our shareholders who are Hong Kong residents.

General Meetings

We are required to hold an annual general meeting each year within six months from the end of our financial year. We may also hold extraordinary general meetings from time to time. Our Board may convene an extraordinary general meeting at will, and shall on requisition in accordance with the Hong Kong Companies Ordinance, proceed to convene an extraordinary general meeting. Our annual general meeting and a meeting called for the purpose of passing a special resolution require at least twenty-one days’ prior notice, and any other general meeting requires at least fourteen days’ prior notice. The notice must specify the place, day and time of the meeting and, in the case of special business, the general nature of that business. The quorum for a general meeting is two shareholders present in person or by proxy. If within thirty minutes from the time appointed for the meeting a quorum is not present, the meeting, if convened upon requisition in accordance with the Hong Kong Companies Ordinance, shall be dissolved; but in any other case it shall stand adjourned to the same day in the next week at the same time and place, or to such other day, time and place as the chairman of the meeting may determine. If at such adjourned meeting a quorum is not present within thirty minutes from the time appointed for the meeting, the member or members present in person or by proxy shall be a quorum and may transact the business for which the meeting is called.

At each annual general meeting one third of our directors are to retire from office by rotation, save any director holding office as chairman or chief executive officer. The directors to retire every year are to be those who have been longest in office since their last election and the retiring directors will be eligible for re-election.

Modification of Rights

Subject to the Hong Kong Companies Ordinance, any of the rights attaching to any class of shares, unless otherwise provided for by the terms of issue of the shares of that class, may be varied or abrogated with the written consent of the holders of not less than 75% of the issued shares of that class or with the sanction of a special resolution passed at a separate general meeting of the holders of shares of that class.

Borrowing Powers

Our Board may exercise all the powers of our company to borrow money and to mortgage or charge all or any part of our undertaking, property and assets, whether present or future, and uncalled capital. Our Board may issue debentures, debenture stock, bonds or other securities of our company, whether outright or as collateral security for any debt, liability or obligation of our company or of any third party. These borrowing powers are subject to variation by a special resolution of our company.

Interested Transactions

Subject to the exceptions described below, none of our directors may vote on any contract, arrangement or proposal in which the director or any of his or her associates is materially interested. Subject to provision of the Hong Kong Companies Ordinance, our directors may vote at a board meeting or by way of written resolution of directors on the following matters:

· any contract or arrangement to give security or indemnity to the director or his or her associates for money lent or obligations incurred or undertaken by such director or his or her associates at the request of or for the benefit of our company or subsidiaries;

· any contract or arrangement for the giving by us of any security or indemnity to a third party for our debts or obligations or debts or obligations of our subsidiaries for which such director or his or her associates assumed responsibility , or guaranteed or secured in whole or in part whether alone or jointly;

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· any contract or arrangement concerning offering of securities by us (or any company which we may promote or be interested in purchasing) for which the director or his or her associates is/are or is/are to be interested as a participant in the underwriting or sub-underwriting;

· any contract or arrangement in which the director or his or her associates are interested in the same manner as other holders of our securities by virtue only of their interest in our securities;

· any proposal or arrangement concerning employee benefits that do not provide privileges to our directors or their associates not generally accorded to the class of persons to whom such scheme or fund relates, including pension fund or retirement, death or disability benefits schemes; and

· any proposal or arrangement concerning the adoption, modification or operation of any employees’ share scheme involving the issue or grant of options over shares or other securities by us to, or for the benefit of, our employees or employees of our subsidiaries under which the director or his or her associates may benefit.

C. Material Contracts

We have not entered into any material contracts in the last two years other than in the ordinary course of business, those described in “Item 7―Major Shareholders and Related Party Transactions ― Related Party Transactions”.

D. Exchange Controls

For information on foreign exchange controls in the PRC, foreign exchange rates, hedging activities and related foreign exchange risks, see “Item 3—Key Information—Selected Financial Data,” “Item 3—Key Information—Risk Factors—Risks Relating to the PRC—Government control of currency conversion and future movements in exchange rates may adversely affect our operations and financial condition” and “Item 11—Qualitative and Quantitative Disclosure about Market Risk.”

E. Taxation

The taxation of income and capital gains of holders of our shares or ADSs is subject to the laws and practices of the PRC, Hong Kong and the jurisdictions in which holders of our shares or ADSs are resident or otherwise subject to tax. The following is a summary of taxation provisions that are anticipated to be material based on current law and practice. This summary is subject to change and does not constitute legal or tax advice. The discussion does not deal with all possible tax consequences relating to an investment in our shares or ADSs. In particular, the discussion does not address the tax consequences under state, local or other laws, such as non-PRC, non-Hong Kong or non-U.S. laws. Accordingly, we urge you to consult your tax adviser regarding the tax consequences of owning our shares and ADSs. The discussion is based upon laws and relevant interpretations in effect as of the date of this annual report, all of which are subject to change. There is no reciprocal tax treaty in effect between Hong Kong and the United States.

The PRC

On April 22, 2009, the State Administration of Taxation of the PRC (the “SAT”) issued the “Notice regarding Matters on Determination of Tax Residence Status of Chinese-controlled Offshore Incorporated Enterprises under Rules of Effective Management” (the “Notice”).

Pursuant to the “Enterprise Income Tax Law of the PRC” (the “New EIT Law”) and the Notice, enterprises established outside of China whose “de facto management bodies” are located in China are considered Chinese Resident Enterprises, or CREs.

We are considered a PRC resident enterprise for purposes of the Notice. In Accordance with the Notice and the PRC income tax law as well as the formal approval from the SAT in October 2010, we are regarded as a CRE pursuant to the provisions of the New EIT Law and the Notice. Accordingly, we are required to withhold 10% corporate income tax when we make dividend distributions to the ADS depositary and to our non-Chinese resident enterprise shareholders, whose names appear on our register of members, as of the record date for such dividend, and who are not individuals. The 10% dividend withholding tax rate will not be reduced under the 1984 Agreement between the United States and the People’s Republic of China for the Avoidance of Double Taxation, or the PRC Treaty. In the past, we did not withhold any tax in respect of dividends payable to any natural person shareholders whose names appeared on our register of members on the relevant record dates.

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Currently, gains realized by foreign individual investors upon the sale of overseas-listed shares or American depositary shares are not subject to tax on capital gains. In accordance with the New EIT Law, capital gains realized by foreign enterprises which are non-resident enterprises in China upon the sale of overseas-listed shares or American depositary shares are generally subject to a PRC enterprise income tax levied at a rate of 10%, unless exempted or reduced pursuant to an applicable double-taxation treaty or other exemption.

Hong Kong

Tax on Dividends

Under the current practices of the Hong Kong Inland Revenue Department, no tax is payable in Hong Kong on dividends paid by us.

Profits Tax

No tax is imposed in Hong Kong in respect of capital gains from the sale of property, such as the shares and ADSs. Trading gains from the sale of property by persons carrying on a trade, profession or business in Hong Kong where such gains are derived from or arise in Hong Kong from such trade, profession or business will be subject to Hong Kong profits tax which is currently imposed at a rate of 16.5% on corporations and at a standard rate of 15% on individuals. Gains from sales of shares effected on the Hong Kong Stock Exchange will be considered to be derived from or arise in Hong Kong. Liability for Hong Kong profits tax will therefore arise in respect of trading gains from sales of shares realized by persons carrying on a business of trading or dealing in securities in Hong Kong.

Stamp Duty

Hong Kong stamp duty, currently charged at the rate of HK$1.00 per HK$1,000 or part thereof on the higher of the consideration for, or the value of, the shares, will be payable by the purchaser on every purchase and by the seller on every sale of shares. A total of HK$2.00 per HK$1,000 or part thereof is currently payable on a typical sale and purchase transaction involving shares. In addition, a fixed duty of HK$5.00 is currently payable on any instrument of transfer of shares. The withdrawal of shares upon the surrender of ADSs, and the issuance of ADSs upon the deposit of shares, will also attract stamp duty at the rate described above for sale and purchase transactions unless the withdrawal or deposit does not result in a change in the beneficial ownership of the shares under Hong Kong law. The issuance of the ADSs upon the deposit of shares issued directly to the depositary or for the account of the depositary does not incur stamp duty if it does not involve a change of beneficial ownership in the shares. No Hong Kong stamp duty is payable upon the transfer of ADSs outside Hong Kong.

U.S. Federal Income Tax Considerations

The following is a discussion of material U.S. federal income tax consequences of owning and disposing of ADSs or shares by the U.S. Holders described below, but it does not purport to be a comprehensive description of all the tax considerations that may be relevant to a particular person’s decision to own such ADSs or shares. This discussion does not address any alternative minimum tax considerations or the potential application of the Medicare contribution tax to “net investment income” of non-corporate U.S. Holders. In addition, this discussion does not address U.S. state, local and non-U.S. tax consequences. The discussion applies only to U.S. Holders who hold ADSs or shares as capital assets for U.S. federal income tax purposes and does not address all of the U.S. federal income tax consequences that may be relevant to U.S. Holders that are subject to special rules, such as:

· certain financial institutions;

· dealers or traders in securities who use a mark-to-market method of tax accounting;

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· persons holding ADSs or shares as part of a straddle, conversion transaction, integrated transaction or similar transaction;

· persons whose functional currency for U.S. federal income tax purposes is not the U.S. dollar;

· partnerships or other entities classified as partnerships for U.S. federal income tax purposes;

· tax-exempt entities, “individual retirement accounts” or “Roth IRAs”;

· persons that own or are deemed to own 10% or more of our stock, by vote or value;

· persons who acquired our ADSs or shares pursuant to the exercise of an employee stock option or otherwise as compensation; or

· persons holding shares in connection with a trade or business conducted outside of the United States.

If an entity that is classified as a partnership for U.S. federal income tax purposes owns ADSs or shares, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the activities of the partnership. Partnerships owning ADSs or shares and partners in such partnerships should consult their tax advisers as to the particular U.S. federal income tax consequences of owning and disposing of the ADSs or shares.

This discussion is based on the Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions, final, temporary and proposed U.S. Treasury regulations and the PRC Treaty, all as of the date hereof. These laws are subject to change, possibly on a retroactive basis. It is also based, in part, on representations by the Depositary and assumes that each obligation under the Deposit Agreement and any related agreement will be performed in accordance with its terms. U.S. Holders should consult their tax advisers concerning the U.S. federal, state, local and non-U.S. tax consequences of owning and disposing of ADSs or shares in their particular circumstances.

As used herein, a “U.S. Holder” is a person that for U.S. federal income tax purposes is a beneficial owner of ADSs or shares and is: (i) a citizen or individual resident of the United States; (ii) a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States, any state therein or the District of Columbia; or (iii) an estate or trust the income of which is subject to U.S. federal income taxation regardless of its source.

In general, a U.S. Holder who owns ADSs should be treated as the owner of the underlying shares represented by those ADSs for U.S. federal income tax purposes. Accordingly, no gain or loss should be recognized if a U.S. Holder exchanges ADSs for the underlying shares represented by those ADSs.

The U.S. Treasury has expressed concerns that parties to whom American depositary shares are released before delivery of shares to the depositary (a pre-release), or intermediaries in the chain of ownership between holders and the issuer of the securities underlying the American depositary shares, may be taking actions that are inconsistent with the claiming of foreign tax credits by holders of American depositary shares. Such actions would also be inconsistent with the claiming of the favorable tax rates, described below, applicable to dividends received by certain non-corporate holders. Accordingly, the creditability of foreign taxes and the availability of the favorable tax rates for dividends received by certain non-corporate holders, described below, could be affected by actions taken by such parties or intermediaries.

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Except as specifically described below, this discussion assumes that we were not, and will not become, a passive foreign investment company, or PFIC, for any taxable year.

Taxation of Distributions

Distributions received by a U.S. Holder on ADSs or shares, other than certain pro rata distributions of common shares to all shareholders, will constitute foreign-source dividend income to the extent paid out of our current or accumulated earnings and profits (as determined for U.S. federal income tax purposes). Because we do not maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions generally will be reported to U.S. Holders as dividends. Dividends will be included in a U.S. Holder’s income on the date of the U.S. Holder’s or, in the case of ADSs, the Depositary’s receipt of the dividend. The amount of the dividend will equal the U.S. dollar value of the Hong Kong dollar distribution, calculated by reference to the exchange rate in effect on the date of receipt, regardless of whether the payment is converted into U.S. dollars on the date of receipt. If the dividend is converted into U.S. dollars on the date of receipt, a U.S. Holder should not be required to recognize foreign currency gain or loss in respect of the dividend income. A U.S. Holder may have foreign currency gain or loss if the dividend is converted into U.S. dollars after the date of receipt. Corporate U.S. Holders will not be entitled to claim a dividends-received deductions with respect to dividends paid by us.

Subject to applicable limitations and the discussion above regarding concerns expressed by the U.S. Treasury, dividends paid by “qualified foreign corporations” to certain non-corporate U.S. shareholders are taxable at rates applicable to long-term capital gains. A foreign corporation is treated as a qualified foreign corporation with respect to dividends paid on stock that is readily tradable on an established securities market in the United States, such as the New York Stock Exchange where our ADSs are traded. A foreign corporation may also be treated as a qualified foreign corporation if it is eligible for benefits of a comprehensive income tax treaty with the United States determined by the U.S. Treasury to be satisfactory for these purposes and that includes an exchange of information program. Non-corporate U.S. Holders should consult their tax advisers to determine whether these favorable rates may apply to dividends they receive from us and whether they are subject to any special rules that limit their ability to be taxed at these favorable rates.

As described in “—Taxation—The PRC,” we are regarded as a CRE pursuant to the provisions of the New EIT Law and the Notice. Accordingly, dividends paid with respect to our ordinary shares or ADSs generally will be subject to PRC withholding taxes. For U.S. federal income tax purposes, the amount of a dividend would include any amounts withheld by us in respect of PRC taxes. Subject to applicable limitations, any PRC income taxes withheld from dividends on ADSs or shares (in the case of a U.S. Holder that is eligible for the benefits of the PRC Treaty, at a rate not exceeding the rate provided by the PRC Treaty) may be creditable against the U.S. Holder’s U.S. federal income tax liability. Where a U.S. Holder is eligible for the benefits of the PRC Treaty, PRC taxes withheld in excess of the rate applicable under the PRC Treaty will not be eligible for credit against the U.S. Holder’s U.S. federal income tax liability. The rules governing foreign tax credits are complex, and U.S. Holders should consult their tax advisers regarding the creditability of foreign taxes in their particular circumstances. Instead of claiming a credit, a U.S. Holder may, at the U.S. Holder’s election, deduct such PRC taxes in computing taxable income, subject to applicable limitations. An election to deduct foreign taxes instead of claiming foreign tax credits must apply to all foreign taxes paid or accrued in the taxable year.

Sale or Other Disposition of ADSs or Shares

A U.S. Holder will generally recognize capital gain or loss on the sale or other disposition of ADSs or shares, which will be long-term capital gain or loss if the U.S. Holder has held such ADSs or shares for more than one year. The amount of the U.S. Holder’s gain or loss will be equal to the difference between the amount realized on the sale or other disposition and the U.S. Holder’s tax basis in the ADSs or shares (each determined in U.S. dollars).

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As described in “—Taxation —The PRC,” gains from dispositions of our ADSs or shares may be subject to PRC tax. A U.S. Holder’s amount realized would include the gross amount of the disposition proceeds before any withholding or deduction of PRC tax. Although under the Code any such gain of a U.S. Holder would generally be characterized as U.S.-source income, a U.S. Holder that is eligible for the benefits of the PRC Treaty may be able to elect to treat the gain as foreign-source gain for foreign tax credit purposes. The rules governing foreign tax credits are complex and the creditability of foreign taxes is subject to limitations. U.S. Holders should consult their tax advisers regarding their eligibility for benefits under the PRC Treaty and the creditability of any PRC tax paid with respect to dispositions in their particular circumstances.

Passive Foreign Investment Company Considerations

We believe that we were not a PFIC for U.S. federal income tax purposes for our taxable year ended December 31, 2017. In general, a non-U.S. company will be a PFIC for U.S. federal income tax purposes for any taxable year in which (i) 75% or more of its gross income consists of passive income or (ii) 50% or more of the average quarterly value of its assets consists of assets that produce, or are held for the production of, passive income. As PFIC status depends upon the composition of our income and assets and the market value of our assets from time to time, and since there are uncertainties in the manner of application of the PFIC rules, there can be no assurance that we will not be a PFIC for any taxable year.

If we were a PFIC for any taxable year during which a U.S. Holder held ADSs or shares, certain adverse U.S. federal income tax rules would apply on a disposition (including certain pledges) of ADSs or shares by the U.S. Holder. In general, under those rules, gain recognized by the U.S. Holder on a sale or other disposition of ADSs or shares would be allocated ratably over the U.S. Holder’s holding period for the ADSs or shares. The amounts allocated to the taxable year of the sale or other disposition and to any year before we became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to tax at the highest rate in effect for individuals or corporations, as appropriate, for such taxable year, and an interest charge would be imposed on the resulting tax liability for each such taxable year. Any distribution in respect of ADSs or shares in excess of 125% of the average of the annual distributions on ADSs or shares received by the U.S. Holder during the preceding three years or the U.S. Holder’s holding period, whichever is shorter, would be subject to taxation in the same manner. Certain elections (such as a mark-to-market election) may be available to U.S. Holders and may result in alternative tax treatment.

In addition, if we were to be treated as a PFIC in a taxable year in which we pay a dividend or the prior taxable year, the favorable rates discussed above with respect to dividends received by certain non-corporate U.S. Holders would not apply.

If we are a PFIC for any taxable year during which a U.S. Holder owned our ADSs or shares, the U.S. Holder will generally be required to file annual reports on IRS Form 8621.

Information Reporting and Backup Withholding

Payments of dividends and sales proceeds that are made within the United States or through certain U.S.-related financial intermediaries may be subject to information reporting and backup withholding, unless the U.S. Holder is an exempt recipient or, in the case of backup withholding, the U.S. Holder provides a correct taxpayer identification number and certifies that it is not subject to backup withholding. The amount of any backup withholding from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability and may entitle such U.S. Holder to a refund, provided that the required information is timely furnished to the Internal Revenue Service.

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Subject to certain exceptions, U.S. Holders who are individuals or certain specified entities may be required to securities of non-U.S. companies, or non-U.S. accounts through which they are held. U.S. Holders should consult their tax advisers regarding the effect, if any, of this requirement on the ownership and disposition of our ADSs or shares.

F. Dividends and Paying Agents

Not applicable.

G. Statement by Experts

Not applicable.

H. Documents on Display

We are subject to the informational requirements of the Exchange Act and accordingly file reports and other information with the Securities and Exchange Commission. You may inspect and copy our reports and other information we file with the Securities and Exchange Commission at the public reference facilities maintained by the Securities and Exchange Commission. Copies of such material may also be obtained at prescribed rates by writing to the Public Reference Section of the Securities and Exchange Commission at 100 F Street, NE, Washington, D.C. 20549. Please call 1-800-SEC-0330 for information on the location and operation of the Securities and Exchange Commission’s public reference facilities. Our filings with the Securities and Exchange Commission are also available to the public over the internet at its website at http://www.sec.gov.

I. Subsidiary Information

Not applicable.

ITEM 11. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

Our market risk exposures primarily consist of fluctuations in oil and gas prices, exchange rates and interest rates.

Commodity Price Risks

We are exposed to fluctuations in prices of crude oil. International oil prices are volatile and this volatility has a significant effect on our net sales and profit. We do not hedge market risk resulting from fluctuations in oil prices. See “Item 4—Information on the Company—Business Overview—Overview” and “Item 3—Key Information—Risk Factors—Risks Relating to Our Operations—Our business, revenues and profits fluctuate with changes in oil and gas prices.”

Currency Risk

Our foreign exchange exposure gives rise to market risk associated with exchange rate movements.

Substantially all of our oil and gas sales are denominated in Renminbi and U.S. dollars. China adopted a managed floating exchange rate approach based on market supply and demand and with reference to a basket of currencies. From January 1, 2017 to December 31, 2018, Renminbi appreciated approximately 10.32% against U.S. dollar.

Management has assessed the Company’s exposure to foreign currency risk by using a sensitivity analysis on the change in foreign exchange rate of the U.S. dollars, to which the Company is mainly exposed to as at December 31, 2017 and 2016. Based on management’s assessment at December 31, 2017, a 5% strengthening/weakening of RMB against U.S. dollars would have increased/decreased the profit for the year of the Company by 0.06% (2016: 6.63%) and the equity of the Company by 0.31% (2016: 0.46%). This analysis has been determined assuming that the change in foreign exchange rates had occurred at the end of the reporting period and had been applied to the foreign currency balances to which the Company has significant exposure with all other variables held constant. The analysis is performed on the same basis for 2016.

The depreciation of Renminbi against U.S. dollar may have the following impact on us:

· Our oil and gas sales may increase, because the benchmark oil and gas prices are usually in U.S. dollars;

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· Our cost for imported equipment and materials will increase, because most of these costs are denominated in U.S. dollars; and

· Our debt repayment burden will increase, since all of our debt is denominated in U.S. dollars.

For further information on our currency risk, see “Item 3—Key Information—Risk Factors—Risks Relating to the PRC—Government control of currency conversion and future movements in exchange rates may adversely affect our operations and financial condition.”

Interest Rate Risk

We are exposed to interest rate risk arising from our debts. An upward fluctuation in interest rates increases the cost of new debt and the cost of servicing our floating rate debt. We may use interest rate swap transactions, from time to time, to hedge our interest rate exposure when considered appropriate, based on existing and anticipated market conditions.

As of December 31, 2017, the interest rates for 95.5% of our outstanding debts were fixed. The term of the weighted average balance was approximately 9.35 years. A fixed interest rate can reduce the volatility of finance costs in uncertain markets. We do not currently engage in any interest rate hedging activities.

As of December 31, 2017, the interest rates for 98.8% of our total outstanding long-term debts were fixed. The following table sets forth additional information about the expected maturity dates of our outstanding long-term debt (including the current portion) as of December 31, 2017.

	2018			2019			2020			2021			2022			2023 and after			Total		Fair value as of December 31, 2017
	(Rmb in millions, except percentages)
Long-term loans, including current portion
Floating rate		210.9			210.9			210.9			107.9			60.9			623.3			1,424.9		1,428.7
Interest rate- Tangguh		Libor + 0.19% ~0.33 5%			Libor + 0.19% ~0.335%			Libor + 0.19% ~0.335%			Libor + 0.19% ~0.335%			Libor + 0.19% ~0.335%			Libor + 0.19% ~0.335%
Interest rate- Tangguh III		Libor + 1.37% ~3.45%			Libor + 1.37% ~ 3.45%			Libor + 1.37% ~3.45%			Libor + 1.37% ~3.45%			Libor + 1.37% ~3.45%			Libor + 1.37% ~3.45%
Long-term guaranteed notes, including current portion
Fixed rate		4,879.7			1,951.9			9,759.5			9,759.5			9,759.5			79,962.4			116,072.4		127,766.8
Average interest rate		4.45	%		4.48	%		4.57	%		4.68	%		4.74	%		4.99	%

For additional discussions of our market risks, see “Item 3—Key Information—Risk Factors.”

Item 12. Description of Securities other than equity securities

A. Debt Securities

Not applicable.

B. Warrants and Rights

Not applicable.

C. Other Securities

Not applicable.

D. American Depositary Shares

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JPMorgan Chase Bank, N.A. is our Depositary. The depositary’s office is located at 4 New York Plaza, New York, NY 10004. Each of our ADSs represents 100 shares.

ADR Fees Payable by Investors

The Depositary may charge each person to whom ADRs are issued, including, without limitation, issuances against deposits of shares, issuances in respect of share distributions, rights and other distributions, issuances pursuant to a stock dividend or stock split declared by us, or issuances pursuant to a merger, exchange of securities or any other transaction or event affecting the ADSs or the deposited securities, and each person surrendering ADSs for withdrawal of deposited securities or whose ADSs are cancelled or reduced for any other reason, US$5.00 for each 100 ADSs (or portion thereof) issued, delivered, reduced, cancelled or surrendered, as the case may be.

The following additional charges shall be incurred by the ADR holders, by any party depositing or withdrawing shares or by any party surrendering ADSs and/or to whom ADSs are issued (including, without limitation, issuances pursuant to a stock dividend or stock split declared by us or an exchange of stock regarding the ADSs or the Deposited Securities or a distribution of ADSs), whichever is applicable:

· a fee of up to US$0.05 per ADS for any cash distribution made pursuant to the deposit agreement;

· a fee of US$1.50 per ADR for transfers of certificated or direct registration ADRs;

· a fee of up to US$0.05 per ADS per calendar year (or portion thereof) for services performed by the Depositary in administering the ADRs (which fee may be charged on a periodic basis during each calendar year and shall be assessed against holders of ADRs as of the record date or record dates set by the Depositary during each calendar year shall be payable in the manner described in the next succeeding provision);

· a fee for the reimbursement of such fees, charges and expenses as are incurred by the Depositary or any of its agents (including, without limitation, the custodian and expenses incurred on behalf of holders in connection with compliance with foreign exchange control regulations or any law or regulation relating to foreign investment) in connection with the servicing of the shares or other deposited securities, the sale of securities (including, without limitation, deposited securities), the delivery of deposited securities or otherwise in connection with the Depositary's or its custodian's compliance with applicable law, rule or regulation (which fees and charges shall be assessed on a proportionate basis against holders as of the record date or dates set by the Depositary and shall be payable at the sole discretion of the Depositary by billing such holders or by deducting such charge from one or more cash dividends or other cash distributions);

· stock transfer or other taxes and other governmental charges;

· cable, telex and facsimile transmission and delivery charges incurred at the request of an ADR holder in connection with the deposit or delivery of shares;

· transfer or registration fees for the registration of transfer of deposited securities on any applicable register in connection with the deposit or withdrawal of deposited securities;

· in connection with the conversion of foreign currency into U.S. dollars, the fees, expenses and other charges charged by the Depositary or its agent (which may be a division, branch or affiliate) so appointed in connection with such conversion; and

· fees of any division, branch or affiliate of the Depositary utilized by the Depositary to direct, manage or execute any public or private sale of securities under the deposit agreement.

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Payments Received by Foreign Private Issuer

The Depositary has agreed to reimburse certain company expenses related to our ADS program and incurred by us in connection with the program. The Depositary reimbursed us, or paid amounts on our behalf to third parties, or waived its fees and expenses, of US$480,759.92 for the year ended December 31, 2017.

Direct Payments

The table below sets forth the types of expenses that the Depositary has agreed to reimburse, and the invoices relating to the year ended December 31, 2017 that were reimbursed:

Category of Expenses	Amount Reimbursed for Fiscal Year Ended December 31, 2017 (US$)(3)
Investor relations(1)		134,308.96
Broker reimbursements(2)		114,335.34
NYSE annual listing fees		85,000.00
TSX annual listing fees		89,285.71
ADR related legal fees		57,829.91
Total		480,759.92

(1) Includes investor relation service fees and investor relations expenses for road show in 2018.

(2) Broker reimbursements are fees payable to Broadridge and other service providers for the distribution of hard copy material to beneficial ADR holders in the Depositary Trust Company. Corporate material includes information related to shareholders’ meetings and related voting instruction cards. These fees are SEC approved.

(3) Includes the 30% withholding tax paid to the U.S. government.

Indirect Payments

The Depositary has also agreed to waive fees for standard costs associated with the administration of the ADS program and has paid certain expenses directly to third parties on our behalf. The table below sets forth those expenses that the Depositary waived or paid directly to third parties relating to the year ended December 31, 2017:

Category of Expenses	Amount Reimbursed for Fiscal Year Ended December 31, 2017 (US$)
Fees waived		150,000

PART II

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

A. Material Modifications to the Instruments Defining the Rights of Security Holders

None.

B. Material Modifications to the Rights of Registered Securities by Issuing or Modifying any Other Class of Securities

None.

C. Withdrawal or Substitution of a Material Amount of the Assets Securing any Registered Securities

Not applicable.

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D. Change of Trustees or Paying Agents for any Registered Securities

Not applicable.

E. Use of Proceeds

Not applicable.

ITEM 15. CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures

An evaluation was carried out under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness, as of December 31, 2017, of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act).

Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2017, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported as and when required by the SEC’s rules and forms and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Management’s annual report on internal control over financial reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2017 using the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, our management has concluded that our internal control over financial reporting as of December 31, 2017 was effective.

(c) Attestation Report of the Registered Public Accounting Firm

Our independent auditors have issued an audit report on the effectiveness of our internal control over financial reporting. This report appears on page F-4.

(d) Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the year ended December 31, 2017 that have materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

Aloysius Hau Yin Tse has been designated by our Board as an audit committee financial expert. Mr. Tse is independent as defined in the listing standards of the New York Stock Exchange.

ITEM 16B. CODE OF ETHICS

Our Board adopted a Code of Ethics in 2003 to provide guidelines to our senior management and directors in legal and ethical matters as well as the sensitivities involved in reporting illegal and unethical matters. The Code of Ethics covers areas such as supervisory rules, insider dealing, market malpractices, conflict of interests, company opportunities, protection and proper use of our assets as well as reporting requirements. As part of the continued efforts to improve our corporate governance standards, our Board conducted an annual review to the Code of Ethics since 2009, and the current version of the Code of Ethics was reviewed and adopted in August 2017.

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We have provided all our directors and senior officers with a copy of the Code of Ethics and require them to comply with the Code of Ethics, so as to ensure our operation is proper and lawful. We will take disciplinary actions towards any act which is in breach of the Code of Ethics. Any change or waiver, explicit or implicit, with respect to our Code of Ethics, must be disclosed to our shareholders either in our annual report or on our internet website, www.cnoocltd.com.

We have posted our Code of Ethics on our website. To request a copy of our Code of Ethics free of charge, please contact our investor relations manager, by email to ir@cnooc.com.cn.

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The aggregate fees billed for professional services rendered by our principal accountant for the audit of our annual financial statements were Rmb 46.7 million for 2016 and Rmb 50.9 million (US$7.8 million) for 2017.

Audit-Related Fees

The aggregate fees billed for services that are normally provided by the accountants in connection with statutory and regulatory filings or engagements and assurance and related services by our principal accountant that are reasonably related to the performance of the audit or review of financial statements and are not reported under “Audit Fees” were Rmb 6.0 million for 2016 and Rmb4.5 million (US$0.7 million) for 2017.

Tax Fees

The aggregate fees billed for professional service rendered by the principal accountant for tax compliance, tax advice and tax planning were nil for 2016 and nil for 2017.

All Other Fees

The aggregate fees billed for professional services rendered by our principal accountant for risk management advisory services and information systems reviews were nil for 2016 and Rmb 250,000 (USD$38,424)for 2017.

There are no other fees payable to our principal accountant for products and/or services provided by our principal accountant, other than the services reported above, for the financial year ended December 31, 2016 and for the financial year ended December 31, 2017.

Audit Committee’s pre-approval policies and procedures

Our audit committee under our Board is responsible for the appointment, compensation and oversight of the work of our principal accountant. Our audit committee adopted a policy calling for the audit committee’s pre-approval for the engagement of our principal accountant for audit and permitted non-audit services. Our Board has also ratified the policy and procedures. Under this audit committee policy, proposed services may be pre-approved by our audit committee either on an annual basis or on a case-by-case basis. Appendices to the audit committee policy set forth (1) the audit, audit-related, tax and other services that may be subject to the general annual pre-approval of the audit committee; and (2) a list of prohibited non-audit services. Our audit committee will periodically review and revise these appendices based on its subsequent determinations. The audit committee policy also provides for procedures to establish annual fee levels or budgets for pre-approved services and ratios between different categories of pre-approved services. In addition, the audit committee policy contains provisions that deal with compliance, monitoring, reporting and other related matters .

During 2017, all fees for audit-related services, tax services and all other services paid to our principal accountant were approved by our audit committee.

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ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Not applicable.

ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

None.

ITEM 16F. CHANGE IN REGISTRANT'S CERTIFYING ACCOUNTANT

Not applicable.

ITEM 16G. CORPORATE GOVERNANCE

See “Item 6—Directors, Senior Management and Employees—Board Practice—Summary of Significant Differences in Corporate Governance Practices for Purposes of Section 303A.11 of the New York Stock Exchange Listed Company Manual.”

ITEM 16H. MINE SAFETY DISCLOSURE

Not applicable.

PART III

ITEM 17. FINANCIAL STATEMENTS

Not applicable.

ITEM 18. FINANCIAL STATEMENTS

See pages beginning on page F-1 following Item 19.

ITEM 19. EXHIBITS

The following documents are filed as part of this annual report:

Exhibit Number	Document
1.1	Articles of Association of the Registrant, as amended in 2009, incorporated by reference to Exhibit 1.1 to our Annual Report on Form 20-F for fiscal year 2010 filed with the Securities and Exchange Commission (File number: 1-14966) and Exhibit 99.1 to Form 6-K furnished with the Securities and Exchange Commission on March 30, 2012 (File number: 1-14966).
1.2	Memorandum of Association of the Registrant, incorporated by reference to Exhibit 3.2 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862) and Exhibit 99.1 to Form 6-K furnished with the Securities and Exchange Commission on March 30, 2012 (File number: 1-14966).
2.1	Form of Indenture, incorporated by reference to Exhibit 2.1 to our annual report on Form 20-F for fiscal year 2002 filed with the Securities and Exchange Commission (File Number: 1-14966).
2.2	Trust Deed dated December 15, 2004 among CNOOC Limited, CNOOC Finance (2004) Limited and J.P. Morgan Corporate Trustee Services Limited, incorporated by reference to Exhibit 2.2 to our annual report on Form 20-F for fiscal year 2004 filed with the Securities and Exchange Commission (File Number: 1-14966).
2.3	Indentures dated January 26, 2011 among CNOOC Finance (2011) Limited, as Issuer, CNOOC Limited, as Guarantor, and The Bank of New York Mellon, as Trustee*.

^* Pursuant to Instruction 2(b)(i) to Item 19 of Form 20-F, we undertake to furnish this document upon request of the Securities and Exchange Commission.

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2.4	Indentures dated May 2, 2012 among CNOOC Finance (2012) Limited, as Issuer, CNOOC Limited, as Guarantor, Citicorp International Limited, as Trustee, Citibank, N.A., London Brach, as Paying Agent, and Citigroup Global Markets Deutschland AG, as Registrar*.
2.5	Fourth Supplemental Indenture dated March 22, 2013 to the Senior Debt Indenture dated May 4, 2007 among CNOOC Limited, Deutsche Bank Trust Company Americas and Nexen Inc., incorporated by reference to Exhibit 4.1 to Form 6-K furnished with the Securities and Exchange Commission on March 22, 2013 (File number: 1-14966).
2.6	Seventh Supplemental Indenture dated March 22, 2013 to the Trust Indenture dated April 28, 1998 among CNOOC Limited, CIBC Mellon Trust Company, The Bank of New York Mellon and Nexen Inc., incorporated by reference to Exhibit 4.2 to Form 6-K furnished with the Securities and Exchange Commission on March 22, 2013 (File number: 1-14966).
2.7	Form of Indenture among CNOOC Finance (2013) Limited, CNOOC Limited and The Bank of New York Mellon, incorporated by reference to Exhibit 4.1 to Form F-3 filed with the Securities and Exchange Commission on May 1, 2013 (File number: 333-188261)
2.8	Form of 1.125% Guaranteed Note due 2016, incorporated by reference to Exhibit 4.2 to Form 6-K furnished with the Securities and Exchange Commission on May 9, 2013 (File number: 1-14966)
2.9	Form of 1.750% Guaranteed Note due 2018, incorporated by reference to Exhibit 4.3 to Form 6-K furnished with the Securities and Exchange Commission on May 9, 2013 (File number: 1-14966)
2.10	Form of 3.000% Guaranteed Note due 2023, incorporated by reference to Exhibit 4.4 to Form 6-K furnished with the Securities and Exchange Commission on May 9, 2013 (File number: 1-14966)
2.11	Form of 4.250% Guaranteed Note due 2043, incorporated by reference to Exhibit 4.5 to Form 6-K furnished with the Securities and Exchange Commission on May 9, 2013 (File number: 1-14966)
2.12	Form of Indenture among CNOOC Nexen Finance (2014) ULC, CNOOC Limited and The Bank of New York Mellon, incorporated by reference to Exhibit 4.3 to Post-Effective Amendment No. 1  to Form F-3 filed with the Securities and Exchange Commission on April 22, 2014 (File number: 333-188261)
2.13	Form of 1.625% Guaranteed Note due 2017, incorporated by reference to Exhibit 4.2 to Form 6-K furnished with the Securities and Exchange Commission on May 1, 2014 (File number: 1-14966)
2.14	Form of 4.250% Guaranteed Note due 2024, incorporated by reference to Exhibit 4.3 to Form 6-K furnished with the Securities and Exchange Commission on May 1, 2014 (File number: 1-14966)
2.15	Form of 4.875% Guaranteed Note due 2044, incorporated by reference to Exhibit 4.4 to Form 6-K furnished with the Securities and Exchange Commission on May 1, 2014 (File number: 1-14966)
2.16	Form of Indenture among CNOOC Finance (2015) Australia Pty Ltd, CNOOC Limited and The Bank of New York Mellon, incorporated by reference to Exhibit 4.5 to Post-Effective Amendment No.2  to Form F-3 filed with the Securities and Exchange Commission on April 27, 2015(File number: 333-188261)
2.17	Form of Indenture among CNOOC Finance (2015) U.S.A. LLC, CNOOC Limited and The Bank of New York Mellon, incorporated by reference to Exhibit 4.7 to Post-Effective Amendment No. 2 to Form F-3 filed with the Securities and Exchange Commission on April 27, 2015 (File number: 333-188261)
2.18	Form of 2.625% Guaranteed Note due 2020, incorporated by reference to Exhibit 4.1 to Form 6-K furnished with the Securities and Exchange Commission on May 5, 2015 (File number: 1-14966)

^* Pursuant to Instruction 2(b)(i) to Item 19 of Form 20-F, we undertake to furnish this document upon request of the Securities and Exchange Commission.

106 

2.19	Form of 3.500% Guaranteed Note due 2025, incorporated by reference to Exhibit 4.2 to Form 6-K furnished with the Securities and Exchange Commission on May 5, 2015 (File number: 1-14966)
2.20	Form of 4.200% Guaranteed Note due 2045, incorporated by reference to Exhibit 4.3 to Form 6-K furnished with the Securities and Exchange Commission on May 5, 2015 (File number: 1-14966)
4.1	The Asset Swap Agreement dated July 20, 1999 between CNOOC and Offshore Oil Company Limited, incorporated by reference to Exhibit 10.1 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.2	The Asset Allocation Agreement dated July 20, 1999 between CNOOC and Offshore Oil Company Limited, incorporated by reference to Exhibit 10.2 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.3	The Reorganization Agreement dated September 13, 1999 between CNOOC, Offshore Oil Company Limited and CNOOC Limited, incorporated by reference to Exhibit 10.3 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.4	Form of the Equity Transfer Agreement between CNOOC and CNOOC Limited, incorporated by reference to Exhibit 10.4 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.5	Form of the Transfer Agreement dated October 1, 1999 between CNOOC and Offshore Oil Company Limited regarding the transfer of the rights and obligations of CNOOC under the 37 PSCs and one geophysical exploration agreement, incorporated by reference to Exhibit 10.5 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.6	Form of Equity Transfer Agreement between China Offshore Oil East China Sea Corporation and Offshore Oil Company Limited regarding the transfer of the rights and obligations under Joint Venture Contract of Shanghai Petroleum and Natural Gas Company Limited dated July 28, 1992 to Offshore Oil Company Limited, incorporated by reference to Exhibit 10.6 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.7	Transfer Agreement dated September 9, 1999 between CNOOC and Offshore Oil Company Limited regarding the transfer of the rights and obligations of CNOOC under the Natural Gas Sale and Purchase Contract dated December 22, 1992 to Offshore Oil Company Limited, incorporated by reference to Exhibit 10.7 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.8	Transfer Agreement dated September 9, 1999 between CNOOC and Offshore Oil Company Limited regarding the transfer of the rights and obligations of CNOOC under the Natural Gas Sale and Purchase Contract dated November 7, 1992 to Offshore Oil Company Limited, incorporated by reference to Exhibit 10.8 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.9	Transfer Agreement dated September 9, 1999 among CNOOC, Offshore Oil Company Limited, the four PRC subsidiaries and CNOOC’s affiliates regarding the transfer of the rights and obligations of the technical services agreements to Offshore Oil Company Limited, incorporated by reference to Exhibit 10.9 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.10	Nanshan Terminal Leasing Agreement dated September 9, 1999 between CNOOC, Hainan China Oil and Offshore Natural Gas Company and Offshore Oil Company Limited, incorporated by reference to Exhibit 10.10 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).

107 

4.11	Trademark License Agreement dated September 9, 1999 between CNOOC, Offshore Oil Company Limited and CNOOC Limited, incorporated by reference to Exhibit 10.11 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.12	Trademark License Agreement dated September 9, 1999 between China Offshore Oil Marketing Company, CNOOC Limited and Offshore Oil Company Limited, incorporated by reference to Exhibit 10.12 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.13	Trademark License Agreement between CNOOC, CNOOC Limited and CNOOC China Limited, incorporated by reference to Exhibit 4.13 to our Annual Report on Form 20-F for fiscal year 2008 filed with the Securities and Exchange Commission (File Number: 1-14966).
4.14	Trademark License Agreement between CNOOC, CNOOC Limited and CNOOC China Limited, incorporated by reference to Exhibit 4.14 to our Annual Report on Form 20-F for fiscal year 2008 filed with the Securities and Exchange Commission (File Number: 1-14966).
4.15	Property Leasing Agreement dated September 9, 1999 between Wui Hai Enterprise Company Limited and Offshore Oil Company Limited in respect of the office premises at 6th, 7th and 8th Floors, CNOOC Plaza, No. 6 Dong Zhi Men Wai Xiao Jie, Beijing, incorporated by reference to Exhibit 10.18 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.16	Property Leasing Agreement dated September 9, 1999 between China Offshore Oil Western South China Sea Corporation and Offshore Oil Company Limited in respect of the office premises at 1st to 9th Floors, Nantiao Road, Potou District Zhangjiang, Guangdong, incorporated by reference to Exhibit 10.19 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.17	Property Leasing Agreement dated September 9, 1999 between China Offshore Oil Bohai Corporation and Offshore Oil Company Limited in respect of the office premises at 1st to 7th Floors and 9th Floor, 2-37 He Kou Jie, Tanggu District, Tianjin, incorporated by reference to Exhibit 10.20 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.18	Property Leasing Agreement dated September 9, 1999 between China Offshore Oil East China Sea Corporation and Offshore Oil Company Limited in respect of the office premises at 20th, 22nd and 23rd Floors, 583 Ling Ling Road, Shanghai, the PRC, incorporated by reference to Exhibit 10.21 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.19	Property Leasing Agreement dated September 9, 1999 between China Offshore Oil Eastern South China Sea Corporation and Offshore Oil Company Limited in respect of the office premises at 3rd Floor and 6th to 11th Floors, 1 Second Industrial Road, Shekou, Shenzhen, the PRC, incorporated by reference to Exhibit 10.22 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.20	Property Leasing Agreement dated September 9, 1999 between China Offshore Oil Bohai Corporation and Offshore Oil Company Limited in respect of the Chengbei Warehouse, Chengbei Road, Tanggu District, Tianjin City, the PRC, incorporated by reference to Exhibit 10.23 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).

108 

4.21	Property Leasing Agreement dated September 9, 1999 between Overseas Oil & Gas Corporation, Ltd. and China Offshore Oil (Singapore) International Pte Ltd in respect of the residential premises at 10-01 and 17-002 Aquamarine Tower, 50 Bayshore Road, 13-05 Jade Tower, 60 Bayshore Road, Singapore, incorporated by reference to Exhibit 10.24 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.22	Suizhong Pier Agreement dated September 9, 1999 between Offshore Oil Company Limited and China Offshore Bohai Corporation, incorporated by reference to Exhibit 10.25 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.23	Form of Novation Agreement among CNOOC, CNOOC China Limited, the Banks and other financial institution and the Fuji Bank Limited Hong Kong Branch, as agent, in respect of the transfer of the US$110 million syndicated loan, incorporated by reference to Exhibit 10.26 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.24	Form of the Undertaking Agreement between CNOOC and CNOOC Limited, incorporated by reference to Exhibit 10.27 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.25	Form of Pre-Global Offering Share Option Scheme for the Senior Management of CNOOC Limited, incorporated by reference to Exhibit 10.31 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.26	Form of Share Option Scheme for the Senior Management of CNOOC Limited, incorporated by reference to Exhibit 10.32 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.27	CNOOC Limited Share Option Scheme adopted on December 31, 2005, incorporated by reference to Exhibit 4.37 to our Annual Report on Form 20-F for fiscal year 2005 filed with the Securities and Exchange Commission (File Number: 1-14966).
4.28	Subscription Agreement dated March 17, 2000 among CNOOC Limited, CNOOC (BVI) Limited, Overseas Oil & Gas Corporation, Ltd., et al., incorporated by reference to Exhibit 10.33 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.29	Subscription Agreement dated May 31, 2000 among CNOOC Limited, CNOOC (BVI) Limited, Overseas Oil & Gas Corporation, Ltd. and Hutchison International Limited, incorporated by reference to Exhibit 10.34 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.30	Subscription Agreement dated May 31, 2000 among CNOOC Limited, CNOOC (BVI) Limited, Overseas Oil & Gas Corporation, Ltd. and Hong Kong Electric Holdings Limited, incorporated by reference to Exhibit 10.35 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.31	Subscription Agreement dated June 28, 2000 among CNOOC Limited, CNOOC (BVI) Limited, Overseas Oil & Gas Corporation, Ltd., et al., incorporated by reference to Exhibit 10.36 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).
4.32	Corporation Placing Agreement dated February 6, 2001 among CNOOC Limited, China National Offshore Oil Corporation, Shell Eastern Petroleum (Pte) Limited and Merrill Lynch Far East Limited, incorporated by reference to Exhibit 10.37 to our Registration Statement on Form F-1 filed with the Securities and Exchange Commission (File Number: 333-10862).

109 

4.33	Equity Transfer Agreement dated September 5, 2003 between CNOOC China Limited and CNOOC (Summary Translation), incorporated by reference to Exhibit 4.38 to our annual report on Form 20-F for fiscal year 2003 filed with the Securities and Exchange Commission (File Number: 1-14966).
4.34	Framework Agreement dated April 8, 2004 with CNOOC Finance Corporation Limited (Summary Translation), incorporated by reference to Exhibit 4.39 to our annual report on Form 20-F for fiscal year 2003 filed with the Securities and Exchange Commission (File Number: 1-14966).
4.35	Framework Agreement dated December 8, 2005 with CNOOC (Summary Translation), incorporated by reference to Exhibit 4.45 to our Annual Report on Form 20-F for fiscal year 2005 filed with the Securities and Exchange Commission (File number: 1-14966).
4.36	Framework Agreement dated December 8, 2005 with China Oilfield Services Limited (Summary Translation), incorporated by reference to Exhibit 4.46 to our Annual Report on Form 20-F for fiscal year 2005 filed with the Securities and Exchange Commission (File number: 1-14966).
4.37	Framework Agreement dated December 8, 2005 with Offshore Oil Engineering Co., Ltd. (Summary Translation), incorporated by reference to Exhibit 4.47 to our Annual Report on Form 20-F for fiscal year 2005 filed with the Securities and Exchange Commission (File number: 1-14966).
4.38	Sale and Purchase Agreement, dated January 8, 2006 between CNOOC Exploration & Production Limited and South Atlantic Petroleum Limited (certain statements, marked with an asterisk in brackets [*], have been omitted from this agreement pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended, and the omitted materials have been filed separately in paper form with the Securities and Exchange Commission), incorporated by reference to Exhibit 4.49 to our Annual Report on Form 20-F for fiscal year 2005 filed with the Securities and Exchange Commission (File number: 1-14966).
4.39	Framework Agreement dated November 8, 2007 with China BlueChemical Ltd. (Summary Translation), incorporated by reference to Exhibit 4.37 to our Annual Report on Form 20-F for fiscal year 2007 filed with the Securities and Exchange Commission (File number: 1-14966).
4.40	Framework Agreement dated November 8, 2007 with CNOOC (Summary Translation), incorporated by reference to Exhibit 4.38 to our Annual Report on Form 20-F for fiscal year 2007 filed with the Securities and Exchange Commission (File number: 1-14966).
4.41	Framework Agreement dated November 8, 2007 with China Oilfield Services Limited (Summary Translation), incorporated by reference to Exhibit 4.39 to our Annual Report on Form 20-F for fiscal year 2007 filed with the Securities and Exchange Commission (File number: 1-14966).
4.42	Framework Agreement dated November 8, 2007 with Offshore Oil Engineering Co., Ltd. (Summary Translation), incorporated by reference to Exhibit 4.40 to our Annual Report on Form 20-F for fiscal year 2007 filed with the Securities and Exchange Commission (File number: 1-14966).
4.43	Framework Agreement dated November 1, 2010 with CNOOC (Summary Translation), incorporated by reference to Exhibit 4.43 to our Annual Report on Form 20-F for fiscal year 2010 filed with the Securities and Exchange Commission (File number: 1-14966).
4.44	Arrangement Agreement dated July 23, 2012 among CNOOC Limited, CNOOC Canada Holding Ltd. and Nexen Inc., incorporated by reference to Exhibit 4.44 to our Annual Report on Form 20-F for fiscal year 2012 filed with the Securities and Exchange Commission (File number: 1-14966).
4.45	Framework Agreement dated November 6, 2013 with CNOOC (Summary Translation), incorporated by reference to Exhibit 4.45 to our Annual Report on Form 20-F for fiscal year 2014 filed with the Securities and Exchange Commission (File number: 1-14966).

110 

4.46	Framework Agreement dated November 15, 2016 with CNOOC (Summary Translation), incorporated by reference to Exhibit 4.46 to our Annual Report on Form 20-F for fiscal year 2016 filed with the Securities and Exchange Commission (File number: 1-14966).
4.47	Framework Agreement dated December 1, 2016 with CNOOC Finance (Summary Translation), incorporated by reference to Exhibit 4.47 to our Annual Report on Form 20-F for fiscal year 2016 filed with the Securities and Exchange Commission (File number: 1-14966).
8.1	List of Subsidiaries.
10.1	Letter from CNOOC Limited dated May 23, 2002 regarding receipt of certain representations from Arthur Andersen & Co pursuant to the requirements of the Securities and Exchange Commission, incorporated by reference to Exhibit 10 to our annual report on Form 20-F for fiscal year 2001 filed with the Securities and Exchange Commission (File Number: 1-14966).
11.1	Code of Ethics for Directors and Senior Officers, as amended in 2017.
12.1	Certification by the Chief Executive Officer in accordance with Section 302 of the Sarbanes-Oxley Act of 2002.
12.2	Certification by the Chief Financial Officer in accordance with Section 302 of the Sarbanes-Oxley Act of 2002.
13.1	Sarbanes-Oxley Act of 2002 Section 906 Certification furnished to (not filed with) the Securities and Exchange Commission.
15.1	2017 Reserves Reports of Ryder Scott Company, L.P.
15.2	2017 Reserves Reports of Gaffney, Cline & Associates (Consultants) Pte Ltd.
15.3	2017 Reserves Report of RPS
15.4	2017 Reserves Audit Report of Ryder Scott Company, L.P.
15.5	2017 Reserves Audit Report of McDaniel & Associates Consultants Ltd.
15.6	2017 Reserves Audit Report of DeGolyer and MacNaughton
15.7	Letter from Ernst & Young (incorporated by reference to Exhibit 15.7 of our Annual Report on Form 20-F (file No. 001-14966) filed with the Securities and Exchange Commission on April 17, 2014).
15.8	Consent from Ryder Scott Company, L.P.
15.9	Consent from Gaffney, Cline & Associates (Consultants) Pte Ltd.
15.10	Consent from RPS
15.11	Consent from McDaniel & Associates Consultants Ltd.
15.12	Consent from DeGolyer and MacNaughton

111 

Signature

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

CNOOC Limited
By:	/s/ Jiewen Li
	Name:   Jiewen Li Title:     Joint Company Secretary

Date: April 19, 2018

112 

CNOOC LIMITED

CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2015, 2016 AND 2017

TOGETHER WITH REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

F-1

INDEX TO FINANCIAL STATEMENTS

	Page
CNOOC LIMITED
Report of independent registered public accounting firm on financial statements for the years ended December 31, 2015, 2016 and 2017	F-3
Report of independent registered public accounting firm on internal control over financial reporting as of Decmeber 31, 2017	F-4
Consolidated statements of profit or loss and other comprehensive income for the years ended December 31, 2015, 2016 and 2017	F-5
Consolidated statements of financial position as of December 31, 2016 and 2017	F-6
Consolidated statements of changes in equity for the years ended December 31, 2015, 2016 and 2017	F-7
Consolidated statements of cash flows for the years ended December 31, 2015, 2016 and 2017	F-9
Notes to the consolidated financial statements	F-10

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To Shareholders and the Board of Directors of CNOOC Limited

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of financial position of CNOOC Limited (the "Company") and subsidiaries (collectively referred to as "the Group") as of December 31, 2017 and 2016, the related consolidated statements of profit or loss and other comprehensive income, consolidated statements of changes in equity, and consolidated statements of cash flows, for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with International Financial Reporting Standards issued by the International Accounting Standards Board and Hong Kong Financial Reporting Standards issued by the Hong Kong Institute of Certified Public Accountants.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Group's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 29, 2018 expressed an unqualified opinion on the Group's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte Touche Tohmatsu

Certified Public Accountants

Hong Kong

March 29, 2018

We have served as the Company's auditor since 2013.

F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To Shareholders and the Board of Directors of CNOOC Limited

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of CNOOC Limited (the "Company") and its subsidiaries (collectively referred to as the "Group") as of December 31, 2017, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Group maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control —Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2017 of the Group and our report dated March 29, 2018 expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying "Management’s annual report on internal control over financial reporting". Our responsibility is to express an opinion on the Group’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Group in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte Touche Tohmatsu

Certified Public Accountants

Hong Kong

March 29, 2018

F-4

CNOOC LIMITED

CONSOLIDATED STATEMENTS OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2015, 2016 AND 2017

(All amounts expressed in millions of Renminbi/US$, except per share data)

	Notes		2015 RMB			2016 RMB			2017 RMB			2017 US$
			million
REVENUE
Oil and gas sales		4		146,597			121,325			151,888			23,345
Marketing revenues				21,422			20,310			28,907			4,443
Other income				3,418			4,855			5,595			860
				171,437			146,490			186,390			28,648
EXPENSES
Operating expenses				(28,372	)		(23,211	)		(24,282	)		(3,732	)
Taxes other than income tax		10(ii)		(10,770	)		(6,941	)		(7,210	)		(1,108	)
Exploration expenses				(9,900	)		(7,359	)		(6,881	)		(1,058	)
Depreciation, depletion and amortization		6		(73,439	)		(68,907	)		(61,257	)		(9,415	)
Special oil gain levy		10 (iii)		(59	)		-			(55	)		(8	)
Impairment and provision		6, 13		(2,746	)		(12,171	)		(9,130	)		(1,403	)
Crude oil and product purchases				(19,840	)		(19,018	)		(27,643	)		(4,249	)
Selling and administrative expense				(5,705	)		(6,493	)		(6,861	)		(1,055	)
Others				(3,150	)		(4,802	)		(6,021	)		(925	)
				(153,981	)		(148,902	)		(149,340	)		(22,953	)
PROFIT/(LOSS) FROM OPERATING ACTIVITIES				17,456			(2,412	)		37,050			5,695
Interest income		6		873			901			653			100
Finance costs		7		(6,118	)		(6,246	)		(5,044	)		(775	)
Exchange (losses)/gains, net				(143	)		(790	)		356			55
Investment income		6		2,398			2,774			2,409			370
Share of profits/(losses) of associates		15		256			(609	)		302			46
Share of profit of a joint venture				1,647			533			553			85
Non-operating income, net				761			574			78			12
PROFIT/(LOSS) BEFORE TAX		6		17,130			(5,275	)		36,357			5,588
Income tax credit/(expense)		10(i)		3,116			5,912			(11,680	)		(1,795	)
PROFIT FOR THE YEAR ATTRIBUTABLE TO OWNERS OF THE PARENT				20,246			637			24,677			3,793
OTHER COMPREHENSIVE INCOME/(EXPENSE)
Items that may be subsequently reclassified to profit or loss
Exchange differences on translation of foreign operations				7,979			10,422			(10,121	)		(1,556	)
Share of other comprehensive income/(expense) of  associates				74			(127	)		36			6
Other items that will not be reclassified to profit or loss
Fair value change on equity investments designated as at fair value through other comprehensive income		17(ii)		(1,573	)		(461	)		(542	)		(83	)
Others				134			12			54			8
OTHER COMPREHENSIVE INCOME/(EXPENSE) FOR THE YEAR, NET OF TAX				6,614			9,846			(10,573	)		(1,625	)
TOTAL COMPREHENSIVE INCOME FOR THE YEAR ATTRIBUTABLE TO OWNERS OF THE PARENT				26,860			10,483			14,104			2,168
EARNINGS PER SHARE ATTRIBUTABLE TO OWNERS OF THE PARENT
Basic (RMB Yuan)		11		0.45			0.01			0.55			US$0.09
Diluted (RMB Yuan)		11		0.45			0.01			0.55			US$0.09

The accompanying notes are an integral part of these financial statements.

F-5

CNOOC LIMITED

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

AS OF DECEMBER 31, 2016 AND 2017

(All amounts expressed in millions of Renminbi/US$)

			2016		2017		2017
	Notes		RMB		RMB		US$
			million
NON-CURRENT ASSETS
Property, plant and equipment		13		432,465		395,868		60,844
Intangible assets		14		16,644		15,070		2,316
Investments in associates		15		3,695		4,067		625
Investment in a joint venture		16		26,300		25,079		3,855
Equity investments		17, 32		4,266		3,540		544
Deferred tax assets		10(i)		24,844		25,509		3,921
Other non-current assets		18		7,422		9,248		1,421
Total non-current assets				515,636		478,381		73,526
CURRENT ASSETS
Inventories and supplies		19		8,709		7,354		1,130
Trade receivables		20		10,199		8,386		1,289
Due from related companies				13,263		12,914		1,985
Derivative financial assets		32		428		-		-
Equity investments		17, 32		15		14		2
Other financial assets		17, 32		52,889		74,344		11,426
Other current asset				5,977		7,874		1,211
Time deposits with maturity over three month		21		16,830		15,380		2,364
Cash and cash equivalent		21		13,735		12,572		1,932
Total current assets				122,045		138,838		21,339
CURRENT LIABILITIES
Loans and borrowings		24		14,867		9,360		1,439
Borrowings from the parent company		28		4,811		4,532		697
Trade and accrued payables		22		10,254		10,062		1,547
Due to the parent company		28		215		193		30
Due to related companies		28		15,091		16,651		2,559
Derivative financial liabilities		32		426		-		-
Other payables and accrued liabilities		23		14,651		13,913		2,137
Taxes payable				6,775		6,701		1,030
Total current liabilities				67,090		61,412		9,439
NET CURRENT ASSETS				54,955		77,426		11,900
TOTAL ASSETS LESS CURRENT LIABILITIES				570,591		555,807		85,426
NON-CURRENT LIABILITIES
Loans and borrowings		24		130,798		118,358		18,191
Provision for dismantlement		25		50,426		52,893		8,130
Deferred tax liabilities		10(i)		5,670		3,303		508
Other non-current liabilities				1,326		1,278		196
Total non-current liabilities				188,220		175,832		27,025
Net assets				382,371		379,975		58,401
EQUITY
Equity attributable to owners of the parent
Issued capital		26		43,081		43,081		6,621
Reserves		27		339,290		336,894		51,780
Total equity				382,371		379,975		58,401

The accompanying notes are an integral part of these financial statements.

F-6

CNOOC LIMITED

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2015, 2016 AND 2017

(All amounts expressed in millions of Renminbi)

	Issued capital		Cumulative translation reserve			Statutory and non- distributable reserves			Other reserves			Retained earnings			Proposed final dividend			Total
Balance at January 1, 2015		43,081		(20,918	)		20,000			6,497			319,625			11,325			379,610
Profit for the year		-		-			-			-			20,246			-			20,246
Other comprehensive income/(expense), net of income tax		-		7,979			-			(1,365	)		-			-			6,614
Total comprehensive income/(expense)		-		7,979			-			(1,365	)		20,246			-			26,860
2014 final dividend		-		-			-			-			58			(11,325	)		(11,267	)
2015 interim dividend		-		-			-			-			(9,162	)		-			(9,162	)
Proposed 2015 final dividend		-		-			-			-			(9,397	)		9,397			-
Balance at December 31, 2015		43,081		(12,939	)*		20,000	*		5,132	*		321,370	*		9,397	*		386,041
Balance at January 1, 2016		43,081		(12,939	)		20,000			5,132			321,370			9,397			386,041
Profit for the year		-		-			-			-			637			-			637
Other comprehensive income/(expense), netof income tax		-		10,422			-			(576	)		-			-			9,846
Total comprehensive income/(expense)		-		10,422			-			(576	)		637			-			10,483
2015 final dividend		-		-			-			-			(143	)		(9,397	)		(9,540	)
2016 interim dividend		-		-			-			-			(4,613	)		-			(4,613	)
Proposed 2016 final dividend		-		-			-			-			(9,096	)		9,096			-
Balance at December 31, 2016		43,081		(2,517	)*		20,000	*		4,556	*		308,155	*		9,096	*		382,371

F-7

CNOOC LIMITED

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2015, 2016 AND 2017 (continued)

(All amounts expressed in millions of Renminbi)

	Issued capital		Cumulative translation reserve			Statutory and non-distributable reserves			Other reserves			Retained earnings			Proposed final dividend			Total
Balance at January 1, 2017		43,081		(2,517	)		20,000			4,556			308,155			9,096			382,371
Profit for the year		-		-			-			-			24,677			-			24,677
Other comprehensive expense, net of income tax		-		(10,121	)		-			(452	)		-			-			(10,573	)
Total comprehensive (expense)/income		-		(10,121	)		-			(452	)		24,677			-			14,104
2016 final dividend		-		-			-			-			183			(9,096	)		(8,913	)
2017 interim dividend		-		-			-			-			(7,587	)		-			(7,587	)
Proposed 2017 final dividend		-		-			-			-			(10,830	)		10,830			-
Appropriation to reserve**		-		-			50,000			-			(50,000	)		-			-
Balance at December 31, 2017		43,081		(12,638	)*		70,000	*		4,104	*		264,598	*		10,830	*		379,975

* These reserve accounts constitute the consolidated reserves of approximately RMB336,894 million (December 31, 2016: RMB339,290 million ) in the consolidated statement of financial position.

** During the year ended December 31, 2017 , CNOOC China Limited (the "CNOOC China"), the Company’s wholly-owned subsidiary, appropriated RMB50,000 million of the general reserve fund.

The accompanying notes are an integral part of these financial statements.

F-8

CNOOC LIMITED

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2015, 2016 AND 2017

(All amounts expressed in millions of Renminbi/US$)

	Notes		2015 RMB			2016 RMB			2017 RMB			2017 US$
	million
CASH FLOWS FROM OPERATING ACTIVITIES
Cash generated from operations		30		96,095			82,137			110,625			17,003
Income taxes paid				(16,000	)		(9,274	)		(15,891	)		(2,442	)
Net cash flows from operating activities				80,095			72,863			94,734			14,561
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditure				(67,674	)		(51,347	)		(47,734	)		(7,337	)
Additions to investments in associates				(9	)		(221	)		(161	)		(25	)
Decrease in time deposits with maturity over three months				4,825			1,180			1,450			223
Dividends received from an associate				164			135			116			18
Dividends received from a joint venture				32			-			243			37
Interest received				812			1,010			666			102
Investment income received				2,177			2,013			1,821			280
Purchase of other financial assets				(122,030	)		(62,900	)		(122,267	)		(18,792	)
Purchase of equity investments				(236	)		(63	)		(51	)		(8	)
Proceeds from sale of other financial assets				104,900			81,675			101,396			15,584
Proceeds from disposal of property, plant and equipment				544			532			110			17
Proceeds from disposal of an associate				-			33			-			-
Net cash flows used in investing activities				(76,495	)		(27,953	)		(64,411	)		(9,901	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of guaranteed notes				23,184			-			-			-
Repayment of guaranteed notes				(789	)		(4,866	)		(8,869	)		(1,363	)
Proceeds from bank loans				20,541			4,293			12,252			1,883
Repayment of bank loans				(24,127	)		(23,412	)		(13,052	)		(2,006	)
Dividends paid				(20,419	)		(14,153	)		(16,448	)		(2,528	)
Interest paid				(5,283	)		(5,102	)		(5,154	)		(792	)
Net cash flows used in financing activities				(6,893	)		(43,240	)		(31,271	)		(4,806	)
NET (DECREASE)/INCREASE IN CASH AND CASH EQUIVALENTS				(3,293	)		1,670			(948	)		(146	)
Cash and cash equivalents at beginning of year				14,918			11,867			13,735			2,111
Effect of foreign exchange rate changes, net				242			198			(215	)		(33	)
CASH AND CASH EQUIVALENTS AT END OF YEAR		21		11,867			13,735			12,572			1,932

The accompanying notes are an integral part of these financial statements.

F-9

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

1. CORPORATE INFORMATION

CNOOC Limited (the "Company") was incorporated in the Hong Kong Special Administrative Region ("Hong Kong") of the People's Republic of China (the "PRC") on August 20, 1999 to hold the interests in certain entities thereby creating a group comprising the Company and its subsidiaries (hereinafter collectively referred to as the "Group"). During the year, the Group was principally engaged in the exploration, development, production and sale of crude oil, natural gas and other petroleum products.

The registered office address of the Company is 65/F, Bank of China Tower, 1 Garden Road, Hong Kong.

In the opinion of the directors of the Company (the "Directors"), the parent and the ultimate holding company of the Company is China National Offshore Oil Corporation ("CNOOC"), a company established in the PRC. In November 2017, CNOOC changed its registered company name which is registered in Chinese pursuant to relevant laws and regulations of China to "中國海洋石油集團有限公司".

Particulars of the principal subsidiaries at the end of the reporting period are as follows:

Name of entity	Place of establishment	Nominal value of ordinary shares issued and paid-up/ registered capital	Percentage of equity attributable to the Group	Principal activities
Directly held subsidiaries:
CNOOC China Limited	Tianjin, PRC	RMB20 billion	100%	Offshore petroleum exploration, development, production and sales, and shale gas exploration in the PRC
China Offshore Oil (Singapore) International Pte Ltd	Singapore	SG$3 million	100%	Sales and marketing of petroleum products outside the PRC
CNOOC International Limited	British Virgin Islands	US$20,000,000,002	100%	Investment holding
CNOOC Finance (2003) Limited	British Virgin Islands	US$1,000	100%	Bond issuance
CNOOC Finance (2011) Limited	British Virgin Islands	US$1,000	100%	Bond issuance
CNOOC Finance (2012) Limited	British Virgin Islands	US$1,000	100%	Bond issuance
CNOOC Finance (2013) Limited	British Virgin Islands	US$1,000	100%	Bond issuance
Indirectly held subsidiaries(1):
CNOOC Deepwater Development Limited	Zhuhai, PRC	RMB20.3 billion	100%	Deepwater and low-grade oil and gas fields exploitation in the PRC and exploration, development, production and sales of oil and gas in the oil and gas fields of South China Sea
CNOOC Southeast Asia Limited	Bermuda	US$12,000	100%	Investment holding
CNOOC SES Ltd.	Malaysia	US$1	100%	Petroleum exploration, development and production in Indonesia
CNOOC Muturi Limited	Isle of Man	US$7,780,770	100%	Petroleum exploration, development and production in Indonesia
CNOOC NWS Private Limited	Singapore	SG$2	100%	Offshore petroleum exploration,  development and production in Australia
CNOOC Exploration & Production Nigeria Limited	Nigeria	NGN10 million	100%	Petroleum exploration, development and production in Africa

F-10

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

 1. CORPORATE INFORMATION (continued)

Name of entity	Place of establishment	Nominal value of ordinary shares issued and paid-up/ registered capital	Percentage of equity attributable to the Group	Principal activities
Indirectly held subsidiaries (continued)(1):
CNOOC Iraq Limited	British Virgin Islands	US$1	100%	Providing services of petroleum exploration and development in the Republic of Iraq
CNOOC Canada Energy Ltd.	Canada	100 common shares without a par value 103,000 preferred shares without a par value	100%	Oil sands exploration,   development and production in Canada
CNOOC Uganda Ltd	Uganda	1 million Uganda Shilling	100%	Petroleum exploration, development and production in Africa
Nexen Energy ULC	Canada	13,671,421,700 common shares without a par value	100%	Petroleum exploration, development and production in Canada
Nexen Petroleum U.K. Limited	England and Wales	GBP98,009,131	100%	Petroleum exploration, development and production in the UK
Nexen Petroleum Nigeria Limited	Nigeria	NGN30 million	100%	Petroleum exploration, development and production in Nigeria
OOGC America LLC	USA	N/A	100%	Petroleum exploration, development and production in the USA
Nexen Petroleum Offshore U.S.A. Inc.	USA	US$15,830	100%	Petroleum exploration, development and production in the USA
Nexen Oil Sands Partnership	Canada	N/A	100%	Petroleum exploration, development and production in Canada
CNOOC PETROLEUM BRASIL LTDA(2)	Brazil	R$2,965,600,000	100%	Petroleum exploration, development and production in Brazil
CNOOC Nexen Finance (2014) ULC	Canada	100 common shares without a par value	100%	Bond issuance
CNOOC Finance (2015) U.S.A. LLC	USA	N/A	100%	Bond Issuance
CNOOC Finance (2015) Australia Pty Ltd	Australia	US$1	100%	Bond Issuance

(1) All subsidiaries are indirectly held through CNOOC International Limited, except CNOOC Deepwater Development Limited which is indirectly held through CNOOC China Limited.

(2) The registered capital of CNOOC PETROLEUM BRASIL LTDA increased from R$2,436,000,000 to R$2,965,600,000 on 20 June 2017.

The above table lists the subsidiaries of the Company which, in the opinion of the Directors, principally affected the results for the year or formed a substantial portion of the total assets of the Group. To give details of other subsidiaries would, in the opinion of the Directors, result in particulars of excessive length.

F-11

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

2.1 STATEMENT OF COMPLIANCE

These financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRSs") issued by the International Accounting Standards Board (the "IASB"), Hong Kong Financial Reporting Standards ("HKFRSs") issued by the Hong Kong Institute of Certified Public Accountants (the "HKICPA"), the Rules Governing the Listing of Securities on The Stock Exchange of Hong Kong Limited (the "Listing Rules") and the Hong Kong Companies Ordinance (Cap. 622). A summary of the significant accounting policies adopted by the Group is set out below.

2.2 CHANGES IN ACCOUNTING POLICY AND DISCLOSURES

The IASB has issued a number of new and revised IFRSs that are first effective for the current accounting year commencing January 1, 2017 or later but available for early adoption. The equivalent new and revised HKFRSs consequently issued by the HKICPA have the same effective dates as those issued by the IASB and are in all material aspects identical to the pronouncements issued by the IASB.

The accounting policies adopted are consistent with those of the year ended December 31, 2016, except for the first time adoption of the amendments to IFRSs/HKFRSs effective for the Group’s financial year beginning on January 1, 2017. The adoption of the amendments had no material impact on the accounting policies, the disclosures or the amounts recognized in the consolidated financial statements of the Group. IFRS 9/HKFRS 9 (2009) Financial Instruments has been early adopted by the Company from year 2015.

The Group has not applied the following new and revised IFRSs/HKFRSs, which may be relevant to the Group and have been issued but are not yet effective, in these consolidated financial statements:

IFRS 9/HKFRS 9	Financial Instruments1
IFRS 15/ HKFRS 15	Revenue from Contracts with Customers and the
	related Amendments 1
IFRS 16/HKFRS 16	Leases2
IFRS 17/HKFRS 17	Insurance Contracts4
IFRIC 22/HK(IFRIC)-Int 22	Foreign Currency Transactions and Advance
	Consideration1
IFRIC 23/HK(IFRIC)-Int 23	Uncertainty over Income Tax Treatments2
Amendments to IFRS 2/HKFRS 2	Classification and Measurement of Share-based
	Payment Transactions1
Amendments to IFRS 4/HKFRS 4	Applying IFRS 9/HKFRS 9 Financial Instruments
	with IFRS 4/HKFRS 4 Insurance Contracts1
Amendments to IFRS 9/HKFRS 9	Prepayment Features with Negative Compensation2
Amendments to IFRS 10/HKFRS 10	Sale or Contribution of Assets between an
and IAS 28/HKAS 28	Investor and its Associate or Joint Venture3
Amendments to IAS 19	Plan Amendment, Curtailment or Settlement2
Amendments to IAS 28/HKAS 28	Long-term Interests in Associates and Joint
	Ventures2
Amendments to IAS 28/HKAS 28	As part of the Annual Improvements to IFRS
	Standards/HKFRSs 2014-2016 Cycle1
Amendments to IAS 40/HKAS 40	Transfers of Investment Property1
Amendments to IFRSs/HKFRSs	Annual Improvements to IFRS Standards/
	HKFRSs 2015-2017 Cycle2

1. Effective for annual periods beginning on or after 1 January 2018, except for the 2009 version of IFRS 9/HKFRS 9, which the Group adopted in advance

2. Effective for annual periods beginning on or after 1 January 2019

3. Effective for annual periods beginning on or after a date to be determined

4. Effective for annual periods beginning on or after 1 January 2021

F-12

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

2.2 CHANGES IN ACCOUNTING POLICY AND DISCLOSURES (continued)

IFRS 15/HKFRS 15 Revenue from Contracts with Customers

IFRS 15/HKFRS 15 Revenue from Contracts with Customers provides a single model for accounting for revenue arising from contracts with customers, focusing on the identification and satisfaction of performance obligations, and is effective for annual periods beginning on or after 1 January 2018. IFRS 15/HKFRS 15 will supersede IAS 18/HKAS 18 Revenue.

The Company expects to adopt the new revenue standard as of 1 January 2018 using the modified retrospective transition method. Based on our assessment, the Company does not expect the implementation of the standard to have a material effect on its consolidated financial statements.

IFRS 16/HKFRS 16 Leases

IFRS 16/HKFRS 16, which upon the effective date will supersede IAS 17/HKAS 17 Leases, introduces a single lessee accounting model and requires a lessee to recognize assets and liabilities for all leases with a term of more than 12 months, unless the underlying asset is of low value. Specifically, under IFRS 16/HKFRS 16, a lessee is required to recognize a right-of-use asset representing its right to use the underlying leased asset and a lease liability representing its obligation to make lease payments. Accordingly, a lessee should recognize depreciation of the right-of-use asset and interest on the lease liability, and also classify cash payments of the lease liability into a principal portion and an interest portion and present them in the consolidated statement of cash flows. Also, the right-of-use asset and the lease liability are initially measured on a present value basis. The measurement includes non-cancellable lease payments and also includes payments to be made in optional periods if the lessee is reasonably certain to exercise an option to extend the lease, or not to exercise an option to terminate the lease. This accounting treatment is significantly different from the lessee accounting for leases that are classified as operating leases under IAS 17/HKAS 17.

In respect of the lessor accounting, IFRS 16/HKFRS 16 substantially carries forward the lessor accounting requirements in IAS 17/HKAS 17. Accordingly, a lessor continues to classify its leases as operating leases or finance leases, and to account for these two types of leases differently.

The Group is in the process of assessing the impact of application of IFRS 16/HKFRS 16. For the moment, it is not practicable to provide a reasonable estimate of the effect of the application of IFRS 16/HKFRS 16 until the Group completes a detail review.

The Group anticipates that the application of other new and revised IFRSs/HKFRSs that have been issued but are not yet effective will have no material effect on the Group’s consolidated financial statements.

F-13

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of preparation

These consolidated financial statements have been prepared under the historical cost convention, except for as detailed in the accounting policies notes hereafter. These consolidated financial statements are presented in Renminbi ("RMB") and all values are rounded to the nearest million except when otherwise indicated.

Basis of consolidation

The consolidated financial statements include the financial statements of the Company and its subsidiaries for the year ended December 31, 2017.

The results of subsidiaries are consolidated from the date of acquisition, being the date on which the Group obtains control, and continue to be consolidated until the date that such control ceases. The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.

The results of subsidiaries are included in the Company's statement of profit or loss and other comprehensive income to the extent of dividends received and receivable. The Company's interests in subsidiaries are stated at cost less any impairment losses.

All intra-group balances, income and expenses and unrealized gains and losses and dividends resulting from intra-group transactions are eliminated in full.

F-14

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Business combinations and goodwill

Business combinations 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 the Group, liabilities assumed by the Group to the former owners of the acquiree and the equity interests issued by the Group in exchange for control of the acquiree. For each business combination, the Group elects whether it measures 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 related costs incurred are included in profit or loss.

When the Group acquires a business, it assesses the financial assets acquired and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree.

If the business combination is achieved in stages, the Group's previously held equity interest in the acquiree is remeasured to fair value at the acquisition date through profit or loss.

Any contingent consideration to be transferred by the acquirer is recognized at fair value at the acquisition date. Contingent consideration classified as an asset or liability is measured at subsequent reporting dates in accordance with IFRS 9/HKFRS 9 (2009) or IAS 39/HKAS 39, with the corresponding gain or loss being recognized in profit or loss. Contingent consideration that is classified as equity is not remeasured and subsequent settlement is accounted for within equity.

Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the amount recognized for non-controlling interests and any fair value of the Group's previously held equity interests in the acquiree over the identifiable net assets acquired and liabilities assumed. If the sum of this consideration and other items is lower than the fair value of the net assets of the business acquired, the difference is recognized in profit or loss as a gain on bargain purchase.

F-15

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Business combinations and goodwill (continued)

After initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the carrying value may be impaired. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group's cash-generating units, or groups of cash-generating units, that are expected to benefit from the synergies of the combination, irrespective of whether other assets or liabilities of the Group are assigned to those units or groups of units.

Impairment is determined by assessing the recoverable amount of the exploration and production ("E&P") segment, using value in use, to which the goodwill relates. Where the recoverable amount of the cash-generating unit (group of cash-generating units) is less than the carrying amount, an impairment loss on goodwill is recognized. An impairment loss recognized for goodwill is not reversed in a subsequent period.

Where goodwill has been allocated to a cash-generating unit (or group of cash-generating units) and part of the operation within that unit is disposed of, the goodwill associated with the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on the disposal. Goodwill disposed of in these circumstances is measured based on the relative value of the operation disposed of and the portion of the cash-generating unit retained.

Subsidiaries

Subsidiaries are all those entities over which the Group has power over the investee such that the Group is able to direct the relevant activities, has exposure or rights to variable returns from its involvement with the investee and has the ability to use its power over the investee to affect the amount of the investor's returns.

Associates

Based on the Group's ownership percentage (considering its direct ownership as well as potentially exercisable or convertible shares) and other contractual rights, the Group has significant influence over its associates, rather than the power to control.

The Group's investments in associates are stated in the consolidated statement of financial position at the Group's share of net assets under the equity method of accounting, less any impairment losses. Adjustments are made to bring into line any dissimilar accounting policies that may exist. Under the equity method, an investment in an associate is initially recognized in the consolidated statement of financial position at cost and adjusted thereafter to recognize the Group's share of the profit or loss and other comprehensive income of the associate. Unrealized gains and losses resulting from transactions between the Group and its associates are eliminated to the extent of the Group's investments in the associates, except where unrealized losses provide evidence of an impairment of the asset transferred. Goodwill arising from the acquisition of associates is included as part of the Group's investments in associates and is not individually tested for impairment.

Joint arrangements

Certain of the Group's 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 control

Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control.

F-16

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Joint arrangements (continued)

Joint operations

Some arrangements have been assessed by the Group 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 the Group's interests in production sharing arrangements and certain joint operation.

The Group entered into numerous production sharing arrangements or similar agreements in China and overseas countries. The Group's participating interest may vary in each arrangement. The Group, as one of the title owners under certain exploration and/or production licenses or permits, is required to bear exploration (with some exceptions in China), development and operating costs together with other co-owners based on each owner's participating interest. Once production occurs, a certain percentage of the annual production or revenue is first distributed to the local government, which, in most cases, with the nature of royalty and other taxes or expenses, and the rest of the annual production or revenue is allocated among the co-owners.

The Group accounts for the assets, liabilities, revenues and expenses relating to its interest in a joint operation in accordance with the IFRSs/HKFRSs applicable to the particular assets, liabilities, revenues and expenses.

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.

The Group's investments in joint ventures are stated in the consolidated statement of financial position at the Group's share of net assets under the equity method of accounting, less any impairment losses. Adjustments are made to bring into line any dissimilar accounting policies that may exist. Under the equity method, an investment in a joint venture is initially recognized in the consolidated statement of financial position at cost and adjusted thereafter to recognize the Group's share of the profit or loss and other comprehensive income of the joint venture. Where the profit sharing ratios are different to the Group's equity interest, the share of post-acquisition results of the joint ventures is determined based on the agreed profit sharing ratio. Unrealized gains and losses resulting from transactions between the Group and its joint ventures are eliminated to the extent of the Group's investments in the joint ventures, except where unrealized losses provide evidence of an impairment of the asset transferred. Goodwill arising from the acquisition of joint ventures is included as part of the Group's investments in joint ventures and is not individually tested for impairment.

Related parties

A party is considered to be related to the Group if:

(a) the party is a person or a close member of that person's family and that person

(i) has control or joint control of the Group;

(ii) has significant influence over the Group; or

(iii) is a member of the key management personnel of the Group or of a parent of the Group;

F-17

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Related parties (continued)

(b) the party is an entity where any of the following conditions applies:

(i) the entity and the Group are members of the same group;

(ii) one entity is an associate or joint venture of the other entity (or of a parent, subsidiary or fellow subsidiary of the other entity);

(iii) the entity and the Group are joint ventures of the same third party;

(iv) one entity is a joint venture of a third entity and the other entity is an associate of the third entity;

(v) the entity is a post-employment benefit plan for the benefit of employees of either the Group or an entity related to the Group;

(vi) the entity is controlled or jointly controlled by a person identified in (a); and

(vii) a person identified in (a)(i) has significant influence over the entity or is a member of the key management personnel of the entity (or of a parent of the entity).

Impairment of non-financial assets other than goodwill

Where an indication of impairment exists, or when annual impairment testing for an asset is required (other than inventories, deferred tax assets, financial assets and goodwill), the asset's recoverable amount is estimated. An asset's recoverable amount is the higher of the asset's or cash-generating unit's value in use and its fair value less costs of disposal, and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets, in which case the recoverable amount is determined for the cash-generating unit to which the asset belongs.

An impairment loss is recognized only if the carrying amount of an asset exceeds its recoverable amount. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. An impairment loss is charged to profit or loss in the period in which it arises in those expense categories consistent with the function of the impaired asset.

An assessment is made at the end of each reporting period as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss of an asset other than goodwill is reversed only if there has been a change in the estimates used to determine the recoverable amount of that asset, but not to an amount higher than the carrying amount that would have been determined (net of any depreciation/amortization) had no impairment loss been recognized for the asset in prior years. A reversal of such an impairment loss is credited to profit or loss in the period in which it arises.

Property, plant and equipment

Property, plant and equipment comprise oil and gas properties, and vehicles and office equipment and others.

(a) Oil and gas properties

For oil and gas properties, the successful efforts method of accounting is adopted. The Group capitalizes the initial acquisition costs of oil and gas properties. Impairment of initial acquisition costs is recognized based on exploratory experience and management judgement and charged to profit and loss as exploration expenses. Upon discovery of commercial reserves, acquisition costs are transferred to proved properties. The costs of drilling and equipping successful exploratory wells, all development expenditures 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 are capitalized. The costs of unsuccessful exploratory wells and all other exploration costs are expensed as incurred.

F-18

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Property, plant and equipment (continued)

(a) Oil and gas properties (continued)

The Group carries exploratory well costs as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Group is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expenses. Exploratory wells that discover potentially economic reserves in areas where major capital expenditure will be required before production would begin and when the major capital expenditure depends upon the successful completion of further exploratory work remain capitalized and are reviewed periodically for impairment.

Producing oil and gas properties are depreciated on a unit-of-production basis over the proved developed reserves. Common facilities that are built specifically to service production directly attributed to designated oil and gas properties are depreciated 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.

Capitalized acquisition costs of proved properties are depreciated on a unit-of-production method over the total proved reserves of the relevant oil and gas properties.

(b) Vehicles, office equipment and others

Vehicles, office equipment and others are stated at cost less accumulated depreciation and impairment losses. The straight-line method is adopted to depreciate the cost less any estimated residual value of these assets over their expected useful lives. The useful lives of vehicles, office equipment and other assets are in line with their beneficial periods.

Where parts of an item of property, plant and equipment have different useful lives, the cost of that item is allocated on a recoverable basis among the parts and each part is depreciated separately.

Residual values, useful lives and the depreciation method are reviewed and, adjusted if appropriate, at each reporting date.

Any gains and losses on disposals of property, plant and equipment (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) are recognized in profit or loss.

Intangible assets (other than goodwill)

The intangible assets of the Group comprise software, gas processing rights of the NWS Project, marketing transportation and storage contracts, drilling rig contracts and seismic data usage rights. Intangible assets with finite lives are carried at cost, less accumulated amortization and accumulated impairment losses. The cost of intangible assets acquired in a business combination is the fair value as at the date of acquisition. Intangible assets with finite lives except for gas processing rights, are amortized on the straight-line basis over the useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization period and the amortization method for an intangible asset with a finite useful life are reviewed at least at each financial year end.

F-19

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Intangible assets (other than goodwill) (continued)

The intangible assets regarding software have been amortized on the straight-line basis over their respective useful lives. The intangible asset regarding the gas processing rights has been amortized upon the commercial production of the liquefied natural gas on a unit-of-production basis over the total proved reserves of the relevant asset. The intangible assets regarding the marketing transportation and storage contracts and drilling rig contracts are amortized over the life of the contracts on the straight-line basis. The intangible assets related to the seismic data usage rights are amortized over the estimated useful life of the seismic data.

Major maintenance and repairs

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets and overhaul costs. Where an asset or part of an asset that was separately depreciated and is replaced, and it is probable that future economic benefits associated with the item will flow to the Group, the replacement expenditure is capitalized. Where part of the asset was not separately considered as a component, the replacement value is used to estimate the carrying amount of the replaced assets which is immediately written off. All other maintenance costs are expensed as incurred.

Research and development costs

All research costs are expensed as incurred.

Expenditure (other than that relating to oil and gas properties discussed above) incurred on projects to develop new products is capitalized and deferred only when the Group can demonstrate the technical feasibility of completing the intangible asset so that it will be available for use or sale, its intention to complete and its ability to use or sell the asset, how the asset will generate future economic benefits, the availability of resources to complete the project and the ability to measure reliably the expenditure during the development. Product development expenditure which does not meet these criteria is expensed when incurred.

Financial assets

All recognized financial assets are subsequently measured in their entirety at either amortized cost or fair value, depending on the classification of the financial assets.

(a) Financial assets at amortized cost

Debt instruments and hybrid contracts that meet the following conditions are subsequently measured at amortized cost less impairment loss:

• the asset is held within a business model whose objective is to hold assets in order to collect contractual cash flows; and

• the contractual terms of the instrument give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

All other financial assets are subsequently measured at fair value.

F-20

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Financial assets (continued)

(a) Financial assets at amortized cost (continued)

The effective interest method is a method of calculating the amortized cost of a debt instrument and of allocating interest income over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees and points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the debt instrument, or, where appropriate, a shorter period, to the net carrying amount on initial recognition. Interest income for debt instruments measured subsequently at amortized cost is recognized in profit or loss in accordance with the policies set out for "Revenue Recognition" below.

(b) Financial assets at fair value through profit or loss (FVTPL)

Investments in equity instruments are classified as at FVTPL, unless the Group designates such investment that is not held for trading as at FVTOCI on initial recognition.

A financial asset is held for trading if it has been acquired principally for the purpose of selling it in the near term or it is a derivative that is not designated and effective as a hedging instrument.

Debt instruments that do not meet the amortized cost criteria (see (a) above) are measured at FVTPL. In addition, debt instruments that meet the amortized cost criteria but are designated as at FVTPL are measured at FVTPL. A debt instrument may be designated as at FVTPL upon initial recognition if such designation eliminates or significantly reduces a measurement or recognition inconsistency that would arise from measuring assets or liabilities or recognizing the gains and losses on them on different bases.

Financial assets at FVTPL are measured at fair value at the end of each reporting period, with any gains or losses arising on remeasurement recognized in profit or loss.

(c) Financial assets at fair value through other comprehensive income (FVTOCI)

On initial recognition, the Group can make an irrevocable election (on an instrument-by-instrument basis) to designate investments in equity instruments as at FVTOCI. The Group has investments in certain equity instruments (publicly traded or non-publicly traded), the purpose of which are not held for trading, but held for medium or long-term strategic purpose. Therefore, those investments in equity securities are designated as at FVTOCI.

Investments in equity instruments at FVTOCI are initially measured at fair value plus transaction costs. Subsequently, they are measured at fair value with gains and losses arising from changes in fair value recognized in other comprehensive income and accumulated in the other reserves. The cumulative gain or loss will not be reclassified to profit or loss on disposal of the investments.

Dividends on these investments in equity instruments are recognized in profit or loss when the Group’s right to receive the dividends is established in accordance with IAS 18/HKAS 18 Revenue, unless the dividends clearly represent a recovery of part of the cost of the investment.

F-21

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

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.

An analysis of fair values of financial instruments and further details as to how they are measured are provided in note 32.

Impairment of financial assets

The Group assesses at each reporting date whether there is any objective evidence that a financial asset, other than those at FVTPL and FVTOCI, or a group of financial assets may be impaired.

In relation to trade and other receivables, a provision for impairment is made when there is objective evidence (such as the probability of insolvency or significant financial difficulties of the debtor and significant changes in the technological, market, economic or legal environment that have an adverse effect on the debtor) that the Group will not be able to collect all of the amounts due under the original terms of an invoice.

If there is objective evidence that an impairment loss on financial assets measured at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset's carrying amount and the present value of estimated future cash flows (excluding future credit losses that have not been incurred) discounted at the financial asset's original effective interest rate (the effective interest rate computed at initial recognition). The carrying amount of the asset is reduced either directly or through the use of an allowance account. The amount of the impairment loss is recognized in profit or loss.

If, in a subsequent year, the amount of the estimated impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized, the previously recognized impairment loss is reduced either directly or by adjusting the allowance account. Any subsequent reversal of an impairment loss is recognized in profit or loss, to the extent that the carrying value of the asset does not exceed amortized cost at the reversal date.

Derecognition of financial assets

A financial asset (or, where applicable a part of a financial asset or part of a group of similar financial assets) is derecognized when:

(i) The contractual rights to receive cash flows from the asset have expired; or

(ii) the Group has transferred its rights to receive cash flows from the asset, or the Group retains the contractual rights to receive the cash flows from the asset, but has assumed an obligation to pay the received cash flows in full without material delay to a third party under a "pass-through" arrangement; and either (a) has transferred substantially all the risks and rewards of the asset, or (b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has no control of the asset.

F-22

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Derecognition of financial assets (continued)

When the Group has transferred its rights to receive cash flows from an asset or has entered into a pass-through arrangement, it evaluates if and to what extent it has retained the risk and rewards of ownership of the asset. When it has neither transferred nor retained substantially all the risks and rewards of the asset nor transferred control of the asset, the Group continues to recognize the transferred asset to the extent of the Group's continuing involvement. In that case, the Group also recognizes an associated liability. The transferred asset and the associated liability are measured on a basis that reflects the rights and obligations that the Group has retained.

Financial liabilities at amortized cost (including interest-bearing loans and borrowings)

Financial liabilities including trade and accrued payables, other payables and accrued liabilities, and interest-bearing loans and borrowings are initially stated at fair value less directly attributable transaction costs and are subsequently measured at amortized cost, using the effective interest method. The related interest expense is recognized in profit or loss.

Gains and losses are recognized in profit or loss when the liabilities are derecognized as well as through the amortization process.

Financial guarantee contracts

A financial guarantee contract is recognized initially at its fair value including transaction costs that are directly attributable to the issue of the guarantee. Subsequent to initial recognition, the liability is measured at the higher of the best estimate of the expenditure required to settle the present obligation at the reporting date and the amount recognized less cumulative amortization.

Derecognition of financial liabilities

Financial liabilities are derecognized when the obligations under the liabilities are discharged, cancelled, or have expired.

When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and a recognition of a new liability, and the difference between the respective carrying amounts is recognized in profit or loss.

Offsetting of financial instruments

Financial assets and liabilities are offset and the net amount reported in the consolidated statement of financial position, if and only if, there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, or to realize the assets and settle the liabilities simultaneously.

Inventories and supplies

Inventories primarily consist of oil and supplies, including items for repairs and maintenance of oil and gas properties. Inventories are stated at the lower of cost and net realizable value. Costs of inventories and supplies represent purchase or production cost of goods and are determined on a weighted average basis.

Cash and cash equivalents

Cash and cash equivalents comprise cash at banks and on hand and short term deposits with an original maturity of three months or less.

F-23

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Provisions

(a) General

A provision is recognized 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.

(b) Dismantlement liability

Dismantlement liability is recognized when the Group has a present legal or constructive obligation as a result of the past events, and it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of the obligation can be made. A corresponding amount equivalent to the provision is also recognized as part of the cost of the related property, plant and equipment. The amount recognized is 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. The unwinding of the discount on the dismantlement provision is included as a finance cost.

Income tax

Income tax comprises current and deferred tax. Income tax is recognized in the consolidated statement of profit or loss and other comprehensive income, either as an expense as it relates to operating activities or as a component of the applicable categories of other comprehensive income or expense.

Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantially enacted, by the reporting date, in the countries where the Group operates and generates taxable income.

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 the accounting profit nor taxable profit or loss; and

· in respect of taxable temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, 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.

F-24

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Income tax (continued)

Deferred tax assets are recognized for all deductible temporary differences, the carryforward of unused tax credits and any unused tax losses to the extent that it is probable that taxable profit and taxable temporary differences will be available against which the deductible temporary differences, the carryforward of unused tax credits and unused tax losses can be utilized, except:

· when the deferred tax assets relating to the deductible temporary differences arise 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 the accounting profit nor taxable profit or loss; and

· in respect of deductible temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, deferred tax assets are only recognized to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized.

The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized. Unrecognized deferred tax assets are reassessed at each reporting date and are recognized to the extent that it is probable that sufficient taxable profit and taxable temporary differences will be available to allow all or part of the deferred tax asset to be utilized.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the reporting date.

Deferred tax assets and deferred tax liabilities are offset if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority.

Revenue recognition

Revenue is recognized when it is probable that the economic benefits will flow to the Group and when the revenue can be measured reliably, on the following bases:

(a) Oil and gas sales

Oil and gas sales represent the invoiced value of sales of oil and gas attributable to the interests of the Group, net of royalties, obligations to governments and other mineral interest owners. Revenue from the sale of oil and gas is recognized when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. Revenue from the production of oil and gas in which the Group has a joint interest with other producers is recognized based on the Group’s working interest and the terms of the relevant production sharing contracts. Differences between production sold and the Group’s share of production are not significant.

F-25

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Revenue recognition (continued)

(a) Oil and gas sales (continued)

Oil and gas lifted and sold by the Group above or below the Group's participating interests in the production sharing contracts results in overlifts and underlifts. The Group records these transactions in accordance with the entitlement method under which overlifts are recorded as liabilities and underlifts are recorded as assets at year-end oil prices. Settlement will be in kind or in cash when the liftings are equalised or in cash when production ceases.

The Group has entered into gas sale contracts with customers, which contain take-or-pay clauses. Under these contracts, the Group makes a long term supply commitment in return for a commitment from the buyer to pay for minimum quantities, whether or not it takes delivery. These commitments contain protective (force majeure) and adjustment provisions. If a buyer has a right to get a "make up" delivery at a later date, revenue recognition is deferred. If no such option exists according to the contract terms, revenue is recognized when the take-or-pay penalty is triggered.

(b) Marketing revenues

Marketing revenues principally represent the sales of oil and gas from the foreign partners under the production sharing contracts and revenues from the trading of oil and gas through the Company’s subsidiaries. The cost of the oil and gas sold is included in “Crude oil and product purchases” in the consolidated statement of profit or loss and other comprehensive income. In addition, the Group’s marketing activities in North America involves entering into contracts to purchase and sell crude oil, natural gas and other energy commodities, and use derivative contracts, including futures, forwards, swaps and options for hedging and trading purposes (collectively derivative contracts). Any change in the fair value is also included in marketing revenue.

(c) Other income

Other income mainly represents project management fees charged to foreign partners, handling fees charged to customers, the sales of diluents to third parties and gains from disposal of oil and gas properties and is recognized when the services have been rendered or the properties have been disposed of. Reimbursement of insurance claims is recognized when the compensation becomes receivable.

(d) Dividend income

Dividend income is recognized when the Group's right to receive payment is established.

(e) Interest income

Interest income is recognized as it accrues using the effective interest method.

The Group presents taxes collected from customers in the consolidated statement of profit or loss and other comprehensive income on a net basis.

F-26

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Share-based payment transactions

Employees (including directors) of the Group receive remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments ("equity-settled transactions").

The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which they are granted. The fair value is determined by using the Black-Scholes option pricing model, further details of which are given in note 26.

The cost of equity-settled transactions is recognized, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled. The cumulative expense recognized for equity-settled transactions at the end of the each reporting period until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The charge or credit to profit or loss for a period represents the movement in the cumulative expense recognized as at the beginning and end of that period.

No expense is recognized for awards that do not ultimately vest for the Group.

No equity-settled award was cancelled or modified during the years ended December 31, 2015, 2016 and 2017.

The dilutive effect of outstanding options is reflected as additional share dilution in the computation of earnings per share.

Retirement and termination benefits

The Group participates in defined contribution plans in accordance with local laws and regulations for full-time employees in the PRC and other countries in which it operates. The Group's contributions to these defined contribution plans are charged to profit or loss in the year to which they relate.

Borrowing costs

Borrowing costs consist of interest and other costs that an entity incurs in connection with the borrowing of funds. Borrowing costs directly relating to the acquisition, construction or production of a qualifying asset that necessarily takes a substantial period of time to get ready for its intended use or sale are capitalized as part of the cost of the respective assets. All other borrowing costs are expensed in the period in which they are incurred.

Foreign currencies

These consolidated financial statements are presented in RMB. Each entity in the Group maintains its books and records in its own functional currency. Foreign currency transactions recorded by the entities of the Group are initially recorded using their respective exchange rates ruling at the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are retranslated at the exchange rates ruling at the end of the reporting period. All differences arising on settlement or translation of monetary items are taken to profit or loss. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rates at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined. The gain or loss arising on retranslation of a non-monetary item is treated consistently with the recognition of the gain or loss on change in fair value of the item.

F-27

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Foreign currencies (continued)

The functional currencies of certain entities within the Group are currencies other than RMB. As at the end of the reporting period, the assets and liabilities of these entities are translated into the presentation currency of the Group at the exchange rates ruling at the reporting date, and their statement of profit or loss and other comprehensive income are translated into RMB at the weighted average exchange rates for the year. The resulting exchange differences are included in the cumulative translation reserve. On disposal of a foreign operation, the deferred cumulative amount recognized in equity relating to that particular foreign operation is recognized in profit or loss.

Operating leases

Leases where substantially all the rewards and risks of ownership of assets remain with the lessor are accounted for as operating leases. Where the Group is the lessee, rentals payable under operating leases are charged to profit or loss on the straight-line basis over the lease terms.

Prepaid land lease payments under operating leases in China are initially stated at cost and subsequently amortized on the straight-line basis over the lease terms.

Contingencies

A contingent liability is disclosed when the existence of an obligation will only be confirmed by future events or when the amount of the obligation cannot be measured reliably.

A contingent asset is not recognized in the financial statements, but is disclosed when an inflow of economic benefits is probable.

Significant accounting judgements, estimates and assumptions

The preparation of the consolidated financial statements in accordance with IFRSs and HKFRSs requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates and judgements are continuously evaluated and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. However, actual outcomes can differ from these estimates.

In the process of applying the Group's accounting policies, the Directors have made the following judgements, estimates and assumptions, which have the most significant effect on the amounts recognized in the consolidated financial statements.

(a) Reserve base

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

Pursuant to the oil and gas reserve estimation requirements under US Securities and Exchange Commission's rules, the Group uses 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 its proved oil and gas reserves.

F-28

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Significant accounting judgements, estimates and assumptions (continued)

(b) Carrying value of oil and gas properties

The calculation of the unit-of-production rate for oil and gas properties amortization could be impacted to the extent that actual production in the future is different from current forecast production based on proved reserves. This would generally result from significant changes in any of the factors or assumptions used in estimating reserves. These factors could include changes in proved reserves, the effect on proved reserves of differences between actual oil and gas prices and oil and gas price assumptions and unforeseen operational issues.

(c) Recoverable amount of oil and gas properties

The Company makes 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, the Company would make an estimate of the asset’s recoverable amount, which is calculated at the higher of the asset’s value in use and its fair value less costs of disposal. The Company recognizes an impairment loss only if the carrying amount of an asset exceeds its recoverable amount. The Company charges an impairment loss to the profit or loss in the period in which it arises. A reversal of an impairment loss is credited to the profit or loss 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 oil and gas 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 the Company's anticipated drilling plan, changes in the Company's capital costs and operating expense assumptions, and discount rate. There is a significant degree of uncertainty with the assumptions used to estimate future cash flows due to various risk factors. The complex economic outlook may also materially and adversely affect the Company’s key assumptions. Changes in economic conditions can also affect the discount rates applied in assessments of impairment.

Actual cash flows are likely to be different from those estimated or forecast since anticipated events frequently do not occur as expected and unforeseen events may arise. The Company's results of operations could be materially and adversely affected for the period in which future 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, the Company believes that the preparation of the sensitivity analysis for the impairment testing will be impracticable. Changes in assumptions could affect impairment charges and reversals in the consolidated statement of profit or loss and other comprehensive income, and the carrying amounts of assets in the consolidated statement of financial position.

F-29

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Significant accounting judgements, estimates and assumptions (continued)

(d) Dismantlement costs

Dismantlement costs will be incurred by the Group at the end of the operating life of certain of the Group's facilities and properties. 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.

(e) Taxes

Uncertainties exist with respect to the interpretation of complex tax regulations (including those applicable to tax credits) and the amount and timing of future taxable income. Given the wide range of international business relationships and the long term nature and complexity of existing contractual agreements, differences arising between the actual results and the assumptions made, or future changes to such assumptions, could necessitate future adjustments to tax income and expense already recorded. The Group establishes provisions, based on best estimates, for possible consequences of audits by the tax authorities of the respective countries in which it operates. The amount of such provisions is based on various factors, such as the Group's experience of previous tax audits and differing interpretations of tax regulations by the taxable entity and the responsible tax authority. Such differences of interpretation may arise on a wide variety of issues depending on the conditions prevailing in the respective group company's domicile.

F-30

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

4. OIL AND GAS SALES

	2015			2016			2017
Gross sales		150,618			124,648			156,304
Less: Royalties		(2,646	)		(2,398	)		(3,226	)
PRC government’s share of oil		(1,375	)		(925	)		(1,190	)
Oil and gas sales		146,597			121,325			151,888

5. SEGMENT INFORMATION

(a) Segment results

The Group is engaged worldwide in the upstream operating activities of the conventional oil and gas, shale oil and gas, oil sands and other unconventional oil and gas business. The Group reports the business through three operating and reporting segments: E&P, trading business and corporate. These segments are operating segments whose financial information are reviewed by the Group’s chief operating decision marker when making decisions regarding allocating resources and assessing performance. The geographical information is separately disclosed in (b).

F-31

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

5 SEGMENT INFORMATION (continued)

(a) Segment results (continued)

The following table presents the segment financial information for the Group for the years ended December 31, 2015, 2016 and 2017.

	E&P									Trading business									Corporate									Eliminations									Consolidated
	2015			2016			2017			2015			2016			2017			2015			2016			2017			2015			2016			2017			2015			2016			2017
External revenue		137,243			114,935			142,429			33,777			30,986			43,618			417			569			343			-			-			-			171,437			146,490			186,390
Intersegment revenue*		12,339			10,676			14,737			(12,339	)		(10,676	)		(14,737	)		85			113			84			(85	)		(113	)		(84	)		-			-			-
Total revenue		149,582			125,611			157,166			21,438			20,310			28,881			502			682			427			(85	)		(113	)		(84	)		171,437			146,490			186,390
Segment profit/(loss) for the year		15,695			(346	)		23,863			879			656			808			6,048			30,701			6,391			(2,376	)		(30,374	)		(6,385	)		20,246			637			24,677
Amounts included in the measure of segment profit or loss
Operating expenses		(28,372	)		(23,220	)		(24,282	)		-			-			-			-			-			-			-			9			-			(28,372	)		(23,211	)		(24,282	)
Taxes other than income tax		(10,748	)		(6,901	)		(7,169	)		7			-			-			(29	)		(40	)		(41	)		-			-			-			(10,770	)		(6,941	)		(7,210	)
Exploration expenses		(9,973	)		(7,393	)		(6,896	)		-			-			-			-			-			-			73			34			15			(9,900	)		(7,359	)		(6,881	)
Depreciation, depletion and amortization		(72,665	)		(68,333	)		(60,834	)		(324	)		(144	)		(67	)		(509	)		(470	)		(423	)		59			40			67			(73,439	)		(68,907	)		(61,257	)
Impairment and provision		(2,690	)		(12,180	)		(9,161	)		(56	)		9			-			-			-			31			-			-			-			(2,746	)		(12,171	)		(9,130	)
Selling and administrative expenses		(3,644	)		(4,920	)		(4,966	)		(340	)		(296	)		(269	)		(1,733	)		(1,307	)		(1,654	)		12			30			28			(5,705	)		(6,493	)		(6,861	)
Interest income		147			217			315			-			1			-			1,028			1,805			1,571			(302	)		(1,122	)		(1,233	)		873			901			653
Finance costs		(3,407	)		(3,384	)		(3,274	)		(1	)		(1	)		(1	)		(3,369	)		(4,183	)		(3,011	)		659			1,322			1,242			(6,118	)		(6,246	)		(5,044	)
Share of profits/(losses) of associates and a joint venture		(117	)		(63	)		(88	)		-			-			-			2,020			(13	)		943			-			-			-			1,903			(76	)		855
Income tax (expense)/credit		44			3,811			(11,236	)		(8	)		(24	)		(3	)		3,080			2,125			(441	)		-			-			-			3,116			5,912			(11,680	)
Other segment information
Investments in associates and a joint venture		800			737			655			-			-			-			27,613			29,258			28,491			-			-			-			28,413			29,995			29,146
Others		532,765			497,413			457,780			3,336			1,898			3,588			344,037			342,810			340,329			(244,189	)		(234,435	)		(213,624	)		635,949			607,686			588,073
Segment assets		533,565			498,150			458,435			3,336			1,898			3,588			371,650			372,068			368,820			(244,189	)		(234,435	)		(213,624	)		664,362			637,681			617,219
Segment liabilities		(364,056	)		(331,339	)		(301,167	)		(2,243	)		(947	)		(2,375	)		(145,475	)		(138,352	)		(124,794	)		233,453			215,328			191,092			(278,321	)		(255,310	)		(237,244	)
Capital expenditure		66,122			49,122			52,790			11			-			-			386			395			421			-			-			-			66,519			49,517			53,211

* Certain oil and gas produced by the E&P segment are sold via the trading business segment. For the Group's chief operating decision maker's assessment of segment performance, these revenues are reclassified back to E&P segment.

F-32

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

5. SEGMENT INFORMATION (continued)

(b) Geographical information

The Group mainly engages in the exploration, development, production and sale of crude oil, natural gas and other petroleum products in offshore China. Activities outside the PRC are mainly conducted in Canada, the United States of America, the United Kingdom, Nigeria, Argentina, Indonesia, Uganda, Iraq, Brazil and Australia etc.

In presenting the Group’s geographical information, revenues from external customers are based on the location of the Group’s customers, and non-current assets are attributed to the segments based on the location of the Group’s assets. 65% (2016: 70%, 2015: 73%) of the Group’s revenues are generated from PRC customers, and revenues generated from customers in other locations are individually less than 10%.

The following table presents certain non-current assets information for the Group’s geographical information for the years ended December 31, 2015, 2016 and 2017.

	PRC						Canada						Others						Consolidated
	2015		2016		2017		2015		2016		2017		2015		2016		2017		2015		2016		2017
Property, plant and equipment		193,359		174,853		162,027		105,383		103,173		95,552		155,399		154,439		138,289		454,141		432,465		395,868
Investments in associates  and a joint venture		3,499		3,451		3,680		816		-		-		24,098		26,544		25,466		28,413		29,995		29,146
Other non-current assets		7,087		6,593		8,502		694		731		605		47		98		141		7,828		7,422		9,248

(c) Information about major customers

The current year's revenue of approximately RMB15,488 million (2016: approximately RMB9,659 million, 2015: approximately RMB14,692 million ) was derived from sales by the E&P segment and the trading business segment to China Petroleum & Chemical Corporation. Sales to CNOOC Group are included in Note 28 (iii).

F-33

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

6. PROFIT/(LOSS) BEFORE TAX

The Group’s profit/(loss) before tax is arrived at after charging/(crediting):

	2015			2016			2017
Crediting:
Interest income from bank deposits		(873	)		(901	)		(653	)
Investment income:
– Fair value changes on other financial assets		(2,398	)		(2,774	)		(2,409	)
Insurance compensation on disposal of property, plant and equipment		(560	)		(520	)		(110	)
Charging:
Auditors’ remuneration:
– Audit fee		45			47			51
– Other fees		12			6			5
		57			53			56
Employee wages, salaries, allowances and social security costs		6,924			6,403			6,517
Impairment and provision:
- Property, plant and equipment		2,358			10,768			8,639
- Trade receivables		4			1,439			212
- Others		384			(36	)		279
		2,746			12,171			9,130
Depreciation, depletion and amortization:
– Property, plant and equipment		72,293			68,303			60,802
– Intangible assets		1,306			1,020			854
– Less: Net amount capitalized		(160	)		(416	)		(399	)
		73,439			68,907			61,257
Operating lease rentals:
– Office properties		438			485			639
– Plant and equipment		2,448			1,747			1,560
		2,886			2,232			2,199
Repairs and maintenance		5,034			4,052			4,800
Research and development costs		1,629			1,424			1,739
Loss on disposal of property, plant and equipment		718			78			116

F-34

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

7. FINANCE COSTS

	2015			2016			2017
Interest on bank loans		291			217			169
Interest on other loans		4,701			5,249			5,207
Other borrowing costs		76			25			18
Total borrowing costs		5,068			5,491			5,394
Less: Amount capitalized in property, plant and equipment (note 13)		(1,385	)		(1,430	)		(2,495	)
		3,683			4,061			2,899
Other finance costs:
Unwinding of discount on provision for dismantlement (note 25)		2,435			2,185			2,145
		6,118			6,246			5,044

The effective interest rates used to determine the amount of related borrowing costs for capitalization varied from 0.95% to 7.875% (2016: from 0.7566% to 7.875% , 2015: from 0.735% to 7.875%) per annum during the year ended at December 31, 2017.

8. KEY MANAGEMENT PERSONNEL’S REMUNERATION

Key management personnel are those persons having authority and responsibility for planning, directing and controlling the activities of the entity, directly or indirectly, including any director (whether executive or otherwise) of the Company.

(i) Directors’ remuneration

	Fees (1) RMB’000		Salaries allowances and benefits in kind (1) RMB’000		Performance related bonuses (1) RMB’000		Pension scheme contributions RMB’000		Total paid/payable during the year RMB’000
2015
Executive directors:
Li Fanrong(4)		-		170		470		117		757
Wu Guangqi(5)(7)		-		170		470		117		757
Subtotal		-		340		940		234		1,514
Non-executive directors:
Wang Yilin(2)		-		-		-		-		-
Yang Hua(2)(4)(10)		-		-		-		-		-
Lv Bo(7)		-		-		-		-		-
Wang Jiaxiang(3)		-		-		-		-		-
Subtotal		-		-		-		-		-
Independent non-executive directors:
Chiu Sung Hong		899		-		-		-		899
Lawrence J. Lau		763		-		-		-		763
Tse Hau Yin, Aloysius		899		-		-		-		899
Kevin G. Lynch		763		-		-		-		763
Subtotal		3,324		-		-		-		3,324
Total		3,324		340		940		234		4,838

F-35

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

8. KEY MANAGEMENT PERSONNEL’S REMUNERATION (continued)

(i) Directors’ remuneration (continued)

	Fees (1) RMB’000		Salaries allowances and benefits in kind (1) RMB’000		Performance related bonuses (1) RMB’000		Pension scheme contributions RMB’000		Total paid/payable during the year RMB’000
2016
Executive directors:
Yang Hua(2)(4)(10)		-		-		-		-		-
Yuan Guagnyu(4)(8)		-		94		78		70		242
Li Fanrong(4)		-		92		454		59		605
Subtotal		-		186		532		129		847
Non-executive directors:
Liu Jian(6)		-		-		-		-		-
Wu Guangqi(5)(7)		-		92		454		59		605
Lv Bo(7)		-		-		-		-		-
Subtotal		-		92		454		59		605
Independent non-executive
directors:
Chiu Sung Hong		957		-		-		-		957
Lawrence J. Lau		812		-		-		-		812
Tse Hau Yin, Aloysius		957		-		-		-		957
Kevin G. Lynch		812		-		-		-		812
Subtotal		3,538		-		-		-		3,538
Total		3,538		278		986		188		4,990

2017
Executive directors:
Yuan Guangyu(4)(8)	-	197	455	134	786
Xu Keqiang(9)	-	146	162	94	402
Subtotal	-	343	617	228	1,188
Non-executive directors:
Yang Hua(2)(4)(10)	-	-	-	-	-
Liu Jian(6)	-	-	-	-	-
Wu Guangqi(5)(7)	-	-	-	-	-
Subtotal	-	-	-	-	-
Independent non-executive
directors:
Chiu Sung Hong	972	-	-	-	972
Lawrence J. Lau	824	-	-	-	824
Tse Hau Yin, Aloysius	972	-	-	-	972
Kevin G. Lynch	824	-	-	-	824
Subtotal	3,592	-	-	-	3,592
Total	3,592	343	617	228	4,780

F-36

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

8. KEY MANAGEMENT PERSONNEL’S REMUNERATION (continued)

(i) Directors’ remuneration (continued)

Notes:

(1) Fees, salaries, allowances, benefits in kind and performance related bonuses represent the gross amount (before applicable individual salary tax) paid/payable to individual directors.

(2) On May 19, 2015, Mr. Yang Hua was appointed as Chairman of the Board and Chairman of the Nomination Committee of the Company and has no longer served as Vice-chairman of the Board. Mr. Wang Yilin resigned as Chairman of the Board, Chairman of the Nomination Committee and non-executive director of the Company.

(3) On September 23, 2015, Mr. Wang Jiaxiang retired as a non-executive director of the Company.

(4) On 15 June 2016, Mr. Yang Hua was re-designated as an Executive Director and appointed as the Chief Executive Officer of the Company. Mr. Yuan Guangyu was appointed as an Executive Director and the President of the Company. Mr. Li Fanrong resigned as an Executive Director, the Chief Executive Officer and the President of the Company.

(5) On 15 June 2016, Mr. Wu Guangqi was re-designated as a Non-executive Director of the Company and resigned as the Compliance Officer of the Company.

(6) On 20 December 2016, Mr. Liu Jian was appointed as the Vice Chairman and a Non-executive Director of the Company.

(7) On 20 December 2016, Mr. Wu Guangqi was appointed as a member of the Remuneration Committee of the Company. Mr. Lv Bo resigned as a Non-executive Director and a member of the Remuneration Committee of the Company.

(8) On 18 April 2017, Mr. Yuan Guangyu was appointed as the Chief Executive Officer of the Company. Mr. Yuan Guangyu resigned as the President of the Company.

(9) On 18 April 2017, Mr. Xu Keqiang was appointed as an Executive Director and the President of the Company.

(10) On 18 April 2017, Mr. Yang Hua was re-designated as a Non-executive Director of the Company. Mr. Yang Hua resigned as the Chief Executive Officer of the Company and he remains as the Chairman of the Board.

The Company has adopted the share option schemes for the grant of options to the Company's directors. The fair value of share options for the directors measured according to the Group's accounting policy as set out in note 3. No Directors exercised any share option in 2015, 2016 or 2017. No new share option was granted to Directors in respect of their services to the Group under the applicable share option schemes of the Company in 2015, 2016 or 2017. Further details of share option scheme and valuation techniques are set out in note 26.

Save as disclosed above, there was no arrangement under which a director waived or agreed to waive any remuneration during the year. In 2017, the executive directors' remuneration shown above were for their services in connection with the management of the affairs of the Company. The other directors' remuneration shown above were for their services as directors of the Company.

F-37

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

8. KEY MANAGEMENT PERSONNEL’S REMUNERATION (continued)

( ii) Other key management personnel’s (excluding Directors’) remuneration

	2015		2016		2017
Short term employee benefits		8		7		9
Pension scheme contributions		1		1		1
Amount paid/payable during the year		9		8		10
Share options*		-		-		-
		9		8		10

The bands of the remuneration of other key management personnel (excluding Directors) and the related number of members of other key management personnel (excluding Directors) are as follows:

	Number of employees
	2015		2016		2017
Nil to RMB 2,000,000		10		10		12
		10		10		12

* This item represents the fair value of share options measured according to the Group's accounting policy as set out in note 3. No other key management personnel exercised any share option in 2015, 2016 or 2017.

F-38

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

9. FIVE HIGHEST PAID EMPLOYEES

During the year, none (2016: none; 2015: none) of the Directors, details of whose remuneration are disclosed in note 8 (i) above, received an amount which falls within the category of the five highest paid employees. Details of the remuneration of the five (2016: five; 2015: five) highest paid employees, for the year are as follows:

	2015		2016		2017
Basic salaries, allowances and benefits in kind(1)		22		23		21
Performance-related bonuses		17		14		19
Pension scheme contributions		1		1		1
Amount paid/payable during the year		40		38		41

(1) Salaries, allowances, and benefits in kind represent the gross amount (before applicable individual salary tax) paid/payable to individual employees.

The remuneration of the five (2016: five, 2015: five) highest paid employees, falls within the following bands:

	2015		2016		2017
RMB5,500,001 to RMB6,000,000		-		1		-
RMB6,000,001 to RMB6,500,000		-		-		1
RMB7,000,001 to RMB7,500,000		3		-		1
RMB7,500,001 to RMB8,000,000		-		3		-
RMB8,000,001 to RMB8,500,000		-		-		1
RMB9,000,001 to RMB9,500,000		2		1		1
RMB10,000,001 to RMB10,500,000		-		-		1
		5		5		5

F-39

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

10. TAX

(i) Income tax

The Company and its subsidiaries are subject, on an entity basis, to income taxes on profits arising in or derived from the tax jurisdictions in which the entities of the Group are domiciled and operate. The Company is subject to profits tax at a rate of 16.5 % (2016: 16.5%, 2015: 16.5%) on profits arising in or derived from Hong Kong.

The Company is regarded as a Chinese Resident Enterprise (as defined in the "Enterprise Income Tax Law of the People's Republic of China") by the State Administration of Taxation of the PRC. As a result, the Company is subject to the PRC corporate income tax at the rate of 25% starting from January 1, 2008. The corporate income tax which is subjected in Hong Kong is qualified as a foreign tax credit to offset the PRC corporate income tax starting from January 1, 2008.

The Company's subsidiary in Mainland China, CNOOC China Limited, is a wholly-owned foreign enterprise. It is subject to corporate income tax at the rate of 25% under the prevailing tax rules and regulations. CNOOC Deepwater Development Limited, a wholly-owned subsidiary of CNOOC China Limited, is subject to corporate income tax at the rate of 15% for the three years ended December 31, 2017, after being assessed as a high and new technology enterprise. The company is in the process of re-applying to be assessed as a high and new technology enterprise from 2018 to 2020.

Subsidiaries of the Group domiciled outside the PRC are subject to income tax at rates ranging from 10% to 50% (2016: 10% to 50%, 2015: 10% to 56%). 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%. The U.K. government decreased the combined income tax rate on North Sea oil and gas activities from 50% to 40% with effect from January 1, 2016.

As of December 31, 2017, deferred tax liabilities related to undistributed earnings of the Company's overseas subsidiaries have not been provided since the timing of the reversal of the taxable temporary differences can be controlled by the Company and it is probable that the temporary differences would not reverse in the foreseeable future.

F-40

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

10. TAX (continued)

(i) Income tax (continued)

An analysis of the tax (credit)/expense in the Group's consolidated statement of profit or loss and other comprehensive income is as follows:

	2015			2016			2017
Current tax
Provision for PRC enterprise income tax on the estimated taxable profits for the year		9,990			7,547			11,472
Provision for overseas enterprise income tax on the estimated taxable profits for the year		3,501			2,983			4,390
Deferred tax
Temporary differences in the current year		(12,585	)		(14,595	)		(7,558	)
Effect of changes in tax rates		(4,022	)		(1,847	)		3,376
Income tax (credit)/expense for the year		(3,116	)		(5,912	)		11,680

A reconciliation of the PRC statutory corporate income tax rate to the effective income tax rate of the Group is as follows:

	2015			2016		2017
	%			%		%
PRC statutory enterprise income tax rate		25.0			25.0		25.0
Effect of different tax rates for overseas subsidiaries		(5.8	)		34.8		(1.6	)
Effect of changes in tax rates		(23.5	)		35.0		9.4
Tax credit from the government		(11.5	)		8.3		(2.7	)
Tax reported in equity-accounted entities		(0.4	)		1.0		(0.2	)
Tax losses previously not recognized		(1.9	)		5.3		-
Others		(0.1	)		2.7		2.2
Group’s effective income tax rate		(18.2	)		112.1		32.1

The movements of deferred tax liabilities net of deferred tax assets are as follows:

	2015			2016			2017
At January 1		14,312			(1,948	)		(19,174	)
Credit to the profit or loss		(12,585	)		(14,595	)		(7,558	)
Changes in tax rates		(4,022	)		(1,847	)		3,376
Charge to equity		141			(226	)		7
Exchange differences		206			(558	)		1,143
At December 31		(1,948	)		(19,174	)		(22,206	)

F-41

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

10. TAX (continued)

(i) Income tax (continued)

Principal components of deferred tax balances are as follows:

	2016			2017
Deferred tax assets
Property, plant and equipment		1,681			7,312
Provision for dismantlement		9,325			9,669
Losses available for offsetting against future taxable profit		21,163			16,529
Fair value of long term borrowings		1,969			1,771
Others		1,389			1,178
		35,527			36,459
Deferred tax liabilities
Property, plant and equipment		(16,208	)		(13,670	)
Fair value changes on other financial assets		(139	)		(232	)
Others		(6	)		(351	)
		(16,353	)		(14,253	)
Net deferred tax assets		19,174			22,206
Of which – deferred tax assets		24,844			25,509
deferred tax liabilities		(5,670	)		(3,303	)

As at December 31, 2017, the Group had approximately RMB87,623 million (December 31, 2016: RMB82,288 million) of carry-forward tax losses, predominantly in North America, that would be available to offset against future taxable profits of the subsidiaries in which the tax losses arose. Most of the US and Canadian tax losses will expire in 8 to 20 years.

Deferred tax assets in respect of tax losses are recognized only to the extent of the anticipated future taxable profits or reversal of existing taxable temporary differences.

As at December 31, 2017, the Group's recognized deferred tax assets on tax losses amounted to RMB75,018 million (December 31, 2016: RMB68,061 million). Unrecognized tax losses, where recovery is not currently expected, amounted to RMB12,605 million (December 31, 2016: RMB14,227 million). This includes RMB3,181 million (2016: RMB3,207 million) of unrecognized tax loss arising from Uganda which has no fixed expiry date. The remainder expires between 5 to 20 years.

As at December 31, 2017, the Group's unrecognized deferred tax assets related to unused tax credits amounted to RMB4,990 million (2016: RMB5,761 million). This includes RMB4,587 million (2016: RMB4,807 million) of unrecognized deferred tax assets related to unused tax credits from Nigeria which has no fixed expiry date. The remainder expires between 2026 and 2036.

The realisability of the deferred tax assets recognized mainly depends on whether sufficient future profits or taxable temporary differences will be available in the future. In case where the actual future taxable profits generated are less than expected, or change in facts and circumstances which result in revision of future taxable profits estimation, the balance of deferred tax assets may be significantly revised.

F-42

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

10. TAX (continued)

(ii)       Other taxes

The Company's PRC subsidiaries pay the following other taxes and dues:

i. Production tax at the rate of 5% on production under production sharing contracts;

ii. VAT at the rates from 13% to 17% on taxable sales under independent oil and gas fields since May 1 2016 according to "Provisional Regulations on VAT of the PRC" and relevant detailed rules according to the "Circular on Certain Policies on the Pilot Program of the Collection of VAT in Lieu of Business Tax" (Cai Shui [2016] No.39), which replaced the production tax at the rate of 5% on production under independent oil and gas fields before May 1 2016. According to “Notice on Simplifying the Relevant Policies on Value-added Tax Rates” (Cai Shui [2017] No.37), with effect from 1 July 2017, the 13% VAT rate shall be removed and gas sales shall be subject to the 11% tax rate.

VAT at the rates from 3% to 17% on other income since May 1 2016, which were subject to the business tax at rates of 3% to 5% or VAT at the rates of 3% to 17% before May 1 2016.

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

iii. Resource tax (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 starting from November 1, 2011, which replaced the royalties for 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. The resource tax rate was changed from 5% to 6% since December 1, 2014;

iv. Export tariff at the rate of 5% on the export value of petroleum oil;

v. City construction tax at the rates of 1% or 7% on the production tax, business tax and VAT paid;

vi. Educational surcharge at the rate of 3% on the production tax, business tax and VAT paid; and

vii. Local educational surcharge at the rate of 2% on the production tax, business tax and VAT paid.

In addition, other taxes paid and payable by the Company's non-PRC subsidiaries include royalty as well as taxes levied on petroleum-related income, budgeted operating and capital expenditure.

F-43

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

10. TAX (continued)

(iii)       Special Oil Gain Levy

In 2006, a Special Oil Gain Levy ("SOG Levy") was imposed by the Ministry of Finance of the PRC ("MOF") at the 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. The MOF has decided to increase the threshold of the SOG Levy to US$65 with effect from January 1, 2015. Notwithstanding this adjustment, the SOG Levy continues to have five levels and is calculated and charged according to the progressive and valorem rates on the excess amounts. The SOG Levy paid can be claimed as a deductible expense for corporate income tax purposes and is calculated based on the actual volume of the crude oil entitled.

11. EARNINGS PER SHARE

	2015		2016		2017
Earnings
Profit for the purpose of basic and diluted earnings per share calculation		20,246		637		24,677
Number of shares
Number of ordinary shares for the purpose of basic earnings per share calculation		44,647,455,984		44,647,455,984		44,647,455,984
Effect of dilutive potential ordinary shares under the share option schemes		37,363,069		11,684,504		4,101,969
Weighted average number of ordinary shares for the purpose of diluted earnings per share		44,684,819,053		44,659,140,488		44,651,557,953
Earnings per share:
Basic (RMB Yuan)		0.45		0.01		0.55
Diluted (RMB Yuan)		0.45		0.01		0.55

F-44

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

12. DIVIDENDS

	2015		2016		2017
Dividend per ordinary share:
2017 interim dividend - HK$0.20 (2016: interim dividend HK$0.12, 2015: interim dividend    HK$0.25) per ordinary share		9,145		4,673		7,601
2016 final dividend - HK$0.23 (2015: final dividend HK$0.25, 2014: final dividend    HK$0.32) per ordinary share		11,274		9,571		8,847
2017 final dividend proposed at HK$0.3 (2016: final dividend proposed at HK$0.23, 2015: final dividend proposed at HK$0.25) per ordinary share by the Board of Directors - not recognized as a liability as at the end of the year		9,397		9,096		10,830

Pursuant to the Enterprise Income Tax Law of the People's Republic of China and related laws and regulations, the Company is regarded as a Chinese Resident Enterprise, and thus is required to withhold corporate income tax at the rate of 10% when it distributes dividends to its non-resident enterprise (as defined in the "Enterprise Income Tax Law of the People's Republic of China") shareholders, with effect from the distribution of the 2008 final dividend. In respect of all shareholders whose names appear on the Company's register of members and who are not individuals (including HKSCC Nominees Limited, corporate nominees or trustees such as securities companies and banks, and other entities or organizations, which are all considered as non-resident enterprise shareholders), the Company will distribute the dividend after deducting corporate income tax of 10%.

F-45

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

13. PROPERTY, PLANT AND EQUIPMENT

	Oil and gas properties			Vehicles and office equipment and others			Total
Cost:
At January 1, 2016		803,986			5,296			809,282
Additions		44,302			236			44,538
Disposals and write-offs		(6,365	)		(37	)		(6,402	)
Exchange differences		25,703			205			25,908
At December 31, 2016		867,626			5,700			873,326
At January 1, 2017		867,626			5,700			873,326
Additions		48,937			99			49,036
Disposals and write-offs		(2,577	)		(914	)		(3,491	)
Exchange differences		(24,985	)		(148	)		(25,133	)
At December 31, 2017		889,001			4,737			893,738
Accumulated depreciation, depletion and amortization and impairment:
At January 1, 2016		(353,824	)		(1,317	)		(355,141	)
Depreciation charge for the year		(67,906	)		(397	)		(68,303	)
Impairment		(10,768	)		-
Disposals and write-offs		3,532			34			3,566
Exchange differences		(10,157	)		(58	)		(10,215	)
At December 31, 2016		(439,123	)		(1,738	)		(440,861	)
At January 1, 2017		(439,123	)		(1,738	)		(440,861	)
Depreciation charge for the year		(60,442	)		(360	)
Impairment		(8,639	)		-			(8,639	)
Disposals and write-offs		1,185			258			1,443
Exchange differences		10,932			57			10,989
At December 31, 2017		(496,087	)		(1,783	)		(497,870	)
Net book value:
At December 31, 2016		428,503			3,962			432,465
At December 31, 2017		392,914			2,954			395,868

Included in the current year's additions was an amount of approximately RMB2,495 million (2016: approximately RMB1,430 million, 2015: approximately RMB1,385 million) in respect of interest capitalized in property, plant and equipment (note 7). Included also in the depreciation charge for the year was an amount of approximately RMB636 million (2016: approximately RMB1,609 million, 2015: approximately RMB3,465 million) in respect of a depreciation charge on dismantlement cost capitalized in oil and gas properties.

F-46

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

13. PROPERTY, PLANT AND EQUIPMENT (continued)

Impairment and provision recognized during the year included the impairment loss to reduce the carrying amount of certain oil and gas properties to the recoverable amount. In 2017, the impairment loss was mainly related to fields in China, Africa and North America which was primarily due to the revision of the oil and gas price forecast and revision of reserves. In 2016, the impairment loss was mainly related to fields in North America, Europe and Africa primarily due to the revision of the oil price forecast and an adjustment in operating plan for oil sand assets in Canada.

For both years, the recoverable amount was calculated based on the assets' value in use and was determined at the cash-generating unit level. The Company identifies a field or the group of fields that could generate cash inflows independently as a cash-generating unit. The principal parameters used in determining the recoverable amount of the Group’s assets include estimates of proved and unproved reserves, future commodity prices that come from the price forecast of respected and independent institutions, combined with internal analysis and judgment of the international market environment, as well as best estimates of drilling and development costs.

The discount rate is derived from the Company’s weighted average cost of capital (“WACC”) and is adjusted, where applicable, to take into account any specific risks relating to the country where the asset is located as well as the asset specific characteristics, such as specific tax treatments, cash flow profiles and economic life. The discount rate used for value in use calculations is 8%-12% in 2017 after tax (2016: 8%-11% after tax). A derived pre-tax discount rate would be in the range of 8%-15% (2016: 9%-11% pre-tax).

For 2016, included in impairment was RMB7,358 million recognized on the Long Lake project, due to the revision of the oil price forecast and adjustments to operating plans caused by the pipeline rupture and the explosion accident. Specifically, the operating plan was changed to defer the timing of when to bring the Long Lake upgrader back online, to make the timing concurrent with the most recent expectation of when sufficient feedstock will be produced from Long Lake assets to maximize the utilization and cash generating potential of the upgrader. The Company also updated the yield assumptions based on the most recent operating performance of the upgrader. The asset was written down to an estimated recoverable amount of RMB33,902 million in June 2016. As at 31 December 2017, the future operating plan of Long Lake assets is still under assessment by management, which may significantly impact the recoverable amount of the oil sands properties of Long Lake assets in the future.

During 2017, the Group wrote off certain oil and gas assets in the North America mainly due to the expiration of lease contracts. Approximately RMB71 million was included in the exploration expenses, and approximately RMB1,588 million was included in the depreciation, depletion and amortisation charge, respectively.

F-47

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

14. INTANGIBLE ASSETS

	Gas processing rights under NWS Project			Drilling rig contracts and seismic data usage rights			Marketing transportation and storage contracts			Software and others			Goodwill			Total
Cost:
At January 1, 2016		1,191			1,596			1,527			2,861			13,805			20,980
Additions		-			-			-			197			-			197
Disposal		-			-			-			(387	)		-			(387	)
Exchange differences		82			109			104			67			943			1,305
At December 31, 2016		1,273			1,705			1,631			2,738			14,748			22,095
At January 1, 2017		1,273			1,705			1,631			2,738			14,748			22,095
Additions		-			-			-			206			-			206
Disposal		-			(1,662	)		(54	)		(199	)		-			(1,915	)
Exchange differences		(74	)		(43	)		(93	)		(57	)		(856	)		(1,123	)
At December 31, 2017		1,199			-			1,484			2,688			13,892			19,263
Accumulated amortization:
At January 1, 2016		(621	)		(958	)		(1,096	)		(1,882	)		-			(4,557	)
Amortization charge for the year		(51	)		(326	)		(135	)		(508	)		-			(1,020	)
Disposal		-			-			-			386			-			386
Exchange differences		(57	)		(80	)		(81	)		(42	)		-			(260	)
At December 31, 2016		(729	)		(1,364	)		(1,312	)		(2,046	)		-			(5,451	)
At January 1, 2017		(729	)		(1,364	)		(1,312	)		(2,046	)		-			(5,451	)
Amortization charge for the year		(46	)		(332	)		(57	)		(419	)		-			(854	)
Disposal		-			1,662			54			199			-			1,915
Exchange differences		43			34			76			44			-			197
At December 31, 2017		(732	)		-			(1,239	)		(2,222	)		-			(4,193	)
Net book value:
At December 31, 2016		544			341			319			692			14,748			16,644
At December 31, 2017		467			-			245			466			13,892			15,070

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in a business combination.

According to the accounting policies as set out in note 3, goodwill is acquired in the acquisition of Nexen Inc., and from the acquisition date, allocated to the entire E&P assets, which are the groups of cash-generating units that are expected to benefit from the synergies of the acquisition.

Impairment is determined by assessing the recoverable amount of the entire E&P assets to which the goodwill relates. Where the recoverable amount of the entire E&P assets is less than the carrying amount of the assets and the goodwill together, an impairment loss on goodwill is recognized.

In assessing value in use of E&P segment, 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. The discount rate used for value in use is derived from the Company’s WACC and is adjusted, where applicable, to take into account any specific risks relating to the country where the asset is located as well as the asset specific characteristics, such as specific tax treatments, cash flow profiles and economic life. However, actual results could differ from those estimates.

The intangible asset regarding the gas processing rights has been amortized upon the commercial production of the liquefied natural gas on a unit-of -production basis over the total proved reserves of the relevant asset. The intangible assets regarding the marketing transportation and storage contracts are amortized on a straight-line basis over the life of the contracts which is less than 20 years. Other identifiable intangible assets are amortized on a straight-line basis over a period ranging from 3 to 5 years.

F-48

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

15. INVESTMENTS IN ASSOCIATES

Particulars of the principal associates at the end of the reporting period are as follows:

Name of associates	Place of establishment	Nominal value of ordinary shares issued and paid-up/registered capital	Percentage of equity attributable to the Group			Principal activities
Shanghai Petroleum  Corporation Limited	Shanghai, PRC	RMB900 million		30	%	Production, processing and technology consultation of oil, gas and relevant products in the PRC
CNOOC Finance  Corporation Limited	Beijing, PRC	RMB4 billion		31.8	%	Provision of deposit, transfer, settlement, loan, discounting and other financing services to CNOOC and its member entities

To give details of other associate would, in the opinion of the Directors, result in particulars of excessive length.

The Group’s investments in associates represent:

	2016		2017
Share of net assets		3,695		4,067

None of the Group’s associates are considered to be individually material. The following table illustrates the summarized financial information of the Group’s associates in the consolidated financial statements:

	2015		2016			2017
Profit/(loss) for the year		256		(609	)		302
Other comprehensive income/(expense)		74		(127	)		36
Total comprehensive income/(expense)		330		(736	)		338

Dividend of RMB116 million was received from the associates in 2017 (2016: RMB135 million).

16.       INVESTMENT IN A JOINT VENTURE

Particulars of the joint venture at the end of the reporting period are as follows:

Name of entity	Place of establishment	Nominal value of ordinary shares issued and paid-up/registered capital	Percentage of equity attributable to the Group			Principal activities
Bridas Corporation	British Virgin Islands	US$                               102,325,582		50	%	Investment holding

F-49

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

16.       INVESTMENT IN A JOINT VENTURE (continued)

Summarized financial information of the joint venture is disclosed below:

			2016			2017
Current assets				9,201			11,614
Non-current assets				66,992			63,660
Current liabilities				(6,866	)		(6,630	)
Non-current liabilities				(16,727	)		(18,486	)
	2015			2016			2017
Revenue	31,231			28,371			29,879
Depreciation, depletion and amortization	(3,535	)		(3,988	)		(3,742	)
Interest income	288			388			313
Finance costs	(799	)		(704	)		(550	)
Profit before tax	4,194			1,226			2,215
Income tax expense	(900	)		(160	)		(1,109	)
Profit after tax	3,294			1,066			1,106
Total comprehensive income	3,294			1,066			1,106

Dividend of US$36 million (equivalent to RMB243 million) was received from the joint venture in 2017, no dividend was received from the joint venture in 2016 and dividend of US$5 million (equivalent to RMB32 million) was received from the joint venture in 2015.

F-50

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

17. EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS

(i)       Equity investments

	2016		2017
Current:
Non-publicly traded investments
Private equity funds classified at FVTOCI		15		14
		15		14
Non-current:
Publicly traded investments
Equity investment in MEG Energy Corporation (“MEG”) classified at FVTOCI(1)		1,356		766
Other equity investment classified at FVTPL		35		15
		1,391		781
Non-publicly traded investments
Private equity fund in Kerogen Energy Fund classified at FVTOCI (2)		2,875		2,759
		4,266		3,540

(1) MEG is principally engaged in the exploitation and production of oil sands. The investment in MEG is designated by the Group as at FVTOCI. As at December 31, 2017, the investment in MEG was stated at the quoted market price.

(2) Kerogen Energy Fund is principally engaged in the investment in the oil and gas industry. The equity investment in Kerogen Energy Fund is designated by the Group as at FVTOCI. The cost of this non-publicly traded equity investment represents an appropriate estimate of its fair value as at January 1, 2017 and December 31, 2017, as sufficient information is not available recently to measure its fair value.

F-51

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

17. EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS (Continued)

(ii)       Other financial assets

	2016		2017
Current:
Non-publicly traded investments classified at FVTPL:
Corporate wealth management products (1)		46,958		66,229
Money market funds (2)		5,931		8,115
		52,889		74,344

(1)` The corporate wealth management products will mature from January 8, 2018 to November 6, 2018 (2016: January 10, 2017 to December 5, 2017).

(2) The money market funds can be redeemed at any time.

The gains of the Group's other financial assets recognized in the profit or loss for the year was RMB2,409 million (2016: RMB2,774 million, 2015: RMB2,398 million).

During the year, the fair value changes on the Group's equity investments recognized directly in other comprehensive expense amounted to RMB542 million (2016: RMB461 million, 2015: RMB1,573 million).

None of the equity investments and other financial assets above is past due or impaired.

F-52

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

18.       OTHER NON-CURRENT ASSETS

Included in the other non-current assets were restricted deposits for future dismantlement. Pursuant to the Provisional Regulations on the Dismantlement of Offshore Oil and Gas Production Facilities of the People's Republic of China, the Group accrues dismantlement costs for all the oil and gas fields under production sharing contracts in the PRC, and makes monthly cash contributions to the specified dismantlement fund accounts supervised by the PRC government. The deposit cannot be withdrawn or utilized for any other purposes but the dismantlement of oil and gas production facilities in the future. As of December 31, 2017, the balance of the specified dismantlement fund accounts was RMB7,555 million (December 31, 2016: RMB6,088 million).

19. INVENTORIES AND SUPPLIES

	2016			2017
Materials and supplies		7,288			6,278
Oil in tanks		1,594			1,540
Less: Provision for inventory obsolescence		(173	)		(464	)
		8,709			7,354

20. TRADE RECEIVABLES

The credit terms of the Group are generally within 30 days after the delivery of oil and gas. Payment in advance or collateral may be required from customers, depending on credit rating. Trade receivables are non-interest-bearing.

All customers have good credit quality with good repayment history and no significant receivables are past due. As at December 31, 2017 and December 31, 2016, the age of substantially all the trade receivables was within one year.

21. CASH AND CASH EQUIVALENTS AND TIME DEPOSITS WITH MATURITY OVER THREE MONTHS

The Group's cash and cash equivalents mainly consist of current deposits and time deposits with maturity within seven days. The bank balances are deposited with creditworthy banks with no recent history of default.

The weighted average effective interest rates of the Group's bank deposits were 2.23% per annum for the year ended December 31, 2017 (2016: 2.95% per annum, 2015: 2.61% per annum).

22. TRADE AND ACCRUED PAYABLES

As at December 31, 2017 and 2016, substantially all the trade and accrued payables were aged within six months. The trade and accrued payables are non-interest-bearing.

F-53

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

23. OTHER PAYABLES AND ACCRUED LIABILITIES

	2016		2017
Accrued payroll and welfare payable		1,509		1,490
Provision for retirement benefits		683		630
Accrued expenses		449		381
Advances from customers		3,272		3,096
Special oil gain levy payable		-		55
Royalties payable		240		75
Provision for dismantlement (note 25)		462		1,180
Other payables		8,251		7,199
		14,866		14,106

24. LOANS AND BORROWINGS

Current

		2016						2017
	Effective interest rate and final maturity	Loans		Notes		Total		Loans		Notes		Total
Short-term loans and borrowings
General loans****	LIBOR+0.35% to 0.75% per annum with maturity within one year		10,361		-		10,361		8,779		-		8,779
			10,361		-		10,361		8,779		-		8,779
Loans and borrowings due within one year
For Tangguh LNG Project**	LIBOR+0.19% to 0.335% per annum with maturity within one year		215		-		215		212		-		212
Notes*			-		9,102		9,102		-		4,901		4,901
			215		9,102		9,317		212		4,901		5,113
			10,576		9,102		19,678		8,991		4,901		13,892

F-54

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

24.       LOANS AND BORROWINGS (continued)

Non-current

		2016						2017
	Effective interest rate and final maturity	Loans		Notes		Total		Loans		Notes		Total
For Tangguh LNG Project**	LIBOR+0.19% to 0.335% per annum with maturity through to 2021		758		-		758		502		-		502
For Tangguh LNG III Project ***	LIBOR+1.37% to 3.45% per annum with maturity through 2021 to 2029		327		-		327		777		-		777
Notes*			-		129,713		129,713		-		117,079		117,079
			1,085		129,713		130,798		1,279		117,079		118,358

F-55

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

24.       LOANS AND BORROWINGS (continued)

* The details of notes are as follows:

					Outstanding Principal Amount
Issued by	Maturity	Coupon Rate			December 31, 2017		December 31,2016
					USD million
CNOOC Finance (2003) Limited	Due in 2033		5.500	%		300		300
CNOOC Finance (2011) Limited	Due in 2021		4.25	%		1,500		1,500
CNOOC Finance (2011) Limited	Due in 2041		5.75	%		500		500
CNOOC Finance (2012) Limited	Due in 2022		3.875	%		1,500		1,500
CNOOC Finance (2012) Limited	Due in 2042		5.000	%		500		500
CNOOC Finance (2013) Limited	Due in 2018		1.750	%		750		750
CNOOC Finance (2013) Limited	Due in 2023		3.000	%		2,000		2,000
CNOOC Finance (2013) Limited	Due in 2043		4.250	%		500		500
CNOOC Nexen Finance (2014) ULC	Matured in 2017		1.625	%		-		1,250
CNOOC Nexen Finance (2014) ULC	Due in 2024		4.25	%		2,250		2,250
CNOOC Nexen Finance (2014) ULC	Due in 2044		4.875	%		500		500
Nexen	Matured in 2017		5.65	%		-		62
Nexen	Due in 2019		6.2	%		300		300
Nexen	Due in 2028		7.4	%		200		200
Nexen	Due in 2032		7.875	%		500		500
Nexen	Due in 2035		5.875	%		790		790
Nexen	Due in 2037		6.4	%		1,250		1,250
Nexen	Due in 2039		7.5	%		700		700
CNOOC Finance (2015) U.S.A. LLC	Due in 2025		3.500	%		2,000		2,000
CNOOC Finance (2015) Australia Pty Ltd	Due in 2020		2.625	%		1,500		1,500
CNOOC Finance (2015) Australia Pty Ltd	Due in 2045		4.200	%		300		300

All the notes issued mentioned above were fully and unconditionally guaranteed by the Company.

F-56

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

24.       LOANS AND BORROWINGS (continued)

** In connection with the Tangguh LNG Project in Indonesia, the Company delivered a guarantee dated October 29, 2007, in favor of Mizuho Corporate Bank, Ltd., which acts as the facility agent for and on behalf of various international commercial banks under a US$884 million commercial loan agreement. The Company guarantees the payment obligations of the trustee borrower under the subject loan agreement and is subject to a maximum cap of approximately US$135,163,308.28.

A letter of credit agreement was signed between the Company and Talisman Energy Inc. (“Talisman”) with execution of the agreement in respect of the sale of a 3.05691% interest of the Company in the Tangguh LNG Project to Talisman. Accordingly, Talisman has delivered valid and unexpired standby letters of credit to the Company (as the beneficiary) as a counter-guarantee to offset the exposure of the Company’s guarantee for the aforesaid interest of 3.05691% in respect of the Tangguh LNG Project financing. The amount of the standby letters of credit was US$30 million. In February 2017, the standby letters of credit were withdrawn as the Company transferred the 3.05691% guarantee obligations to BP Corporation North America Inc..

*** In connection with the financing for the third LNG process train of Tangguh LNG Project in Indonesia, the Company delivered two guarantees dated August 3, 2016, in favor of Mizuho Bank, Ltd., which acts as the facility agent for and on behalf of various international commercial banks and Indonesian local commercial banks under two commercial loan agreements with aggregate loan amount of US$2,145 million. The Company guarantees the payment obligations of the trustee borrower under the subject loan agreements and is subject to an aggregate maximum cap of approximately US$573 million.

**** As at December 31, 2017, US$650 million bank loans (2016: US$800 million) were guaranteed by the Company.

As at December 31, 2017, US$694 million shareholder loans (2016: US$694 million) of the Group were included in general loans. For details please refer to Note 28(v).

F-57

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

24.       LOANS AND BORROWINGS (continued)

The maturities of the long term bank loans are as follows:

	2016			2017
Repayable:
Within one year		215			212
After one year but within two years		225			212
After two years but within three years		225			212
After three years but within four years		225			108
After four years but within five years		97			61
After five years		313			686
		1,300			1,491
Amount due within one year shown under current liabilities		(215	)		(212	)
		1,085			1,279

Supplemental information with respect to the long term bank loans:

For the year ended December 31	Balance at year end		Weighted average interest rate at year end			Maximum amount outstanding during the year		Average amount outstanding during the year (1)		Weighted average interest rate during the year (2)
2016		1,300		1.74	%		1,369		1,199		1.29	%
2017		1,491		2.52	%		1,491		1,396		2.13	%

(1) The average amount outstanding is computed by averaging the outstanding principal balances as at January 1, and December 31, of each year.

(2) The weighted average interest rate is computed by averaging the interest rates as at January 1, and December 31, of each year.

There was no default of principal, interest or redemption terms of the loans and borrowings during the year.

F-58

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

25. PROVISION FOR DISMANTLEMENT

	2016			2017
At January 1		50,063			50,888
New projects(1)		1,395			1,244
Revision(1)		(2,072	)		421
Utilization		(398	)		(440	)
Deletions		(33	)		-
Unwinding of discount(2) (note 7)		2,185			2,145
Exchange differences		(252	)		(185	)
At December 31		50,888			54,073
Current portion of dismantlement included in other payables and accrued liabilities (note 23)		(462	)		(1,180	)
At December 31		50,426			52,893

(1) The amounts are included in the additions of oil and gas properties in note 13.

(2) The discount rates used for calculating the provision for dismantlement are within the range of 4% to 5%
(2016: 4% to 5%, 2015: 4% to 5%).

26. SHARE CAPITAL

	Number of shares		Issued share capital equivalent of RMB million
Issued and fully paid:
Ordinary shares with no par value as at January 1, 2016, as at December 31, 2016 and as at December 31, 2017		44,647,455,984		43,081

F-59

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

26. SHARE CAPITAL (continued)

Share option schemes

The Company has adopted the share option schemes for the grant of options to the Company's directors, senior management and other eligible grantees.

(1) Pre-Global Offering Share Option Scheme (expired in 2011);

(2) 2001 Share Option Scheme (expired in 2011);

(3) 2002 Share Option Scheme (expired in 2015); and

(4) 2005 Share Option Scheme (as defined below).

Under these share option schemes, the Remuneration Committee of the Board will from time to time propose for the Board's approval the grant of share options and the number of share options to be granted to the relevant grantees. The maximum aggregate number of shares (including those that could be subscribed for under the Pre-Global Offering Share Option Scheme, the 2001 Share Option Scheme, the 2002 Share Option Scheme and the 2005 Share Option Scheme) which may be issued upon exercise of all options granted shall not exceed 10% of the total issued share capital of the Company as at December 31, 2005, being the date on which the shareholders of the Company approved the 2005 Share Option Scheme, excluding shares under options which have lapsed.

2005 Share Option Scheme

On December 31, 2005, the Company adopted a new share option scheme (the "2005 Share Option Scheme"). Under the 2005 Share Option Scheme, the Board has the authority to grant options to subscribe for shares to the directors, officers and employees of the Company and its subsidiaries, and any other persons who in the sole discretion of the Board, have contributed or will contribute to the Group. Unless approved by the shareholders, the total number of shares issued and to be issued upon exercise of the options granted to each individual (including exercised and unexercised options) under the 2005 Share Option Scheme or any other share option scheme adopted by the Company, in any 12-month period, must not exceed 1% of the shares in issue of the Company.

F-60

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

26. SHARE CAPITAL (continued)

Share option schemes (continued)

2005 Share Option Scheme (continued)

According to the 2005 Share Option Scheme, the consideration payable by a grantee for the grant of options will be HK$1.00. The exercise price for such options will be determined by the Board at its discretion at the date of grant, except that such price shall be at least the higher of:

(1) the nominal value of a share of the Company on the date of grant;

(2) the average closing price of the shares as stated in the HKSE's daily quotation sheets for the five trading days immediately preceding the date of grant; and

(3) the closing price of the shares as stated in the HKSE's daily quotation sheet on the date of grant.

The period within which the options must be exercised, as well as any minimum holding period or performance targets which apply to the options, will be specified by the Board of the Company at the time of grant. The exercise periods for options granted under the 2005 Share Option Scheme shall end not later than 10 years from the date of grant. No options may be granted under the 2005 Share Option Scheme after the date of the 10th anniversary of the adoption of the 2005 Share Option Scheme.

No new share option was granted during the year (2016 and 2015: nil) and the Group recognized an equity-settled share option expense of nil (2016 and 2015: nil) during the year.

The fair value of equity-settled share options granted was estimated as at the date of grant if any, using the Black-Scholes option pricing model, taking into account the terms and conditions upon which the options were granted.

Details of the share options outstanding are as follows:

	2016					2017
	Number of share options			Weighted average exercise price		Number of share options			Weighted average exercise price
				HK$					HK$
Outstanding at the beginning of the year		262,592,000			10.56		187,529,000			11.40
Granted during the year		-			-		-			-
Forfeited during the year		(37,893,000	)		11.30		(22,506,000	)		12.43
Expired during the year		(37,170,000	)		5.56		(35,104,000	)		7.29
Exercised during the year		-			-		-			-
Outstanding at the end of the year		187,529,000			11.40		129,919,000			12.34
Exercisable at the end of the year		187,529,000			11.40		129,919,000			12.34

No share options had been cancelled or modified during the years ended December 31, 2015, 2016 or 2017.

F-61

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

26. SHARE CAPITAL (continued)

At the date of approval of these consolidated financial statements for issuance, the share options outstanding under these share option schemes represented approximately 0.29% of the Company's shares in issue as at that date (2016: 0.42%, 2015: 0.59%). The weighted average remaining contractual life of share options outstanding at the end of the year was 1.52 years (2016: 2.11 years, 2015: 2.74 years). The exercise in full of the outstanding share options would, under the present capital structure of the Company, result in the issue of 129,919,000 (2016: 187,529,000 ) additional ordinary shares of the Company and additional share capital of RMB1,339,702,913 (2016: RMB1,912,814,087 ).

27. RESERVES

According to the laws and regulations of the PRC and the articles of association of CNOOC China Limited, CNOOC China Limited is required to provide for certain statutory funds, namely, the general reserve fund and the staff and workers' bonus and welfare fund, which are appropriated from net profit (after making up for losses from previous years), but before dividend distribution.

The general reserve fund, which is determined at the discretion of the board of directors of CNOOC China Limited, can only be used, upon approval by the relevant authority, to offset against accumulated losses or to increase capital.

Appropriation to the staff and workers' bonus and welfare fund, which is determined at the discretion of the board of directors of CNOOC China Limited, is expensed as incurred under IFRSs/HKFRSs. The staff and workers' bonus and welfare fund can only be used for special bonuses or collective welfare of employees.

As at December 31, 2017, the general reserve fund amounted to RMB60,000 million (December 31, 2016: RMB10,000 million).

In accordance with the "Temporary Regulation for Safety Expense Financial Management of Higher Risk Industry" and the implementation guidance issued by the MOF of the PRC, the Group is required to accrue a safety fund for its oil and gas exploration and production activities within the PRC by appropriating a portion of its net profit to other reserves based on its annual production from offshore China. Such reserve is reduced for expenses incurred to improve the safety conditions of oil and gas production. When the safety fund is fully utilized, additional expenses incurred for safety production purposes are charged directly to the profit or loss for the year. As of December 31, 2017, the Group's safety fund reserve under the PRC regulations amounted to nil (December 31, 2016: nil).

F-62

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

28. RELATED PARTY TRANSACTIONS

As disclosed in note 1, the Company is a subsidiary of CNOOC, which is a state-owned enterprise subject to the control of the State Council of the PRC. The State Council of the PRC directly and indirectly controls a significant number of state-owned entities and organizations.

Comprehensive framework agreement with CNOOC in respect of a range of products and services

As the Group is controlled by CNOOC, transactions with CNOOC, its subsidiaries and associates (the "CNOOC Group") are disclosed as related party transactions. The connected transactions or continuing connected transactions defined in Chapter 14A of the Listing Rules in respect of items listed below also constitute related party transactions. The Company has complied with the disclosure requirements in accordance with Chapter 14A of the Listing Rules for continuing connected transactions listed below. The Company entered into a comprehensive framework agreement with CNOOC on November 15, 2016 for the provision (1) by the Group to the CNOOC Group and (2) by the CNOOC Group to the Group, 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 continuing connected transactions under the comprehensive framework agreement and the relevant annual caps for the three years from January 1, 2017 were approved by the independent shareholders of the Company 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 the CNOOC Group to the Group:

(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) Floating production, storage and offloading ("FPSO") vessel leases

(2) Provision of management, technical, facilities and ancillary services, including the supply of materials by the Group to the CNOOC Group; and

(3) Sales of petroleum and natural gas products by the Group to the CNOOC Group:

(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

F-63

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

28. RELATED PARTY TRANSACTIONS (continued)

Pricing principles

The basic pricing principle for the continuing connected transactions between the Group and the CNOOC Group 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).

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 prices; 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 the CNOOC Group to the Group and (3)(a)-(3)(b) above provided by the Group to the CNOOC Group, on the basis of the above pricing principle, are 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 the CNOOC Group to the Group, 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 CNOOC Group 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 Group to the CNOOC Group, on the basis of the above pricing principle, are determined through arm’s length negotiation between both parties with reference market price.

F-64

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

28. RELATED PARTY TRANSACTIONS (continued)

The following is a summary of significant related party transactions entered into in the ordinary course of business between the Group and its related parties during the year and the balances arising from related party transactions at the end of the year:

(i) Provision of exploration, oil and gas development, oil and gas production as well as marketing, management and ancillary services by the CNOOC Group to the Group

	2015		2016		2017
Provision of exploration and support services		7,457		4,357		5,912
- Inclusive of amounts capitalized under property, plant and equipment		4,158		2,364		3,392
Provision of oil and gas development and support services		22,733		14,214		16,317
Provision of oil and gas production and support services (note a)		8,384		7,250		8,894
Provision of marketing, management and ancillary services (note b)		954		994		1,450
FPSO vessel leases (note c)		1,770		1,551		1,383
		41,298		28,366		33,956

(ii) Provision of management, technical, facilities and ancillary services, including the supply of materials by the Group to the CNOOC Group

The Group did not enter into any transactions in the above category for the years ended December 31, 2015, 2016 or 2017.

(iii) Sales of petroleum and natural gas products by the Group to the CNOOC Group

	2015		2016		2017
Sales of petroleum and natural gas products (other than long-term sales of natural gas and liquefied natural gas) (note d)		105,401		88,682		109,518
Long term sales of natural gas and liquefied natural gas (note e)		10,557		8,663		9,837
		115,958		97,345		119,355

F-65

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

28. RELATED PARTY TRANSACTIONS (continued)

(iv) Transactions and balances with CNOOC Finance Corporation Limited (“CNOOC Finance”) (note f)

(a) Interest income received by the Group

	2015		2016		2017
Interest income from deposits in CNOOC Finance		629		564		360

(b) Deposits balances made by the Group

	2016		2017
Deposits in CNOOC Finance		19,437		19,465

(v) Balances with the CNOOC Group

	2016		2017
Amount due to CNOOC
- included in other payables and accrued liabilities		215		193
Amount due to other related parties
- included in trade and accrued payables		15,091		16,651
		15,306		16,844
Borrowings from CNOOC (note g)		4,811		4,532
Amounts due from other related parties
– included in trade receivables		13,090		12,401
– included in other current assets		173		513
		13,263		12,914

(vi) Balance with a joint venture

	2016		2017
Amount due from a joint venture
– included in other current assets		135		126

F-66

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

28. RELATED PARTY TRANSACTIONS (continued)

(vii) Transactions and balances with other state-owned enterprises

The Group enters into extensive transactions covering sales of crude oil and natural gas, purchase of property, plant and equipment and other assets, receiving of services, and making deposits with state-owned enterprises, other than the CNOOC Group, in the normal course of business on terms comparable to those with other non-state-owned enterprises. The purchases of property, plant and equipment and other assets, and receipt of services from these state-owned enterprises are individually not significant. The individually significant sales transactions with these state-owned enterprises are disclosed in note 33. In addition, the Group had certain of its cash in bank and time deposits with certain state-owned banks in the PRC as at December 31, 2017, as summarized below:

	2016		2017
Cash and cash equivalents		6,612		3,824
Time deposits with maturity over three months		108		13
Specified dismantlement fund accounts (note 18)		6,088		7,555
		12,808		11,392

Interest rates for the above time deposits and specified dismantlement fund accounts are at prevailing market rates.

(viii) Key management personnel’s remuneration

Key management personnel’s remuneration is disclosed in note 8.

(ix) Coalbed Methane Resources Exploration and Development Cooperation Agreement with China United Coalbed Methane Corporation Limited

	2016		2017
Accumulated investment		1,647		1,940

The amount due to the parent company and amounts due from/to related parties are unsecured, interest-free and are repayable on demand, unless otherwise disclosed.

F-67

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

28. RELATED PARTY TRANSACTIONS (continued)

Notes:

a) These represent the services for production operations, the provision of various facilities and ancillary services, such as provision of different types of materials, medical and employee welfare services, maintenance and repair of major equipment and supply of water, electricity and heat to the Group, some of which may not be available from independent third parties or available on comparable terms.

b) These include marketing, administration and management, management of oil and gas operations and integrated research services as well as other ancillary services relating to exploration, development, production and research activities of the Group. In addition, the CNOOC Group leased certain premises to the Group for use as office premises and staff quarters out of which they provided management services to certain properties.

c) CNOOC Energy Technology & Services Limited leased FPSO vessels to the Group for use in oil production operations.

d) The sales include crude oil, condensate oil, liquefied petroleum gas, natural gas and liquefied natural gas to the CNOOC Group. Individual sales contracts were entered into from time to time between the Group and the CNOOC Group.

e) It is the market practice for sales terms to be determined based on the estimated reserves and production profile of the relevant gas fields. The long term sales contracts usually last for 5 to 20 years.

f) CNOOC Finance is a 31.8% owned associate of the Company and also a subsidiary of CNOOC. Under the financial services framework agreement with CNOOC Finance dated December 1, 2016, CNOOC Finance continues to provide to the Group settlement, depository, discounting, loans and entrustment loans services. The agreement is effective from January 1, 2017 to December 31, 2019. The depository services were exempted from independent shareholders’ approval requirements under the Listing Rules. The Group's maximum daily outstanding balance for deposits stated in CNOOC Finance (including accrued interest but excluding funds placed for the purpose of extending entrustment loans pursuant to the entrustment loan services) in 2017 was RMB19,500 million (2016: RMB22,000 million).

g) In September 2014, CNOOC provided CNOOC International Limited, a wholly-owned subsidiary of the Company a five-year uncommitted revolving loan facility for general purposes, with the principal amount of US$135 million of 0.95% per annum. As at December 31, 2017, the withdrawal amount of the loan was US$130 million (December 31, 2016: US$130 million); In December 2014, CNOOC provided the Company a five-year uncommitted revolving loan facility for general purposes, with the principal amount of US$600 million of 0.95% per annum. As at December 31, 2017, the withdrawal amount of the loan was US$564 million (December 31, 2016: US$564 million).

F-68

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

29. RETIREMENT BENEFITS

All the Group's full-time employees in the PRC are covered by a state-managed retirement benefit plan operated by the government of the PRC, and are entitled to an annual pension. The PRC government is responsible for the pension liabilities to these retired employees. The Group is required to make annual contributions to the state-managed retirement benefit plan at rates ranging from 11% to 22% of the employees' base salaries.

The Company is required to make contributions to a defined contribution mandatory provident fund at a rate of 5% of the salaries of all full-time employees in Hong Kong. The related pension costs are expensed as incurred.

The Group provides retirement benefits for all local employees in overseas locations in accordance with relevant labor law, and provides employee benefits to expatriate staff in accordance with the relevant employment contracts.

During the year, the Group's pension costs charged to the consolidated statement of profit or loss and other comprehensive income amounted to RMB651 million (2016: RMB695 million, 2015: RMB613 million).

30. NOTE TO THE CONSOLIDATED STATEMENT OF CASH FLOWS

Reconciliation of profit/(loss) before tax to cash generated from operations

	2015			2016			2017
Profit/(loss) before tax		17,130			(5,275	)		36,357
Adjustments for:
Interest income		(873	)		(901	)		(653	)
Finance costs		6,118			6,246			5,044
Exchange losses/(gains), net		143			790			(356	)
Share of (profits)/losses of associates		(256	)		609			(302	)
Share of profit of a joint venture		(1,647	)		(533	)		(553	)
Investment income		(2,398	)		(2,774	)		(2,409	)
Impairment and provision		2,746			12,171			9,130
Depreciation, depletion and amortization		73,439			68,907			61,257
Loss on disposal and write-off of property, plant and equipment		2,115			2,304			1,937
Others		70			-			-
Subtotal		96,587			81,544			109,452
Decrease/(increase) in trade receivables and other current assets		7,932			(2,820	)		(1,073	)
Decrease in inventories and supplies		1,427			922			1,464
(Decrease)/increase in trade and accrued payables and other payables		(9,851	)		2,491			782
Cash generated from operations		96,095			82,137			110,625

F-69

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

30. NOTE TO THE CONSOLIDATED STATEMENT OF CASH FLOWS (continued)

Reconciliation of liabilities arising from financing activities

The table below details changes in the Group's liabilities arising from financing activities, including both cash and non-cash changes. Liabilities arising from financing activities are those for which cash flows were, or future cash flows will be, classified in the Group's consolidated statement of cash flows as cash flows from financing activities.

	Loans and borrowings			Interest payable			Dividend
	(Note 24)			(Note 23)			payable			Total
At January 1, 2017		150,476			1,244			-			151,720
Financing cash flows		(9,669	)		(5,154	)		(16,448	)		(31,271	)
Foreign exchange translation		(8,911	)		51			(52	)		(8,912	)
Finance costs		354			5,040			-			5,394
Dividends declared		-			-			16,500			16,500
At December 31, 2017		132,250			1,181			-			133,431

F-70

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

31. COMMITMENTS AND CONTINGENCIES

(i) Capital commitments

As at December 31, 2017, the Group had the following capital commitments, principally for the construction of property, plant and equipment:

	2016		2017
Contracted, but not provided for (1)		46,515		46,704

(1) The capital commitments contracted, but not provided for, include the estimated payments to the Ministry of Land and Resources of the PRC for the next five years with respect to the Group's exploration and production licenses.

The above table includes a commitment of approximately RMB4,030 million (December 31, 2016: RMB2,482 million) contracted with the CNOOC Group.

Capital commitments of a joint venture:

	2016		2017
Contracted, but not provided for		360		691

As at December 31, 2017, the Group had unutilized banking facilities amounting to approximately RMB53,749 million (December 31, 2016: RMB60,697 million).

(ii) Operating lease commitments

a. Office properties

The Group leases certain of its office properties under operating lease arrangements. Leases for properties are negotiated for terms ranging from 6 months to 20 years.

As at December 31, 2017, the Group had total minimum lease payments under non-cancellable operating leases falling due as follows:

	2016		2017
Commitments due:
No later than one year		1,317		1,630
Later than one year and not later than  two years		896		1,048
Later than two years and not later than  five years		1,534		1,274
Later than five years		1,963		1,774
		5,710		5,726

The above table includes minimum lease payments of approximately RMB1,218 million (December 31, 2016: RMB639 million) to the CNOOC Group.

F-71

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

31. COMMITMENTS AND CONTINGENCIES (continued)

(ii) Operating lease commitments (continued)

a. Office properties (continued)

Office properties commitments of a joint venture:

	2016		2017
Commitments due:
No later than one year		25		18
Later than one year and not later than two years		17		12
Later than two years and not later than five years		26		16
Later than five years		51		23
		119		69

b. Plant and equipment

The Group leases certain of its plant and equipment under operating lease arrangements for a term from 1 year to 25 years.

As at December 31, 2017, the Group had total minimum lease payments under non-cancellable operating leases falling due as follows:

	2016		2017
Commitments due:
No later than one year		1,378		1,272
Later than one year and not later than two years		734		875
Later than two years and not later than five years		1,316		1,616
Later than five years		3,878		3,406
		7,306		7,169

The above table includes a commitment of approximately RMB3,366 million (December 31, 2016: RMB3,211 million) to the CNOOC Group.

F-72

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

31. COMMITMENTS AND CONTINGENCIES (continued)

(iii) Contingencies

(i) Two oil spill accidents ( the “Penglai 19-3 Oilfield Oil Spill Accidents”) occurred on June 4, and June 17, 2011 respectively at Platforms B and C of the Penglai 19-3 oilfield, which is being operated under a production sharing contract (the “PSC”) among CNOOC China Limited, a subsidiary of the Company, and two subsidiaries of ConocoPhillips, a U.S. based oil company, among which ConocoPhillips China Inc. (the “COPC”) was the operator and responsible for the daily operations of the oilfield when the Penglai 19-3 Oilfield Oil Spill Accidents occurred.

On August 10, 2015, the Company received a Notice Calling for Responses from the Qingdao Maritime Court of the People’s Republic of China (the “Qingdao Maritime Court”) for a public interest action filed by China Biodiversity Conservation and Green Development Foundation (the “Plaintiff”) in relation to the Penglai 19-3 Oilfield Oil Spill Accidents (the “Lawsuit”). The Lawsuit is lodged against COPC and CNOOC China Limited. On February 2, 2018, CNOOC China Limited received a ruling dated December 28, 2017 issued by Qingdao Maritime Court (the "Ruling"). Pursuant to the Marine Environment Protection Law of the People’s Republic of China amended in 2016, Qingdao Maritime Court ruled that the Plaintiff was not an appropriate entity to file Lawsuit, and rejected it. As none of the parties to the Lawsuit appealed within the time limit, the Ruling came into effect. Therefore, CNOOC China Limited bears no liability for the Lawsuit.

The Company is of the view that there was no material financial impact of the Penglai 19-3 Oilfield Oil Spill Accidents on the Company.

(ii) As a Chinese Resident Enterprise, the Company may be liable to pay taxes on the deemed interest income for the funding provided to its overseas subsidiaries starting from January 1, 2008. The Company has prepared contemporaneous documentation in accordance with applicable PRC tax laws and regulations and is currently awaiting confirmation from its in-charge tax authority.

The Group is subject to tax in numerous jurisdictions around the world. There are audits in progress and items under review. Difference in positions taken by taxation authorities over the interpretation and application of tax laws and regulations may increase the Group's tax liability. Management has assessed the possible future outcome of matters that are currently under dispute. The Company believes that an adequate provision for future tax liability has been included in the consolidated financial statements based on available information.

In addition to the matters mentioned above, the Group is dealing with a number of other lawsuits and arbitrations that arise in the ordinary course of business. While the results of these legal proceedings cannot be ascertained at this stage, the Company believes these proceedings are not expected to have a material effect on the consolidated financial statements.

F-73

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

32.       FINANCIAL INSTRUMENTS

Fair value of financial instruments

The Group enters into contracts to purchase and sell crude oil, natural gas and other energy commodities, and use derivative contracts, including futures, forwards, swaps and options for hedging and trading purposes (collectively derivative contracts). The Group also uses derivatives to manage foreign currency risk for non-trading purposes.

For purposes of estimating the fair value of the derivative contracts, wherever possible, the Group utilizes quoted market price and, if not available, estimates from third-party brokers. These brokers’ estimates are corroborated with multiple sources and/or other observable market data utilizing assumptions that market participants would use when pricing the assets or liabilities, including assumptions about risk and market liquidity.

The carrying values of the Group’s cash and cash equivalents, time deposits, trade receivables, other current assets, short-term loans, trade and accrued payables, other payables and accrued liabilities approximated to their fair values at the reporting date due to the short maturity of these instruments.

The carrying amount of the Group’s non-current non-publicly traded equity investments represents an appropriate estimate of their fair values, as sufficient information is not available recently to measure their fair values as at December 31, 2017 and 2016.

The fair value of the Group's long term bank loans with floating interest rates approximated to the carrying amount as at December 31, 2017 and 2016.

The estimated fair value of the Group's long term guaranteed notes was approximately RMB128,315 million as at December 31, 2017 (2016: RMB140,135 million), which was determined by reference to the market price as at December 31, 2017.

F-74

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

32. FINANCIAL INSTRUMENTS (continued)

Fair value hierarchy

The Group uses the following hierarchy that reflects the significance of the inputs used in making the fair value measurement:

Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities. Active markets are those in which transaction occur in sufficient frequency and volume to provide pricing information on an on-going basis.

Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options, including those that have prices similar to quoted market prices, private equity funds and corporate wealth management products. The Group obtains information from sources of independent price publications, over-the-counter broker quotes and the fund management’s quotations as at the reporting date.

Level 3: fair value measurements are those derived from valuation techniques that include inputs for the asset or liability that are not based on observable market data (unobservable inputs), or where the observable data does not support the majority of the instruments fair value.

As at December 31, 2017 and December 31, 2016, the Group held the following financial instruments measured at fair value for each hierarchy respectively:

Assets measured at fair value	December 31 2017		Level 1		Level 2		Level 3
Other financial assets-current
Corporate wealth management products		66,229		-		66,229		-
Money market funds		8,115		8,115		-		-
Derivative financial assets – current		-		-		-		-
Equity investments
Non-publicly traded investments- current		14		-		14		-
Publicly traded investments-non current		781		781		-		-
		75,139		8,896		66,243		-
Liabilities measured at fair value
Derivative financial liabilities – current		-		-		-		-

F-75

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

32. FINANCIAL INSTRUMENTS (continued)

Fair value hierarchy (continued)

Assets measured at fair value	December 31 2016			Level 1		Level 2			Level 3
Other financial assets-current
Corporate wealth management products		46,958			-		46,958			-
Money market funds		5,931			5,931		-			-
Derivative financial assets – current		428			-		428			-
Equity investments
Non-publicly traded investments- current		15			-		15			-
Publicly traded investments-non current		1,391			1,391		-			-
		54,723			7,322		47,401			-
Liabilities measured at fair value
Derivative financial liabilities – current		(426	)		-		(426	)		-

For financial assets and liabilities arising from derivative contracts, inputs may be readily observable, market-corroborated or generally unobservable. The Group utilizes valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. To value longer term transactions and transactions in less active markets for which pricing information is not generally available, unobservable inputs may be used.

No amounts have been transferred between the different levels of the fair value hierarchy for the year.

F-76

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

33. CONCENTRATION OF CUSTOMERS

A substantial portion of the Group's oil and gas commodities sales to third-party customers is made to a small number of customers on credit. Details of the gross sales to these top five third party customers are as follows:

	2015		2016		2017
China Petroleum & Chemical Corporation*		14,692		9,659		15,488
PetroChina Company Limited*		5,502		6,923		11,957
BP p.l.c.		3,093		2,843		3,108
Phillips 66		N/A		N/A		2,631
Royal Dutch Shell PLC		6,917		3,661		2,627
EOG Resources, Inc.		3,746		2,660		N/A

* These transactions are with other state-owned enterprises.

34. FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES

The Group's principal financial instruments comprise bank loans, long term guaranteed notes, equity investment and other financial assets, cash and short term deposits. The Group has various other financial assets and liabilities such as trade receivables, trade and accrued payables, which arise directly from its operations.

The Group is exposed to credit risk, oil and gas price risk, currency risk, interest rate risk and liquidity risk.

The Group's senior management oversees the management of these risks. The Group's senior management is supported by various departments that advise on financial risks and the appropriate financial risks governance framework for the Group. Those departments provide assurance to the Group's senior management that the Group's financial risk-taking activities are governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite.

F-77

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

34. FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES (continued)

(i) Credit risk

The carrying amounts of the Group's cash and cash equivalents, time deposits, money market funds and corporate wealth management products, trade receivables and other receivables, and other current assets except for prepayments represent the Group's maximum exposure to credit risk in relation to its financial assets.

The significant portion of the Group's trade receivables is related to the sale of oil and natural gas to third party customers. The Group performs ongoing credit evaluations of the customers' financial condition and collateral may be required from customers. The Group made an impairment allowance on doubtful receivables and actual losses have been within management's expectation.

Concentrations of credit risk are managed by customer/counterparty and by geographical region. At December 31, 2017, the Group has certain concentrations of credit risk as 0.16% (2016: 1%) and 7.63% (2016: 5%) of the Group's trade receivables were due from the Group's largest third-party customer and the five largest third-party customers, respectively.

No other financial assets carry a significant exposure to credit risk.

(ii) Oil and gas price risk

Since the Group makes reference to international oil prices to determine its realized oil price, fluctuations in international oil price would have a significant impact on the Group's sales revenue, profit, assets value and cashflow. In addition, certain of the Group's natural gas sales contracts contain price adjustment provisions. Any changes in international oil prices, inflation rate and domestic natural gas price policies may result in changes in natural gas prices, which will affect the Group's profitability. In North America, the majority of the Group's oil and gas production is sold under short-term contracts, exposing the Group to the risk of price movements. Other energy contracts the Group enters into also expose the Group to oil and gas price risk between the time the Group purchases and sells contracted volumes.

(iii) Currency risk

Substantially all of the Group's oil and gas sales are denominated in Renminbi and United States dollars ("US dollars"). Starting from July 21, 2005, China reformed the exchange rate regime by moving into a managed floating exchange rate regime based on market supply and demand with reference to a basket of currencies. Renminbi would no longer be pegged to the US dollars. From January 1, 2017 to December 31, 2017 (the last working day in 2017), Renminbi has appreciated by approximately 6.16% (December 31, 2016: depreciated by approximately 6.39%) against the US dollars. At December 31, 2017, approximately 82% (December 31, 2016: 88%, December 31, 2015: 89%) of the Group's cash and cash equivalents and time deposits with maturity over three months were denominated in Renminbi, and the remaining amounts were substantially denominated in US dollars and Hong Kong dollars. The Group also has exposures to currencies other than the US dollars, such as Canadian dollar and British Pounds as such exposures are considered insignificant.

F-78

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

34. FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES (continued)

(iii) Currency risk (continued)

Management has assessed the Group's exposure to foreign currency risk by using a sensitivity analysis on the change in foreign exchange rate of the US dollars, to which the Group is mainly exposed to as at December 31, 2017 and 2016. Based on management's assessment at December 31, 2017, a 5% strengthening/weakening of RMB against US dollars would have increased/decreased the profit for the year of the Group by 0.06% (December 31, 2016: 6.63%) and the equity of the Group by 0.31% (December 31, 2016: 0.46%). This analysis has been determined assuming that the change in foreign exchange rates had occurred at the end of the reporting period and had been applied to the foreign currency balances to which the Group has significant exposure with all other variables held constant. The analysis is performed on the same basis for 2016.

Senior management is closely monitoring the Group's net exposure to foreign currency risk. The appreciation of Renminbi against the US dollars may have the following impact on the Group. On one hand, since the benchmark oil and gas prices are usually in US dollars against Renminbi, the Group's oil and gas sales may decrease due to the depreciation of the US dollars against Renminbi. On the other hand, the depreciation of the US dollars against Renminbi will also decrease the Group's costs for imported equipment and materials, most of which are denominated in the US dollars. In addition, the debt repayment by the Group will decrease since all of the Group’s interest-bearing debts are also denominated in the US dollars.

(iv) Interest rate risk

The interest rate risk is closely monitored by the Group's senior management. As at the end of 2017, the interest rates for 95.5% of the Group's debts were fixed. Apart from borrowing for Tangguh LNG Project, all of the Group's long term debts are fixed rate. The weighted average term of the Group's debt balance outstanding was approximately 9.35 years. The fixed interest rates can reduce the volatility of finance costs under uncertain environments and the Group's exposure to changes in interest rates is not expected to be material.

(v) Liquidity risk

The Group manages its liquidity risk by regularly monitoring its liquidity requirements and its compliance with debt covenants to ensure that it maintains sufficient cash and cash equivalents, and readily realizable equity investments and other financial assets, and adequate time deposits to meet its liquidity requirements in the short and long term. In addition, bank facilities have been put in place for contingency purposes.

The Group's trade and accrued payables, other payables and accrued liabilities are all due for settlement within six months after the reporting date.

F-79

CNOOC LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts expressed in millions of Renminbi unless otherwise stated)

34. FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES (continued)

(vi) Capital management

The primary objectives of the Group's capital management are to safeguard the Group's ability to continue as a going concern and to maintain healthy capital ratios in order to support its business and maximize shareholders' value.

The Group manages its capital structure and makes adjustments to it in light of changes in economic conditions. To maintain or adjust the capital structure, the Group may return capital to shareholders, raise new debt or issue new shares. No changes were made in the objectives, policies or processes for managing capital during the years end December 31, 2015, 2016 and 2017.

The Group monitors capital on the basis of the debt to capital ratio, which is calculated as interest-bearing debts divided by total capital (equity attributable to owners of the parent plus interest-bearing debts).

	2015			2016			2017
Interest-bearing debts		164,645			150,476			132,250
Equity attributable to owners of the parent		386,041			382,371			379,975
Total capital		550,686			532,847			512,225
Gearing ratio		29.9	%		28.2	%		25.8	%

35. CHARGE OF ASSETS

CNOOC NWS Private Limited, a wholly-owned subsidiary of the Group, together with the other joint venture partners and the operator of the NWS Project, signed a Deed of Cross Charge and an Extended Deed of Cross Charge whereby certain liabilities incurred or to be incurred, if any, by the Company in respect of the NWS Project are secured by its interest in the NWS Project.

36. SUBSEQUENT EVENTS

The Group has no significant subsequent events needed to be disclosed in the consolidated financial statements.

37. APPROVAL OF THE FINANCIAL STATEMENTS

The consolidated financial statements were approved and authorized for issue by the Board of Directors on March 29, 2018.

F-80

EX-8.1

Exhibit 8.1

Subsidiaries

As of December 31, 2017, we owned, directly or indirectly, the following subsidiaries.

Name of entity	Our interest	Jurisdiction of incorporation
CNOOC China Limited	100%	Tianjin, PRC
CNOOC International Limited	100%	British Virgin Islands
China Offshore Oil (Singapore) International Pte Ltd	100%	Singapore
CNOOC Finance (2003) Limited	100%	British Virgin Islands
Malacca Petroleum Limited	100%	Bermuda
OOGC America LLC	100%	Delaware, USA
OOGC Malacca Limited	100%	Bermuda
CNOOC Southeast Asia Limited	100%	Bermuda
CNOOC Africa Holding Ltd.	100%	British Virgin Islands
CNOOC Africa Ltd.	100%	British Virgin Islands
CNOOC SES Ltd.	100%	Labuan, F.T.,  Malaysia
CNOOC Poleng Ltd.	100%	Labuan, F.T.,  Malaysia
CNOOC Madura Ltd.	100%	Labuan, F.T.,  Malaysia
CNOOC NWS Private Limited	100%	Singapore
CNOOC Australia E&P Pty Ltd	100%	Australia
CNOOC Muturi Holding Limited	100%	British Virgin Islands
CNOOC Muturi Limited	100%	The Isle of Man
CNOOC Australia Limited	100%	British Virgin Islands
CNOOC Exploration & Production Nigeria Limited	100%	Nigeria
CNOOC Hong Kong Holding Limited	100%	Hong Kong
CNOOC Congo SA	100%	Republic of Congo
CNOOC Caspian (Kazakhstan) Ltd.	100%	Cayman Islands

CNOOC Australia International Holdings Private Limited	100%	Singapore
CNOOC Australia Energy Capital Management Pty Ltd	100%	Australia
CNOOC Batanghari Ltd.	100%	Labuan, F.T.,  Malaysia
CNOOC Palung Aru Ltd.	100%	Labuan, F.T.,  Malaysia
CNOOC FPSO Holding Limited	100%	Liberia
CNOOC Liberia Limited	100%	Liberia
CNOOC Uganda (BVI) Ltd	100%	British Virgin Islands
De coöperatieve vereniging CNOOC Netherlands U.A.	100%	The Netherlands
CNOOC Netherlands B.V.	100%	The Netherlands
CNOOC Uganda Ltd	100%	Uganda
CNOOC Deepwater Development Limited	100%	Zhuhai, PRC
CNOOC Hainan Dock Limited	100%	Hainan, PRC
CNOOC Iraq Limited	100%	British Virgin Islands
CNOOC Finance (2011) Limited	100%	British Virgin Islands
CNOOC Reserves Fund I, Ltd.	100%	Cayman Islands
CNOOC Luxembourg S.à r.l.	100%	Luxembourg
CNOOC Finance (2012) Limited	100%	British Virgin Islands
CNOOC Finance (2013) Limited	100%	British Virgin Islands
Tainan-Chaoshan Petroleum Operating Company Limited*	50%	British Virgin Islands
Husky - CNOOC Madura Limited *	40%	British Virgin Islands
Chaoyang Petroleum (BVI) Limited*	50%	British Virgin Islands
Chaoyang Petroleum (Trinidad) Block 3A Limited*	50%	Barbados
Chaoyang Petroleum (Trinidad) Block 2C Limited*	50%	Barbados
Bridas Corporation*†	50%	British Virgin Islands
Axion Energy Holding Ltd. *	50%	British Virgin Islands

PNG Energy Limited	70%	British Virgin Islands
GINI Energy Ltd	70%	Papua New Guinea
CNOOC Iceland ehf.	100%	Iceland
CNOOC Luxembourg Holding S.à r.l.	100%	Luxembourg
CNOOC PETROLEUM BRASIL LTDA	100%	Brazil
CNOOC International Energy Services (Beijing) Limited	100%	Beijing, PRC
China Offshore Oil Corporation E&P Mexico, S.A.P.I. de C.V.	100%	Mexico
China Offshore Oil Corporation E&P Services Mexico, S.A.P.I. de C.V.	100%	Mexico
CNOOC New Zealand E&P Limited	100%	New Zealand
CNOOC Finance (2015) Australia Pty Ltd	100%	Australia
Canadian Nexen Petroleum East Al Hajr Ltd.	100%	Alberta, Canada
CanadianOxy Offshore Production Co.	100%	Delaware, USA
CNOOC Canada Energy Ltd.	100%	British Columbia, Canada
CNOOC Nexen Finance (2014) ULC	100%	Nova Scotia, Canada
CNOOC Nexen Petroleum Guyana Limited	100%	Barbados
CNOOC UK Limited	100%	England and Wales
CNOOC West Africa Petroleum E & P SA	100%	Senegal
ICM Assurance Ltd.	100%	Barbados
Nexen Energy Acquisitions Holdings Limited	100%	Jersey
Nexen Energy Capital Management U.S.A. Inc.	100%	Delaware, USA
Nexen Energy Holdings International Limited	100%	Jersey
Nexen Energy Holdings U.S.A. Inc.	100%	Delaware, USA
Nexen Energy Marketing U.S.A. Inc.	100%	Delaware, USA
Nexen Energy Services U.S.A. Inc.	100%	Delaware, USA
Nexen Energy ULC	100%	British Columbia, Canada
Nexen Ettrick U.K. Limited	100%	England and Wales

Nexen Holdings U.S.A. Inc.	100%	Delaware, USA
Nexen Holdings West Africa Limited	100%	Jersey
Nexen Oil & Gas Holdings U.S.A. LLC.	100%	Delaware, USA
Nexen Oilfield Services Nigeria Limited	100%	Jersey
Nexen Petroleum Colombia Limited	100%	Jersey
Nexen Petroleum Deepwater Nigeria Limited	100%	Nigeria
Nexen Petroleum Dragon U.K. Limited	100%	England and Wales
Nexen Petroleum Exploration and Production Nigeria Limited	100%	Nigeria
Nexen Petroleum Nigeria Limited	100%	Nigeria
Nexen Petroleum Offshore U.S.A. Inc.	100%	Delaware, USA
Nexen Petroleum Operations Yemen Limited	100%	Jersey
Nexen Petroleum Sales U.S.A. Inc.	100%	Texas, USA
Nexen Petroleum U.K. Holdings Limited	100%	England and Wales
Nexen Petroleum U.K. Limited	100%	England and Wales
Nexen Petroleum U.S.A. Inc.	100%	Delaware, USA
Nexen Resource Holdings U.K. Limited	100%	England and Wales
Wascana Energy 2001 Ltd.	100%	Saskatchewan, Canada
Canadian Nexen Petroleum Yemen	100%	Alberta, Canada
Nexen Marketing	100%	Alberta, Canada
Nexen Nigerian Holdings Coöperatief U.A	100%	The Netherlands
Nexen Oil Sands Partnership	100%	Alberta, Canada
CNOOC Finance (2015) U.S.A. LLC	100%	Delaware, USA

________________

* We and our partners jointly control these entities.

† The name of this entity was changed to BC Energy Investments Corp. on March 23, 2018.

EX-11.1

Exhibit 11.1

CNOOC Limited

(incorporated under the laws of Hong Kong with limited liability)

Code of Ethics for Directors and Senior Officers

24 August 2017

I.INTRODUCTION

This “CNOOC Limited Code of Ethics for Directors and Senior Officers” (the “Code of Ethics”) summarizes the major long-standing principles of conduct that our company, CNOOC Limited (the “Company” or “our company”), follows to ensure our business is conducted with integrity and in compliance with the law. Because our company is incorporated in Hong Kong with our shares listed on the Stock Exchange of Hong Kong Limited (the “Hong Kong Stock Exchange”) and our ADRs listed on the New York Stock Exchange and the Toronto Stock Exchange, and because our core operation areas are in the People’s Republic of China (the “PRC”), we are at least subject to laws and ethical rules of all these jurisdictions. We expect our directors and senior management to know and follow the policies outlined in this Code of Ethics. For the purpose of this Code of Ethics, the scope of senior management includes Chief Executive Officer, President, Chief Financial Officer, Executive Vice Presidents, Senior Vice Presidents, Vice Presidents, Compliance Officer, General Counsel, Company Secretary and general managers and deputy general managers or other equal ranking personnel of the Company's headquarters, departments of the Company’s headquarters, wholly-owned subsidiaries and regional branch companies (collectively, the “Senior Officers”). Apart from any applicable sanctions under relevant laws, rules and regulations, any director or Senior Officer who violates the provisions or spirit of these policies is subject to disciplinary action, up to and including termination of employment.

Each of the directors and Senior Officers has the responsibility to obey applicable laws and act honestly and ethically. To that end, this Code of Ethics is a guide intended to assist each of the directors and Senior Officers to perform proper commercial conduct and to report illegal or unethical conduct. It is not, however, a comprehensive document that addresses every legal or ethical issue that a director or Senior Officer may confront, nor is it a summary of all laws and policies that apply to our business. This Code of Ethics is supplemental to other policies, manuals and internal regulations of our company.

If any director or Senior Officer has any questions about this Code of Ethics or is concerned or unsure about conducts he or she believes may violate this Code of Ethics, other policies of our company or any applicable laws, rules or regulations, the director or Senior Officer should consult with our Compliance Officer, General Counsel, and/or a member of the Audit Committee of our Board of Directors (the “Audit Committee”). No one at our company has the authority to make exceptions to these policies, other than our Board of Directors (the “Board”) or a committee of the Board, and only if such exceptions are allowed under applicable laws and rules.

II. COMPLIANCE WITH LAWS, RULES AND REGULATIONS

The directors and Senior Officers must comply fully with, among other things, all applicable laws, rules and regulations that govern our business conduct in the PRC, Hong Kong Special Administrative Region of the PRC (“Hong Kong”), the United States of America (the “U.S.”), Canada, and any other region or country in which the Company

1

conducts its business, including, but not limited to, securities laws, the Rules Governing the Listing of Securities on The Stock Exchange of Hong Kong Limited (the “Listing Rules”), the New York Stock Exchange rules, the Toronto Stock Exchange Company Manual, environmental laws, insider trading and other market misconduct laws (including, but not limited to, the Securities and Futures Ordinance (Cap.571, Laws of Hong Kong) (the “SFO”)), the U.S. Foreign Corrupt Practices Act and applicable laws relating to the disclosure of payments made to governments for the purpose of commercial development of oil and gas.

III.PROHIBITION AGAINST INSIDER TRADING/INSIDER DEALING AND PROCEDURE OF HANDLING INSIDE INFORMATION

The directors and Senior Officers who have access to, or knowledge of, material non-public information from or about our company are prohibited from buying, selling or otherwise trading in our stock or other securities of our company. The prohibition contained in this section not only applies to the directors and Senior Officers but also to any “manager, secretary of, or any other person involved in the management of, a corporation” (collectively, the “Managers”). “Material non-public” information includes any information, positive or negative, that has not yet been made available or disclosed to the public and that might be of significance to an investor, as part of the total mix of information, in deciding whether to buy or sell stock or other securities.

Such insiders are also prohibited from giving “tips” on material non-public information, that is, directly or indirectly disclosing such information to any other person, including family members, other relatives and friends, so that they may trade in our stock or other securities of our company. Furthermore, if, during the course of service with our company, any director, Senior Officer or Manager acquires material non-public information about another company, such as one of our customers or suppliers or our affiliates, or learn that our company is planning to enter into a major transaction with another company (such as an acquisition), the directors, Senior Officers or Managers are restricted from trading in the securities of the other company.

In the U.S., such “insider trading” is both unethical and illegal, with criminal penalties of up to US$5 million and a jail term of up to 20 years and civil penalties in the U.S. of up to three times the illegal profit gained or loss avoided.

In Hong Kong, “insider dealing” within the meaning of the SFO is broadly similar to insider trading in the U.S. It also constitutes a criminal offence, subject to a maximum penalty of HK$10,000,000 and 10 years’ imprisonment.

In Canada, “insider trading” and “tipping” restrictions are generally similar to those in the U.S., with penalties including a fine of no more than CAD$5,000,000 or imprisonment for a term of no more than 5 year less a day, or both, and also liable to compensate the counterparty to any trades for the damages that result from such trade.

In addition to prohibition from insider trading/insider dealing set forth above, Part XIVA

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of the SFO has been enacted and became effective on 1 January 2013. Such provisions impose statutory obligation of disclosure of “inside” information by listed corporations, in addition to the disclosure obligations under the Listing Rules and the Codes on Takeovers and Mergers and Share Buy-backs. Consequential amendments to the Listing Rules also came into effect on the same day.

Under the SFO, “inside information”, in relation to a listed corporation, means specific information that is about (i) the corporation; (ii) a shareholder or officer of the corporation; or (iii) the listed securities of the corporation or their derivatives; and is not generally known to the persons who are accustomed or would be likely to deal in the listed securities of the corporation but would if generally known to them be likely to materially affect the price of the listed securities.

In general, a listed corporation must, as soon as reasonably practicable after any inside information has come to its knowledge, disclose the information to the public. Although the disclosure obligation rests with the listed corporation, the listed corporation is considered to have knowledge of the inside information when (a) one or more of its officers (which include a director, manager (a person who, under the immediate authority of the board of directors of the listed corporation, is charged with management responsibility affecting the whole of the listed corporation or a substantial part of the listed corporation) or secretary of, or any other person involved in the management (a person who discharges the role of a “manager”) of, the listed corporation) knows or ought reasonably to have known that information in the course of performing functions as officers of the listed corporation and (b) a reasonable person, acting as an officer of the corporation, would consider that the information is inside information in relation to the listed corporation. The listed corporation and its directors must take all reasonable steps to maintain strict confidentiality of inside information until it is announced.

In addition to the provisions under the SFO, where in the view of the Hong Kong Stock Exchange, there is or there is likely to be a false market in an issuer’s securities, the listed corporation must, as soon as reasonably practicable after consultation with the Hong Kong Stock Exchange, announce the information necessary to avoid a false market in its securities. Under the Listing Rules, a listed corporation must not divulge any information in such a way as to place in a privileged dealing position any person or class or category of persons. It must not release any information in such a way that transactions may be entered into at prices which do not reflect the latest available information.

According to the SFO, it is ultimately the responsibility of a listed corporation’s directors and senior officers to ensure that the listed corporation complies with the disclosure obligation. Accordingly, the Company’s directors and Senior Officers are obliged to take all reasonable measures to ensure proper safeguards exist to prevent the Company from breaching the statutory disclosure requirement, which would include the creation and maintenance of appropriate internal control and reporting systems. If a breach on the part of the Company is attributable to the failure to take all reasonable measures to ensure that proper safeguards exist by, or to any intentional, reckless or negligent conduct of, any

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directors or Senior Officers, the directors or Senior Officers concerned would also be liable.

IV. PROHIBITION AGAINST OTHER MARKET MISCONDUCT

The prohibition contained in this section is derived from Hong Kong laws and regulations. It not only applies to the directors and Senior Officers but also to the Managers. Each of the directors, Senior Officers and Managers is ethically and legally required to take all reasonable measures from time to time to ensure that proper safeguards exist to prevent our company from acting in a way which would result in our company perpetrating any “market misconduct” within the meaning of the SFO. Under Hong Kong laws, the directors, Senior Officers and Managers may be subject to criminal liability if they have actively participated in, consented to, or connived in the criminal misconduct of the corporation which they manage. Under the SFO, “market misconduct” includes insider dealing (see above) and the following:

(a) False Trading

False trading in our securities takes place if a person, whether in Hong Kong or overseas, does or causes anything to be done with the intention that, or being reckless as to whether, it has or is likely to have the effect of creating a false or misleading market in our securities. Creation of a false market includes activities undertaken by any person creating or maintaining an artificial price for our securities. The directors, Senior Officers and Managers are therefore obliged not to undertake any such activities and to have due regard to the prohibition against false trading in carrying out or authorizing transactions which may impact the price of our securities.

(b) Price Rigging

Price rigging occurs where a person, in Hong Kong or elsewhere, engages in a sale or purchase of securities, not involving change in the beneficial ownership of those securities and which has the effect of maintaining, increasing, reducing, stabilizing or causing fluctuations in the price of securities traded on a recognized stock exchange in Hong Kong or overseas. The directors, Senior Officers and Managers must not engage in any such transaction if price rigging, as described above, forms a purpose, even if not the dominant purpose, of the transaction. The onus will be on the relevant director, Senior Officers or Manager to establish that the purpose of any transaction which has the effect of price rigging did not include the purpose of creating a false or misleading appearance with respect to the price of our securities.

(c) Disclosure of False or Misleading Information Inducing Transactions

In broad terms, the SFO prohibits the disclosure of false or misleading information that is likely to induce another person to subscribe for, sell or buy securities or deal in futures contracts in Hong Kong. Accordingly, with respect to information disclosed to third

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parties or to the public generally and which may be expected to induce transactions in our securities (which could include, without limitation, information disclosed through or in the form of a prospectus or other offering memorandum, annual reports, periodic reports, press releases and announcements or through the release of financial information), the directors, Senior Officers and Managers are required to pay proper regard to the veracity of any such information and to consider whether such information is misleading through the inclusion or omission of any material fact.

(d) Disclosure of Information About Prohibited Transactions

Disclosure of information concerning the effect on the price of our securities or futures contracts dealt in by our company, by a transaction carried out in breach of the market misconduct provisions relating to our securities or one of our affiliates or to the futures contracts is itself prohibited in circumstances where the person making the disclosure has been involved directly or indirectly in the transaction or has, or expects to receive, directly or indirectly a benefit as a result of the disclosure. Accordingly, the directors, Senior Officers and Managers should exercise caution and have regard to the relevant provisions of the SFO.

(e) Stock Market Manipulation

“Stock market manipulation” refers to two or more transactions in securities of a corporation that, by themselves or in conjunction with any other transactions, affects or likely to affect (by way of increasing, reducing, or stabilizing) the price of any securities traded on a recognized stock exchange in Hong Kong or overseas and with the intention of inducing another person to sell, purchase or subscribe for, or to refrain from selling, purchasing or subscribing for such securities or the securities of a related corporation. The directors, Senior Officers and Managers must ensure that no transactions in our securities or securities of our affiliates constitute stock market manipulation.

Each form of market misconduct identified above is unethical and illegal. All such market misconduct constitutes criminal offences in Hong Kong, with penalties of up to HK$10,000,000 and 10 years’ imprisonment. An offender may also be liable to civil penalties and may be disqualified from acting as a director of, or participating in the management of, a listed or other specified corporation for a period of up to five years. In addition, as a part of this Code of Ethics, we have attached the Model Code for Securities Transactions by Directors of Listed Issuers (the “Model Code”) issued by the Hong Kong Stock Exchange as Appendix 2 to this Code of Ethics. All of our directors should comply with the Model Code; and all Senior Officers should follow the spirit of the Model Code in conducting their securities transactions. In most instances, Senior Officers who are not our directors are subject to the same ethical and legal requirements in securities transactions as our directors.

V. CONFLICTS OF INTEREST

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Business decisions must be made in the best interest of our company, not motivated by personal interest or gain. Therefore, as a matter of our company policy, all directors and Senior Officers must avoid any actual or perceived conflict of interest. A “conflict of interest” occurs when an individual’s personal interests interfere or conflict in any way (or even appear to interfere or conflict) with the interests of our company. A conflict of interest situation can arise when an employee takes actions or has interests (financial or otherwise) that may make it difficult to perform his or her company work objectively and effectively. Conflicts of interest may also arise when an employee or a member of his or her family receives improper personal benefits as a result of his or her position in our company, regardless of whether such benefits are received from our company or a third party. In relation to loans to, or guarantees of obligations of, employees and their family members, please refer to our company's “Regulations on Prohibition of Provision of Loans to Directors and Senior Officers of CNOOC Limited”. Directors and Senior Officers should also read carefully and comply with our company's “Regulations on the Management of Conflicts of Interest of CNOOC Limited”.

It is difficult to identify exhaustively what constitutes a conflict of interest. For this reason, the directors and Senior Officers must avoid any situation in which their independent business judgment might appear to be compromised. Questions about potential conflicts of interest situations, and disclosure of these situations as they arise, should be addressed and reported to our Compliance Officer, General Counsel and/or a member of the Audit Committee.

VI. CORPORATE OPPORTUNITIES

All directors and Senior Officers are prohibited from: (a) taking themselves personally opportunities that properly belong to our company or are discovered through the use of corporate property, information or position; (b) using corporate property, information or position for personal gain; and (c) competing with our company. All directors and Senior Officers owe a duty to our company to advance its legitimate interests when the opportunity to do so arises.

VII. PROTECTION AND PROPER USE OF COMPANY ASSETS

All directors and Senior Officers must protect our assets and ensure their efficient use. Such assets include, without limitation, intellectual property such as our corporate name, logos, trademarks, patents, copyrights, confidential information, ideas, plans and strategies. Theft, carelessness and waste have a direct impact on our profitability. Any misuse or infringement of our company assets should be reported to our Compliance Officer, General Counsel and/or a member of the Audit Committee.

VIII. PUBLIC COMPANY REPORTING

As a result of our status as a public company in Hong Kong, the U.S. and Canada, we are required to file periodic and other reports with the Hong Kong Stock Exchange, the Hong Kong Securities and Futures Commission, the U.S. Securities and Exchange Commission,

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the Toronto Stock Exchange and the Canadian securities regulatory authorities. Our company views its public disclosure responsibility seriously. To that end, in respect of the various disclosure and reporting obligations to which our company is from time to time subject in Hong Kong, in the U.S. and in Canada, each of the directors and Senior Officers must:

A.take all reasonable steps to ensure that these reports and other public communications furnish the marketplace with full, fair, accurate, timely and understandable disclosure regarding the financial and business condition of our company;

B.promptly bring to the attention of the Audit Committee any material information of which such director or Senior Officer may become aware that affects the disclosures made by our company in its public filings or otherwise would assist the Audit Committee in fulfilling its responsibilities as specified in applicable securities laws and regulations; and

C.promptly bring to the attention of our Compliance Officer, General Counsel and/or the Audit Committee any information he or she may have concerning (i) significant deficiencies in the design or operation of internal controls that could adversely affect our company’s ability to record, process, summarize and report financial data, or (ii) any fraud, whether or not material, involving management or other employees who have a significant role in our company’s financial reporting, disclosures or internal controls.

IX. REPORTING ILLEGAL OR UNETHICAL BEHAVIOR

Each of the directors and Senior Officers has a duty to adhere to this Code of Ethics. Each of the directors and Senior Officers must also promptly bring to the attention of our Compliance Officer, General Counsel and/or the Audit Committee any information he or she may have concerning evidence of a material violation of the securities or other laws, rules or regulations applicable to our company and the operation of its business, by our company or any agent thereof, or of a violation of this Code of Ethics, including any actual or apparent conflicts of interest between personal and professional relationships, involving any management or other employees who have a significant role in our company’s financial reporting, disclosures or internal controls. Confidentiality will be maintained to the fullest extent possible.

A director or Senior Officer will not be penalized for making a good-faith report of violations of this Code of Ethics or other illegal or unethical conduct, nor will we permit retaliation of any kind against anyone who makes a good-faith report. A director or Senior Officer who deliberately submits a false report of a violation, however, will be subject to disciplinary action. If a director or Senior Officer reports a violation and in some way is also involved in the violation, the fact that such director or Senior Officer stepped forward will be considered. If the result of an investigation indicates that corrective action is required, the Board will decide, or designate appropriate persons to decide, what actions to take, including, when appropriate, legal proceedings and

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disciplinary action up to and including termination, to rectify the problem and avoid the likelihood of its recurrence.

X. RELATIONSHIP WITH COMPANY MANUAL

This Code of Ethics supplements the existing policies and procedures already in place as stated in other company manuals and communicated to all employees. Certain policies referred to in this Code of Ethics are contained in their entirety in the other company manuals. The company manuals contain information that is proprietary and confidential, and our company hereby expressly denies waiving any right to assert claims that the contents of such company manuals are proprietary and/or confidential. This Code of Ethics and other company manuals are statements of goals and expectations for individual and business conduct. They are not intended to, and do not in any way constitute, an employment contract or an assurance of continued employment. Our company does not create any contractual rights by issuing this Code of Ethics or any company manual.

XI. AMENDMENT, MODIFICATION AND WAIVER

This Code of Ethics may be amended, modified or waived by the Board. Any change to, or waiver (whether explicit or implicit) of, this Code of Ethics must be disclosed to our stockholders either by including a statement in our annual report on Form 20-F filed with the U.S. Securities and Exchange Commission or by publishing a statement on our website, www.cnoocltd.com.

XII. ACKNOWLEDGMENT

Each of the directors and Senior Officers is accountable for knowing and abiding by the policies contained in this Code of Ethics. Our company may require that the directors and Senior Officers sign an acknowledgment every year confirming that they have received and read this Code of Ethics, understand them and are complying with them.

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Appendix 1:

Contact Information

Audit Committee

Email: ac@cnooc.com.cn

Compliance Officer and General Counsel: Mr. Chenwei

Address: Room 906B, CNOOC Plaza, 25 Chaoyangmenbei Dajie, Beijing, People’s Republic of China

Postcode: 100010

Tel: （86-10）84528299

Email: chenwei@cnooc.com.cn

The above contact information shall be released as appendix according to changes of circumstances.

Appendix 2: Model Code for Securities Transactions by Directors of Listed Issuers by the Hong Kong Stock Exchange

BASIC PRINCIPLES

1.This code (both the basic principles and the rules) sets a required standard against which directors must measure their conduct regarding transactions in securities of their listed issuers. Any breach of such required standard will be regarded as a breach of the Exchange Listing Rules. A director must seek to secure that all dealings in which he is or is deemed to be interested be conducted in accordance with this code.

2.A listed issuer may adopt its own code on terms no less exacting than those set out in this code if it so wishes. Any breach of such code will not be a breach of the Exchange Listing Rules unless it is also a breach of the required standard contained in this code.

3.The Exchange regards it as highly desirable that directors of a listed issuer should hold securities in the listed issuer.

4.Directors wishing to deal in any securities in a listed issuer must first have regard to the provisions of Parts XIII and XIV of the Securities and Futures Ordinance with respect to insider dealing and market misconduct. However, there are occasions where directors should not be free to deal in the listed issuer’s securities even though the statutory requirements will not be contravened.

5.The single most important thrust of this code is that directors who are aware of or privy to any negotiations or agreements related to intended acquisitions or disposals which are notifiable transactions under Chapter 14 of the Listing Rules or connected transactions under Chapter 14A of the Listing Rules or any inside information must

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refrain from dealing in the issuer’s securities as soon as they become aware of them or privy to them until the information has been announced. Directors who are privy to relevant negotiations or agreements or any inside information should caution those directors who are not so privy that there may be inside information and that they must not deal in the issuer’s securities for a similar period.

6.In addition, a director must not make any unauthorised disclosure of confidential information, whether to co-trustees or to any other person (even those to whom he owes a fiduciary duty) or make any use of such information for the advantage of himself or others.

INTERPRETATION

7. For the purpose of this code:

(a)“dealing” includes, subject to paragraph (d) below, any acquisition, disposal or transfer of, or offer to acquire, dispose of or transfer, or creation of pledge, charge or any other security interest in, any securities of the listed issuer or any entity whose assets solely or substantially comprise securities of the listed issuer, and the grant, acceptance, acquisition, disposal, transfer, exercise or discharge of any option (whether call, put or both) or other right or obligation, present or future, conditional or unconditional, to acquire, dispose of or transfer securities, or any interest in securities, of the listed issuer or any such entity, in each case whether or not for consideration and any agreements to do any of the foregoing, and “deal” shall be construed accordingly;

(b)“beneficiary” includes any discretionary object of a discretionary trust (where the director is aware of the arrangement) and any beneficiary of a non-discretionary trust;

(c)“securities” means listed securities and any unlisted securities that are convertible or exchangeable into listed securities and structured products (including derivative warrants), such as those described in Chapter 15A of the Exchange Listing Rules, issued in respect of the listed securities of a listed issuer;

(d)notwithstanding the definition of “dealing” in paragraph (a) above, the following dealings are not subject to the provisions of this code:

(i)taking up of entitlements under a rights issue, bonus issue, capitalisation issue or other offer made by the listed issuer to holders of its securities (including an offer of shares in lieu of a cash dividend) but, for the avoidance of doubt, applying for excess shares in a rights issue or applying for shares in excess of an assured allotment in an open offer is a “dealing”;

(ii)allowing entitlements to lapse under a rights issue or other offer made by the listed issuer to holders of its securities (including an offer of shares in lieu of a

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cash dividend);

(iii)undertakings to accept, or the acceptance of, a general offer for shares in the listed issuer made to shareholders other than those that are concert parties (as defined under the Takeovers Code) of the offeror;

(iv)exercise of share options or warrants or acceptance of an offer for shares pursuant to an agreement entered into with a listed issuer before a period during which dealing is prohibited under this code at the pre-determined exercise price, being a fixed monetary amount determined at the time of grant of the share option or warrant or acceptance of an offer for shares;

(v)an acquisition of qualification shares where, under the listed issuer’s constitutional documents, the final date for acquiring such shares falls within a period when dealing is prohibited under this code and such shares cannot be acquired at another time;

(vi)dealing where the beneficial interest or interests in the relevant security of the listed issuer do not change;

(vii)dealing where a shareholder places out his existing shares in a “top-up” placing where the number of new shares subscribed by him pursuant to an irrevocable, binding obligation equals the number of existing shares placed out and the subscription price (after expenses) is the same as the price at which the existing shares were placed out; and

(viii)dealing where the beneficial ownership is transferred from another party by operation of law.

8.For the purpose of this code, the grant to a director of an option to subscribe or purchase his company’s securities shall be regarded as a dealing by him, if the price at which such option may be exercised is fixed at the time of such grant. If, however, an option is granted to a director on terms whereby the price at which such option may be exercised is to be fixed at the time of exercise, the dealing is to be regarded as taking place at the time of exercise.

RULES

A. Absolute Prohibitions:

1.A director must not deal in any of the securities of the issuer at any time when he possesses inside information in relation to those securities, or where clearance to deal is not otherwise conferred upon him under rule B.8 of this code.

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2.A director must not deal in the securities of an issuer when by virtue of his position as a director of another issuer, he possesses inside information in relation to those securities.

3.(a) A director must not deal in any securities of the listed issuer on any day on which its financial results are published and:

(i) during the period of 60 days immediately preceding the publication date of the annual results or, if shorter, the period from the end of the relevant financial year up to the publication date of the results; and

(ii) during the period of 30 days immediately preceding the publication date of the quarterly results (if any) and half-year results or, if shorter, the period from the end of the relevant quarterly or half-year period up to the publication date of the results,

unless the circumstances are exceptional, for example, where a pressing financial commitment has to be met as described in section C below. In any event, the director must comply with the procedure in rules B.8 and B.9 of this code.

(b) The listed issuer must notify the Exchange in advance of the commencement of each period during which directors are not allowed to deal under rule A.3(a).

Note: Directors should note that the period during which they are not allowed to deal under rule A.3 will cover any period of delay in the publication of a results announcement.

4.Where a director is a sole trustee, the provisions of this code will apply to all dealings of the trust as if he were dealing on his own account (unless the director is a bare trustee and neither he nor any of his close associates is a beneficiary of the trust, in which case the provisions of this code will not apply).

5.Where a director deals in the securities of a listed issuer in his capacity as a co-trustee and he has not participated in or influenced the decision to deal in the securities and is not, and none of his close associates is, a beneficiary of the trust, dealings by the trust will not be regarded as his dealings.

6.The restrictions on dealings by a director contained in this code will be regarded as equally applicable to any dealings by the director’s spouse or by or on behalf of any minor child (natural or adopted) and any other dealings in which for the purposes of Part XV of the Securities and Futures Ordinance he is or is to be treated as interested. It is the duty of the director, therefore, to seek to avoid any such dealing at a time when he himself is not free to deal.

7.When a director places investment funds comprising securities of the listed issuer under professional management, discretionary or otherwise, the managers must nonetheless be made subject to the same restrictions and procedures as the director himself in respect of

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any proposed dealings in the listed issuer’s securities.

B. Notification

8.A director must not deal in any securities of the issuer without first notifying in writing the chairman or a director (otherwise than himself) designated by the board for the specific purpose and receiving a dated written acknowledgement. In his own case, the chairman must first notify the board at a board meeting, or alternatively notify a director (otherwise than himself) designated by the board for the purpose and receive a dated written acknowledgement before any dealing. The designated director must not deal in any securities of the issuer without first notifying the chairman and receiving a dated written acknowledgement. In each case,

(a) a response to a request for clearance to deal must be given to the relevant director within five business days of the request being made; and

(b) the clearance to deal in accordance with (a) above must be valid for no longer than five business days of clearance being received.

Note: For the avoidance of doubt, the restriction under A.1 of this code applies if inside information develops following the grant of clearance.

9.The procedure established within the listed issuer must, as a minimum, provide for there to be a written record maintained by the listed issuer that the appropriate notification was given and acknowledged pursuant to rule B.8 of this code, and for the director concerned to have received written confirmation to that effect.

10.Any director of the listed issuer who acts as trustee of a trust must ensure that his co-trustees are aware of the identity of any company of which he is a director so as to enable them to anticipate possible difficulties. A director having funds under management must likewise advise the investment manager.

11.Any director who is a beneficiary, but not a trustee, of a trust which deals in securities of the listed issuer must endeavour to ensure that the trustees notify him after they have dealt in such securities on behalf of the trust, in order that he in turn may notify the listed issuer. For this purpose, he must ensure that the trustees are aware of the listed issuers of which he is a director.

12.The register maintained in accordance with Section 352 of the Securities and Futures Ordinance should be made available for inspection at every meeting of the board.

13.The directors of a company must as a board and individually endeavour to ensure that any employee of the company or director or employee of a subsidiary company who, because of his office or employment in the company or a subsidiary, is likely to possess inside information in relation to the securities of any issuer does not deal in those securities when he would be prohibited from dealing by this code if he were a director.

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C. Exceptional circumstances

14.If a director proposes to sell or otherwise dispose of securities of the listed issuer under exceptional circumstances where the sale or disposal is otherwise prohibited under this code, the director must, in addition to complying with the other provisions of this code, comply with the provisions of rule B.8 of this code regarding prior written notice and acknowledgement. The director must satisfy the chairman or the designated director that the circumstances are exceptional and the proposed sale or disposal is the only reasonable course of action available to the director before the director can sell or dispose of the securities. The listed issuer shall give written notice of such sale or disposal to the Exchange as soon as practicable stating why it considered the circumstances to be exceptional. The listed issuer shall publish an announcement in accordance with rule 2.07C immediately after any such sale or disposal and state that the chairman or the designated director is satisfied that there were exceptional circumstances for such sale or disposal of securities by the director. An example of the type of circumstances which may be considered exceptional for such purposes would be a pressing financial commitment on the part of the director that cannot otherwise be satisfied.

D. Disclosure

15.In relation to securities transactions by directors, a listed issuer shall disclose in its interim reports (and summary interim reports, if any) and the Corporate Governance Report contained in its annual reports (and summary financial reports, if any):

(a)whether the listed issuer has adopted a code of conduct regarding securities transactions by directors on terms no less exacting than the required standard set out in this code;

(b)having made specific enquiry of all directors, whether its directors have complied with, or whether there has been any non-compliance with, the required standard set out in this code and its code of conduct regarding securities transactions by directors; and

(c)in the event of any non-compliance with the required standard set out in this code, details of such non-compliance and an explanation of the remedial steps taken by the listed issuer to address such non-compliance.

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EX-12.1

Exhibit 12.1

CERTIFICATIONS

I, Guangyu Yuan, certify that:

1. I have reviewed this annual report on Form 20-F of CNOOC Limited;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4. The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: April 19, 2018

By:	/s/  Guangyu Yuan
	Name: Guangyu Yuan
	Title: Chief Executive Officer

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EX-12.2

Exhibit 12.2

CERTIFICATIONS

I, Weizhi Xie, certify that:

1, I have reviewed this annual report on Form 20-F of CNOOC Limited

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report

4. The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: April 19, 2018

By:	/s/  Weizhi Xie
	Name: Weizhi Xie
	Title: Chief Financial Officer

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EX-13.1

Exhibit 13.1

CERTIFICATIONS

The certifications set forth below are being submitted in connection with the Annual Report on Form 20-F for the year ended December 31, 2017 (the “Report”) for the purpose of complying with Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 (the “Exchange Act”) and Section 1350 of Chapter 63 of Title 18 of the United States Code.

Guangyu Yuan, the Chief Executive Officer and Weizhi Xie, the Chief Financial Officer of CNOOC Limited, each certifies that, to the best of his knowledge:

1. the Report fully complies with the requirements of Section 13(a) or 15(d) of the Exchange Act; and

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of CNOOC Limited.

Date: April 19, 2018

By:	/s/  Guangyu Yuan
	Name: Guangyu Yuan
	Title: Chief Executive Officer

By:	/s/  Weizhi Xie
	Name: Weizhi Xie
	Title: Chief Financial Officer

EX-15.1

Exhibit 15.1

CNOOC LIMITED

Estimated

Future Reserves and Income

Attributable to Certain Leasehold Interests

and

Derived Through Certain Production Sharing Contracts

SEC Parameters

As of

December 31, 2017

/s/ Eric T. Nelson

Eric T. Nelson, P.E.

TBPE License No. 102286

Managing Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

	TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
	1100 LOUISIANA    SUITE 4600	HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191

March 15, 2018

CNOOC Limited

No. 25, ChaoYangMenBei Dajie

DongCheng District

Beijing 100010

China

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production and income attributable to certain leasehold interests and derived through certain production sharing contracts of CNOOC Limited (CNOOC) as of December 31, 2017. The subject properties are located in the countries of Australia, Brazil, China, and Indonesia. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on March 8, 2018 and presented herein, was prepared for public disclosure by CNOOC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of CNOOC’s total net proved reserves as of December 31, 2017. Based on information provided by CNOOC, the third party estimate conducted by Ryder Scott addresses 29 percent of the total proved developed net liquid hydrocarbon reserves, 45 percent of the total proved developed net gas reserves, 17 percent of the total proved undeveloped net liquid hydrocarbon reserves and 28 percent of the total proved undeveloped net gas reserves of CNOOC.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2017, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

SUITE  600,  1015  4TH  STREET, S.W.	CALGARY, ALBERTA T2R 1J4	TEL (403) 262-2799	FAX (403) 262-2790
621  17TH STREET, SUITE 1550	DENVER, COLORADO 80293-1501	TEL (303) 623-9147	FAX (303) 623-4258

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (3rd Party Evaluation (1P))

March 15, 2018

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Attributable to Certain Leasehold Interests and

Derived Through Certain Production Sharing Contracts of

CNOOC Limited

As of December 31, 2017

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate – Barrels		398,724,388		22,757,269		321,531,378		743,013,035
Plant Products – Barrels		11,172,397		2,500,103		2,968,947		16,641,447
Gas – MMCF		1,346,649		109,143		1,396,257		2,852,049
Income Data (M$)
Future Gross Revenue	$	29,656,542	$	2,014,015	$	25,155,214	$	56,825,771
Deductions		16,761,963		1,008,871		15,186,369		32,957,203
Future Net Income (FNI)	$	12,894,579	$	1,005,144	$	9,968,845	$	23,868,568
Discounted FNI @ 10%	$	11,118,096	$	630,417	$	4,377,166	$	16,125,679

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

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Cashflow, a proprietary program of Ryder Scott. Ryder Scott notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of the Natural Resource Tax in China and royalties in Australia which are shown as “production taxes.” The Value Added Tax (VAT) received as in China as part of hydrocarbon sales is shown as “Other” revenue. The deductions incorporate the normal direct costs of operating the wells, recompletion costs, development costs, and certain abandonment costs net of salvage. The balance of VAT owed in China and Domestic Market Obligation fees in Indonesia are shown as “other” deductions. The future net income is before the deduction of foreign government income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 63 percent and gas reserves account for 27 percent of total future gross revenue from proved reserves, with the remaining 10 percent due to VAT received.

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (3rd Party Evaluation (1P))

March 15, 2018

Page 3

	Discounted Future Net Income (M$)
	As of December 31, 2017
Discount Rate		Total
Percent		Proved
7		$17,971,828
8		$17,320,103
9		$16,705,641
11		$15,577,687

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

Reserves Included in This Report

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

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

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

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

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (3rd Party Evaluation (1P))

March 15, 2018

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Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production, unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to CNOOC for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with CNOOC the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of CNOOC’s representations regarding such contractual information should be construed as a legal opinion on this matter.

This report includes certain volumes of proved reserves attributable to royalties owed to the host government that are treated as taxes to be paid in cash. In Australia, the government has received the royalty payments in cash, and CNOOC is reasonably certain the government will continue to receive its royalty in cash. These future royalty payments, if converted to reserves, are equivalent to 0.4 percent of CNOOC’s total net proved reserves as evaluated by Ryder Scott on a barrel equivalent (BOE) basis calculated by converting natural gas using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.

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

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

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (3rd Party Evaluation (1P))

March 15, 2018

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or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

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

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

	Approximate Percent Proved Reserves Estimated by the Various Methods
	Liquid Hydrocarbons		Gas
Method	Developed	Undeveloped	Developed	Undeveloped
Performance	75%	0%	47%	0%
Volumetric	10%	79%	48%	100%
Analogy	0%	4%	5%	0%
Combination	15%	17%	0%	0%

These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through October 31, 2017 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by CNOOC and were considered sufficient for the purpose thereof. The volumetric method, analogy or a combination of methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (3rd Party Evaluation (1P))

March 15, 2018

Page 6

The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by CNOOC that were available through October 31, 2017. The data utilized from the analogues as well as the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

CNOOC has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by CNOOC with respect to property interests owned or derived, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, Natural Resource Tax, Value Added Tax and Windfall Profits Taxes in China, Royalties in Australia and Domestic Market Obligation fees in Indonesia, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by CNOOC. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

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

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by CNOOC. Wells or locations

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (3rd Party Evaluation (1P))

March 15, 2018

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that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

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

Hydrocarbon Prices

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

CNOOC furnished us with the above mentioned average prices in effect on December 31, 2017. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The following table summarizes the “benchmark prices” and “price reference” used for the geographic areas included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (3rd Party Evaluation (1P))

March 15, 2018

Page 8

Geographic Area	Product	Price Reference	Average Benchmark Prices*	Average Proved Realized Prices
China	Oil/Condensate	Daqing	$48.59/bbl	$49.03/bbl
		Duri	$44.53/bbl
		Tapis	$54.65/bbl
		WTI Cushing	$51.34/bbl
	NGLs	Jinzhou	$515.09/MT	$37.34/bbl
		Maoming	$578.85/MT
	Gas	Gas Sales Agreements		$5.16/MCF
Asia	Oil/Condensate	Cinta	$51.82/bbl	$49.49/bbl
		Bontang Return Condensate	$54.42/bbl
		Lalang	$53.86/bbl
		Senipah Condensate	$54.22/bbl
		Widuri	$51.90/bbl
	NGLs	Bontang Return Condensate	$54.42/bbl	$45.24/bbl
	Gas	Gas Sales Agreements		$7.21/MCF Gas Sales Agreements
		JCC	$55.35/Bbl
		SoCal Border (ICE)	$2.91/MMBTU
Brazil	Oil	Brent	$54.42/bbl	$51.46/bbl
Oceania	Oil/Condensate	Brent	$54.42/bbl	$54.82/bbl
	NGLs	Saudi CP	$484.87/MT	$57.88/bbl
	Gas	JCC	$55.35/Bbl	$3.23/MCF

*In this report, the benchmark prices for certain NGLs were based on U.S. dollars per metric ton (MT).

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

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of CNOOC and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by CNOOC. No deduction was made for loan repayments, interest expenses or exploration and development prepayments that were not charged directly to the leases or wells.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (3rd Party Evaluation (1P))

March 15, 2018

Page 9

Development costs were furnished to us by CNOOC and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by CNOOC were accepted without independent verification.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with CNOOC’s plans to develop these reserves as of December 31, 2017. The implementation of CNOOC’s development plans as presented to us and incorporated herein is subject to the approval process adopted by CNOOC’s management. As the result of our inquiries during the course of preparing this report, CNOOC has informed us that the development activities included herein have been subjected to and received the internal approvals required by CNOOC’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to CNOOC. Additionally, CNOOC has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2017, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

The initial production date of certain proved undeveloped gas fields/reservoirs in Brazil, China and Indonesia were scheduled beyond the SEC nominal 5 year development period because these fields/reservoirs are associated with long term gas contracts or LNG sales, and their gas deliverability are not needed within the 5 year period. The reserves from these fields/reservoirs represent 4.1 percent of the total net proved reserves of CNOOC as evaluated by Ryder Scott on a barrel equivalent (BOE) basis using the conversion factor as previously noted. CNOOC and its partners anticipated for these fields/reservoirs to be developed prior to the expiration of the long term gas sales and LNG sales and purchase agreement period. In the case of Brazil, 2 of the 17 wells approved under the field’s FID were planned outside of 5 year period due to facility production constraints and the ongoing development of the Libra area, which is a major deepwater development.

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

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (3rd Party Evaluation (1P))

March 15, 2018

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

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

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

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by CNOOC Limited.

CNOOC makes periodic filings on Form 20-F with the SEC under the 1934 Exchange Act. Furthermore, CNOOC has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 20-F is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form F-3 of CNOOC of the references to our name as well as to the references to our third party report for CNOOC, which appears in the December 31, 2017 annual report on Form 20-F of CNOOC. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by CNOOC.

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

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

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Eric T. Nelson

Eric T. Nelson, P.E.

TBPE License No. 102286

Managing Senior Vice President

[SEAL]

ETN (DPR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Eric T. Nelson is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Nelson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2005, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Nelson served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Nelson’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Nelson earned a Bachelor of Science degree in Chemical Engineering from the University of Tulsa in 2002 (summa cum laude) and a Master of Business Administration from the University of Texas in 2007 (Dean’s Award). He is a licensed Professional Engineer in the State of Texas. Mr. Nelson is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Nelson fulfills. As part of his 2017 continuing education hours, Mr. Nelson attended over 20 hours of training during 2017 covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, evaluations of resource play reserves, evaluation of simulation models, procedures and software, and ethics training.

Based on his educational background, professional training and more than 12 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Nelson has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

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

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

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

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

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

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Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

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

RESERVES (SEC DEFINITIONS)

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

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

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

PROVED RESERVES (SEC DEFINITIONS)

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

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

(i) The area of the reservoir considered as proved includes:

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

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

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

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

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

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

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

DEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

Developed Producing (SPE-PRMS Definitions)

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

Developed Producing Reserves

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

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Developed Non-Producing

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

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

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

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

UNDEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC LIMITED

Estimated

Future Reserves and Income

CNOOC’s 25% Ownership of

Pan American Energy LLC

SEC Parameters

As of

December 31, 2017

/s/ Eric T. Nelson	/s/ Anna M. Hardesty
Eric T. Nelson, P.E.	Anna M. Hardesty, P.E.
TBPE License No. 102286	TBPE License No.65320
Managing Senior Vice President	Senior Vice President

[SEAL] [SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

	TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
	1100 LOUISIANA    SUITE 4600	HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191

March 16, 2018

CNOOC Limited

No. 25, ChaoYangMenBei Dajie

DongCheng District

Beijing 100010

China

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production and income attributable to CNOOC Limited’s 25 percent ownership of Pan American Energy LLC (Pan American) as of December 31, 2017. The subject properties are located in the country of Argentina. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 5, 2018 and presented herein, was prepared for public disclosure by CNOOC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations, though there is a minor oil price consideration due to recent deregulation as discussed below.

The properties evaluated by Ryder Scott account for a portion of CNOOC’s total net proved reserves as of December 31, 2017. Based on information provided by CNOOC, the third party estimate conducted by Ryder Scott addresses 0.19 percent of the total proved developed net liquid hydrocarbon reserves, 6.97 percent of the total proved developed net gas reserves, 0.08 percent of the total proved undeveloped net liquid hydrocarbon reserves and 2.27 percent of the total proved undeveloped net gas reserves of CNOOC.

The estimated reserves and future income amounts presented in this report, as of December 31, 2017, are related to hydrocarbon prices. The hydrocarbon prices normally used for proved reserves that are based on SEC parameters utilize the average prices during the 12-month period prior to the “as of date” of the report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Previously for crude oil produced in Argentina, the governmental energy industry regulators set the price on a monthly basis. However, beginning in October 2017, oil prices have been deregulated. Therefore, the average monthly price for the remainder of the year was used as the benchmark price and was then adjusted for differentials to determine the actual average realized price used in the preparation of this report. For gas sales, some of the prices received by Pan American are determined by the Argentine government’s incentive programs and these were applied to the projects that currently receive or qualify to receive such prices in the future. Actual future prices may vary significantly from the prices required by SEC regulations and prices established by governmental agencies; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

SUITE  600,  1015  4TH  STREET, S.W.	CALGARY, ALBERTA T2R 1J4	TEL (403) 262-2799	FAX (403) 262-2790
621  17TH STREET, SUITE 1550	DENVER, COLORADO 80293-1501	TEL (303) 623-9147	FAX (303) 623-4258

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (Pan American Energy, LLC)

March 16, 2018

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

CNOOC Limited’s 25% Ownership of

Pan American Energy, LLC

As of December 31, 2017

	Proved – SEC Definitions
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Cond/Gasoline – Barrels		2,488,434		338,665		1,520,733		4,347,832
Gas – MMcf		215,021		8,446		114,698		338,165
Income Data ($M)
Future Gross Revenue	$	1,243,977	$	67,479	$	659,839	$	1,971,295
Deductions		476,708		28,753		394,966		900,427
Future Net Income (FNI)	$	767,269	$	38,726	$	264,873	$	1,070,868
Discounted FNI @ 10%	$	516,087	$	23,768	$	70,727	$	610,582

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and include volumes of gasoline, which are stripped from the gas and sold as oil. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is not subject to direct production taxes. The deductions incorporate the normal direct costs of operating the wells, recompletion costs, development costs, provincial royalty payments and certain abandonment costs net of salvage. The future net income is before the deduction of Argentine federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Gas reserves account for approximately 87.8 percent of the total future gross revenue from proved reserves, and liquid hydrocarbon reserves account for the remaining 12.2 percent of the total future gross revenue from proved reserves.

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (Pan American Energy, LLC)

March 16, 2018

Page 3

	Discounted Future Net Income ($M)
	As of December 31, 2017
Discount Rate		Total
Percent		Proved
7		$708,392
8		$673,063
9		$640,557
11		$582,883

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

Reserves Included in This Report

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

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

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include gas consumed in operations as reserves.

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

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time,

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (Pan American Energy, LLC)

March 16, 2018

Page 4

reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production, unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the country of Argentina may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Pan American and/or CNOOC for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Pan American the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Pan American’s representations regarding such contractual information should be construed as a legal opinion on this matter.

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

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

Estimates of Reserves

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (Pan American Energy, LLC)

March 16, 2018

Page 5

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

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

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

	Approximate Percent of Proved Reserves Estimated by the Various Methods
	Liquid Hydrocarbons		Gas
Method	Developed	Undeveloped	Developed	Undeveloped
Performance	44%	0%	43%	0%
Volumetric	6%	33%	16%	52%
Analogy	28%	64%	5%	40%
Combination	22%	3%	36%	8%

These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through November 2017 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by Pan American and were considered sufficient for the purpose thereof. The volumetric method, analogy or a combination of methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by Pan American that were available through December 2017. The data utilized from the analogues as well as the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (Pan American Energy, LLC)

March 16, 2018

Page 6

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

Pan American has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Pan American with respect to property interests owned by CNOOC, production and well tests from examined wells, normal direct costs of operating the wells or contracts, other costs such as transportation and/or processing fees, provincial royalty payments, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Pan American. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations, except as discussed previously.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were projected based on a type curve derived from analogy to surrounding historical well production. In some cases the production rates of some wells were held constant for a period of time due to the effects of curtailment from capacity limitations, and thereafter declined at their normal decline rate. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (Pan American Energy, LLC)

March 16, 2018

Page 7

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

Hydrocarbon Prices

As previously discussed for proved reserves that are based on SEC price parameters, the hydrocarbon prices utilize the average prices during the 12-month period prior to the “as of date” of the report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. In the past for crude oil produced in Argentina, the governmental energy industry regulators set the oil price on a monthly basis. However, beginning in October 2017 oil prices have been deregulated. Therefore, the average monthly price for the remainder of the year was used as the benchmark price. These prices were then adjusted for differentials to determine the actual average realized prices used in the preparation of this report. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract.

Pan American furnished us with the above mentioned average prices in effect on December 31, 2017. For crude oil, these initial prices were determined using the method mentioned above. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, buoy and storage fees, turnover tax fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Pan American. The differentials furnished to us were accepted as factual data; however, we have not conducted an independent verification of the data used by Pan American to determine these differentials.

Certain gas prices for low permeability reservoirs, economically marginal, and capital intensive projects were provided by Pan American based on governmental price allowances for such gas. These price allowances are approved by the Argentine government on a case by case basis. The government also considers price allowances for projects that allow a company to increase production above a baseline as an incentive to produce more gas, which is in short supply in Argentina. Such higher gas price allowances under programs designated as “Gas Plus” or “Gas Plan” or “Resolucion 419/17” by the Argentine government are being paid for certain volumes of gas delivered by Pan American from certain properties that meet these higher gas price criteria. In all cases where we have used Gas Plus, Gas Plan or Resolucion 419/17 prices, Pan American has informed us that such prices are either currently in effect or have reasonable expectation of being received in the future.

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (Pan American Energy, LLC)

March 16, 2018

Page 8

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
Argentina	Oil/Cond/Gasoline	Medanito Hidra	$58.54/bbl $52.52/bbl	$55.43/bbl
	Gas	Various Contracts	N/A	$5.12/Mcf

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

Costs

Operating costs for the properties and wells in this report were furnished by Pan American and are based on their operating expense reports. These costs include only those costs directly applicable to the properties or wells. The operating costs include a portion of general and administrative costs allocated directly to the properties and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the overhead costs that are allocated directly to the properties and wells under terms of operating agreements. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Pan American. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the properties or wells.

Development costs were furnished to us by Pan American and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Pan American were accepted without independent verification.

The developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Pan American’s plans to develop these reserves as of December 31, 2017. The implementation of Pan American’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Pan American’s management. As the result of our inquiries during the course of preparing this report, CNOOC has informed us that the development activities included herein have been subjected to and received the internal approvals required by CNOOC’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Pan American. Additionally, Pan American has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2017, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

The plan of development for the gas reserves to be produced from the offshore fields in the Austral Basin calls for one future well in the Vega Pleyade field, which is scheduled to be drilled beyond five years from the date it was initially categorized as proved undeveloped. Pan American has provided us with a letter explaining the reasons for such a delay. Additionally, facilities were installed and two new wells were put on production in 2016. In our opinion, Pan American has a coherent and

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (Pan American Energy, LLC)

March 16, 2018

Page 9

reasonable explanation for deferring the drilling of this well. Additionally, as development is now proceeding, we have assigned the reserves corresponding to this development as proved.

Current costs were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

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

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

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

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

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by CNOOC Limited.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited (Pan American Energy, LLC)

March 16, 2018

Page 10

CNOOC makes periodic filings on Form 20-F with the SEC under the 1934 Exchange Act. Furthermore, CNOOC has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 20-F is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form F-3 of CNOOC of the references to our name as well as to the references to our third party report for CNOOC, which appears in the December 31, 2017 annual report on Form 20-F of CNOOC. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by CNOOC.

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

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

Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
/s/ Eric T. Nelson
Eric T. Nelson, P.E.
TBPE License No. 102286
Managing Senior Vice President	[SEAL]
/s/ Anna M. Hardesty
Anna M. Hardesty, P.E.
TBPE License No. 65320
Senior Vice President	[SEAL]

ETN-AMH (FWZ)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Anna Milena Hardesty, P.E. is the primary technical person responsible for the estimate of the reserves, future production and income presented herein.

Ms. Hardesty, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Ms. Hardesty served in a number of engineering positions with Ryder Scott as a consulting engineer, Santa Fe Energy (now Devon), Gruy and Associates, Golden Engineering, Pressler and Associates, and Exxon Company USA. For more information regarding Ms. Hardesty’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Ms. Hardesty earned a Bachelor of Science degree in Mechanical Engineering from Tulane University, New Orleans in 1981 and a Masters in Science in Business from the University of Texas, Austin in 2001. Ms. Hardesty is a licensed Professional Engineer in the States of Texas and Florida and is also a Certified Engineer in Society of Petroleum Engineers (SPEC). She is also a member of the Society of Petroleum Engineers (SPE), the Society of Petroleum Evaluation Engineers (SPEE), the Association of International Petroleum Negotiators (AIPN) and World Affairs Council of Houston. She is also a past Program Chairman 2011, past Treasurer 2012, past Vice-Chairman 2013 and past Chairman 2014 for the SPEE chapter in Houston.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Ms. Hardesty fulfills. As part of her 2017 continuing education hours, Ms. Hardesty attended at least fifteen (1-hour each) presentations on various petroleum related subjects, sponsored by SPEE, SPE and AIPN. She also attended various presentations/seminars that included new unconventional resource play estimations, guidelines for probabilistic estimations and insights on PRMS guidelines as well as an ethics class required to maintain her Registered Engineer status in the states of Texas and Florida. With her attendance in the various seminars and courses mentioned above during 2017, Ms. Hardesty earned over 40 hours of formalized training in reservoir/petroleum engineering, geoscience, unconventional resource evaluation methods, petroleum engineering software and ethics for consultants.

Based on her educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Ms. Hardesty has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

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

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

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

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

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

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

RESERVES (SEC DEFINITIONS)

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

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

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

PROVED RESERVES (SEC DEFINITIONS)

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

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

(i) The area of the reservoir considered as proved includes:

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

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

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

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

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

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

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

DEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

Developed Producing (SPE-PRMS Definitions)

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

Developed Producing Reserves

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing

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

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

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

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

UNDEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EX-15.2

Exhibit 15.2

 

Independent Letter

The Missan Oil Fields In Eastern Iraq
Estimated Proved Reserves and Financial Data,
Based on SEC Rules

Prepared for

CNOOC Limited

As of 31 December 2017

March 2018

This summary letter is based on Gaffney, Cline & Associates’ official report and has been provided at the request of CNOOC Limited.

www.gaffney-cline.com

 

Gaffney, Cline & Associates

(Consultants) Pte. Ltd.

80 Anson Road

#31-01C Fuji Xerox Towers

Singapore 079907

Telephone: +65 6225 6951

www.gaffney-cline.com

13 March 2018

CNOOC Limited

No. 25, Chaoyangmenbei Dajie

Dongcheng District

Beijing 100010, P.R. China

Gentlemen,

Independent Letter

The Missan Oil Fields in Eastern Iraq
Estimated proved Reserves and Financial Data, Based on SEC Rules
As of 31 December 2017

At the request of CNOOC Limited (CNOOC), Gaffney, Cline & Associates (GCA) has prepared an independent estimate of the proved reserves and financial data attributable to certain participating interests owned by CNOOC as of 31 December 2017. The reserves and income data were estimated based on Rules of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released 14 January 2009 in the Federal Register, including all references to Regulation S-X and Regulation S-K (SEC Rules). GCA’s independent study, completed on 3 March 2018 and summarized herein, was prepared for public disclosure by CNOOC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC Rules. In GCA’s opinion, the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose and have been carried out in line with the SEC Oil and Gas Reserves Definitions attached hereto as an Appendix.

The subject properties of the Missan Oil Fields (Missan) are located in eastern Iraq, 350 km southeast of Baghdad. Based on information provided by CNOOC, the Proved reserves estimates for properties evaluated by GCA for this report represent approximately 1.23 percent of CNOOC’s total net proved reserves as of 31 December 2017. GCA is not in a position to verify this statement as it was not requested to review all CNOOC’s other oil and gas assets.

CNOOC have signed a 20-year Technical Service Contract (TSC) with the Missan Oil Company of The Iraqi Ministry of Oil (MOC) for the rehabilitation of production and enhanced recovery of petroleum from Missan. CNOOC is the lead contractor of, and holds a 63.75% participating interest in, the project.

SML/YDH/jbi/PS-17-2055/L0032	1
CNOOC Limited (Missan)

The oil reserves and financial data reported herein were estimated on the basis of SEC Rules. GCA has classified as Reserves those hydrocarbon volumes that would be economically recoverable as a result of implementing the Rehabilitation Plan only.

In line with the foregoing, the statement of reserves, presented herein, is economically recoverable as a result of implementing Rehabilitation Plan and including its extension to the end of 2021. Any volumes produced as a result of further development are currently classified as Contingent Resources. CNOOC envisages an Enhanced Redevelopment Plan (ERP) to follow immediately after the completion of the Rehabilitation Plan. Details of the ERP have not been provided to GCA at this stage. Therefore, GCA’s estimates included in this report are limited to volumes classified as Reserves. As such, the volumes actually recovered under the enlarged plan are expected to be significantly greater than those presented. However, should the ERP not be approved, it is possible that CNOOC would be seen as in default of the contract and there could be an early termination and a consequential reduction in reserves.

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

Economic models were constructed based on terms of the TSC as provided by CNOOC and the current performance of the TSC, in order to calculate CNOOC’s Net Entitlement volumes, which are made up of CNOOC’s share of Service Fees (Petroleum Cost Recovery and Remuneration Fees) plus Supplementary Fees, converted to volumetric equivalents.

The price used was determined by calculating the quality differential between the SEC Brent price (the average first-day-of-the-month price of Brent crude during 2017) and the Iraq average oil price as published by SOMO for each month in 2017 and applying the average differential to the SEC price for the 31 December 2017. Based on the data made available to GCA for January to December 2017, the 2017 average differential to SEC Brent was a US$7.20/Bbl discount. Based on an SEC Brent price of US$54.42/Bbl this results in an average sales price of US$47.22/Bbl, which has been assumed to remain constant for the duration of the project life.

Future capital costs were derived from the 2018 development plan prepared by CNOOC for the field. Recent historical operating expense data were utilized as the basis for operating cost projections. GCA found that CNOOC has projected sufficient capital investments and operating expenses to produce economically the projected volumes recoverable from the 2018 - 2021 development activities.

Actual future prices may vary significantly from the prices required by SEC Rules; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized in the following table. Reserves net to CNOOC are quoted as Net Entitlement Reserves reflecting the terms of the TSC.

SML/YDH/jbi/PS-17-2055/L0032	2
CNOOC Limited (Missan)

Estimated Net Reserves and Financial Data

As of 31 December 2017

	Proved
	Developed		Undeveloped	Total  Proved
	Producing	Non-Producing
Net Reserves
Oil/Condensate – Mstb	25,796	0	33,820	59,615
Income Data (M$)
Future Gross Revenue	$ 1,218,081	$  0	$ 1,596,959	$ 2,815,040
Deductions	$ 665,078	$  0	$ 1,493,697	$ 2,158,775
Future Net Income (FNI)	$ 553,003	$  0	$ 103,262	$ 656,265
Discounted FNI @ 10%	$ 518,604	$  0	$ 38,395	$ 557,000

Liquid hydrocarbons are expressed in thousands of standard (42 gallon) barrels (Mstb). In this report, the revenues, deductions and income data are expressed in thousands of US dollars (M$).

The future gross revenue represents CNOOC’s net entitlement share of Service Fees (Petroleum Cost Recovery plus Remuneration Fees) due under the Technical Service Contract (TSC). Deductions represent CNOOC’s 85% (i.e. 63.75%/75% of total project) share of project Capital Expenditure, Operating Expenditure, contractual Supplementary Costs, State partner ‘carry’ and Training Fees. Future Net Income represents CNOOC’s Future Gross Revenue less costs incurred, and on a post-tax basis, under the terms of the TSC.

The results included herein were prepared in accordance with the disclosure requirements set forth in the SEC Rules and intended for public disclosure as an exhibit in filings made with the SEC by CNOOC.

Basis of Opinion

This document reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by CNOOC, the limited scope of engagement, and the time permitted to conduct the evaluation.

In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein. GCA has not independently verified any information provided by, or at the direction of, CNOOC, and has accepted the accuracy and completeness of this data. GCA has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.

The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.

SML/YDH/jbi/PS-17-2055/L0032	3
CNOOC Limited (Missan)

In the preparation of this report, GCA has used definitions contained within Part 210 Rule 4-10(a) of Regulation S-X of the US Securities and Exchange Commission (see Appendix I).

There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas resources assessments must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas resources prepared by other parties may differ, perhaps materially, from those contained within this report.

The accuracy of any resources estimate is a function of the quality of the available data and of engineering and geological interpretation. Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material. Accordingly, resource estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.

Oil and condensate volumes are reported in thousands of standard barrels at stock tank conditions (Mstb). Standard conditions are defined as 14.7 psia and 60° Fahrenheit.

GCA prepared an independent assessment of the reserves based on data and interpretations provided by CNOOC.

Definition of Reserves

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

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

Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. All categories of reserves volumes quoted herein have been derived within the context of an economic limit test (ELT) assessment (pre-tax and exclusive of accumulated depreciation amounts) prior to any Net Present Value (NPV) analysis.

Reserves net to CNOOC are quoted as Net Entitlement Reserves, reflecting the terms of the applicable Technical Service Contract (TSC). Lease fuel has been excluded from the reserve volumes.

GCA has not undertaken a site visit and inspection because it was not necessary and not required within the scope of work. As such, GCA is not in a position to comment on the operations or facilities in place, their appropriateness and condition, or whether they are in compliance with the regulations pertaining to such operations. Further, GCA is not in a position to comment on any aspect of health, safety, or environment of such operation.

This report has been prepared based on GCA’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However, GCA is not in a position to attest to property title or rights, conditions of these rights

SML/YDH/jbi/PS-17-2055/L0032	4
CNOOC Limited (Missan)

(including environmental and abandonment obligations), or any necessary licenses and consents (including planning permission, financial interest relationships, or encumbrances thereon for any part of the appraised properties).

Use of Net Present Values

It should be clearly noted that the Net Present Values (NPV) contained herein do not represent a GCA opinion as to the market value of the subject property, nor any interest in it.

In assessing a likely market value, it would be necessary to take into account a number of additional factors including reserves risk (i.e., that Proved and/or Probable and/or Possible reserves may not be realized within the anticipated timeframe for their exploitation); perceptions of economic and sovereign risk, including potential change in regulations; potential upside; other benefits, encumbrances or charges that may pertain to a particular interest; and, the competitive state of the market at the time. GCA has explicitly not taken such factors into account in deriving the NPVs presented herein.

Qualifications

In performing this study, GCA is not aware that any conflict of interest has existed. As an independent consultancy, GCA is providing impartial technical, commercial, and strategic advice within the energy sector. GCA’s remuneration was not in any way contingent on the contents of this report.

In the preparation of this document, GCA has maintained, and continues to maintain, a strict independent consultant-client relationship with CNOOC. Furthermore, the management and employees of GCA have no interest in any of the assets evaluated or are related with the analysis performed, as part of this report.

Staff members who prepared this report hold appropriate professional and educational qualifications and have the necessary levels of experience and expertise to perform the work.

The technical person primarily responsible for overseeing this estimate is Mr. Stephen M. Lane. Mr. Lane holds a BSc (Hons) in Geology, is a member of the Society of Petroleum Engineers and is a very experienced Geoscientist and Petrophysicist with over 40 years’ background in providing geological and petrophysical expertise to clients worldwide. He has particular involvement as lead petrophysicist/geologist and Project Manager in many oil and gas reserve certifications both for project finance and for SEC reporting purposes, frequent involvement in the valuation of E&P assets for acquisition and divestment purposes and production of public documents such as Competent Person’s Reports.

This letter should not be used for purposes other than those for which it is intended. This letter should not be reproduced, either in whole or part, without the written permission of GCA. CNOOC will obtain GCA’s prior written or email approval for the use with third parties and context of the use with third parties of any results, statements or opinions expressed by GCA to CNOOC, which are attributed to GCA. Such requirement of approval shall include, but not be confined to, statements or references in documents of a public or semi-public nature such as loan agreements, prospectuses, reserve statements, websites, press releases, etc.

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As independent reserve engineers/advisors for CNOOC, GCA hereby confirms that it has granted and not withdrawn its consent to the references to GCA and to the inclusion of information contained in our report entitled “Executive Report for Reserves Estimation of the Missan Oil Fields in Eastern Iraq as of 31 December 2017” as of 5 March 2018 prepared for CNOOC, and to the annexation of our report as an exhibit in CNOOC’s annual report on Form 20-F for the fiscal year ended 31 December 2017.

Yours faithfully,

Gaffney, Cline & Associates (Consultants) Pte Ltd

/s/ Hu Yundong

Project Manager

Dr Hu Yundong, Senior Advisor

/s/ Stephen Lane

Reviewed by

Stephen Lane, Technical Director

Appendix I SEC Reserves Definitions

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Appendix I
SEC Reserves Definitions

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U.S. SECURITIES AND EXCHANGE COMMISSION (SEC)

MODERNIZATION OF OIL AND GAS REPORTING¹

Oil and Gas Reserves Definitions and Reporting

(a)       Definitions

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

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

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

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

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

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

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

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

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

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

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

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

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

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

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

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

(iv) Provide improved recovery systems.

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

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

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

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

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

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

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

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(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

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

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

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

(16)       Oil and gas producing activities.

(i) Oil and gas producing activities include:

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

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

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

(1) Lifting the oil and gas to the surface; and

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

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

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

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

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to

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upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

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

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

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

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

(D) Production of geothermal steam.

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

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

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

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

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

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

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be

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established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

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

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

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

(20)       Production costs.

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

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

(B) Repairs and maintenance.

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

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

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate.

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Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

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

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

(i) The area of the reservoir considered as proved includes:

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

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

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

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

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

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

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

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23)       Proved properties. Properties with proved reserves.

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

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

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

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

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

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

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

(30)       Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31)       Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from

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existing wells where a relatively major expenditure is required for recompletion.

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

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

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

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

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Independent Letter

The Greater Angostura Fields
Block 2C, Trinidad & Tobago
Estimated Proved Reserves and Financial Data,
Based on SEC Rules

Prepared for

CNOOC Limited

As of 31 December 2017

March 2018

This summary letter is based on Gaffney, Cline & Associates’ official report and has been provided at the request of CNOOC Limited.

www.gaffney-cline.com

 

Gaffney, Cline & Associates

(Consultants) Pte. Ltd.

80 Anson Road

#31-01C Fuji Xerox Towers

Singapore 079907

Telephone: +65 6225 6951

www.gaffney-cline.com

13 March 2018

CNOOC Limited

No. 25, Chaoyangmenbei Dajie

Dongcheng District

Beijing 100010, P.R. China

Gentlemen,

Independent Letter

The Greater Angostura Fields
Block 2C, Trinidad & Tobago
Estimated proved Reserves and Financial Data, Based on SEC Rules
As of 31 December 2017

At the request of CNOOC Limited (CNOOC), Gaffney, Cline & Associates (GCA) has prepared an independent estimate of the proved reserves and financial data attributable to certain participating interests owned by CNOOC as of 31 December 2017. The reserves and income data were estimated based on Rules of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released 14 January 2009 in the Federal Register, including all references to Regulation S-X and Regulation S-K (SEC Rules). GCA’s independent study, completed on 3 March 2018 and summarized herein, was prepared for public disclosure by CNOOC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC Rules. In GCA’s opinion, the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose and have been carried out in line with the SEC Oil and Gas Reserves Definitions attached hereto an Appendix.

The subject properties in Block 2C are located 24 miles offshore east coast of Trinidad & Tobago. Based on information provided by CNOOC, the Proved reserves estimates for properties evaluated by GCA for this report represent approximately 0.20 percent of CNOOC’s total net proved reserves as at 31 December 2017. GCA is not in a position to verify this statement as it was not requested to review all CNOOC’s other oil and gas assets.

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GCA prepared an independent assessment of the reserves based on data and interpretations provided by CNOOC. GCA checked and verified the in place volume estimation. GCA reviewed the well and reservoir performances employing Decline Curve Analysis (DCA) and material balance techniques. Economic models were constructed based on terms of the PSC as provided by CNOOC, in order to calculate CNOOC’s Net Entitlement volumes, which are made up of CNOOC’s share of contractors revenue (Petroleum Cost Recovery and Profit Oil) converted to volumetric equivalents.

The price used in the cashflow analysis was determined by calculating the average quality differential between the Brent price and the actual sales price of Calypso crude for each lifting month in 2017 and applying the average differential to the SEC Brent price, which is the un-weighted 12-month average of the first-day-of-the month Brent crude oil price from January to December 2017. Based on the data made available to GCA from January to December 2017, the 2017 average differential to Brent was a US$5.01/Bbl discount. Based on an SEC Brent price of US$54.42/Bbl this results in an average sales price of US$49.41/Bbl, which has been assumed to remain constant for the duration of the project life. The gas prices used were based on the gas sales information from January to December 2017 provided by CNOOC. The un-weighted average gas price was calculated to be US$2.24/MMBtu, and this price has been assumed to remain constant for the duration of the project life. Oil and gas prices were not escalated throughout the evaluation period.

Actual future prices may vary significantly from the prices required by SEC Rules; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized in the following table. Reserves net to CNOOC are quoted as Net Entitlement Reserves reflecting the terms of the PSC.

Estimated Net Reserves and Financial Data

As of 31 December 2017

	Proved
	Developed		Undeveloped	Total Proved
	Producing	Non-Producing
Net Reserves
Oil/Condensate – Mstb	599	0	85	684
Gas – MMscf	52,652	0	529	53,181
Income Data (M$)
Future Gross Revenue	$  117,501	$  0	$  5,975	$ 123,476
Deductions	$   70,452	$  0	$  7,669	$ 78,121
Future Net Income (FNI)	$  47,049	$  0	$ - 1,694	$  45,355
Discounted FNI @ 10%	$  37,949	$  0	$ - 1,987	$  35,962

Liquid hydrocarbons are expressed in thousands of standard (42 gallon) barrels (Mstb). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMscf) at standard temperature (60 °F) and pressure (14.7 psia). In this report, the revenues, deductions and income data are expressed in thousands of US dollars (M$).

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The future gross revenue represents CNOOC’s net entitlement under the PSC (Cost Recovery plus Profit Share). Deductions represent CNOOC’s 12.5% share of project Capital Expenditure, Operating Expenditure and Abandonment Costs (ABEX). Future Net Income represents CNOOC’s Profit Share, net of ABEX, under the terms of the PSC.

The results included herein were prepared in accordance with the disclosure requirements set forth in the SEC Rules and intended for public disclosure as an exhibit in filings made with the SEC by CNOOC.

Basis of Opinion

This document reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by CNOOC, the limited scope of engagement, and the time permitted to conduct the evaluation.

In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein. GCA has not independently verified any information provided by, or at the direction of, CNOOC, and has accepted the accuracy and completeness of this data. GCA has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.

The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.

In the preparation of this report, GCA has used definitions contained within Part 210 Rule 4-10(a) of Regulation S-X of the US Securities and Exchange Commission (see Appendix I).

There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas resources assessments must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas resources prepared by other parties may differ, perhaps materially, from those contained within this report.

The accuracy of any resources estimate is a function of the quality of the available data and of engineering and geological interpretation. Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material. Accordingly, resource estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.

Oil and condensate volumes are reported in thousands of standard barrels at stock tank conditions (Mstb). Gas volumes are reported in millions of cubic feet (MMscf) at standard conditions. Standard conditions are defined as 14.7 psia and 60° Fahrenheit.

GCA prepared an independent assessment of the reserves based on data and interpretations provided by CNOOC.

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Definition of Reserves

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

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

Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. All categories of reserves volumes quoted herein have been derived within the context of an economic limit test (ELT) assessment (pre-tax and exclusive of accumulated depreciation amounts) prior to any Net Present Value (NPV) analysis.

Reserves net to CNOOC are quoted as Net Entitlement Reserves, reflecting the terms of the applicable Production Sharing Contract (PSC). Lease fuel has been excluded from the reserve volumes.

GCA has not undertaken a site visit and inspection because it was not necessary and not required within the scope of work. As such, GCA is not in a position to comment on the operations or facilities in place, their appropriateness and condition, or whether they are in compliance with the regulations pertaining to such operations. Further, GCA is not in a position to comment on any aspect of health, safety, or environment of such operation.

This report has been prepared based on GCA’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However, GCA is not in a position to attest to property title or rights, conditions of these rights (including environmental and abandonment obligations), or any necessary licenses and consents (including planning permission, financial interest relationships, or encumbrances thereon for any part of the appraised properties).

Use of Net Present Values

It should be clearly noted that the Net Present Values (NPV) contained herein do not represent a GCA opinion as to the market value of the subject property, nor any interest in it.

In assessing a likely market value, it would be necessary to take into account a number of additional factors including reserves risk (i.e., that Proved and/or Probable and/or Possible reserves may not be realized within the anticipated timeframe for their exploitation); perceptions of economic and sovereign risk, including potential change in regulations; potential upside; other benefits, encumbrances or charges that may pertain to a particular interest; and, the competitive state of the market at the time. GCA has explicitly not taken such factors into account in deriving the NPVs presented herein.

Qualifications

In performing this study, GCA is not aware that any conflict of interest has existed. As an independent consultancy, GCA is providing impartial technical, commercial, and strategic advice within the energy sector. GCA’s remuneration was not in any way contingent on the contents of this report.

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In the preparation of this document, GCA has maintained, and continues to maintain, a strict independent consultant-client relationship with CNOOC. Furthermore, the management and employees of GCA have no interest in any of the assets evaluated or are related with the analysis performed, as part of this report.

Staff members who prepared this report hold appropriate professional and educational qualifications and have the necessary levels of experience and expertise to perform the work.

The technical person primarily responsible for overseeing this estimate is Mr. Stephen M. Lane. Mr. Lane holds a BSc (Hons) in Geology, is a member of the Society of Petroleum Engineers and is a very experienced Geoscientist and Petrophysicist with over 40 years’ background in providing geological and petrophysical expertise to clients worldwide. He has particular involvement as lead petrophysicist/geologist and Project Manager in many oil and gas reserve certifications both for project finance and for SEC reporting purposes, frequent involvement in the valuation of E&P assets for acquisition and divestment purposes and production of public documents such as Competent Person’s Reports.

This letter should not be used for purposes other than those for which it is intended. This letter should not be reproduced, either in whole or part, without the written permission of GCA. CNOOC will obtain GCA’s prior written or email approval for the use with third parties and context of the use with third parties of any results, statements or opinions expressed by GCA to CNOOC, which are attributed to GCA. Such requirement of approval shall include, but not be confined to, statements or references in documents of a public or semi-public nature such as loan agreements, prospectuses, reserve statements, websites, press releases, etc.

As independent reserve engineers/advisors for CNOOC, GCA hereby confirms that it has granted and not withdrawn its consent to the references to GCA and to the inclusion of information contained in our report entitled “Executive Report for Reserves Estimation of the Greater Angostura Fields in Block 2C, Trinidad & Tobago as at 31 December 2017” as of 5 March 2018 prepared for CNOOC, and to the annexation of our report as an exhibit in CNOOC’s annual report on Form 20-F for the fiscal year ended 31 December 2017.

Yours faithfully,

GAFFNEY, CLINE & ASSOCIATES (CONSULTANTS) PTE LTD

/s/ Hu Yundong

Project Manager

Dr Hu Yundong, Senior Advisor

/s/ Stephen Lane

Reviewed by

Stephen Lane, Technical Director

Appendix I SEC Reserves Definitions

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Appendix I
SEC Reserves Definitions

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U.S. SECURITIES AND EXCHANGE COMMISSION (SEC)

MODERNIZATION OF OIL AND GAS REPORTING¹

Oil and Gas Reserves Definitions and Reporting

(a)       Definitions

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

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

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

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

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

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

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

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

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

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

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

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

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

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

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

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

(iv) Provide improved recovery systems.

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

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

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

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

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

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

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

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(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

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

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

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

(16)       Oil and gas producing activities.

(i) Oil and gas producing activities include:

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

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

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

(1) Lifting the oil and gas to the surface; and

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

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

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

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

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to

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upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

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

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

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

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

(D) Production of geothermal steam.

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

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

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

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

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

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

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of

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the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

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

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

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

(20)       Production costs.

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

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

(B) Repairs and maintenance.

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

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

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration,

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and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

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

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

(i) The area of the reservoir considered as proved includes:

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

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

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

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

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

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

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

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23)       Proved properties. Properties with proved reserves.

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

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

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

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

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

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

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

(30)       Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

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

(i) Reserves on undrilled acreage shall be limited to those directly offsetting

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development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

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

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

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

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EX-15.3

Exhibit 15.3

 

20405 Tomball Parkway, Building 2, Suite 200, Houston, Texas 77070, USA

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

January 31, 2018

CNOOC Limited

No. 25, Chaoyangmenbei Dajie

Dongcheng District

Beijing 100010, P.R. China

Gentlemen:

As per your request, RPS has prepared an estimate of the proved reserves, future production and income attributable to certain leasehold interests owned by CNOOC Limited as of December 31, 2017. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register, including all references to Regulation S-X and Regulation S-K (SEC regulations). Our third party revision, completed on January 31, 2018 and presented herein, was prepared for public disclosure by CNOOC Limited in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves and future net income amounts presented in this report, as of December 31, 2017, are based on the reserve estimate review that RPS performed for PAE’s year-end 2017 reserve report. In our opinion, the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

CNOOC Limited holds 50% interest in Bridas Corporation and Bridas Corporation holds 50% interests in PAE. Therefore CNOOC Limited, through Bridas Corporation, owns 25% of participating interests in PAE.

The subject properties are located in Argentina and Bolivia, South America. The properties evaluated by RPS account for a portion of CNOOC Limited’s total net proved reserves as of December 31, 2017.

Based on information provided by CNOOC, the third party estimate conducted by RPS addresses 6.25 percent of the Total Proved reserves of CNOOC on a barrel oil equivalent basis (BOE).

The estimated reserves and future net income amounts presented in this report, as of December 31, 2017, are related to hydrocarbon prices. . Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized in the following table.

SEC PARAMETERS

Estimated Net CNOOC Limited Reserves and Income Data

As of December 31, 2017

Note: Hydrocarbon liquids are crude oil, condensate and gasoline which are reported in thousands (10³) stock tank barrels (Mbbl). The Condensate and Gasoline estimates are volumes captured during field separation and gas plant processing in the field. The natural gas reserves reported include gas sales and fuel gas. These volumes are reported in million (10⁶) cubic feet (MMcf) at standard conditions of 14.7 psia and 60⁰ Fahrenheit.

In this report, the revenues, deductions and income data are expressed as thousands of U.S. dollars (M$).

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

Note：The future gross revenue is after the deduction of royalty and turnover taxes in Argentina. The deductions also account for the joint venture (JV) terms PAE has with Petrominera del Chubut S.E. (PMC), new JV partner in the Anticlinal Funes field, in which PAE carries all the investments

and cost, in return receives a greater share of the production until reimbursed. In Bolivia royalty IDH and YPFB part has been also subtracted.

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

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

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

Reserves Included in This Report

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

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

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves

are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At CNOOC Limited’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

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

For Cerro Dragón, Piedra Clavada and Koluel Kaike areas there are volumes of Proved Undeveloped Reserves associated with Proved Locations that have been booked for more than 5 years. PAE's continued development activities over the years have created new opportunities that have delayed drilling some of the existing Proved locations. All Proved locations are planned to be drilled in the following 5 years in each area.

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

Estimates of Reserves

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

These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through December 31, 2017 in those cases where such data were considered to be definitive. The volumetric method, analogy or a combination of methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. The volumetric analysis utilized pertinent well and seismic data supplied to RPS by PAE that were available through December 31, 2017. The data utilized from the analogues as well as the well and seismic data incorporated into our volumetric analysis were considered sufficient and appropriate for the purpose thereof.

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

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

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

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

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

Future Production Rates

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

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

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

Hydrocarbon Prices

The hydrocarbon liquid prices for the export market used in the preparation of this report are based on the average prices during the 12-month period for the year 2017, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period in accordance with SEC guidelines. The local market was deregulated effective October 2017 and therefore the price was estimated as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within the fourth quarter of 2017. Natural gas prices are based on existing gas contracts, and on the reasonable expectation that such gas contracts, will be extended to the entire life of the concession. There are some areas under Gas-Plus contract scheme with a specific price. For economic runs the gas price used was estimated based on production forecast weighted average taking into consideration both natural gas and Gas-Plus prices.

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

Costs

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

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

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

Standards of Independence and Professional Qualification

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

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

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

As indicated above, this study was based on data supplied by PAE. The supplied information was reviewed for reasonableness from a technical perspective. As is common in oil field situations, basic physical measurements taken over time cannot be verified independently in retrospect. As such, beyond the application of normal professional judgment, such data must be accepted as representative.

The opinions and interpretations presented in this report represent our best technical interpretation of the data made available to us. However, due to the uncertainty inherent in the estimation of all sub-surface parameters, we cannot and do not guarantee the accuracy or correctness of any interpretation and we shall not, except in the case of gross or willful negligence on our part, be liable or responsible for any loss, cost damages or expenses incurred or sustained by anyone resulting from any interpretation made by any of our officers, agents or employees.

Except for the provision of professional services on a fee basis, RPS does not have a commercial arrangement with any other person or company involved in the interests that are the subject of this report.

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

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by CNOOC Limited.

Very truly yours,

RPS

/s/ Victor Wayne Taylor

[SEAL]

Victor Wayne Taylor

PE License# 71417

Principal Engineer

EX-15.4

Exhibit 15.4 

	TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
	1100 LOUISIANA    SUITE 4600	HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191

January 16, 2018

CNOOC Limited 

c/o Nexen Energy ULC 

801-7th Avenue S.W. 

Calgary, Alberta T2P 3P7 

Canada

Gentlemen:

At the request of CNOOC Limited (CNOOC), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves attributable to certain leasehold and royalty interests of OOGC America, LLC (OOGC) as of December 31, 2017 prepared by OOGC’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). CNOOC indirectly retains 100 percent ownership of OOGC. Our reserves audit, completed on January 11, 2018 and presented herein, was prepared for public disclosure by CNOOC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent OOGC’s estimated net reserves attributable to the leasehold and royalty interests in certain properties owned by OOGC and reviewed by Ryder Scott, as of December 31, 2017. The properties reviewed by Ryder Scott incorporate OOGC reserve determinations and are located in the states of Colorado, Texas, and Wyoming.

The properties reviewed by Ryder Scott account for all of OOGC’s total net proved reserves as of December 31, 2017. CNOOC has represented that these properties represent 4.6 percent of its total company proved reserves on an equivalent barrel basis as of December 31, 2017. The portions reviewed by Ryder Scott as determined by various metrics are as follows:

Portions Reviewed
CNOOC Limited
	Developed	Undeveloped	Total
Net Liquid Reserves	7.0%	3.2%	4.9%
Net Gas Reserves	7.4%	2.7%	4.5%
Net Liquid Equivalent Reserves	6.8%	3.0%	4.6%

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and

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thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.

Based on our review, including the data, technical processes and interpretations presented by OOGC, it is our opinion that the overall procedures and methodologies utilized by OOGC in preparing their estimates of the proved reserves as of December 31, 2017 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by OOGC are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

The estimated reserves presented in this report are related to hydrocarbon prices. OOGC has informed us that in the preparation of their reserve and income projections, as of December 31, 2017, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by OOGC attributable to OOGC's interests in properties that we reviewed are summarized below:

SEC PARAMETERS

OOGC’s Estimates of Net Reserves

Certain Leasehold and Royalty Interests of

OOGC America, LLC

As of December 31, 2017

	Proved
	Developed				Total
	Producing		Undeveloped		Proved
Total Net Reserves
Oil/Condensate – MBarrels		78,874		48,122		126,996
Plant Products – MBarrels		26,485		14,882		41,367
Gas – MMCF		211,700		118,960		330,660
Total Oil Equivalents – MBOE*		140,642		82,831		223,473

* 6 Mcf = 1 bbl liquid equivalent

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousands of barrels of oil equivalent.

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January 16, 2018 

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Reserves Included in This Report

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

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report.

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

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

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

Audit Data, Methodology, Procedure and Assumptions

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

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reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

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

The proved reserves, prepared by OOGC, for the properties that we reviewed were estimated by performance methods, analogy, or a combination of methods. All of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods, primarily decline curve analysis, which utilized extrapolations of historical production and pressure data available through December 2017, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by OOGC or obtained from public data sources and were considered sufficient for the purpose thereof. All of the proved undeveloped reserves that we reviewed were estimated by the analogy method. The data utilized from the analogues were considered sufficient for the purpose thereof. All of the proved reserves that were reviewed are attributable to horizontal wells and locations.

To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

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January 16, 2018 

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As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by OOGC relating to hydrocarbon prices and costs as noted herein.

Data used in this audit were obtained from reviews with OOGC personnel, OOGC files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report Ryder Scott have relied, without independent verification, upon such information furnished by OOGC with respect to property interests, production from such properties, current costs of operation and development, prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. Furthermore, if in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. A field examination of the properties was not considered necessary for the purposes of this report. OOGC did not place any limitations on the Ryder Scott work performed.

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

The initial SEC hydrocarbon prices in effect on December 31, 2017 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by OOGC for the geographic areas reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used by OOGC to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used by OOGC were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by OOGC.

The table below summarizes OOGC’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as OOGC’s “average realized prices.” The average realized prices shown in the table below were determined from OOGC’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and OOGC’s estimate of the total net reserves for the properties reviewed by us for the geographic area.

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January 16, 2018 

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Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Prices Net of Marketing, Transmission, and Processing	Average Realized Prices at Point of Sale
	North America
United States	Oil/Condensate	West Texas Intermediate	$51.34/bbl	$47.58/bbl	$51.86/bbl
	NGLs*	Mt Belvieu	$26.87/bbl	$17.84/bbl**	$23.23/bbl
	Gas	Henry Hub	$2.96/MMBTU	$(1.42)/Mcf**	$3.36/Mcf

* NGL price was based upon the Mt. Belvieu benchmarks for each NGL constituent multiplied by fractional contribution

** Includes certain gas gathering and related services fees

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

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Operating costs furnished by OOGC are based on the operating expense reports of OOGC and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by OOGC were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by OOGC. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by OOGC are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by OOGC were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by OOGC. The estimated net cost of abandonment after salvage was included by OOGC for properties where abandonment costs net of salvage were significant. OOGC’s estimates of the net abandonment costs were accepted without independent verification.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with the operator’s plans to develop these reserves as of December 31, 2017. The implementation of the development plans as presented to us is subject to the approval process adopted by OOGC’s management. As the result of our inquiries during the course of our review, OOGC has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by OOGC’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE

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processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to OOGC. Additionally, OOGC has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2017, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

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

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

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

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

OOGC’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

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

Certain technical personnel of OOGC are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

OOGC has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In

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performing our audit of OOGC’s forecast of future proved production, we have relied upon data furnished by OOGC with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by OOGC. We consider the factual data furnished to us by OOGC to be appropriate and sufficient for the purpose of our review of OOGC’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by OOGC and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by OOGC, it is our opinion that the overall procedures and methodologies utilized by OOGC in preparing their estimates of the proved reserves as of December 31, 2017 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by OOGC are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by OOGC in their estimation of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in estimates for these properties.

We were in reasonable agreement with OOGC's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between OOGC's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to OOGC when its reserve estimates were prepared. However not withstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by OOGC.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited – OOGC America, LLC 

January 16, 2018 

Page 9

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

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

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

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by CNOOC Limited.

CNOOC makes periodic filings on Form 20-F with the SEC under the 1934 Exchange Act. Furthermore, CNOOC has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 20-F is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form F-3 of CNOOC of the references to our name as well as to the references to our third party report for CNOOC, which appears in the December 31, 2017 annual report on Form 20-F of CNOOC. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by CNOOC.

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

CNOOC Limited – OOGC America, LLC 

January 16, 2018 

Page 10

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

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Val Rick Robinson

Val Rick Robinson, P.E.

TBPE License No. 105137

Managing Senior Vice President

[SEAL]

VRR (FWZ)/pl

cc: Mr. Yong Wang, OOGC Reserves Engineer

Mr. Todd Nicol, OOGC Asset Manager 

Terrance Kryschuk, Deloitte LLP 

Jenny Yang, Deloitte LLP

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Engineer

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Val Rick Robinson was the primary technical person responsible for the estimate of the reserves, future production and income presented herein.

Mr. Robinson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Robinson served in a number of engineering positions with ExxonMobil Corporation. For more information regarding Mr. Robinson’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com.

Mr. Robinson earned a Bachelor of Science degree in Chemical Engineering from Brigham Young University in 2003 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Robinson fulfills. As part of his 2017 continuing education hours, Mr. Robinson attended 28 hours of formalized training including the 2017 RSC Reserves Conference and various professional society presentations covering such topics as the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register, the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, overviews of the various productive basins of North America, computer software, and professional ethics.

Based on his educational background, professional training and more than 14 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Robinson has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

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

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

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

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

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

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

RESERVES (SEC DEFINITIONS)

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

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

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

PROVED RESERVES (SEC DEFINITIONS)

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

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

(i) The area of the reservoir considered as proved includes:

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

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

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

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

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

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

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

DEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

Developed Producing (SPE-PRMS Definitions)

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

Developed Producing Reserves

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing 

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

Shut-In 

Shut-in Reserves are expected to be recovered from: 

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

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

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

UNDEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EX-15.5

Exhibit 15.5

January 18, 2018

CNOOC Limited

c/o Nexen Energy ULC

801 – 7^th Avenue SW

Calgary, Alberta

T2P 3P7

Re: McDaniel & Associates - Report of Third Party for certain Canadian Oil Sands properties owned by CNOOC Limited

Gentlemen:

Pursuant to your request, McDaniel & Associates Consultants Ltd. (“McDaniel”) has conducted an independent audit of CNOOC Limited’s (“CNOOC”) proved bitumen and synthetic crude oil reserves, as of December 31, 2017, for certain Canadian Oil Sands properties owned by CNOOC and managed by its wholly-owned subsidiary, Nexen Energy ULC (“Nexen”), as shown in Table 1. CNOOC has represented that these properties account for 18 percent of its total company proved reserves on an equivalent barrel basis as of December 31, 2017, and that its reserves estimates have been prepared in accordance with the United States Securities and Exchange Commission (SEC) definitions. We have reviewed information provided to us by Nexen on behalf of CNOOC that it represents to be its estimates of the reserves, as of December 31, 2017, for the same properties as those which we audited. The completion date of our report is January 18, 2018. This report was prepared in accordance with guidelines specified in
Item 1202(a)(8) of Regulation S-K and is to be used for inclusion in certain filings of the SEC.

Reserves included herein are expressed as reserves as represented by CNOOC. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2017. Working interest reserves are defined as that portion of the gross reserves attributable to the interests owned by CNOOC after deducting all working interests owned by others. Net reserves are defined as working interest reserves after the deduction of royalties.

Estimates of bitumen and synthetic crude oil should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

2200, Bow Valley Square 3, 255 - 5 Avenue SW, Calgary AB T2P 3G6        Tel: (403) 262-5506       Fax: (403) 233-2744        www.mcdan.com

Nexen Energy ULC	January 18, 2018
Report of Third Party for certain Canadian Oil Sands Properties owned by CNOOC Limited	Page 2

Data used in this audit were obtained from reviews with Nexen personnel, Nexen files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Nexen with respect to property interests, production from such properties, current costs of operation and development, prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. Furthermore, if in the course of our examination something came to our attention, which brought into question the validity or sufficiency of any of such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

The process of estimating reserves requires complex judgments and decision-making based on available geological, geophysical, engineering and economic data. To estimate the economically recoverable oil, synthetic crude oil and natural gas reserves, and related future net cash flows, we consider many factors and make assumptions including:

· expected reservoir characteristics based on geological, geophysical and engineering assessments;

· future production rates based on historical performance and expected future operating and investment activities;

· future oil and gas prices and quality differentials;

· assumed effects of regulation by governmental agencies; and

· future development and operating costs

Estimates of reserves were prepared using standard geological and engineering methods generally accepted by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” 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.

Discovered oil and natural gas reserves are generally only produced when they are economically recoverable. As such, oil and gas prices, and capital and operating costs have an impact on whether reserves will ultimately be produced. As required by SEC rules, reserves represent the quantities that are expected to be economically recoverable using existing prices and costs. Estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.

Nexen Energy ULC	January 18, 2018
Report of Third Party for certain Canadian Oil Sands Properties owned by CNOOC Limited	Page 3

The proved reserves estimates in this report were based upon 2017 first-of-the month fiscal average pricing using benchmark pricing. Oil prices were primarily based upon West Texas Intermediate at Cushing crude oil benchmark of US$51.34 per barrel and Western Canadian Select at Hardisty benchmark of US$38.86 per barrel. Specific pricing for each field was adjusted for historical quality and transportation cost differentials, and for currency exchange rates. The resulting adjusted price is referred to as the “realized price.” For total proved reserves, the estimated realized prices were US$28.65 per barrel of Bitumen and US$52.62 per barrel of synthetic crude oil, based upon a volume weighted average of the properties evaluated.

Generally, operations are subject to various levels of government controls and regulations. These laws and regulations may include matters relating to land tenure, drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment, that are subject to change from time to time. Current legislation is generally a matter of public record, and additional legislation or amendments that will affect reserves or when any such proposals, if enacted, might become effective generally cannot be predicted. Changes in government regulations could affect reserves or related economics. In the regions that are currently being evaluated we believe we have applied existing regulations appropriately.

CNOOC Estimates

Nexen on behalf of CNOOC has represented that estimated proved reserves attributable to the audited properties are based on SEC definitions. CNOOC represents that its estimates of the reserves attributable to these properties represent 18 percent of its total company proved reserves after royalties on an equivalent basis and are as follows, expressed in thousands of barrels (Mbbl), and thousands of barrels of oil equivalent (Mboe):

CNOOC’s estimate of Reserves as of December 31, 2017

Certain Canadian Fields Audited by McDaniel & Associates

 Oil Sands

CNOOC Reserves	Synthetic Crude Oil (Mbbl)	Bitumen (Mbbl)	Oil Equivalent (Mboe)
Working Interest Reserves (after royalties)
Proved	785,879	80,260	866,139

Note: Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent based on an energy equivalent basis.

Reserves Audit Opinion

McDaniel has used all data, assumptions, procedures and methods that it considers necessary to prepare this report.

Nexen Energy ULC	January 18, 2018
Report of Third Party for certain Canadian Oil Sands Properties owned by CNOOC Limited	Page 4

In our opinion, the information relating to estimated proved reserves of bitumen and synthetic crude oil contained in this opinion has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7 and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (5), (8) of Regulation S-K of the Securities and Exchange Commission.

We have examined the assumptions, data, methods procedures and proved reserves estimates prepared by Nexen on behalf of CNOOC. In our opinion, the proved reserves for the reviewed properties as estimated by CNOOC are, in aggregate on the basis of equivalent barrels, reasonable because when compared to our estimates, or if we were to perform our own detailed estimates, reflect a difference of not more than plus or minus 10 percent.

The analyses of these properties, as reported herein, was conducted within the context of an audit of a distinct group of properties in aggregate as part of the total corporate level reserves. Extraction and use of these analyses outside of this context may not be appropriate without supplementary due diligence.

McDaniel is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 60 years. McDaniel does not have any financial interest, including stock ownership, in CNOOC. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Nexen on behalf of CNOOC.

This report was prepared by McDaniel & Associates Consultants Ltd. for the exclusive use of CNOOC. It is not to be reproduced, distributed, or made available, in whole or in part to any person, company, or organization other than CNOOC without the knowledge and consent of McDaniel & Associates Consultants Ltd. We reserve the right to revise any of the estimates provided herein if any relevant data existing prior to preparation of this report was not made available or if any data provided was found to be erroneous.

If there are any questions, please contact the writer directly at (403) 218-1379.

Sincerely,

McDaniel & Associates Consultants Ltd.

/s/ P. A. Welch

____________________________

P. A. Welch, P. Eng.

CC: Mr. Mike Birdgeneau, P. Eng., Team Lead, Oil Sands Resource Planning

Ms. Charishe Amante, P. Eng., Corporate Reserves Analyst

Mr. Terrance Kryschuk, Deloitte LLP

Ms. Jenny Yang, Deloitte LLP

Nexen Energy ULC	January 18, 2018
Report of Third Party for certain Canadian Oil Sands Properties owned by CNOOC Limited	Page 5

Table 1

CNOOC Properties Audited by McDaniel & Associates

Select Canadian Oil Sands Properties

December 31, 2017

	BUSINESS UNIT	FIELD NAME
1	OIL SANDS	LONG LAKE
2	OIL SANDS	SYNCRUDE

Nexen Energy ULC	January 18, 2018
Report of Third Party for certain Canadian Oil Sands Properties owned by CNOOC Limited	Page 6

CERTIFICATE OF QUALIFICATION

I, Philip Arthur Welch, Petroleum Engineer of 2200, 255 - 5th Avenue, S.W., Calgary, Alberta, Canada hereby certify:

1. That I am the President & Managing Director of McDaniel & Associates Consultants Ltd., APEGA Permit Number P3145, which Company did prepare, at the request of CNOOC Limited., the report entitled "Report of Third Party for certain Canadian Oil Sands properties owned by CNOOC Limited, As of December 31, 2017", dated January 18, 2018, and that I supervised the preparation of this report.

2. That I attended the University of British Columbia in the years 1980 to 1987 and that I graduated with a Bachelor of Applied Science and Master of Applied Science degrees in Mechanical Engineering, that I am a registered Professional Engineer with the Association of Professional Engineers and Geoscientists of Alberta; that I am a member of the Society of Petroleum Engineers; that I am a member of the Society of Petroleum Evaluation Engineers; and that I have in excess of 25 years of experience in oil and gas reservoir studies and evaluations.

3. That I have no direct or indirect interest in the properties or securities of CNOOC Limited., nor do I expect to receive any direct or indirect interest in the properties or securities of CNOOC Limited., or any affiliate thereof.

4. That the aforementioned report was not based on a personal field examination of the properties in question, however, such an examination was not deemed necessary in view of the extent and accuracy of the information available on the properties in question.

/s/ P. A. Welch 

____________________________

P. A. Welch, P. Eng.

Calgary, Alberta

Dated: January 18, 2018

EX-15.6

Exhibit 15.6

DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

This is a digital representation of a DeGolyer and MacNaughton report.

This file is intended to be a manifestation of certain data in the subject report and as such are subject to the same conditions thereof. The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

January 23, 2018

CNOOC Limited
c/o Nexen Energy ULC
801-7th Avenue S.W.
Calgary, AB
T2P 3P7

Re: Report of Third Party for CNOOC Limited’s interest in the Liza Field
Offshore Guyana

Ladies and Gentlemen:

Pursuant to your request, we have conducted a reserves evaluation of the net proved oil, condensate, natural gas liquids (NGL), and gas reserves, as of December 31, 2017, of the Liza field offshore Guyana with interests represented to be owned by CNOOC Limited (CNOOC). This evaluation was completed on January 23, 2018. CNOOC has represented that these properties account for approximately 1 percent on a net equivalent barrel basis of CNOOC’s net proved reserves as of December 31, 2017, and that the net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided to us by Nexen Energy ULC (Nexen), a subsidiary of CNOOC, that it represents to be CNOOC’s estimates of the net reserves, as of December 31, 2017, for the same properties as those which we evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by CNOOC.

Reserves estimates included herein are expressed as net reserves as represented by Nexen. Gross reserves are defined as the total estimated petroleum to be produced from this field after December 31, 2017. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by CNOOC after deducting all interests owned by others.

 2

DeGolyer and MacNaughton

The Liza field in which CNOOC has an interest is subject to the terms of a Petroleum Agreement between the Government of the Cooperative Republic of Guyana and the joint venture participants. The terms of these agreements generally allow for working interest participants to be reimbursed for portions of capital costs and operating expenses and to share in the profits. The reimbursements and profit proceeds are converted to a barrel of oil equivalent or cubic foot of gas equivalent by dividing by product prices to determine the “entitlement reserves.” These entitlement reserves are equivalent in principle to net reserves and are used to calculate an equivalent net share, termed an “entitlement interest.” In this report, CNOOC reserves or interest in these properties subject to this production sharing agreement is the entitlement based on CNOOC’s working interest.

Estimates of oil, condensate, NGL, and gas reserves should be regarded only as estimates. Such estimates are based upon information that is currently available and may change as further production history and additional information become available. Such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this evaluation were obtained from reviews with Nexen personnel and from Nexen files. In the preparation of this report we have relied upon such information furnished by Nexen with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. Furthermore, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. In our opinion, the adequacy and quality of the data provided to us were sufficient for us to conduct this reserves evaluation. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as

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presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by Nexen on behalf of CNOOC, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the fluid properties, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

Petroleum reserves estimated by CNOOC and evaluated by DeGolyer and MacNaughton are classified as proved and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. Reserves were estimated only to the limit of economic production rates under existing economic and operating conditions using prices and costs consistent with the effective date of this report.

Oil and condensate reserves estimated herein are those to be recovered by conventional field operations. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity. NGL reserves estimated herein are those to be recovered by low-temperature

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separation. Currently, there are no plans to process produced gas to recover condensate or NGL; therefore, the condensate and NGL reserves were estimated to be zero. Oil, condensate, and NGL reserves estimates included in this report are expressed in terms of barrels representing 42 United States gallons per barrel.

Gas reserves estimated herein are expressed as sales gas at a temperature base of 60 degrees Fahrenheit and a pressure based of 14.7 pounds per square inch. Separator gas is the gas remaining after field separation but prior to gas processing and shrinkage for fuel use and flare. Sales gas is the deliverable quantity of separator gas available for sales after deductions for fuel usage and shrinkage. Currently, there is no market for the associated solution gas; therefore, the sales gas reserves were estimated to be zero.

Definition of Reserves

Petroleum reserves estimated by CNOOC included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by CNOOC in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

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

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project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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

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

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

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

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and, (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

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(v) Existing economic and operating 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.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

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

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

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

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

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

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(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in Rule 4-10(a)(2) of Regulation S-X, or by other evidence using reliable technology establishing reasonable certainty.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs. Prices and costs herein are expressed in United States dollars (U.S.$).

Oil Prices

Nexen, on behalf of CNOOC, has represented that the oil prices for the Liza field were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. To account for quality and transportation costs, Nexen, on behalf of CNOOC, provided price differentials to a Brent reference price of U.S.$54.39 per barrel and the prices were held constant thereafter. The realized price, or volume-weighted average oil price attributable to estimated proved reserves, was U.S.$53.30 per barrel.

Operating Expenses, Capital Costs, and Abandonment Costs

Operating expenses, capital costs, and abandonment costs, based on information provided by Nexen, on behalf of CNOOC, were used in estimating future costs required to operate the field. These costs were not escalated for inflation.

If during the course of our examination, the validity or sufficiency of the provided future prices and costs data was questioned, we did not rely on the provided future prices and costs data until we had satisfactorily resolved our

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DeGolyer and MacNaughton

questions relating thereto or had independently verified the future prices and costs data.

CNOOC’s oil and gas reserves have been estimated assuming the continuation of the current regulatory environment. Changes in the regulatory environment by host governments may impact the operating environment and oil and gas reserves estimates of industry participants. Such regulatory changes could include increased mandatory government participation in producing contracts, changes in royalty terms, cancellation or amendment of contract rights, or expropriation or nationalization of property. While the oil and gas industry is subject to regulatory changes that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2017, estimated oil and gas reserves.

CNOOC Estimates

Nexen, on behalf of CNOOC, has represented that its estimated net proved reserves attributable to the reviewed property were based on the definition of proved reserves of the SEC. The CNOOC net proved reserves attributable to the Liza field offshore Guyana, as of December 31, 2017, and which represent approximately 1 percent of total CNOOC net reserves on a net equivalent barrel basis, are summarized as follows, expressed in expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Estimated by CNOOC Net Proved Reserves as of December 31, 2017
		Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Proved
Developed		0	0	0	0
Undeveloped		37,779	0	0	37,779
Total		37,779	0	0	37,779

Note: Gas is converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

The assumptions, data, methods, and procedures used by DeGolyer and MacNaughton to conduct the reserves evaluation are appropriate for the purposes of this report.

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In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9, of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b) and 1201, 1202(a)(1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC, provided however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

In our opinion, the proved reserves for the reviewed properties are, in aggregate, on the basis of equivalent barrels, reasonable because when compared to our estimates reflect a difference of not more than plus or minus 10 percent.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. This report does not constitute a legal or accounting opinion. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in CNOOC. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Nexen on behalf of CNOOC. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

/s/ DeGOLYER and MacNAUGHTON

DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716

[SEAL]
	/s/ Thomas C. Pence
	Thomas C. Pence, P.E. Senior Vice President DeGolyer and MacNaughton

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DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Thomas C. Pence, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1. That I am a Senior Vice President of DeGolyer and MacNaughton, which company did prepare the letter report dated January 23, 2017, on the proved reserves evaluation of certain properties attributable to CNOOC Limited, and that I, as Senior Vice President, was responsible for the preparation of this letter report.

2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and that I have in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations.

[SEAL]
	/s/ Thomas C. Pence
	Thomas C. Pence, P.E. Senior Vice President DeGolyer and MacNaughton

EX-15.8

Exhibit 15.8

	TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
	1100 LOUISIANA    SUITE 4600	HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191

Consent of Independent Consultant

We consent to the reference to our firm in the form and context in which they appear in this Annual Report on Form 20-F, and the inclusion of our reports herein for CNOOC Limited, filed with the Securities and Exchange Commission.

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

 Houston, Texas

 April 6, 2018

SUITE  600,  1015  4TH  STREET, S.W.	CALGARY, ALBERTA T2R 1J4	TEL (403) 262-2799	FAX (403) 262-2790
621  17TH STREET, SUITE 1550	DENVER, COLORADO 80293-1501	TEL (303) 623-9147	FAX (303) 623-4258

EX-15.9

Exhibit 15.9

 

4 April 2018

China National Offshore Oil Corporation Limited

No. 25, Chaoyangmenbei Daijie Dongcheng District

Beijing 100010,

P.R. China

Dear Sir,

Consent of Gaffney, Cline & Associates

As independent reserves advisors of CNOOC Limited (CNOOC), Gaffney, Cline & Associates (GCA) hereby confirms that it has granted and not withdrawn its consent to the references to GCA and to the inclusion of information contained in our reports entitled “Independent Letter –The Missan Oil Fields In Eastern Iraq Estimated Proved Reserves and Financial Data, Based on SEC Rules as of 31 December 2017” and “Independent Letter –The Greater Angostura Fields Block 2C, Trinidad & Tobago Estimated Proved Reserves and Financial Data, Based on SEC Rules as of 31 December 2017” as of March 2018 prepared for CNOOC, and to the annexation of our reports as an exhibit on Form 20-F in CNOOC’s Annual Report pursuant to Section 13 or 15(d) of the Securities and Exchange Commission Act of 1934.

Yours faithfully,

Gaffney, Cline & Associates (Consultants) Pte Ltd

/s/ Stephen Lane

Stephen M. Lane, Technical Director

SML/YDH/mlt/PS-17-2055 & PS-17-2056/L0051

China National Offshore Oil Corporation Limited

 UEN: 198701453N

EX-15.10

Exhibit 15.10

20405 Tomball Parkway, Building Two, Suite 200, Houston, Texas 77070

T 281 448 6188 W www.rpsgroup.com/usa

RPS Consent of Independent Consultant

We consent to the reference to our firm in the form and context in which they appear in this Annual Report on Form 20-F, and the inclusion of reports herein for CNOOC Limited filed with the Securities and Exchange Commission.

RPS

By: /s/ Doug Matthys

Name: Doug Matthys

Title: Chief Operating Officer

Houston, Texas

March 21, 2018

United Kingdom I USA I Canada I Australia I Malaysia I Ireland I Netherlands I Singapore I Russia I Brazil I Africa

EX-15.11

Exhibit 15.11

 

Consent of Independent Consultant

We consent to the reference to our firm in the form and context in which they appear in this Annual Report on Form 20-F, and the inclusion of our reports herein for CNOOC Limited, filed with the Securities and Exchange Commission.

McDANIEL & ASSOCIATES CONSULTANTS LTD.

By: /s/ Phil A. Welch

Name: Phil A. Welch, P. Eng.

Title: President & Managing Director

McDaniel & Associates Consultants Ltd.

2200, Bow Valley Square 3,

255 - 5 Avenue S.W. Calgary, Alberta,

T2P 3G6 Canada

April 9, 2018

2200, Bow Valley Square 3, 255 - 5 Avenue SW, Calgary AB T2P 3G6 Tel: (403) 262-5506 Fax: (403) 233-2744 www.mcdan.com

EX-15.12

Exhibit 15.12

DeGolyer and MacNaughton 

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

Consent of DeGolyer and MacNaughton

We consent to the reference to DeGolyer and MacNaughton in the form and context in which it appears in the Annual Report on Form 20-F of CNOOC Limited, for the year ended December 31, 2017, and the inclusion of our report dated January 23, 2018, concerning our opinion on the proved reserves as of December 31, 2017, herein for CNOOC Limited, to be filed with the Securities and Exchange Commission.

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

Dallas, Texas

April 9, 2018

XML

DOCUMENT AND ENTITY INFORMATION	12 Months Ended
	Dec. 31, 2017 shares
Document and Entity Information [abstract]
Entity Registrant Name	CNOOC LTD
Entity Central Index Key	0001095595
Document Type	20-F
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	44,647,455,984
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY

XML

CONSOLIDATED STATEMENTS OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥) ¥ / shares	Dec. 31, 2017 USD ($) $ / shares	Dec. 31, 2016 CNY (¥) ¥ / shares	Dec. 31, 2015 CNY (¥) ¥ / shares
REVENUE [abstract]
Oil and gas sales	¥ 151,888	$ 23,345	¥ 121,325	¥ 146,597
Marketing revenues	28,907	4,443	20,310	21,422
Other income	5,595	860	4,855	3,418
Total revenue	186,390	28,648	146,490	171,437
EXPENSES [abstract]
Operating expenses	(24,282)	(3,732)	(23,211)	(28,372)
Taxes other than income tax	(7,210)	(1,108)	(6,941)	(10,770)
Exploration expenses	(6,881)	(1,058)	(7,359)	(9,900)
Depreciation, depletion and amortization	(61,257)	(9,415)	(68,907)	(73,439)
Special oil gain levy	(55)	(8)	0	(59)
Impairment and provision	(9,130)	(1,403)	(12,171)	(2,746)
Crude oil and product purchases	(27,643)	(4,249)	(19,018)	(19,840)
Selling and administrative expenses	(6,861)	(1,055)	(6,493)	(5,705)
Others	(6,021)	(925)	(4,802)	(3,150)
Total expenses	(149,340)	(22,953)	(148,902)	(153,981)
PROFIT/(LOSS) FROM OPERATING ACTIVITIES	37,050	5,695	(2,412)	17,456
Interest income	653	100	901	873
Finance costs	(5,044)	(775)	(6,246)	(6,118)
Exchange (losses)/gains, net	356	55	(790)	(143)
Investment income	2,409	370	2,774	2,398
Share of profits/(losses) of associates	302	46	(609)	256
Share of profit of a joint venture	553	85	533	1,647
Non-operating income, net	78	12	574	761
PROFIT/(LOSS) BEFORE TAX	36,357	5,588	(5,275)	17,130
Income tax credit/(expense)	(11,680)	(1,795)	5,912	3,116
PROFIT FOR THE YEAR ATTRIBUTABLE TO OWNERS OF THE PARENT	24,677	3,793	637	20,246
Items that may be subsequently reclassified to profit or loss
Exchange differences on translation of foreign operations	(10,121)	(1,556)	10,422	7,979
Share of other comprehensive income/(expense) of associates	36	6	(127)	74
Other items that will not be reclassified to profit or loss
Fair value change on equity investments designated as at fair value through other comprehensive income	(542)	(83)	(461)	(1,573)
Others	54	8	12	134
OTHER COMPREHENSIVE INCOME/(EXPENSE) FOR THE YEAR, NET OF TAX	(10,573)	(1,625)	9,846	6,614
TOTAL COMPREHENSIVE INCOME FOR THE YEAR ATTRIBUTABLE TO OWNERS OF THE PARENT	¥ 14,104	$ 2,168	¥ 10,483	¥ 26,860
EARNINGS PER SHARE ATTRIBUTABLE TO OWNERS OF THE PARENT [abstract]
Basic (RMB Yuan) | (per share)	¥ 0.55	$ 0.085	¥ 0.01	¥ 0.45
Diluted (RMB Yuan) | (per share)	¥ 0.55	$ 0.085	¥ 0.01	¥ 0.45

XML

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION ¥ in Millions, $ in Millions	Dec. 31, 2017 CNY (¥)		Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)
NON-CURRENT ASSETS [abstract]
Property, plant and equipment	¥ 395,868		$ 60,844	¥ 432,465
Intangible assets	15,070		2,316	16,644
Investments in associates	4,067		625	3,695
Investment in a joint venture	25,079		3,855	26,300
Equity investments	3,540		544	4,266
Deferred tax assets	25,509		3,921	24,844
Other non-current assets	9,248		1,421	7,422
Total non-current assets	478,381		73,526	515,636
CURRENT ASSETS [abstract]
Inventories and supplies	7,354		1,130	8,709
Trade receivables	8,386		1,289	10,199
Due from related companies	12,914		1,985	13,263
Derivative financial assets	0		0	428
Equity investments	14		2	15
Other financial assets	74,344		11,426	52,889
Other current assets	7,874		1,211	5,977
Time deposits with maturity over three months	15,380		2,364	16,830
Cash and cash equivalents	12,572		1,932	13,735
Total current assets	138,838		21,339	122,045
CURRENT LIABILITIES [abstract]
Loans and borrowings	9,360		1,439	14,867
Borrowings from the parent company	4,532	[1]	697	4,811	[1]
Trade and accrued payables	10,062		1,547	10,254
Due to the parent company	193		30	215
Due to related companies	16,651		2,559	15,091
Derivative financial liabilities	0		0	426
Other payables and accrued liabilities	13,913		2,137	14,651
Taxes payable	6,701		1,030	6,775
Total current liabilities	61,412		9,439	67,090
NET CURRENT ASSETS	77,426		11,900	54,955
TOTAL ASSETS LESS CURRENT LIABILITIES	555,807		85,426	570,591
NON-CURRENT LIABILITIES [abstract]
Loans and borrowings	118,358		18,191	130,798
Provision for dismantlement	52,893		8,130	50,426
Deferred tax liabilities	3,303		508	5,670
Other non-current liabilities	1,278		196	1,326
Total non-current liabilities	175,832		27,025	188,220
Net assets	379,975		58,401	382,371
Equity attributable to owners of the parent
Issued capital	43,081		6,621	43,081
Reserves	336,894		51,780	339,290
Total equity	¥ 379,975		$ 58,401	¥ 382,371

[1] In September 2014, CNOOC provided CNOOC International Limited, a wholly-owned subsidiary of the Company a five-year uncommitted revolving loan facility for general purposes, with the principal amount of US$135 million of 0.95% per annum. As at December 31, 2017, the withdrawal amount of the loan was US$130 million (December 31, 2016: US$130 million); In December 2014, CNOOC provided the Company a five-year uncommitted revolving loan facility for general purposes, with the principal amount of US$600 million of 0.95% per annum. As at December 31, 2017, the withdrawal amount of the loan was US$564 million (December 31, 2016: US$564 million).

XML

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY ¥ in Millions, $ in Millions	CNY (¥)	USD ($)	Issued capital [member] CNY (¥)	Cumulative translation reserve [member] CNY (¥)	Statutory and non-distributable reserves [member] CNY (¥)	Statutory and non-distributable reserves [member] CNOOC China Limited [member] CNY (¥)	Other reserves [member] CNY (¥)	Retained earnings [member] CNY (¥)	Retained earnings [member] CNOOC China Limited [member] CNY (¥)	Proposed final dividend [member] CNY (¥)	Total equity attributable to owners of the Company [member] CNY (¥)
Balance at beginning of year at Dec. 31, 2014			¥ 43,081	¥ (20,918)	¥ 20,000		¥ 6,497	¥ 319,625		¥ 11,325	¥ 379,610
Profit for the year	¥ 20,246		0	0	0		0	20,246		0	20,246
Other comprehensive income/(expense), net of income tax	6,614		0	7,979	0		(1,365)	0		0	6,614
Total comprehensive income/(expense)			0	7,979	0		(1,365)	20,246		0	26,860
Final dividend			0	0	0		0	58		(11,325)	(11,267)
Interim dividend			0	0	0		0	(9,162)		0	(9,162)
Proposed final dividend	(9,397)		0	0	0		0	(9,397)		9,397	0
Balance at end of year at Dec. 31, 2015			43,081	(12,939)	20,000		5,132	321,370		9,397	386,041
Profit for the year	637		0	0	0		0	637		0	637
Other comprehensive income/(expense), net of income tax	9,846		0	10,422	0		(576)	0		0	9,846
Total comprehensive income/(expense)			0	10,422	0		(576)	637		0	10,483
Final dividend			0	0	0		0	(143)		(9,397)	(9,540)
Interim dividend			0	0	0		0	(4,613)		0	(4,613)
Proposed final dividend	(9,096)		0	0	0		0	(9,096)		9,096	0
Balance at end of year at Dec. 31, 2016	382,371		43,081	(2,517)	20,000		4,556	308,155		9,096	382,371
Reserves	339,290
Profit for the year	24,677	$ 3,793	0	0	0		0	24,677		0	24,677
Other comprehensive income/(expense), net of income tax	(10,573)	(1,625)	0	(10,121)	0		(452)	0		0	(10,573)
Total comprehensive income/(expense)			0	(10,121)	0		(452)	24,677		0	14,104
Final dividend			0	0	0		0	183		(9,096)	(8,913)
Interim dividend			0	0	0		0	(7,587)		0	(7,587)
Proposed final dividend	(10,830)		0	0	0		0	(10,830)		10,830	0
Appropriation to reserve			0	0		¥ 50,000	0		¥ (50,000)	0	0
Balance at end of year at Dec. 31, 2017	379,975	58,401	¥ 43,081	¥ (12,638)	¥ 70,000		¥ 4,104	¥ 264,598		¥ 10,830	¥ 379,975
Reserves	¥ 336,894	$ 51,780

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CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
CASH FLOWS FROM OPERATING ACTIVITIES [abstract]
Cash generated from operations	¥ 110,625,000,000	$ 17,003	¥ 82,137,000,000	¥ 96,095,000,000
Income tax paid	(15,891,000,000)	(2,442)	(9,274,000,000)	(16,000,000,000)
Net cash flows from operating activities	94,734,000,000	14,561	72,863,000,000	80,095,000,000
CASH FLOWS FROM INVESTING ACTIVITIES [abstract]
Capital expenditure	(47,734,000,000)	(7,337)	(51,347,000,000)	(67,674,000,000)
Additions to investments in associates	(161,000,000)	(25)	(221,000,000)	(9,000,000)
Decrease in time deposits with maturity over three months	1,450,000,000	223	1,180,000,000	4,825,000,000
Dividends received from an associate	116,000,000	18	135,000,000	164,000,000
Dividends received from a joint venture	243,000,000	37	0	32,000,000
Interest received	666,000,000	102	1,010,000,000	812,000,000
Investment income received	1,821,000,000	280	2,013,000,000	2,177,000,000
Purchase of other financial assets	(122,267,000,000)	(18,792)	(62,900,000,000)	(122,030,000,000)
Purchase of equity investments	(51,000,000)	(8)	(63,000,000)	(236,000,000)
Proceeds from sale of other financial assets	101,396,000,000	15,584	81,675,000,000	104,900,000,000
Proceeds from disposal of property, plant and equipment	110,000,000	17	532,000,000	544,000,000
Proceeds from disposal of an associate	0	0	33,000,000	0
Net cash flows used in investing activities	(64,411,000,000)	(9,901)	(27,953,000,000)	(76,495,000,000)
CASH FLOWS FROM FINANCING ACTIVITIES [abtract]
Proceeds from issuance of guaranteed notes	0	0	0	23,184,000,000
Repayment of guaranteed notes	(8,869,000,000)	(1,363)	(4,866,000,000)	(789,000,000)
Proceeds from bank loans	12,252,000,000	1,883	4,293,000,000	20,541,000,000
Repayment of bank loans	(13,052,000,000)	(2,006)	(23,412,000,000)	(24,127,000,000)
Dividends paid	(16,448,000,000)	(2,528)	(14,153,000,000)	(20,419,000,000)
Interest paid	(5,154,000,000)	(792)	(5,102,000,000)	(5,283,000,000)
Net cash flows used in financing activities	(31,271,000,000)	(4,806)	(43,240,000,000)	(6,893,000,000)
NET (DECREASE)/INCREASE IN CASH AND CASH EQUIVALENTS	(948,000,000)	(146)	1,670,000,000	(3,293,000,000)
Cash and cash equivalents at beginning of year	13,735,000,000		11,867,000,000	14,918,000,000
Effect of foreign exchange rate changes, net	(215,000,000)	(33)	198,000,000	242,000,000
CASH AND CASH EQUIVALENTS AT END OF YEAR	¥ 12,572,000,000	$ 1,932	¥ 13,735,000,000	¥ 11,867,000,000

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CORPORATE INFORMATION

12 Months Ended

Dec. 31, 2017

CORPORATE INFORMATION [abstract]

Disclosure of corporate information

1.        CORPORATE INFORMATION

CNOOC Limited (the "Company") was incorporated in the Hong Kong Special Administrative Region ("Hong Kong") of the People's Republic of China (the "PRC") on August20,1999 to hold the interests in certain entities thereby creating a group comprising the Company and its subsidiaries (hereinafter collectively referred to as the "Group"). During the year, the Group was principally engaged in the exploration, development, production and sale of crude oil, natural gas and other petroleum products.

The registered office address of the Company is 65/F, Bank of China Tower, 1 Garden Road, Hong Kong.

In the opinion of the directors of the Company (the "Directors"), the parent and the ultimate holding company of the Company is China National Offshore Oil Corporation ("CNOOC"), a company established in the PRC. In November 2017, CNOOC changed its registered company name which is registered in Chinese pursuant to relevant laws and regulations of China to "中國海洋石油集團有限公司".

Particulars of the principal subsidiaries at the end of the reporting period are as follows:

Name of entity	Place of establishment	Nominal value of ordinary shares issued and paid-up/ registered capital	Percentage of equity attributable to the Group	Principal activities
Directly held subsidiaries:
CNOOC China Limited	Tianjin, PRC	RMB20 billion	100%	Offshore petroleum exploration, development, production and sales, and shale gas exploration in the PRC
China Offshore Oil (Singapore) International Pte Ltd	Singapore	SG$3 million	100%	Sales and marketing of petroleum products outside the PRC
CNOOC International Limited	British Virgin Islands	US$20,000,000,002	100%	Investment holding
CNOOC Finance (2003) Limited	British Virgin Islands	US$1,000	100%	Bond issuance
CNOOC Finance (2011) Limited	British Virgin Islands	US$1,000	100%	Bond issuance
CNOOC Finance(2012) Limited	British Virgin Islands	US$1,000	100%	Bond issuance
CNOOC Finance(2013) Limited	British Virgin Islands	US$1,000	100%	Bond issuance
Indirectly held subsidiaries(1):
CNOOC Deepwater Development Limited	Zhuhai, PRC	RMB20.3 billion	100%	Deepwater and low-grade oil and gas fields exploitation in the PRC and exploration, development, production and sales of oil and gas in the oil and gas fields of South China Sea
CNOOC Southeast Asia Limited	Bermuda	US$12,000	100%	Investment holding
CNOOC SES Ltd.	Malaysia	US$1	100%	Petroleum exploration, development and production in Indonesia
CNOOC Muturi Limited	Isle of Man	US$7,780,770	100%	Petroleum exploration, development and production in Indonesia
CNOOC NWS Private Limited	Singapore	SG$2	100%	Offshore petroleum exploration, development and production in Australia
CNOOC Exploration &      Production Nigeria      Limited	Nigeria	NGN10 million	100%	Petroleum exploration, development and production in Africa

1.        CORPORATE INFORMATION (continued)

Name of entity	Place of establishment	Nominal value of ordinary shares issued and paid-up/registered capital	Percentage of equity attributable to the Group	Principal activities
Indirectly held subsidiaries (continued)(1):
CNOOC Iraq Limited	British Virgin Islands	US$1	100%	Providing services of petroleum exploration and development in the Republicof Iraq
CNOOC Canada Energy Ltd.	Canada	100 common shares without a par value 103,000 preferred shares without a par value	100%	Oil sands exploration,   development and production in Canada
CNOOC Uganda Ltd	Uganda	1 million Uganda Shilling	100%	Petroleum exploration, development and production in Africa
Nexen Energy ULC	Canada	13,671,421,700 common shares without a par value	100%	Petroleum exploration, development and production in Canada
Nexen Petroleum U.K. Limited	England and Wales	GBP98,009,131	100%	Petroleum exploration, development and production in the UK
Nexen Petroleum Nigeria Limited	Nigeria	NGN30 million	100%	Petroleum exploration, development and production in Nigeria
OOGC America LLC	USA	N/A	100%	Petroleum exploration, development and production in the USA
Nexen Petroleum Offshore U.S.A. Inc.	USA	US$15,830	100%	Petroleum exploration, development and production in the USA
Nexen Oil Sands Partnership	Canada	N/A	100%	Petroleum exploration, development and production in Canada
CNOOC PETROLEUM BRASIL LTDA(2)	Brazil	R$2,965,600,000	100%	Petroleum exploration, development and production in Brazil
CNOOC Nexen Finance (2014) ULC	Canada	100 common shares without a par value	100%	Bond issuance
CNOOC Finance (2015) U.S.A. LLC	USA	N/A	100%	Bond Issuance
CNOOC Finance (2015) Australia Pty Ltd	Australia	US$1	100%	Bond Issuance

(1)All subsidiaries are indirectly held through CNOOC International Limited, except CNOOC Deepwater Development Limited which is indirectly held through CNOOC China Limited.

(2)The registered capital of CNOOC PETROLEUM BRASIL LTDA increased from R$2,436,000,000 to R$2,965,600,000 on 20 June 2017.

The above table lists the subsidiaries of the Company which, in the opinion of the Directors, principally affected the results for the year or formed a substantial portion of the total assets of the Group. To give details of other subsidiaries would, in the opinion of the Directors, result in particulars of excessive length.

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STATEMENT OF COMPLIANCE

12 Months Ended

Dec. 31, 2017

STATEMENT OF COMPLIANCE [abstract]

Disclosure of statement of compliance

2.1       STATEMENT OF COMPLIANCE

These financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRSs") issued by the International Accounting Standards Board (the "IASB"), Hong Kong Financial Reporting Standards ("HKFRSs") issued by the Hong Kong Institute of Certified Public Accountants (the "HKICPA"), the Rules Governing the Listing of Securities on The Stock Exchange of Hong Kong Limited (the "Listing Rules") and the Hong Kong Companies Ordinance (Cap. 622). A summary of the significant accounting policies adopted by the Group is set out below.

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CHANGES IN ACCOUNTING POLICY AND DISCLOSURES

12 Months Ended

Dec. 31, 2017

CHANGES IN ACCOUNTING POLICY AND DISCLOSURES [abstract]

Disclosure of changes in accounting policy and disclosures

2.2      CHANGES IN ACCOUNTING POLICY AND DISCLOSURES

The IASB has issued a number of new and revised IFRSs that are first effective for the current accounting year commencing January1, 2017 or later but available for early adoption. The equivalent new and revised HKFRSs consequently issued by the HKICPA have the same effective dates as those issued by the IASB and are in all material aspects identical to the pronouncements issued by the IASB.

The accounting policies adopted are consistent with those of the year ended December31, 2016, except for the first time adoption of the amendments to IFRSs/HKFRSs effective for the Group’s financial year beginning on January 1, 2017. The adoption of the amendments had no material impact on the accounting policies, the disclosures or the amounts recognized in the consolidated financial statements of the Group. IFRS 9/HKFRS 9 (2009) Financial Instruments has been early adopted by the Company from year 2015.

The Group has not applied the following new and revised IFRSs/HKFRSs, which may be relevant to the Group and have been issued but are not yet effective, in these consolidated financial statements:

IFRS 9/HKFRS 9                                                Financial Instruments¹

IFRS 15/HKFRS 15                                             Revenue from Contracts with Customers and the

related Amendments ¹

IFRS 16/HKFRS 16                                              Leases²

IFRS 17/HKFRS 17                                              Insurance Contracts⁴

IFRIC 22/HK(IFRIC)-Int 22                                Foreign Currency Transactions and Advance

                                                                         Consideration¹

IFRIC 23/HK(IFRIC)-Int 23                                Uncertainty over Income Tax Treatments²

Amendments to IFRS 2/HKFRS 2                       Classification and Measurement of Share-based

                                                                         Payment Transactions¹

Amendments to IFRS 4/HKFRS 4                       Applying IFRS 9/HKFRS 9 Financial Instruments

                                                                         with IFRS 4/HKFRS 4 Insurance Contracts¹

Amendments to IFRS 9/HKFRS 9                       Prepayment Features with Negative Compensation²

Amendments to IFRS 10/HKFRS 10                 Sale or Contribution of Assets between an

  and IAS 28/HKAS 28                                         Investor and its Associate or Joint Venture³

Amendments to IAS 19                                        Plan Amendment, Curtailment or Settlement²

Amendments to IAS 28/HKAS 28                       Long-term Interests in Associates and Joint

Ventures²

Amendments to IAS 28/HKAS 28                       As part of the Annual Improvements to IFRS

Standards/HKFRSs 2014-2016 Cycle¹

Amendments to IAS 40/HKAS 40                       Transfers of Investment Property¹

Amendments to IFRSs/HKFRSs                           Annual Improvements to IFRS Standards/

                                                                                HKFRSs 2015-2017 Cycle²

1.    Effective for annual periods beginning on or after 1 January 2018, except for the 2009 version of IFRS 9/HKFRS 9, which the Group adopted in advance

2.    Effective for annual periods beginning on or after 1 January 2019

3.    Effective for annual periods beginning on or after a date to be determined

4.    Effective for annual periods beginning on or after 1 January 2021

2.2      CHANGES IN ACCOUNTING POLICY AND DISCLOSURES (continued)

IFRS 15/HKFRS 15 Revenue from Contracts with Customers

IFRS 15/HKFRS 15 Revenue from Contracts with Customers provides a single model for accounting for revenue arising from contracts with customers, focusing on the identification and satisfaction of performance obligations, and is effective for annual periods beginning on or after 1 January 2018. IFRS 15/HKFRS 15 will supersede IAS 18/HKAS 18 Revenue.

The Company expects to adopt the new revenue standard as of 1 January 2018 using the modified retrospective transition method. Based on our assessment, the Company does not expect the implementation of the standard to have a material effect on its consolidated financial statements.

IFRS 16/HKFRS 16 Leases

IFRS 16/HKFRS 16, which upon the effective date will supersede IAS 17/HKAS 17 Leases, introduces a single lessee accounting model and requires a lessee to recognize assets and liabilities for all leases with a term of more than 12 months, unless the underlying asset is of low value. Specifically, under IFRS 16/HKFRS 16, a lessee is required to recognize a right-of-use asset representing its right to use the underlying leased asset and a lease liability representing its obligation to make lease payments. Accordingly, a lessee should recognize depreciation of the right-of-use asset and interest on the lease liability, and also classify cash payments of the lease liability into a principal portion and an interest portion and present them in the consolidated statement of cash flows. Also, the right-of-use asset and the lease liability are initially measured on a present value basis. The measurement includes non-cancellable lease payments and also includes payments to be made in optional periods if the lessee is reasonably certain to exercise an option to extend the lease, or not to exercise an option to terminate the lease. This accounting treatment is significantly different from the lessee accounting for leases that are classified as operating leases under IAS 17/HKAS 17.

In respect of the lessor accounting, IFRS 16/HKFRS 16 substantially carries forward the lessor accounting requirements in IAS 17/HKAS 17. Accordingly, a lessor continues to classify its leases as operating leases or finance leases, and to account for these two types of leases differently.

The Group is in the process of assessing the impact of application of IFRS 16/HKFRS 16. For the moment, it is not practicable to provide a reasonable estimate of the effect of the application of IFRS 16/HKFRS 16 until the Group completes a detail review.

The Group anticipates that the application of other new and revised IFRSs/HKFRSs that have been issued but are not yet effective will have no material effect on the Group’s consolidated financial statements.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2017

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [abstract]

Disclosure of summary of significant accounting policies

3.         SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of preparation

These consolidated financial statements have been prepared under the historical cost convention, except for as detailed in the accounting policies notes hereafter. These consolidated financial statements are presented in Renminbi ("RMB") and all values are rounded to the nearest million except when otherwise indicated.

Basis of consolidation

The consolidated financial statements include the financial statements of the Company and its subsidiaries for the year ended December 31, 2017.

The results of subsidiaries are consolidated from the date of acquisition, being the date on which the Group obtains control, and continue to be consolidated until the date that such control ceases. The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.

The results of subsidiaries are included in the Company's statement of profit or loss and other comprehensive income to the extent of dividends received and receivable. The Company's interests in subsidiaries are stated at cost less any impairment losses.

All intra-group balances, income and expenses and unrealized gains and losses and dividends resulting from intra-group transactions are eliminated in full.

3.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Business combinations and goodwill

Business combinations 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 the Group, liabilities assumed by the Group to the former owners of the acquiree and the equity interests issued by the Group in exchange for control of the acquiree.  For each business combination, the Group elects whether it measures 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 related costs incurred are included in profit or loss.

When the Group acquires a business, it assesses the financial assets acquired and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree.

If the business combination is achieved in stages, the Group's previously held equity interest in the acquiree is remeasured to fair value at the acquisition date through profit or loss.

Any contingent consideration to be transferred by the acquirer is recognized at fair value at the acquisition date. Contingent consideration classified as an asset or liability is measured at subsequent reporting dates in accordance with IFRS 9/HKFRS 9 (2009) or IAS 39/HKAS 39, with the corresponding gain or loss being recognized in profit or loss. Contingent consideration that is classified as equity is not remeasured and subsequent settlement is accounted for within equity.

Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the amount recognized for non-controlling interests and any fair value of the Group's previously held equity interests in the acquiree over the identifiable net assets acquired and liabilities assumed. If the sum of this consideration and other items is lower than the fair value of the net assets of the business acquired, the difference is recognized in profit or loss as a gain on bargain purchase.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Business combinations and goodwill(continued)

After initial recognition, goodwill is measured at cost less any accumulated impairment losses.  Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the carrying value may be impaired. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group's cash-generating units, or groups of cash-generating units, that are expected to benefit from the synergies of the combination, irrespective of whether other assets or liabilities of the Group are assigned to those units or groups of units.

Impairment is determined by assessing the recoverable amount of the exploration and production ("E&P") segment, using value in use, to which the goodwill relates. Where the recoverable amount of the cash-generating unit (group of cash-generating units) is less than the carrying amount, an impairment loss on goodwill is recognized. An impairment loss recognized for goodwill is not reversed in a subsequent period.

Where goodwill has been allocated to a cash-generating unit (or group of cash-generating units) and part of the operation within that unit is disposed of, the goodwill associated with the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on the disposal. Goodwill disposed of in these circumstances is measured based on the relative value of the operation disposed of and the portion of the cash-generating unit retained.

Subsidiaries

Subsidiaries are all those entities over which the Group has power over the investee such that the Group is able to direct the relevant activities, has exposure or rights to variable returns from its involvement with the investee and has the ability to use its power over the investee to affect the amount of the investor's returns.

Associates

Based on the Group's ownership percentage (considering its direct ownership as well as potentially exercisable or convertible shares) and other contractual rights, the Group has significant influence over its associates, rather than the power to control.

The Group's investments in associates are stated in the consolidated statement of financial position at the Group's share of net assets under the equity method of accounting, less any impairment losses. Adjustments are made to bring into line any dissimilar accounting policies that may exist. Under the equity method, an investment in an associate is initially recognized in the consolidated statement of financial position at cost and adjusted thereafter to recognize the Group's share of the profit or loss and other comprehensive income of the associate. Unrealized gains and losses resulting from transactions between the Group and its associates are eliminated to the extent of the Group's investments in the associates, except where unrealized losses provide evidence of an impairment of the asset transferred. Goodwill arising from the acquisition of associates is included as part of the Group's investments in associates and is not individually tested for impairment.

Joint arrangements

Certain of the Group's 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 control

Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Joint arrangements (continued)

Joint operations

Some arrangements have been assessed by the Group 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 the Group's interests in production sharing arrangements and certain joint operation.

The Group entered into numerous production sharing arrangements or similar agreements in China and overseas countries. The Group's participating interest may vary in each arrangement. The Group, as one of the title owners under certain exploration and/or production licenses or permits, is required to bear exploration (with some exceptions in China), development and operating costs together with other co-owners based on each owner's participating interest. Once production occurs, a certain percentage of the annual production or revenue is first distributed to the local government, which, in most cases, with the nature of royalty and other taxes or expenses, and the rest of the annual production or revenue is allocated among the co-owners.

The Group accounts for the assets, liabilities, revenues and expenses relating to its interest in a joint operation in accordance with the IFRSs/HKFRSs applicable to the particular assets, liabilities, revenues and expenses.

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.

The Group's investments in joint ventures are stated in the consolidated statement of financial position at the Group's share of net assets under the equity method of accounting, less any impairment losses. Adjustments are made to bring into line any dissimilar accounting policies that may exist. Under the equity method, an investment in a joint venture is initially recognized in the consolidated statement of financial position at cost and adjusted thereafter to recognize the Group's share of the profit or loss and other comprehensive income of the joint venture. Where the profit sharing ratios are different to the Group's equity interest, the share of post-acquisition results of the joint ventures is determined based on the agreed profit sharing ratio. Unrealized gains and losses resulting from transactions between the Group and its joint ventures are eliminated to the extent of the Group's investments in the joint ventures, except where unrealized losses provide evidence of an impairment of the asset transferred. Goodwill arising from the acquisition of joint ventures is included as part of the Group's investments in joint ventures and is not individually tested for impairment.

Related parties

A party is considered to be related to the Group if:

(a)the party is a person or a close member of that person's family and that person

(i)has control or joint control of the Group;

(ii)has significant influence over the Group; or

(iii)is a member of the key management personnel of the Group or of a parent of the Group;

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Related parties (continued)

(b)the party is an entity where any of the following conditions applies:

(i)the entity and the Group are members of the same group;

(ii)one entity is an associate or joint venture of the other entity (or of a parent, subsidiary or fellow subsidiary of the other entity);

(iii)the entity and the Group are joint ventures of the same third party;

(iv)one entity is a joint venture of a third entity and the other entity is an associate of the third entity;

(v)the entity is a post-employment benefit plan for the benefit of employees of either the Group or an entity related to the Group;

(vi)the entity is controlled or jointly controlled by a person identified in (a); and

(vii)a person identified in (a)(i) has significant influence over the entity or is a member of the key management personnel of the entity (or of a parent of the entity).

Impairment of non-financial assets other than goodwill

Where an indication of impairment exists, or when annual impairment testing for an asset is required (other than inventories, deferred tax assets, financial assets and goodwill), the asset's recoverable amount is estimated. An asset's recoverable amount is the higher of the asset's or cash-generating unit's value in use and its fair value less costs of disposal, and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets, in which case the recoverable amount is determined for the cash-generating unit to which the asset belongs.

An impairment loss is recognized only if the carrying amount of an asset exceeds its recoverable amount. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. An impairment loss is charged to profit or loss in the period in which it arises in those expense categories consistent with the function of the impaired asset.

An assessment is made at the end of each reporting period as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss of an asset other than goodwill is reversed only if there has been a change in the estimates used to determine the recoverable amount of that asset, but not to an amount higher than the carrying amount that would have been determined (net of any depreciation/amortization) had no impairment loss been recognized for the asset in prior years. A reversal of such an impairment loss is credited to profit or loss in the period in which it arises.

Property, plant and equipment

Property, plant and equipment comprise oil and gas properties, and vehicles and office equipment and others.

(a)Oil and gas properties

For oil and gas properties, the successful efforts method of accounting is adopted. The Group capitalizes the initial acquisition costs of oil and gas properties. Impairment of initial acquisition costs is recognized based on exploratory experience and management judgement and charged to profit and loss as exploration expenses. Upon discovery of commercial reserves, acquisition costs are transferred to proved properties. The costs of drilling and equipping successful exploratory wells, all development expenditures 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 are capitalized. The costs of unsuccessful exploratory wells and all other exploration costs are expensed as incurred.

3.         SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Property, plant and equipment(continued)

(a)Oil and gas properties (continued)

The Group carries exploratory well costs as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Group is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expenses. Exploratory wells that discover potentially economic reserves in areas where major capital expenditure will be required before production would begin and when the major capital expenditure depends upon the successful completion of further exploratory work remain capitalized and are reviewed periodically for impairment.

Producing oil and gas properties are depreciated on a unit-of-production basis over the proved developed reserves. Common facilities that are built specifically to service production directly attributed to designated oil and gas properties are depreciated 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.

Capitalized acquisition costs of proved properties are depreciated on a unit-of-production method over the total proved reserves of the relevant oil and gas properties.

(b)Vehicles, office equipment and others

Vehicles, office equipment and others are stated at cost less accumulated depreciation and impairment losses. The straight-line method is adopted to depreciate the cost less any estimated residual value of these assets over their expected useful lives. The useful lives of vehicles, office equipment and other assets are in line with their beneficial periods.

Where parts of an item of property, plant and equipment have different useful lives, the cost of that item is allocated on a recoverable basis among the parts and each part is depreciated separately.

Residual values, useful lives and the depreciation method are reviewed and, adjusted if appropriate, at each reporting date.

Any gains and losses on disposals of property, plant and equipment (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) are recognized in profit or loss.

Intangible assets (other than goodwill)

The intangible assets of the Group comprise software, gas processing rights of the NWS Project, marketing transportation and storage contracts, drilling rig contracts and seismic data usage rights. Intangible assets with finite lives are carried at cost, less accumulated amortization and accumulated impairment losses. The cost of intangible assets acquired in a business combination is the fair value as at the date of acquisition. Intangible assets with finite lives except for gas processing rights, are amortized on the straight-line basis over the useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization period and the amortization method for an intangible asset with a finite useful life are reviewed at least at each financial year end.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Intangible assets (other than goodwill) (continued)

The intangible assets regarding software have been amortized on the straight-line basis over their respective useful lives. The intangible asset regarding the gas processing rights has been amortized upon the commercial production of the liquefied natural gas on a unit-of-production basis over the total proved reserves of the relevant asset. The intangible assets regarding the marketing transportation and storage contracts and drilling rig contracts are amortized over the life of the contracts on the straight-line basis. The intangible assets related to the seismic data usage rights are amortized over the estimated useful life of the seismic data.

Major maintenance and repairs

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets and overhaul costs. Where an asset or part of an asset that was separately depreciated and is replaced, and it is probable that future economic benefits associated with the item will flow to the Group, the replacement expenditure is capitalized. Where part of the asset was not separately considered as a component, the replacement value is used to estimate the carrying amount of the replaced assets which is immediately written off. All other maintenance costs are expensed as incurred.

Research and development costs

All research costs are expensed as incurred.

Expenditure (other than that relating to oil and gas properties discussed above) incurred on projects to develop new products is capitalized and deferred only when the Group can demonstrate the technical feasibility of completing the intangible asset so that it will be available for use or sale, its intention to complete and its ability to use or sell the asset, how the asset will generate future economic benefits, the availability of resources to complete the project and the ability to measure reliably the expenditure during the development. Product development expenditure which does not meet these criteria is expensed when incurred.

Financial assets

All recognized financial assets are subsequently measured in their entirety at either amortized cost or fair value, depending on the classification of the financial assets.

(a)Financial assets at amortized cost

Debt instruments and hybrid contracts that meet the following conditions are subsequently measured at amortized cost less impairment loss:

•  the asset is held within a business model whose objective is to hold assets in order to collect contractual cash flows; and

•  the contractual terms of the instrument give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

All other financial assets are subsequently measured at fair value.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Financial assets (continued)

(a)Financial assets at amortized cost (continued)

The effective interest method is a method of calculating the amortized cost of a debt instrument and of allocating interest income over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees and points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the debt instrument, or, where appropriate, a shorter period, to the net carrying amount on initial recognition. Interest income for debt instruments measured subsequently at amortized cost is recognized in profit or loss in accordance with the policies set out for "Revenue Recognition" below.

(b)Financial assets at fair value through profit or loss (FVTPL)

Investments in equity instruments are classified as at FVTPL, unless the Group designates such investment that is not held for trading as at FVTOCI on initial recognition.

A financial asset is held for trading if it has been acquired principally for the purpose of selling it in the near term or it is a derivative that is not designated and effective as a hedging instrument.

Debt instruments that do not meet the amortized cost criteria (see (a) above) are measured at FVTPL. In addition, debt instruments that meet the amortized cost criteria but are designated as at FVTPL are measured at FVTPL. A debt instrument may be designated as at FVTPL upon initial recognition if such designation eliminates or significantly reduces a measurement or recognition inconsistency that would arise from measuring assets or liabilities or recognizing the gains and losses on them on different bases.

Financial assets at FVTPL are measured at fair value at the end of each reporting period, with any gains or losses arising on remeasurement recognized in profit or loss.

(c)Financial assets at fair value through other comprehensive income (FVTOCI)

On initial recognition, the Group can make an irrevocable election (on an instrument-by-instrument basis) to designate investments in equity instruments as at FVTOCI.  The Group has investments in certain equity instruments (publicly traded or non-publicly traded), the purpose of which are not held for trading, but held for medium or long-term strategic purpose. Therefore, those investments in equity securities are designated as at FVTOCI.

Investments in equity instruments at FVTOCI are initially measured at fair value plus transaction costs. Subsequently, they are measured at fair value with gains and losses arising from changes in fair value recognized in other comprehensive income and accumulated in the other reserves. The cumulative gain or loss will not be reclassified to profit or loss on disposal of the investments.

Dividends on these investments in equity instruments are recognized in profit or loss when the Group’s right to receive the dividends is established in accordance with IAS 18/HKAS 18 Revenue, unless the dividends clearly represent a recovery of part of the cost of the investment.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

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.

An analysis of fair values of financial instruments and further details as to how they are measured are provided in note 32.

Impairment of financial assets

The Group assesses at each reporting date whether there is any objective evidence that a financial asset, other than those at FVTPL and FVTOCI, or a group of financial assets may be impaired.

In relation to trade and other receivables, a provision for impairment is made when there is objective evidence (such as the probability of insolvency or significant financial difficulties of the debtor and significant changes in the technological, market, economic or legal environment that have an adverse effect on the debtor) that the Group will not be able to collect all of the amounts due under the original terms of an invoice.

If there is objective evidence that an impairment loss on financial assets measured at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset's carrying amount and the present value of estimated future cash flows (excluding future credit losses that have not been incurred) discounted at the financial asset's original effective interest rate (the effective interest rate computed at initial recognition). The carrying amount of the asset is reduced either directly or through the use of an allowance account. The amount of the impairment loss is recognized in profit or loss.

If, in a subsequent year, the amount of the estimated impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized, the previously recognized impairment loss is reduced either directly or by adjusting the allowance account. Any subsequent reversal of an impairment loss is recognized in profit or loss, to the extent that the carrying value of the asset does not exceed amortized cost at the reversal date.

Derecognition of financial assets

A financial asset (or, where applicable a part of a financial asset or part of a group of similar financial assets) is derecognized when:

(i)The contractual rights to receive cash flows from the asset have expired; or

(ii)the Group has transferred its rights to receive cash flows from the asset, or the Group retains the contractual rights to receive the cash flows from the asset, but has assumed an obligation to pay the received cash flows in full without material delay to a third party under a "pass-through" arrangement; and either (a) has transferred substantially all the risks and rewards of the asset, or (b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has no control of the asset.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Derecognition of financial assets(continued)

When the Group has transferred its rights to receive cash flows from an asset or has entered into a pass-through arrangement, it evaluates if and to what extent it has retained the risk and rewards of ownership of the asset. When it has neither transferred nor retained substantially all the risks and rewards of the asset nor transferred control of the asset, the Group continues to recognize the transferred asset to the extent of the Group's continuing involvement. In that case, the Group also recognizes an associated liability. The transferred asset and the associated liability are measured on a basis that reflects the rights and obligations that the Group has retained.

Financial liabilities at amortized cost (including interest-bearing loans and borrowings)

Financial liabilities including trade and accrued payables, other payables and accrued liabilities, and interest-bearing loans and borrowings are initially stated at fair value less directly attributable transaction costs and are subsequently measured at amortized cost, using the effective interest method. The related interest expense is recognized in profit or loss.

Gains and losses are recognized in profit or loss when the liabilities are derecognized as well as through the amortization process.

Financial guarantee contracts

A financial guarantee contract is recognized initially at its fair value including transaction costs that are directly attributable to the issue of the guarantee. Subsequent to initial recognition, the liability is measured at the higher of the best estimate of the expenditure required to settle the present obligation at the reporting date and the amount recognized less cumulative amortization.

Derecognition of financial liabilities

Financial liabilities are derecognized when the obligations under the liabilities are discharged, cancelled, or have expired.

When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and a recognition of a new liability, and the difference between the respective carrying amounts is recognized in profit or loss.

Offsetting of financial instruments

Financial assets and liabilities are offset and the net amount reported in the consolidated statement of financial position, if and only if, there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, or to realize the assets and settle the liabilities simultaneously.

Inventories and supplies

Inventories primarily consist of oil and supplies, including items for repairs and maintenance of oil and gas properties. Inventories are stated at the lower of cost and net realizable value. Costs of inventories and supplies represent purchase or production cost of goods and are determined on a weighted average basis.

Cash and cash equivalents

Cash and cash equivalents comprise cash at banks and on hand and short term deposits with an original maturity of three months or less.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Provisions

(a)General

A provision is recognized 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.

(b)Dismantlement liability

Dismantlement liability is recognized when the Group has a present legal or constructive obligation as a result of the past events, and it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of the obligation can be made. A corresponding amount equivalent to the provision is also recognized as part of the cost of the related property, plant and equipment. The amount recognized is 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. The unwinding of the discount on the dismantlement provision is included as a finance cost.

Income tax

Income tax comprises current and deferred tax. Income tax is recognized in the consolidated statement of profit or loss and other comprehensive income, either as an expense as it relates to operating activities or as a component of the applicable categories of other comprehensive income or expense.

Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantially enacted, by the reporting date, in the countries where the Group operates and generates taxable income.

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 the accounting profit nor taxable profit or loss; and

·in respect of taxable temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, 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.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Income tax (continued)

Deferred tax assets are recognized for all deductible temporary differences, the carryforward of unused tax credits and any unused tax losses to the extent that it is probable that taxable profit and taxable temporary differences will be available against which the deductible temporary differences, the carryforward of unused tax credits and unused tax losses can be utilized, except:

·when the deferred tax assets relating to the deductible temporary differences arise 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 the accounting profit nor taxable profit or loss; and

·in respect of deductible temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, deferred tax assets are only recognized to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized.

The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized. Unrecognized deferred tax assets are reassessed at each reporting date and are recognized to the extent that it is probable that sufficient taxable profit and taxable temporary differences will be available to allow all or part of the deferred tax asset to be utilized.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the reporting date.

Deferred tax assets and deferred tax liabilities are offset if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority.

Revenue recognition

Revenue is recognized when it is probable that the economic benefits will flow to the Group and when the revenue can be measured reliably, on the following bases:

(a)Oil and gas sales

Oil and gas sales represent the invoiced value of sales of oil and gas attributable to the interests of the Group, net of royalties, obligations to governments and other mineral interest owners. Revenue from the sale of oil and gas is recognized when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. Revenue from the production of oil and gas in which the Group has a joint interest with other producers is recognized based on the Group’s working interest and the terms of the relevant production sharing contracts. Differences between production sold and the Group’s share of production are not significant.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Revenue recognition (continued)

(a)Oil and gas sales (continued)

Oil and gas lifted and sold by the Group above or below the Group's participating interests in the production sharing contracts results in overlifts and underlifts. The Group records these transactions in accordance with the entitlement method under which overlifts are recorded as liabilities and underlifts are recorded as assets at year-end oil prices. Settlement will be in kind or in cash when the liftings are equalised or in cash when production ceases.

The Group has entered into gas sale contracts with customers, which contain take-or-pay clauses. Under these contracts, the Group makes a long term supply commitment in return for a commitment from the buyer to pay for minimum quantities, whether or not it takes delivery. These commitments contain protective (force majeure) and adjustment provisions. If a buyer has a right to get a "make up" delivery at a later date, revenue recognition is deferred. If no such option exists according to the contract terms, revenue is recognized when the take-or-pay penalty is triggered.

(b)Marketing revenues

Marketing revenues principally represent the sales of oil and gas from the foreign partners under the production sharing contracts and revenues from the trading of oil and gas through the Company’s subsidiaries. The cost of the oil and gas sold is included in “Crude oil and product purchases” in the consolidated statement of profit or loss and other comprehensive income. In addition, the Group’s marketing activities in North America involves entering into contracts to purchase and sell crude oil, natural gas and other energy commodities, and use derivative contracts, including futures, forwards, swaps and options for hedging and trading purposes (collectively derivative contracts). Any change in the fair value is also included in marketing revenue.

(c)Other income

Other income mainly represents project management fees charged to foreign partners, handling fees charged to customers, the sales of diluents to third parties and gains from disposal of oil and gas properties and is recognized when the services have been rendered or the properties have been disposed of. Reimbursement of insurance claims is recognized when the compensation becomes receivable.

(d)Dividend income

Dividend income is recognized when the Group's right to receive payment is established.

(e)Interest income

Interest income is recognized as it accrues using the effective interest method.

The Group presents taxes collected from customers in the consolidated statement of profit or loss and other comprehensive income on a net basis.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Share-based payment transactions

Employees (including directors) of the Group receive remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments ("equity-settled transactions").

The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which they are granted. The fair value is determined by using the Black-Scholes option pricing model, further details of which are given in note 26.

The cost of equity-settled transactions is recognized, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled. The cumulative expense recognized for equity-settled transactions at the end of the each reporting period until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The charge or credit to profit or loss for a period represents the movement in the cumulative expense recognized as at the beginning and end of that period.

No expense is recognized for awards that do not ultimately vest for the Group.

No equity-settled award was cancelled or modified during the years ended December 31, 2015, 2016 and 2017.

The dilutive effect of outstanding options is reflected as additional share dilution in the computation of earnings per share.

Retirement and termination benefits

The Group participates in defined contribution plans in accordance with local laws and regulations for full-time employees in the PRC and other countries in which it operates. The Group's contributions to these defined contribution plans are charged to profit or loss in the year to which they relate.

Borrowing costs

Borrowing costs consist of interest and other costs that an entity incurs in connection with the borrowing of funds. Borrowing costs directly relating to the acquisition, construction or production of a qualifying asset that necessarily takes a substantial period of time to get ready for its intended use or sale are capitalized as part of the cost of the respective assets. All other borrowing costs are expensed in the period in which they are incurred.

Foreign currencies

These consolidated financial statements are presented in RMB. Each entity in the Group maintains its books and records in its own functional currency. Foreign currency transactions recorded by the entities of the Group are initially recorded using their respective exchange rates ruling at the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are retranslated at the exchange rates ruling at the end of the reporting period. All differences arising on settlement or translation of monetary items are taken to profit or loss. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rates at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined. The gain or loss arising on retranslation of a non-monetary item is treated consistently with the recognition of the gain or loss on change in fair value of the item.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Foreign currencies (continued)

The functional currencies of certain entities within the Group are currencies other than RMB. As at the end of the reporting period, the assets and liabilities of these entities are translated into the presentation currency of the Group at the exchange rates ruling at the reporting date, and their statement of profit or loss and other comprehensive income are translated into RMB at the weighted average exchange rates for the year. The resulting exchange differences are included in the cumulative translation reserve. On disposal of a foreign operation, the deferred cumulative amount recognized in equity relating to that particular foreign operation is recognized in profit or loss.

Operating leases

Leases where substantially all the rewards and risks of ownership of assets remain with the lessor are accounted for as operating leases. Where the Group is the lessee, rentals payable under operating leases are charged to profit or loss on the straight-line basis over the lease terms.

Prepaid land lease payments under operating leases in China are initially stated at cost and subsequently amortized on the straight-line basis over the lease terms.

Contingencies

A contingent liability is disclosed when the existence of an obligation will only be confirmed by future events or when the amount of the obligation cannot be measured reliably.

A contingent asset is not recognized in the financial statements, but is disclosed when an inflow of economic benefits is probable.

Significant accounting judgements, estimates and assumptions

The preparation of the consolidated financial statements in accordance with IFRSs and HKFRSs requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates and judgements are continuously evaluated and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. However, actual outcomes can differ from these estimates.

In the process of applying the Group's accounting policies, the Directors have made the following judgements, estimates and assumptions, which have the most significant effect on the amounts recognized in the consolidated financial statements.

(a)Reserve base

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

Pursuant to the oil and gas reserve estimation requirements under US Securities and Exchange Commission's rules, the Group uses 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 its proved oil and gas reserves.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Significant accounting judgements, estimates and assumptions(continued)

(b)Carrying value of oil and gas properties

The calculation of the unit-of-production rate for oil and gas properties amortization could be impacted to the extent that actual production in the future is different from current forecast production based on proved reserves. This would generally result from significant changes in any of the factors or assumptions used in estimating reserves. These factors could include changes in proved reserves, the effect on proved reserves of differences between actual oil and gas prices and oil and gas price assumptions and unforeseen operational issues.

(c)Recoverable amount of oil and gas properties

The Company makes 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, the Company would make an estimate of the asset’s recoverable amount, which is calculated at the higher of the asset’s value in use and its fair value less costs of disposal. The Company recognizes an impairment loss only if the carrying amount of an asset exceeds its recoverable amount. The Company charges an impairment loss to the profit or loss in the period in which it arises. A reversal of an impairment loss is credited to the profit or loss 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 oil and gas 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 the Company's anticipated drilling plan, changes in the Company's capital costs and operating expense assumptions, and discount rate. There is a significant degree of uncertainty with the assumptions used to estimate future cash flows due to various risk factors. The complex economic outlook may also materially and adversely affect the Company’s key assumptions. Changes in economic conditions can also affect the discount rates applied in assessments of impairment.

Actual cash flows are likely to be different from those estimated or forecast since anticipated events frequently do not occur as expected and unforeseen events may arise. The Company's results of operations could be materially and adversely affected for the period in which future 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, the Company believes that the preparation of the sensitivity analysis for the impairment testing will be impracticable. Changes in assumptions could affect impairment charges and reversals in the consolidated statement of profit or loss and other comprehensive income, and the carrying amounts of assets in the consolidated statement of financial position.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Significant accounting judgements, estimates and assumptions(continued)

(d)Dismantlement costs

Dismantlement costs will be incurred by the Group at the end of the operating life of certain of the Group's facilities and properties. 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.

(e)Taxes

Uncertainties exist with respect to the interpretation of complex tax regulations (including those applicable to tax credits) and the amount and timing of future taxable income. Given the wide range of international business relationships and the long term nature and complexity of existing contractual agreements, differences arising between the actual results and the assumptions made, or future changes to such assumptions, could necessitate future adjustments to tax income and expense already recorded. The Group establishes provisions, based on best estimates, for possible consequences of audits by the tax authorities of the respective countries in which it operates. The amount of such provisions is based on various factors, such as the Group's experience of previous tax audits and differing interpretations of tax regulations by the taxable entity and the responsible tax authority. Such differences of interpretation may arise on a wide variety of issues depending on the conditions prevailing in the respective group company's domicile.

XML

OIL AND GAS SALES

12 Months Ended

Dec. 31, 2017

OIL AND GAS SALES [abstract]

Disclosure of oil and gas sales

4.        OIL AND GAS SALES

	2015	2016	2017
Gross sales	150,618	124,648	156,304
Less: Royalties	(2,646)	(2,398)	(3,226)
PRC government’s share of oil	(1,375)	(925)	(1,190)
Oil and gas sales	146,597	121,325	151,888

XML

SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2017

SEGMENT INFORMATION [abstract]

Disclosure of segment information

5.        SEGMENT INFORMATION

(a)Segment results

The Group is engaged worldwide in the upstream operating activities of the conventional oil and gas, shale oil and gas, oil sands and other unconventional oil and gas business. The Group reports the business through three operating and reporting segments: E&P, trading business and corporate. These segments are operating segments whose financial information are reviewed by the Group’s chief operating decision marker when making decisions regarding allocating resources and assessing performance. The geographical information is separately disclosed in (b).

5         SEGMENT INFORMATION (continued)

(a)Segment results (continued)

The following table presents the segment financial information for the Group for the years ended December 31, 2015, 2016 and 2017.

	E&P			Trading business			Corporate			Eliminations			Consolidated
	2015	2016	2017	2015	2016	2017	2015	2016	2017	2015	2016	2017	2015	2016	2017
External revenue	137,243	114,935	142,429	33,777	30,986	43,618	417	569	343	-	-	-	171,437	146,490	186,390
Intersegment revenue*	12,339	10,676	14,737	(12,339)	(10,676)	(14,737)	85	113	84	(85)	(113)	(84)	-	-	-
Total revenue	149,582	125,611	157,166	21,438	20,310	28,881	502	682	427	(85)	(113)	(84)	171,437	146,490	186,390
Segment profit/(loss) for the year	15,695	(346)	23,863	879	656	808	6,048	30,701	6,391	(2,376)	(30,374)	(6,385)	20,246	637	24,677
Amounts included in the measure of        segment profit or loss
Operating expenses	(28,372)	(23,220)	(24,282)	-	-	-	-	-	-	-	9	-	(28,372)	(23,211)	(24,282)
Taxes other than income tax	(10,748)	(6,901)	(7,169)	7	-	-	(29)	(40)	(41)	-	-	-	(10,770)	(6,941)	(7,210)
Exploration expenses	(9,973)	(7,393)	(6,896)	-	-	-	-	-	-	73	34	15	(9,900)	(7,359)	(6,881)
Depreciation, depletion and amortization	(72,665)	(68,333)	(60,834)	(324)	(144)	(67)	(509)	(470)	(423)	59	40	67	(73,439)	(68,907)	(61,257)
Impairment and provision	(2,690)	(12,180)	(9,161)	(56)	9	-	-	-	31	-	-	-	(2,746)	(12,171)	(9,130)
Selling and administrative expenses	(3,644)	(4,920)	(4,966)	(340)	(296)	(269)	(1,733)	(1,307)	(1,654)	12	30	28	(5,705)	(6,493)	(6,861)
Interest income	147	217	315	-	1	-	1,028	1,805	1,571	(302)	(1,122)	(1,233)	873	901	653
Finance costs	(3,407)	(3,384)	(3,274)	(1)	(1)	(1)	(3,369)	(4,183)	(3,011)	659	1,322	1,242	(6,118)	(6,246)	(5,044)
Share of profits/(losses) of   associates and a joint venture	(117)	(63)	(88)	-	-	-	2,020	(13)	943	-	-	-	1,903	(76)	855
Income tax (expense)/credit	44	3,811	(11,236)	(8)	(24)	(3)	3,080	2,125	(441)	-	-	-	3,116	5,912	(11,680)
Other segment information
Investments in associates and a joint     venture	800	737	655	-	-	-	27,613	29,258	28,491	-	-	-	28,413	29,995	29,146
Others	532,765	497,413	457,780	3,336	1,898	3,588	344,037	342,810	340,329	(244,189)	(234,435)	(213,624)	635,949	607,686	588,073
Segment assets	533,565	498,150	458,435	3,336	1,898	3,588	371,650	372,068	368,820	(244,189)	(234,435)	(213,624)	664,362	637,681	617,219
Segment liabilities	(364,056)	(331,339)	(301,167)	(2,243)	(947)	(2,375)	(145,475)	(138,352)	(124,794)	233,453	215,328	191,092	(278,321)	(255,310)	(237,244)
Capital expenditure	66,122	49,122	52,790	11	-	-	386	395	421	-	-	-	66,519	49,517	53,211

* Certain oil and gas produced by the E&P segment are sold via the trading business segment. For the Group's chief operating decision maker's assessment of segment performance, these revenues are reclassified back to E&P segment.

5.        SEGMENT INFORMATION (continued)

(b)Geographical information

The Group mainly engages in the exploration, development, production and sale of crude oil, natural gas and other petroleum products in offshore China. Activities outside the PRC are mainly conducted in Canada, the United States of America, the United Kingdom, Nigeria, Argentina, Indonesia, Uganda, Iraq, Brazil and Australia etc.

In presenting the Group’s geographical information, revenues from external customers are based on the location of the Group’s customers, and non-current assets are attributed to the segments based on the location of the Group’s assets. 65% (2016: 70%, 2015: 73%) of the Group’s revenues are generated from PRC customers, and revenues generated from customers in other locations are individually less than 10%.

The following table presents certain non-current assets information for the Group’s geographical information for the years ended December 31, 2015, 2016 and 2017.

	PRC			Canada			Others			Consolidated
	2015	2016	2017	2015	2016	2017	2015	2016	2017	2015	2016	2017
Property, plant and equipment	193,359	174,853	162,027	105,383	103,173	95,552	155,399	154,439	138,289	454,141	432,465	395,868
Investments in associates and a joint venture	3,499	3,451	3,680	816	-	-	24,098	26,544	25,466	28,413	29,995	29,146
Other non-current assets	7,087	6,593	8,502	694	731	605	47	98	141	7,828	7,422	9,248

(c)Information about major customers

The current year's revenue of approximately RMB15,488 million (2016: approximately RMB9,659 million, 2015: approximately RMB14,692 million ) was derived from sales by the E&P segment and the trading business segment to China Petroleum & Chemical Corporation. Sales to CNOOC Group are included in Note 28 (iii).

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PROFIT/(LOSS) BEFORE TAX

12 Months Ended

Dec. 31, 2017

PROFIT/(LOSS) BEFORE TAX [abstract]

Disclosure of profit/(loss) before tax

6.         PROFIT/(LOSS) BEFORE TAX

The Group’s profit/(loss) before tax is arrived at after charging/(crediting):

	2015	2016	2017
Crediting:
Interest income from bank deposits	(873)	(901)	(653)
Investment income:
– Fair value changes on other financial assets	(2,398)	(2,774)	(2,409)
Insurance compensation on disposal of property, plant and equipment	(560)	(520)	(110)
Charging:
Auditors’ remuneration:
– Audit fee	45	47	51
– Other fees	12	6	5
	57	53	56
Employee wages, salaries, allowances and social security costs	6,924	6,403	6,517
Impairment and provision:
- Property, plant and equipment	2,358	10,768	8,639
- Trade receivables	4	1,439	212
- Others	384	(36)	279
	2,746	12,171	9,130
Depreciation, depletion and amortization:
– Property, plant and equipment	72,293	68,303	60,802
– Intangible assets	1,306	1,020	854
– Less: Net amount capitalized	(160)	(416)	(399)
	73,439	68,907	61,257
Operating lease rentals:
– Office properties	438	485	639
– Plant and equipment	2,448	1,747	1,560
	2,886	2,232	2,199
Repairs and maintenance	5,034	4,052	4,800
Research and development costs	1,629	1,424	1,739
Loss on disposal of property, plant and equipment	718	78	116

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FINANCE COSTS

12 Months Ended

Dec. 31, 2017

FINANCIAL COSTS [abstract]

Disclosure of finance costs

7.        FINANCE COSTS

	2015	2016	2017
Interest on bank loans	291	217	169
Interest on other loans	4,701	5,249	5,207
Other borrowing costs	76	25	18
Total borrowing costs	5,068	5,491	5,394
Less: Amount capitalized in property, plant and equipment (note 13)	(1,385)	(1,430)	(2,495)
	3,683	4,061	2,899
Other finance costs:
Unwinding of discount on provision for dismantlement (note 25)	2,435	2,185	2,145
	6,118	6,246	5,044

The effective interest rates used to determine the amount of related borrowing costs for capitalization varied from 0.95% to 7.875% (2016: from 0.7566% to 7.875% , 2015: from 0.735% to 7.875%) per annum during the year ended at December 31, 2017.

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KEY MANAGEMENT PERSONNEL'S REMUNERATION

12 Months Ended

Dec. 31, 2017

KEY MANAGEMENT PERSONNEL'S REMUNERATION [abstract]

Disclosure of key management personnel's remuneration

8.        KEY MANAGEMENT PERSONNEL’SREMUNERATION

Key management personnel are those persons having authority and responsibility for planning, directing and controlling the activities of the entity, directly or indirectly, including any director (whether executive or otherwise) of the Company.

(i)      Directors’ remuneration

		Salaries			Total
		allowances	Performance	Pension	paid/payable
		and benefits	related	scheme	during
	Fees (1)	in kind(1)	bonuses (1)	contributions	the year
	RMB’000	RMB’000	RMB’000	RMB’000	RMB’000
2015
Executive directors:
Li Fanrong(4)	-	170	470	117	757
Wu Guangqi(5)(7)	-	170	470	117	757
Subtotal	-	340	940	234	1,514
Non-executive directors:
Wang Yilin(2)	-	-	-	-	-
Yang Hua(2)(4)(10)	-	-	-	-	-
Lv Bo(7)	-	-	-	-	-
Wang Jiaxiang(3)	-	-	-	-	-
Subtotal	-	-	-	-	-
Independent non-executive
directors:
Chiu Sung Hong	899	-	-	-	899
Lawrence J. Lau	763	-	-	-	763
Tse Hau Yin, Aloysius	899	-	-	-	899
Kevin G. Lynch	763	-	-	-	763
Subtotal	3,324	-	-	-	3,324
Total	3,324	340	940	234	4,838

8.        KEY MANAGEMENT PERSONNEL’SREMUNERATION (continued)

(i)Directors’ remuneration (continued)

		Salaries			Total
		allowances	Performance	Pension	paid/payable
		and benefits	related	scheme	during
	Fees (1)	in kind (1)	bonuses(1)	contributions	the year
	RMB’000	RMB’000	RMB’000	RMB’000	RMB’000
2016
Executive directors:
Yang Hua(2)(4)(10)	-	-	-	-	-
Yuan Guagnyu(4)(8)	-	94	78	70	242
Li Fanrong(4)	-	92	454	59	605
Subtotal	-	186	532	129	847
Non-executive directors:
Liu Jian(6)	-	-	-	-	-
Wu Guangqi(5)(7)	-	92	454	59	605
Lv Bo(7)	-	-	-	-	-
Subtotal	-	92	454	59	605
Independent non-executive
directors:
Chiu Sung Hong	957	-	-	-	957
Lawrence J. Lau	812	-	-	-	812
Tse Hau Yin, Aloysius	957	-	-	-	957
Kevin G. Lynch	812	-	-	-	812
Subtotal	3,538	-	-	-	3,538
Total	3,538	278	986	188	4,990
2017
Executive directors:
Yuan Guangyu(4)(8)	-	197	455	134	786
Xu Keqiang(9)	-	146	162	94	402
Subtotal	-	343	617	228	1,188
Non-executive directors:
Yang Hua(2)(4)(10)	-	-	-	-	-
Liu Jian(6)	-	-	-	-	-
Wu Guangqi(5)(7)	-	-	-	-	-
Subtotal	-	-	-	-	-
Independent non-executive
directors:
Chiu Sung Hong	972	-	-	-	972
Lawrence J. Lau	824	-	-	-	824
Tse Hau Yin, Aloysius	972	-	-	-	972
Kevin G. Lynch	824	-	-	-	824
Subtotal	3,592	-	-	-	3,592
Total	3,592	343	617	228	4,780

8.        KEY MANAGEMENT PERSONNEL’S REMUNERATION (continued)

(i)      Directors’ remuneration (continued)

Notes:

(1)Fees, salaries, allowances,benefits in kind and performance related bonuses represent the gross amount (before applicable individual salary tax) paid/payable to individual directors.

(2)On May 19, 2015, Mr. Yang Hua was appointed as Chairman of the Board and Chairman of the Nomination Committee of the Company and has no longer served as Vice-chairman of the Board. Mr. Wang Yilin resigned as Chairman of the Board, Chairman of the Nomination Committee and non-executive director of the Company.

(3)On September 23, 2015, Mr. Wang Jiaxiang retired as a non-executive director of the Company.

(4)On 15 June 2016, Mr. Yang Hua was re-designated as an Executive Director and appointed as the Chief Executive Officer of the Company. Mr. Yuan Guangyu was appointed as an Executive Director and the President of the Company. Mr. Li Fanrong resigned as an Executive Director, the Chief Executive Officer and the President of the Company.

(5)On 15 June 2016, Mr. Wu Guangqi was re-designated as a Non-executive Director of the Company and resigned as the Compliance Officer of the Company.

(6)On 20December 2016, Mr. Liu Jian was appointed as the Vice Chairman and a Non-executive Director of the Company.

(7)On 20 December 2016, Mr. Wu Guangqi was appointed as a member of the Remuneration Committee of the Company. Mr. Lv Bo resigned as a Non-executive Director and a member of the Remuneration Committee of the Company.

(8)On 18 April 2017, Mr. Yuan Guangyu was appointed as the Chief Executive Officer of the Company. Mr. Yuan Guangyu resigned as the President of the Company.

(9)On 18 April 2017, Mr. Xu Keqiang was appointed as an Executive Director and the President of the Company.

(10)On 18 April 2017, Mr. Yang Hua was re-designated as a Non-executive Director of the Company. Mr. Yang Hua resigned as the Chief Executive Officer of the Company and he remains as the Chairman of the Board.

The Company has adopted the share option schemes for the grant of options to the Company's directors. The fair value of share options for the directors measured according to the Group's accounting policy as set out in note 3. No Directors exercised any share option in 2015, 2016 or 2017. No new share option was granted to Directors in respect of their services to the Group under the applicable share option schemes of the Company in 2015, 2016 or 2017. Further details of share option scheme and valuation techniques are set out in note 26.

Save as disclosed above, there was no arrangement under which a director waived or agreed to waive any remuneration during the year. In 2017, the executive directors' remuneration shown above were for their services in connection with the management of the affairs of the Company. The other directors' remuneration shown above were for their services as directors of the Company.

8.        KEY MANAGEMENT PERSONNEL’SREMUNERATION (continued)

( ii )     Other key management personnel’s (excluding Directors’) remuneration

	2015	2016	2017
Short term employee benefits	8	7	9
Pension scheme contributions	1	1	1
Amount paid/payable during the year	9	8	10
Share options*	-	-	-
	9	8	10

The bands of the remuneration of other key management personnel (excluding Directors) and the related number of members of other key management personnel (excluding Directors) are as follows:

	Number of employees
	2015	2016	2017
Nil to RMB 2,000,000	10	10	12
	10	10	12

*               This item represents the fair value of share options measured according to the Group's accounting policy as set out in note 3. No other key management personnel exercised any share option in 2015, 2016 or 2017.

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FIVE HIGHEST PAID EMPLOYEES

12 Months Ended

Dec. 31, 2017

FIVE HIGHEST PAID EMPLOYEES [abstract]

Disclosure of five highest paid employees

9.        FIVE HIGHEST PAID EMPLOYEES

During the year, none (2016: none; 2015: none) of the Directors, details of whose remuneration are disclosed in note 8(i) above, received an amount which falls within the category of the five highest paid employees.Details of the remuneration of the five (2016: five; 2015: five) highest paid employees, for the year are as follows:

	2015	2016	2017
Basic salaries, allowances and benefits in kind(1)	22	23	21
Performance-related bonuses	17	14	19
Pension scheme contributions	1	1	1
Amount paid/payable during the year	40	38	41

(1)   Salaries, allowances, and benefits in kind represent the gross amount (before applicable individual salary tax) paid/payable to individual employees.

The remuneration of the five (2016: five, 2015: five) highest paid employees, falls within the following bands:

	2015	2016	2017
RMB5,500,001 to RMB6,000,000	-	1	-
RMB6,000,001 to RMB6,500,000	-	-	1
RMB7,000,001 to RMB7,500,000	3	-	1
RMB7,500,001 to RMB8,000,000	-	3	-
RMB8,000,001 to RMB8,500,000	-	-	1
RMB9,000,001 to RMB9,500,000	2	1	1
RMB10,000,001 to RMB10,500,000	-	-	1
	5	5	5

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TAX

12 Months Ended

Dec. 31, 2017

TAX [abstract]

Disclosure of tax

10.TAX

(i)       Income tax

The Company and its subsidiaries are subject, on an entity basis, to income taxes on profits arising in or derived from the tax jurisdictions in which the entities of the Group are domiciled and operate. The Company is subject to profits tax at a rate of 16.5 % (2016: 16.5%, 2015: 16.5%) on profits arising in or derived from Hong Kong.

The Company is regarded as a Chinese Resident Enterprise (as defined in the "Enterprise Income Tax Law of the People's Republic of China") by the State Administration of Taxation of the PRC. As a result, the Company is subject to the PRC corporate income tax at the rate of 25% starting from January 1, 2008. The corporate income tax which is subjected in Hong Kong is qualified as a foreign tax credit to offset the PRC corporate income tax starting from January 1, 2008.

The Company's subsidiary in Mainland China, CNOOC China Limited, is a wholly-owned foreign enterprise. It is subject to corporate income tax at the rate of 25% under the prevailing tax rules and regulations. CNOOC Deepwater Development Limited, a wholly-owned subsidiary of CNOOC China Limited, is subject to corporate income tax at the rate of 15% for the three years ended December 31, 2017, after being assessed as a high and new technology enterprise. The company is in the process of re-applying to be assessed as a high and new technology enterprise from 2018 to 2020.

Subsidiaries of the Group domiciled outside the PRC are subject to income tax at rates ranging from 10% to 50% (2016: 10% to 50%, 2015: 10% to 56%). 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%. The U.K. government decreased the combined income tax rate on North Sea oil and gas activities from 50% to 40% with effect from January 1, 2016.

As of December 31, 2017, deferred tax liabilities related to undistributed earnings of the Company's overseas subsidiaries have not been provided since the timing of the reversal of the taxable temporary differences can be controlled by the Company and it is probable that the temporary differences would not reverse in the foreseeable future.

10.      TAX (continued)

(i)       Income tax (continued)

An analysis of the tax (credit)/expense in the Group's consolidated statement of profit or loss and other comprehensive income is as follows:

	2015	2016	2017
Current tax
Provision for PRC enterprise income tax on the estimated taxable profits for the year	9,990	7,547	11,472
Provision for overseas enterprise income tax on the estimated taxable profits for the year	3,501	2,983	4,390
Deferred tax
Temporary differences in the current year	(12,585)	(14,595)	(7,558)
Effect of changes in tax rates	(4,022)	(1,847)	3,376
Income tax (credit)/expense for the year	(3,116)	(5,912)	11,680

A reconciliation of the PRC statutory corporate income tax rate to the effective income tax rate of the Group is as follows:

	2015	2016	2017
	%	%	%
PRC statutory enterprise income tax rate	25.0	25.0	25.0
Effect of different tax rates for overseas subsidiaries	(5.8)	34.8	(1.6)
Effect of changes in tax rates	(23.5)	35.0	9.4
Tax credit from the government	(11.5)	8.3	(2.7)
Tax reported in equity-accounted entities	(0.4)	1.0	(0.2)
Tax losses previously not recognized	(1.9)	5.3	-
Others	(0.1)	2.7	2.2
Group’s effective income tax rate	(18.2)	112.1	32.1

The movements of deferred tax liabilities net of deferred tax assets are as follows:

	2015	2016	2017
At January 1	14,312	(1,948)	(19,174)
Credit to the profit or loss	(12,585)	(14,595)	(7,558)
Changes in tax rates	(4,022)	(1,847)	3,376
Charge to equity	141	(226)	7
Exchange differences	206	(558)	1,143
At December 31	(1,948)	(19,174)	(22,206)

10.       TAX (continued)

(i)       Income tax (continued)

Principal components of deferred tax balances are as follows:

	2016	2017
Deferred tax assets
Property, plant and equipment	1,681	7,312
Provision for dismantlement	9,325	9,669
Losses available for offsetting against future taxable profit	21,163	16,529
Fair value of long term borrowings	1,969	1,771
Others	1,389	1,178
	35,527	36,459
Deferred tax liabilities
Property, plant and equipment	(16,208)	(13,670)
Fair value changes on other financial assets	(139)	(232)
Others	(6)	(351)
	(16,353)	(14,253)
Net deferred tax assets	19,174	22,206
Of which – deferred tax assets	24,844	25,509
deferred tax liabilities	(5,670)	(3,303)

As at December 31, 2017, the Group had approximately RMB87,623 million (December 31, 2016: RMB82,288 million) of carry-forward tax losses, predominantly in North America, that would be available to offset against future taxable profits of the subsidiaries in which the tax losses arose. Most of the US and Canadian tax losses will expire in 8 to 20 years.

Deferred tax assets in respect of tax losses are recognized only to the extent of the anticipated future taxable profits or reversal of existing taxable temporary differences.

As at December 31, 2017, the Group's recognized deferred tax assets on tax losses amounted to RMB75,018 million (December 31, 2016: RMB68,061 million). Unrecognized tax losses, where recovery is not currently expected, amounted to RMB12,605 million (December 31, 2016: RMB14,227 million). This includes RMB3,181 million (2016: RMB3,207 million) of unrecognized tax loss arising from Uganda which has no fixed expiry date. The remainder expires between 5 to 20 years.

As at December 31, 2017, the Group's unrecognized deferred tax assets related to unused tax credits amounted to RMB4,990 million (2016: RMB5,761 million). This includes RMB4,587 million (2016: RMB4,807 million) of unrecognized deferred tax assets related to unused tax credits from Nigeria which has no fixed expiry date. The remainder expires between 2026 and 2036.

The realisability of the deferred tax assets recognized mainly depends on whether sufficient future profits or taxable temporary differences will be available in the future. In case where the actual future taxable profits generated are less than expected, or change in facts and circumstances which result in revision of future taxable profits estimation, the balance of deferred tax assets may be significantly revised.

10.      TAX (continued)

(ii)      Other taxes

The Company's PRC subsidiaries pay the following other taxes and dues:

i.Production tax at the rate of 5% on production under production sharing contracts;

ii.VAT at the rates from 13% to 17% on taxable sales under independent oil and gas fields since May 1 2016 according to "Provisional Regulations on VAT of the PRC" and relevant detailed rules according to the "Circular on Certain Policies on the Pilot Program of the Collection of VAT in Lieu of Business Tax" (Cai Shui [2016] No.39), which replaced the production tax at the rate of 5% on production under independent oil and gas fields before May 1 2016. According to “Notice on Simplifying the Relevant Policies on Value-added Tax Rates” (Cai Shui [2017] No.37), with effect from 1 July 2017, the 13% VAT rate shall be removed and gas sales shall be subject to the 11% tax rate.

VAT at the rates from 3% to 17% on other income since May 1 2016, which were subject to the business tax at rates of 3% to 5% or VAT at the rates of 3% to 17% before May 1 2016.

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

iii.Resource tax (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 starting from November1, 2011, which replaced the royalties for oil and gas fields, except for those under production sharing contracts signed before November1, 2011 which will be subject to related resource tax requirement after the expiration of such production sharing contracts. The resource tax rate was changed from 5% to 6% since December 1, 2014;

iv.Export tariff at the rate of 5% on the export value of petroleum oil;

v.City construction tax at the rates of 1% or 7% on the production tax, business tax and VAT paid;

vi.Educational surcharge at the rate of 3% on the production tax, business tax and VAT paid; and

vii.Local educational surcharge at the rate of 2% on the production tax, business tax and VAT paid.

In addition, other taxes paid and payable by the Company's non-PRC subsidiaries include royalty as well as taxes levied on petroleum-related income, budgeted operating and capital expenditure.

10.      TAX (continued)

(iii)     Special Oil Gain Levy

In 2006, a Special Oil Gain Levy ("SOG Levy") was imposed by the Ministry of Finance of the PRC ("MOF") at the 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. The MOF has decided to increase the threshold of the SOG Levy to US$65 with effect from January 1,2015. Notwithstanding this adjustment, the SOG Levy continues to have five levels and is calculated and charged according to the progressive and valorem rates on the excess amounts. The SOG Levy paid can be claimed as a deductible expense for corporate income tax purposes and is calculated based on the actual volume of the crude oil entitled.

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EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2017

EARNINGS PER SHARE [abstract]

Disclosure of earnings per share

11.      EARNINGS PER SHARE

	2015	2016	2017
Earnings
Profit for the purpose of basic and diluted earnings per share calculation	20,246	637	24,677
Number of shares
Number of ordinary shares for the purpose of basic earnings per share calculation	44,647,455,984	44,647,455,984	44,647,455,984
Effect of dilutive potential ordinary shares under the share option schemes	37,363,069	11,684,504	4,101,969
Weighted average number of ordinaryshares for the purpose of diluted earningsper share	44,684,819,053	44,659,140,488	44,651,557,953
Earnings per share:
Basic (RMB Yuan)	0.45	0.01	0.55
Diluted (RMB Yuan)	0.45	0.01	0.55

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DIVIDENDS

12 Months Ended

Dec. 31, 2017

DIVIDENDS [abstract]

Disclosure of dividends

12.   DIVIDENDS

	2015	2016	2017
Dividend per ordinary share:
2017 interim dividend - HK$0.20 (2016: interim dividend HK$0.12, 2015: interim dividend    HK$0.25) per ordinary share	9,145	4,673	7,601
2016 final dividend - HK$0.23 (2015: final dividend HK$0.25, 2014: final dividend    HK$0.32) per ordinary share	11,274	9,571	8,847
2017 final dividend proposed at HK$0.3 (2016: final dividend proposed at HK$0.23, 2015: final dividend proposed at HK$0.25) per ordinary share by the Board of Directors - not recognized as a liability as at the end of the year	9,397	9,096	10,830

Pursuant to the Enterprise Income Tax Law of the People's Republic of China and related laws and regulations, the Company is regarded as a Chinese Resident Enterprise, and thus is required to withhold corporate income tax at the rate of 10% when it distributes dividends to its non-resident enterprise (as defined in the "Enterprise Income Tax Law of the People's Republic of China") shareholders, with effect from the distribution of the 2008 final dividend. In respect of all shareholders whose names appear on the Company's register of members and who are not individuals (including HKSCC Nominees Limited, corporate nominees or trustees such as securities companies and banks, and other entities or organizations, which are all considered as non-resident enterprise shareholders), the Company will distribute the dividend after deducting corporate income tax of 10%.

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PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2017

PROPERTY, PLANT AND EQUIPMENT [abstract]

Disclosure of property, plant and equipment

13.      PROPERTY, PLANT AND EQUIPMENT

	Oil and gas properties	Vehicles and office equipment and others	Total
Cost:
At January 1, 2016	803,986	5,296	809,282
Additions	44,302	236	44,538
Disposals and write-offs	(6,365)	(37)	(6,402)
Exchange differences	25,703	205	25,908
At December 31, 2016	867,626	5,700	873,326
At January 1, 2017	867,626	5,700	873,326
Additions	48,937	99	49,036
Disposals and write-offs	(2,577)	(914)	(3,491)
Exchange differences	(24,985)	(148)	(25,133)
At December 31, 2017	889,001	4,737	893,738
Accumulated depreciation, depletion and amortization and impairment:
At January 1, 2016	(353,824)	(1,317)	(355,141)
Depreciation charge for the year	(67,906)	(397)	(68,303)
Impairment	(10,768)	-	(10,768)
Disposals and write-offs	3,532	34	3,566
Exchange differences	(10,157)	(58)	(10,215)
At December 31, 2016	(439,123)	(1,738)	(440,861)
At January 1, 2017	(439,123)	(1,738)	(440,861)
Depreciation charge for the year	(60,442)	(360)	(60,802)
Impairment	(8,639)	-	(8,639)
Disposals and write-offs	1,185	258	1,443
Exchange differences	10,932	57	10,989
At December 31, 2017	(496,087)	(1,783)	(497,870)
Net book value:
At December 31, 2016	428,503	3,962	432,465
At December 31, 2017	392,914	2,954	395,868

Included in the current year's additions was an amount of approximately RMB2,495 million (2016: approximately RMB1,430 million, 2015: approximately RMB1,385 million) in respect of interest capitalized in property, plant and equipment (note 7). Included also in the depreciation charge for the year was an amount of approximately RMB636 million (2016: approximately RMB1,609 million, 2015: approximately RMB3,465 million) in respect of a depreciation charge on dismantlement cost capitalized in oil and gas properties.

13.      PROPERTY, PLANT AND EQUIPMENT (continued)

Impairment and provision recognized during the year included the impairment loss to reduce the carrying amount of certain oil and gas properties to the recoverable amount. In 2017, the impairment loss was mainly related to fields in China, Africa and North America which was primarily due to the revision of the oil and gas price forecast and revision of reserves. In 2016, the impairment loss was mainly related to fields in North America, Europe and Africa primarily due to the revision of the oil price forecast and an adjustment in operating plan for oil sand assets in Canada.

For both years, the recoverable amount was calculated based on the assets' value in use and was determined at the cash-generating unit level. The Company identifies a field or the group of fields that could generate cash inflows independently as a cash-generating unit. The principal parameters used in determining the recoverable amount of the Group’s assets include estimates of proved and unproved reserves, future commodity prices that come from the price forecast of respected and independent institutions, combined with internal analysis and judgment of the international market environment, as well as best estimates of drilling and development costs.

The discount rate is derived from the Company’s weighted average cost of capital (“WACC”) and is adjusted, where applicable, to take into account any specific risks relating to the country where the asset is located as well as the asset specific characteristics, such as specific tax treatments, cash flow profiles and economic life. The discount rate used for value in use calculations is 8%-12% in 2017 after tax (2016:8%-11% after tax). A derived pre-tax discount rate would be in the range of 8%-15% (2016: 9%-11% pre-tax).

For 2016, included in impairment was RMB7,358 million recognized on the Long Lake project, due to the revision of the oil price forecast and adjustments to operating plans caused by the pipeline rupture and the explosion accident. Specifically, the operating plan was changed to defer the timing of when to bring the Long Lake upgrader back online, to make the timing concurrent with the most recent expectation of when sufficient feedstock will be produced from Long Lake assets to maximize the utilization and cash generating potential of the upgrader. The Company also updated the yield assumptions based on the most recent operating performance of the upgrader. The asset was written down to an estimated recoverable amount of RMB33,902 million in June 2016. As at 31 December 2017, the future operating plan of Long Lake assets is still under assessment by management, which may significantly impact the recoverable amount of the oil sands properties of Long Lake assets in the future.

During 2017, the Group wrote off certain oil and gas assets in the North America mainly due to the expiration of lease contracts. Approximately RMB71 million was included in the exploration expenses, and approximately RMB1,588 million was included in the depreciation, depletion and amortisation charge, respectively.

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INTANGIBLE ASSETS

12 Months Ended

Dec. 31, 2017

INTANGIBLE ASSETS [abstract]

Disclosure of intangible assets

14.      INTANGIBLE ASSETS

	Gas processing rights under NWS Project	Drilling rig contracts and seismic data usage rights	Marketing transportation and storage contracts	Software and others	Goodwill	Total
Cost:
At January 1, 2016	1,191	1,596	1,527	2,861	13,805	20,980
Additions	-	-	-	197	-	197
Disposal	-	-	-	(387)	-	(387)
Exchange differences	82	109	104	67	943	1,305
At December 31, 2016	1,273	1,705	1,631	2,738	14,748	22,095
At January 1, 2017	1,273	1,705	1,631	2,738	14,748	22,095
Additions	-	-	-	206	-	206
Disposal	-	(1,662)	(54)	(199)	-	(1,915)
Exchange differences	(74)	(43)	(93)	(57)	(856)	(1,123)
At December 31, 2017	1,199	-	1,484	2,688	13,892	19,263
Accumulated amortization:
At January 1, 2016	(621)	(958)	(1,096)	(1,882)	-	(4,557)
Amortization charge for the year	(51)	(326)	(135)	(508)	-	(1,020)
Disposal	-	-	-	386	-	386
Exchange differences	(57)	(80)	(81)	(42)	-	(260)
At December 31, 2016	(729)	(1,364)	(1,312)	(2,046)	-	(5,451)
At January 1, 2017	(729)	(1,364)	(1,312)	(2,046)	-	(5,451)
Amortization charge for the year	(46)	(332)	(57)	(419)	-	(854)
Disposal	-	1,662	54	199	-	1,915
Exchange differences	43	34	76	44	-	197
At December 31, 2017	(732)	-	(1,239)	(2,222)	-	(4,193)
Net book value:
At December 31, 2016	544	341	319	692	14,748	16,644
At December 31, 2017	467	-	245	466	13,892	15,070

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in a business combination.

According to the accounting policies as set out in note 3, goodwill is acquired in the acquisition of Nexen Inc., and from the acquisition date, allocated to the entire E&P assets, which are the groups of cash-generating units that are expected to benefit from the synergies of the acquisition.

Impairment is determined by assessing the recoverable amount of the entire E&P assets to which the goodwill relates. Where the recoverable amount of the entire E&P assets is less than the carrying amount of the assets and the goodwill together, an impairment loss on goodwill is recognized.

In assessing value in use of E&P segment, 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. The discount rate used for value in use is derived from the Company’s WACC and is adjusted, where applicable, to take into account any specific risks relating to the country where the asset is located as well as the asset specific characteristics, such as specific tax treatments, cash flow profiles and economic life. However, actual results could differ from those estimates.

The intangible asset regarding the gas processing rights has been amortized upon the commercial production of the liquefied natural gas on a unit-of-production basis over the total proved reserves of the relevant asset. The intangible assets regarding the marketing transportation and storage contracts are amortized on a straight-line basis over the life of the contracts which is less than 20 years. Other identifiable intangible assets are amortized on a straight-line basis over a period ranging from 3 to 5 years.

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INVESTMENTS IN ASSOCIATES

12 Months Ended

Dec. 31, 2017

INVESTMENTS IN ASSOCIATES [abstract]

Disclosure of investments in associates

15.      INVESTMENTS IN ASSOCIATES

Particulars of the principal associates at the end of the reporting period are as follows:

		Nominal value
		of ordinary shares issued and	Percentageof equity
	Placeof	paid-up/registered	attributable to
Name of associates	establishment	capital	the Group	Principal activities
Shanghai Petroleum	Shanghai, PRC	RMB900 million	30%	Production, processing and technology consultation of oil,
Corporation Limited				gas and relevant products
				in the PRC
CNOOC Finance	Beijing, PRC	RMB4 billion	31.8%	Provision of deposit, transfer,
Corporation Limited				settlement, loan, discounting
				and other financing services to
				CNOOC and its member entities

To give details of other associate would, in the opinion of the Directors, result in particulars of excessive length.

The Group’s investments in associates represent:

	2016	2017
Share of net assets	3,695	4,067

None of the Group’s associates are considered to be individually material. The following table illustrates the summarized financial information of the Group’s associates in the consolidated financial statements:

	2015	2016	2017
Profit/(loss) for the year	256	(609)	302
Other comprehensive income/(expense)	74	(127)	36
Total comprehensive income/(expense)	330	(736)	338

Dividend of RMB116 million was received from the associates in 2017 (2016: RMB135 million).

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INVESTMENT IN A JOINT VENTURE

12 Months Ended

Dec. 31, 2017

INVESTMENT IN A JOINT VENTURE [abstract]

Disclosure of investment in a joint venture

16.       INVESTMENT IN A JOINT VENTURE

Particulars of the joint venture at the end of the reporting period are as follows:

Name of entity	Place of establishment	Nominal value of ordinary shares issued and paid-up/registered capital	Percentage of equity attributableto the Group	Principal activities
Bridas Corporation	British Virgin Islands	US$ 102,325,582	50%	Investment holding

16.INVESTMENT IN A JOINT VENTURE (continued)

Summarized financial information of the joint venture is disclosed below:

	2016		2017
Current assets		9,201	11,614
Non-current assets		66,992	63,660
Current liabilities		(6,866)	(6,630)
Non-current liabilities		(16,727)	(18,486)
	2015	2016		2017
Revenue	31,231	28,371	29,879
Depreciation, depletion and amortization	(3,535)	(3,988)	(3,742)
Interest income	288	388	313
Finance costs	(799)	(704)	(550)
Profit before tax	4,194	1,226	2,215
Income tax expense	(900)	(160)	(1,109)
Profit after tax	3,294	1,066	1,106
Total comprehensive income	3,294	1,066	1,106

Dividend of US$36 million (equivalent to RMB243 million) was received from the joint venture in 2017, no dividend was received from the joint venture in 2016and dividend of US$5 million (equivalent to RMB32 million) was received from the joint venture in 2015.

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EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS

12 Months Ended

Dec. 31, 2017

EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS [abstract]

Disclosure of equity investments and other financial assets

17.      EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS

           (i)  Equity investments

	2016	2017
Current:
Non-publicly traded investments
Private equity funds classified at FVTOCI	15	14
	15	14

Non-current:
Publicly traded investments
Equity investment in MEG Energy Corporation (“MEG”) classified at FVTOCI(1)	1,356	766
Other equity investment classified at FVTPL	35	15
	1,391	781
Non-publicly traded investments
Private equity fund in Kerogen Energy Fund  classified at FVTOCI(2)	2,875	2,759
	4,266	3,540

(1)MEG is principally engaged in the exploitation and production of oil sands. The investment in MEG is designated by the Group as at FVTOCI. As at December 31, 2017, the investment in MEG was stated at the quoted market price.

(2)Kerogen Energy Fund is principally engaged in the investment in the oil and gas industry. The equity investment in Kerogen Energy Fund is designated by the Group as at FVTOCI. The cost of this non-publicly traded equity investment represents an appropriate estimate of its fair value as at January 1, 2017 and December 31, 2017, as sufficient information is not available recently to measure its fair value.

17.       EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS (Continued)

           (ii) Other financial assets

	2016	2017
Current:
Non-publicly traded investments classified at FVTPL:
Corporate wealth management products (1)	46,958	66,229
Money market funds (2)	5,931	8,115
	52,889	74,344

(1)The corporate wealth management products will mature from January 8, 2018 to November 6, 2018 (2016: January 10, 2017 to December 5, 2017).

(2)The money market funds can be redeemed at any time.

The gains of the Group's other financial assets recognized in the profit or loss for the year was RMB2,409 million (2016: RMB2,774 million, 2015: RMB2,398 million).

During the year, the fair value changes on the Group's equity investments recognized directly in other comprehensive expense amounted to RMB542 million (2016: RMB461 million, 2015: RMB1,573 million).

None of the equity investments and other financial assets above is past due or impaired.

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OTHER NON-CURRENT ASSETS

12 Months Ended

Dec. 31, 2017

OTHER NON-CURRENT ASSETS [abstract]

Disclosure of other non-current assets

18.      OTHER NON-CURRENT ASSETS

Included in the other non-current assets were restricted deposits for future dismantlement.  Pursuant to the Provisional Regulations on the Dismantlement of Offshore Oil and Gas Production Facilities of the People's Republic of China, the Group accrues dismantlement costs for all the oil and gas fields under production sharing contracts in the PRC, and makes monthly cash contributions to the specified dismantlement fund accounts supervised by the PRC government. The deposit cannot be withdrawn or utilized for any other purposes but the dismantlement of oil and gas production facilities in the future. As of December 31, 2017, the balance of the specified dismantlement fund accounts was RMB7,555 million (December31, 2016: RMB6,088 million).

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INVENTORIES AND SUPPLIES

12 Months Ended

Dec. 31, 2017

INVENTORIES AND SUPPLIES [abstract]

Disclosure of inventories and supplies

19.      INVENTORIES AND SUPPLIES

	2016	2017
Materials and supplies	7,288	6,278
Oil in tanks	1,594	1,540
Less: Provision for inventory obsolescence	(173)	(464)
	8,709	7,354

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TRADE RECEIVABLES

12 Months Ended

Dec. 31, 2017

TRADE RECEIVABLES [abstract]

Disclosure of trade receivables

20.       TRADE RECEIVABLES

The credit terms of the Group are generally within 30 days after the delivery of oil and gas. Payment in advance or collateral may be required from customers, depending on credit rating. Trade receivables are non-interest-bearing.

All customers have good credit quality with good repayment history and no significant receivables are past due. As at December 31, 2017 and December 31, 2016, the age of substantially all the trade receivables was within one year.

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CASH AND CASH EQUIVALENTS AND TIME DEPOSITS WITH MATURITY OVER THREE MONTHS

12 Months Ended

Dec. 31, 2017

CASH AND CASH EQUIVALENTS AND TIME DEPOSITS WITH MATURITY OVER THREE MONTHS [abstract]

Disclosure of cash and cash equivalents and time deposits with maturity over three months

21.      CASH AND CASH EQUIVALENTS AND TIME DEPOSITS WITH MATURITY OVER THREE MONTHS

The Group's cash and cash equivalents mainly consist of current deposits and time deposits with maturity within seven days. The bank balances are deposited with creditworthy banks with no recent history of default.

The weighted average effective interest rates of the Group's bank deposits were 2.23% per annum for the year ended December 31, 2017 (2016: 2.95% per annum, 2015: 2.61% per annum).

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TRADE AND ACCRUED PAYABLES

12 Months Ended

Dec. 31, 2017

TRADE AND ACCRUED PAYABLES [abstract]

Disclosure of trade and accrued payables

22.      TRADE AND ACCRUED PAYABLES

As at December 31, 2017 and 2016, substantially all the trade and accrued payables were aged within six months. The trade and accrued payables are non-interest-bearing.

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OTHER PAYABLES AND ACCRUED LIABILITIES

12 Months Ended

Dec. 31, 2017

OTHER PAYABLES AND ACCRUED LIABILITIES [abstract]

Disclosure of other payables and accrued liabilities

23.      OTHER PAYABLES AND ACCRUED LIABILITIES

	2016	2017
Accrued payroll and welfare payable	1,509	1,490
Provision for retirement benefits	683	630
Accrued expenses	449	381
Advances from customers	3,272	3,096
Special oil gain levy payable	-	55
Royalties payable	240	75
Provision for dismantlement (note 25)	462	1,180
Other payables	8,251	7,199
	14,866	14,106

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LOANS AND BORROWINGS

12 Months Ended

Dec. 31, 2017

LOANS AND BORROWINGS [abstract]

Disclosure of loans and borrowings

24.      LOANS AND BORROWINGS

Current

		2016			2017
	Effective interest rate and final maturity	Loans	Notes	Total	Loans	Notes	Total
Short-term loans and borrowings
General loans****	LIBOR+0.35% to 0.75% per annum with maturity within one year	10,361	-	10,361	8,779	-	8,779
		10,361	-	10,361	8,779	-	8,779
Loans and borrowings due within one year
For Tangguh LNG Project**	LIBOR+0.19% to 0.335% per annum with maturity within one year	215	-	215	212	-	212
Notes*		-	9,102	9,102	-	4,901	4,901
		215	9,102	9,317	212	4,901	5,113
		10,576	9,102	19,678	8,991	4,901	13,892

24.   LOANS AND BORROWINGS (continued)

Non-current

		2016			2017
	Effective interest rate andfinal maturity	Loans	Notes	Total	Loans	Notes	Total
For Tangguh LNG Project**	LIBOR+0.19% to 0.335% per annum with maturity through to 2021	758	-	758	502	-	502
For Tangguh LNG III Project ***	LIBOR+1.37% to 3.45% per annum with maturity through 2021 to 2029	327	-	327	777	-	777
Notes*		-	129,713	129,713	-	117,079	117,079
		1,085	129,713	130,798	1,279	117,079	118,358

24.   LOANS AND BORROWINGS (continued)

*    The details of notes are as follows:

Issued by	Maturity	Coupon Rate	Outstanding Principal Amount
			December 31, 2017	December 31,2016
			USD million	USD million
CNOOC Finance (2003) Limited	Due in 2033	5.500%	300	300
CNOOC Finance (2011) Limited	Due in 2021	4.25%	1,500	1,500
CNOOC Finance (2011) Limited	Due in 2041	5.75%	500	500
CNOOC Finance (2012) Limited	Due in 2022	3.875%	1,500	1,500
CNOOC Finance (2012) Limited	Due in 2042	5.000%	500	500
CNOOC Finance (2013) Limited	Due in 2018	1.750%	750	750
CNOOC Finance (2013) Limited	Due in 2023	3.000%	2,000	2,000
CNOOC Finance (2013) Limited	Due in 2043	4.250%	500	500
CNOOC Nexen Finance (2014) ULC	Matured in 2017	1.625%	-	1,250
CNOOC Nexen Finance (2014) ULC	Due in 2024	4.25%	2,250	2,250
CNOOC Nexen Finance (2014) ULC	Due in 2044	4.875%	500	500
Nexen	Matured in 2017	5.65%	-	62
Nexen	Due in 2019	6.2%	300	300
Nexen	Due in 2028	7.4%	200	200
Nexen	Due in 2032	7.875%	500	500
Nexen	Due in 2035	5.875%	790	790
Nexen	Due in 2037	6.4%	1,250	1,250
Nexen	Due in 2039	7.5%	700	700
CNOOC Finance (2015) U.S.A. LLC	Due in 2025	3.500%	2,000	2,000
CNOOC Finance (2015) Australia Pty Ltd	Due in 2020	2.625%	1,500	1,500
CNOOC Finance (2015) Australia Pty Ltd	Due in 2045	4.200%	300	300

All the notes issued mentioned above were fully and unconditionally guaranteed by the Company.

24.   LOANS AND BORROWINGS (continued)

**     In connection with the Tangguh LNG Project in Indonesia, the Company delivered a guarantee dated October 29, 2007, in favor of Mizuho Corporate Bank, Ltd., which acts as the facility agent for and on behalf of various international commercial banks under a US$884 million commercial loan agreement. The Company guarantees the payment obligations of the trustee borrower under the subject loan agreement and is subject to a maximum cap of approximately US$135,163,308.28.

A letter of credit agreement was signed between the Company and Talisman Energy Inc. (“Talisman”) with execution of the agreement in respect of the sale of a 3.05691% interest of the Company in the Tangguh LNG Project to Talisman. Accordingly, Talisman has delivered valid and unexpired standby letters of credit to the Company (as the beneficiary) as a counter-guarantee to offset the exposure of the Company’s guarantee for the aforesaid interest of 3.05691% in respect of the Tangguh LNG Project financing. The amount of the standby letters of credit was US$30 million. In February 2017, the standby letters of credit were withdrawn as the Company transferred the 3.05691% guarantee obligations to BP Corporation North America Inc..

***   In connection with the financing for the third LNG process train of Tangguh LNG Project in Indonesia, the Company delivered two guarantees dated August 3, 2016, in favor of Mizuho Bank, Ltd., which acts as the facility agent for and on behalf of various international commercial banks and Indonesian local commercial banks under two commercial loan agreements with aggregate loan amount of US$2,145 million. The Company guarantees the payment obligations of the trustee borrower under the subject loan agreements and is subject to an aggregate maximum cap of approximately US$573 million.

**** As at December 31, 2017, US$650 million bank loans (2016: US$800 million) were guaranteed by the Company.

           As at December 31, 2017, US$694 million shareholder loans (2016: US$694 million) of the Group were   included in general loans. For details please refer to Note 28(v).

24.   LOANS AND BORROWINGS (continued)

The maturities of the long term bank loans are as follows:

	2016	2017
Repayable:
Within one year	215	212
After one year but within two years	225	212
After two years but within three years	225	212
After three years but within four years	225	108
After four years but within five years	97	61
After five years	313	686
	1,300	1,491
Amount due within one year shown under current liabilities	(215)	(212)
	1,085	1,279

Supplemental information with respect to the long term bank loans:

			Maximum	Average	Weighted
		Weighted	amount	amount	average
		average	outstanding	outstanding	interest rate
For the year ended	Balance	interest rate	during the	during the	during the
December 31	at year end	at year end	year	year (1)	year (2)
2016	1,300	1.74%	1,369	1,199	1.29%
2017	1,491	2.52%	1,491	1,396	2.13%

(1)    The average amount outstanding is computed by averaging the outstanding principal balances as at January 1, and December 31, of each year.

(2)    The weighted average interest rate is computed by averaging the interest rates as at January 1, and December 31, of each year.

There was no default of principal, interest or redemption terms of the loans and borrowings during the year.

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PROVISION FOR DISMANTLEMENT

12 Months Ended

Dec. 31, 2017

PROVISION FOR DISMANTLEMENT [abstract]

Disclosure of provision for dismantlement

25.      PROVISION FOR DISMANTLEMENT

	2016	2017
At January 1	50,063	50,888
New projects(1)	1,395	1,244
Revision(1)	(2,072)	421
Utilization	(398)	(440)
Deletions	(33)	-
Unwinding of discount(2) (note 7)	2,185	2,145
Exchange differences	(252)	(185)
At December 31	50,888	54,073
Current portion of dismantlement included in other payables and accrued liabilities (note 23)	(462)	(1,180)
At December 31	50,426	52,893

(1)The amounts are included in the additions of oil and gas properties in note 13.

(2)The discount rates used for calculating the provision for dismantlement are within the range of 4% to 5% (2016: 4% to 5%, 2015: 4% to 5%).

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SHARE CAPITAL

12 Months Ended

Dec. 31, 2017

SHARE CAPITAL [abstract]

Disclosure of share capital

26.      SHARE CAPITAL

		Issued share capital  equivalent of
	Number of shares	RMB million
Issued and fully paid:
Ordinary shares with no par value as at January 1, 2016, as at December 31, 2016 and as at December 31, 2017	44,647,455,984	43,081

26.      SHARE CAPITAL (continued)

Share option schemes

The Company has adopted the share option schemes for the grant of options to the Company's directors, senior management and other eligible grantees.

(1)      Pre-Global Offering Share Option Scheme (expired in 2011);

(2)      2001 Share Option Scheme (expired in 2011);

(3)      2002 Share Option Scheme (expired in 2015); and

(4)      2005 Share Option Scheme (as defined below).

Under these share option schemes, the Remuneration Committee of the Board will from time to time propose for the Board's approval the grant of share options and the number of share options to be granted to the relevant grantees. The maximum aggregate number of shares (including those that could be subscribed for under the Pre-Global Offering Share Option Scheme, the 2001 Share Option Scheme, the 2002 Share Option Scheme and the 2005 Share Option Scheme) which may be issued upon exercise of all options granted shall not exceed 10% of the total issued share capital of the Company as at December 31, 2005, being the date on which the shareholders of the Company approved the 2005 Share Option Scheme, excluding shares under options which have lapsed.

2005 Share Option Scheme

On December 31, 2005, the Company adopted a new share option scheme (the "2005 Share Option Scheme"). Under the 2005 Share Option Scheme, the Board has the authority to grant options to subscribe for shares to the directors, officers and employees of the Company and its subsidiaries, and any other persons who in the sole discretion of the Board, have contributed or will contribute to the Group. Unless approved by the shareholders, the total number of shares issued and to be issued upon exercise of the options granted to each individual (including exercised and unexercised options) under the 2005 Share Option Scheme or any other share option scheme adopted by the Company, in any 12-month period, must not exceed 1% of the shares in issue of the Company.

26.      SHARE CAPITAL (continued)

Share option schemes (continued)

2005 Share Option Scheme (continued)

According to the 2005 Share Option Scheme, the consideration payable by a grantee for the grant of options will be HK$1.00. The exercise price for such options will be determined by the Board at its discretion at the date of grant, except that such price shall be at least the higher of:

(1)      the nominal value of a share of the Company on the date of grant;

(2)      the average closing price of the shares as stated in the HKSE's daily quotation sheets for the five trading days immediately preceding the date of grant; and

(3)      the closing price of the shares as stated in the HKSE's daily quotation sheet on the date of grant.

The period within which the options must be exercised, as well as any minimum holding period or performance targets which apply to the options, will be specified by the Board of the Company at the time of grant. The exercise periods for options granted under the 2005 Share Option Scheme shall end not later than 10 years from the date of grant. No options may be granted under the 2005 Share Option Scheme after the date of the 10th anniversary of the adoption of the 2005 Share Option Scheme.

No new share option was granted during the year (2016 and 2015: nil) and the Group recognized an equity-settled share option expense of nil (2016 and 2015: nil) during the year.

The fair value of equity-settled share options granted was estimated as at the date of grant if any, using the Black-Scholes option pricing model, taking into account the terms and conditions upon which the options were granted.

Details of the share options outstanding are as follows:

	2016		2017
	Number of share options	Weighted average exercise price	Number of share options	Weighted average exercise price
		HK$		HK$
Outstanding at the beginning of the year	262,592,000	10.56	187,529,000	11.40
Granted during the year	-	-	-	-
Forfeited during the year	(37,893,000)	11.30	(22,506,000)	12.43
Expired during the year	(37,170,000)	5.56	(35,104,000)	7.29
Exercised during the year	-	-	-	-
Outstanding at the end of the year	187,529,000	11.40	129,919,000	12.34
Exercisable at the end of the year	187,529,000	11.40	129,919,000	12.34

No share options had been cancelled or modified during the years ended December 31, 2015, 2016 or 2017.

26.      SHARE CAPITAL (continued)

At the date of approval of these consolidated financial statements for issuance, the share options outstanding under these share option schemes represented approximately 0.29% of the Company's shares in issue as at that date (2016: 0.42%, 2015: 0.59%). The weighted average remaining contractual life of share options outstanding at the end of the year was 1.52 years (2016: 2.11 years, 2015: 2.74 years). The exercise in full of the outstanding share options would, under the present capital structure of the Company, result in the issue of 129,919,000 (2016: 187,529,000) additional ordinary shares of the Company and additional share capital of RMB1,339,702,913 (2016: RMB1,912,814,087).

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RESERVES

12 Months Ended

Dec. 31, 2017

RESERVES [abstract]

Disclosure of reserves

27.      RESERVES

According to the laws and regulations of the PRC and the articles of association of CNOOC China Limited, CNOOC China Limited is required to provide for certain statutory funds, namely, the general reserve fund and the staff and workers' bonus and welfare fund, which are appropriated from net profit (after making up for losses from previous years), but before dividend distribution.

The general reserve fund, which is determined at the discretion of the board of directors of CNOOC China Limited, can only be used, upon approval by the relevant authority, to offset against accumulated losses or to increase capital.

Appropriation to the staff and workers' bonus and welfare fund, which is determined at the discretion of the board of directors of CNOOC China Limited, is expensed as incurred under IFRSs/HKFRSs. The staff and workers' bonus and welfare fund can only be used for special bonuses or collective welfare of employees.

As at December 31, 2017, the general reserve fund amounted to RMB60,000 million (December 31, 2016: RMB10,000 million).

In accordance with the "Temporary Regulation for Safety Expense Financial Management of Higher Risk Industry" and the implementation guidance issued by the MOF of the PRC, the Group is required to accrue a safety fund for its oil and gas exploration and production activities within the PRC by appropriating a portion of its net profit to other reserves based on its annual production from offshore China. Such reserve is reduced for expenses incurred to improve the safety conditions of oil and gas production. When the safety fund is fully utilized, additional expenses incurred for safety production purposes are charged directly to the profit or loss for the year. As of December 31, 2017, the Group's safety fund reserve under the PRC regulations amounted to nil (December 31, 2016: nil).

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2017

RELATED PARTY TRANSACTIONS [abstract]

Disclosure of related party transactions

28.      RELATED PARTY TRANSACTIONS

As disclosed in note 1, the Company is a subsidiary of CNOOC, which is a state-owned enterprise subject to the control of the State Council of the PRC. The State Council of the PRC directly and indirectly controls a significant number of state-owned entities and organizations.

Comprehensive framework agreement with CNOOC in respect of a range of products and services

As the Group is controlled by CNOOC, transactions with CNOOC, its subsidiaries and associates (the "CNOOC Group") are disclosed as related party transactions. The connected transactions or continuing connected transactions defined in Chapter 14A of the Listing Rules in respect of items listed below also constitute related party transactions. The Company has complied with the disclosure requirements in accordance with Chapter 14A of the Listing Rules for continuing connected transactions listed below. The Company entered into a comprehensive framework agreement with CNOOC on November 15, 2016 for the provision (1) by the Group to the CNOOC Group and (2) by the CNOOC Group to the Group, 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 continuing connected transactions under the comprehensive framework agreement and the relevant annual caps for the three years from January 1, 2017 were approved by the independent shareholders of the Company 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 the CNOOC Group to the Group:

(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)Floating production, storage and offloading ("FPSO")vessel leases

(2)Provision of management, technical, facilities and ancillary services, including the supply of materials by the Group to the CNOOC Group; and

(3)Sales of petroleum and natural gas products by the Group to the CNOOC Group:

(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

28.      RELATED PARTY TRANSACTIONS (continued)

Pricing principles

The basic pricing principle for the continuing connected transactions between the Group and the CNOOC Group 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 ofcontracts, the volume of services, overall customer relationship and other market factors).

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 prices; 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 the CNOOC Group to the Group and (3)(a)-(3)(b) above provided by the Group to the CNOOC Group, on the basis of the above pricing principle, are based on market prices (as defined in the comprehensiveframework agreement).

The continuing connected transactions referred to in paragraph (1)(c)-(1)(d) above provided by the CNOOC Group to the Group, 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 CNOOC Group 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 Group to the CNOOC Group, on the basis of the above pricing principle, are determined through arm’s length negotiation between both parties with reference market price.

28.      RELATED PARTY TRANSACTIONS (continued)

The following is a summary of significant related party transactions entered into in the ordinary course of business between the Group and its related parties during the year and the balances arising from related party transactions at the end of the year:

(i)     Provision of exploration, oil and gas development, oil and gas production as well as marketing, management and ancillary services by the CNOOC Group to the Group

	2015	2016	2017
Provision of exploration and support services	7,457	4,357	5,912
- Inclusive of amounts capitalized under property, plant and equipment	4,158	2,364	3,392
Provision of oil and gas development and support services	22,733	14,214	16,317
Provision of oil and gas production and support services (note a)	8,384	7,250	8,894
Provision of marketing, management and ancillary services (note b)	954	994	1,450
FPSO vessel leases (note c)	1,770	1,551	1,383
	41,298	28,366	33,956

(ii)   Provision of management, technical, facilities and ancillary services, including the supply of materials by the Group to the CNOOC Group

The Group did not enter into any transactions in the above category for the years ended December 31, 2015, 2016 or 2017.

(iii)  Sales of petroleum and natural gas products by the Group to the CNOOC Group

	2015	2016	2017
Sales of petroleum and natural gas products (other than long-term sales of natural gas and liquefied natural gas) (note d)	105,401	88,682	109,518
Long term sales of natural gas and liquefied natural gas (note e)	10,557	8,663	9,837
	115,958	97,345	119,355

28.      RELATED PARTY TRANSACTIONS (continued)

(iv)     Transactions and balances with CNOOC Finance Corporation Limited (“CNOOC Finance”) (note f)

(a)Interest income received by the Group

	2015	2016	2017
Interest income from deposits in CNOOC Finance	629	564	360

(b)Deposits balances made by the Group

	2016	2017
Deposits in CNOOC Finance	19,437	19,465

(v)       Balances with the CNOOC Group

	2016	2017
Amount due to CNOOC
- included in other payables and accrued liabilities	215	193
Amount due to other related parties
- included in trade and accrued payables	15,091	16,651
	15,306	16,844
Borrowings from CNOOC (note g)	4,811	4,532
Amounts due from other related parties
– included in trade receivables	13,090	12,401
– included in other current assets	173	513
	13,263	12,914

(vi)     Balance with a joint venture

	2016	2017
Amount due from a joint venture
– included in other current assets	135	126

28.      RELATED PARTY TRANSACTIONS (continued)

(vii)    Transactions and balances with other state-owned enterprises

The Group enters into extensive transactions covering sales of crude oil and natural gas, purchase of property, plant and equipment and other assets, receiving of services, and making deposits with state-owned enterprises, other than the CNOOC Group, in the normal course of business on terms comparable to those with other non-state-owned enterprises. The purchases of property, plant and equipment and other assets, and receipt of services from these state-owned enterprises are individually not significant. The individually significant sales transactions with these state-owned enterprises are disclosed in note 33. In addition, the Group had certain of its cash in bank and time deposits with certain state-owned banks in the PRC as at December 31, 2017, as summarized below:

	2016	2017
Cash and cash equivalents	6,612	3,824
Time deposits with maturity over three months	108	13
Specified dismantlement fund accounts (note 18)	6,088	7,555
	12,808	11,392

Interest rates for the above time deposits and specified dismantlement fund accounts are at prevailing market rates.

(viii)   Key management personnel’sremuneration

Key management personnel’s remuneration is disclosed in note 8.

(ix)     Coalbed Methane Resources Exploration and Development Cooperation Agreement with China United Coalbed Methane Corporation Limited

	2016	2017
Accumulated investment	1,647	1,940

The amount due to the parent company and amounts due from/to related parties are unsecured, interest-free and are repayable on demand, unless otherwise disclosed.

28.      RELATED PARTY TRANSACTIONS (continued)

Notes:

a)        These represent the services for production operations, the provision of various facilities and ancillary services, such as provision of different types of materials, medical and employee welfare services, maintenance and repair of major equipment and supply of water, electricity and heat to the Group, some of which may not be available from independent third parties or available on comparable terms.

b)        These include marketing, administration and management, management of oil and gas operations and integrated research services as well as other ancillary services relating to exploration, development, production and research activities of the Group. In addition, the CNOOC Group leased certain premises to the Group for use as office premises and staff quarters out of which they provided management services to certain properties.

c)        CNOOC Energy Technology & Services Limited leased FPSO vessels to the Group for use in oil production operations.

d)        The sales include crude oil, condensate oil, liquefied petroleum gas, natural gas and liquefied natural gas to the CNOOC Group. Individual sales contracts were entered into from time to time between the Group and the CNOOC Group.

e)        It is the market practice for sales terms to be determined based on the estimated reserves and production profile of the relevant gas fields. The long term sales contracts usually last for 5 to 20 years.

f)        CNOOC Finance is a 31.8% owned associate of the Company and also a subsidiary of CNOOC. Under the financial services framework agreement with CNOOC Finance dated December 1, 2016, CNOOC Finance continues to provide to the Group settlement, depository, discounting, loans and entrustment loans services. The agreement is effective from January 1, 2017 to December 31, 2019. The depository services were exempted from independent shareholders’ approval requirements under the Listing Rules. The Group's maximum daily outstanding balance for deposits stated in CNOOC Finance (including accrued interest but excluding funds placed for the purpose of extending entrustment loans pursuant to the entrustment loan services) in 2017 was RMB19,500 million (2016: RMB22,000 million).

g)        In September 2014, CNOOC provided CNOOC International Limited, a wholly-owned subsidiary of the Company a five-year uncommitted revolving loan facility for general purposes, with the principal amount of US$135 million of 0.95% per annum. As at December 31, 2017, the withdrawal amount of the loan was US$130 million(December 31, 2016: US$130 million); In December 2014, CNOOC provided the Company a five-year uncommitted revolving loan facility for general purposes, with the principal amount of US$600 million of 0.95% per annum. As at December 31, 2017, the withdrawal amount of the loan was US$564 million (December 31, 2016: US$564 million).

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RETIREMENT BENEFITS

12 Months Ended

Dec. 31, 2017

RETIREMENT BENEFITS [abstract]

Disclosure of retirement benefits

29.      RETIREMENT BENEFITS

All the Group's full-time employees in the PRC are covered by a state-managed retirement benefit plan operated by the government of the PRC, and are entitled to an annual pension. The PRC government is responsible for the pension liabilities to these retired employees. The Group is required to make annual contributions to the state-managed retirement benefit plan at rates ranging from 11% to 22% of the employees' base salaries.

The Company is required to make contributions to a defined contribution mandatory provident fund at a rate of 5% of the salaries of all full-time employees in Hong Kong. The related pension costs are expensed as incurred.

The Group provides retirement benefits for all local employees in overseas locations in accordance with relevant labor law, and provides employee benefits to expatriate staff in accordance with the relevant employment contracts.

During the year, the Group's pension costs charged to the consolidated statement of profit or loss and other comprehensive income amounted to RMB651 million (2016: RMB695 million, 2015: RMB613 million).

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NOTE TO THE CONSOLIDATED STATEMENT OF CASH FLOWS

12 Months Ended

Dec. 31, 2017

CONSOLIDATED STATEMENTS OF CASH FLOWS [abstract]

Disclosure of note to the consolidated statement of cash flows

30.      NOTE TO THE CONSOLIDATED STATEMENT OF CASH FLOWS

Reconciliation of profit/(loss) before tax to cash generated from operations

	2015	2016	2017
Profit/(loss) before tax	17,130	(5,275)	36,357
Adjustments for:
Interest income	(873)	(901)	(653)
Finance costs	6,118	6,246	5,044
Exchange losses/(gains), net	143	790	(356)
Share of (profits)/losses of associates	(256)	609	(302)
Share of profit of a joint venture	(1,647)	(533)	(553)
Investment income	(2,398)	(2,774)	(2,409)
Impairment and provision	2,746	12,171	9,130
Depreciation, depletion and amortization	73,439	68,907	61,257
Loss on disposal and write-off of property, plant and equipment	2,115	2,304	1,937
Others	70	-	-
Subtotal	96,587	81,544	109,452
Decrease/(increase) in trade receivables and other current assets	7,932	(2,820)	(1,073)
Decrease in inventories and supplies	1,427	922	1,464
(Decrease)/increase in trade and accrued payables and other payables	(9,851)	2,491	782
Cash generated from operations	96,095	82,137	110,625

30.      NOTE TO THE CONSOLIDATED STATEMENT OF CASH FLOWS (continued)

Reconciliation of liabilities arising from financing activities

The table below details changes in the Group's liabilities arising from financing activities, including both cash and non-cash changes. Liabilities arising from financing activities are those for which cash flows were, or future cash flows will be, classified in the Group's consolidated statement of cash flows as cash flows from financing activities.

	Loans and borrowings	Interest payable	Dividend payable	Total
	(Note 24)	(Note 23)
At January 1, 2017	150,476	1,244	-	151,720
Financing cash flows	(9,669)	(5,154)	(16,448)	(31,271)
Foreign exchange translation	(8,911)	51	(52)	(8,912)
Finance costs	354	5,040	-	5,394
Dividends declared	-	-	16,500	16,500
At December 31, 2017	132,250	1,181	-	133,431

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2017

COMMITEMENTS AND CONTINGENCIES [abstract]

Disclosure of commitments and contingencies

31.      COMMITMENTS AND CONTINGENCIES

(i)        Capital commitments

As at December31, 2017, the Group had the following capital commitments, principally for the construction of property, plant and equipment:

	2016	2017
Contracted, but not provided for (1)	46,515	46,704

(1)   The capital commitments contracted, but not provided for, include the estimated payments to the Ministry of Land and Resources of the PRC for the next five years with respect to the Group's exploration and production licenses.

The above table includes a commitment of approximately RMB4,030 million (December 31, 2016: RMB2,482 million) contracted with the CNOOC Group.

Capital commitments of a joint venture:

	2016	2017
Contracted, but not provided for	360	691

As at December 31, 2017, the Group had unutilized banking facilities amounting to approximately RMB53,749 million (December 31, 2016: RMB60,697 million).

(ii)      Operatingleasecommitments

a.Office properties

The Group leases certain of its office properties under operating lease arrangements. Leases for properties are negotiated for terms ranging from 6 months to 20 years.

As at December 31, 2017, the Group had total minimum lease payments under non-cancellable operating leases falling due as follows:

	2016	2017
Commitments due:
No later than one year	1,317	1,630
Later than one year and not later than   two years	896	1,048
Later than two years and not later than   five years	1,534	1,274
Later than five years	1,963	1,774
	5,710	5,726

The above table includes minimum lease payments of approximately RMB1,218 million (December 31, 2016: RMB639 million) to the CNOOC Group.

31.      COMMITMENTS AND CONTINGENCIES (continued)

(ii)      Operating lease commitments(continued)

a.       Office properties (continued)

Office properties commitments of a joint venture:

	2016	2017
Commitments due:
No later than one year	25	18
Later than one year and not later than two years	17	12
Later than two years and not later than five years	26	16
Later than five years	51	23
	119	69

b.       Plant and equipment

The Group leases certain of its plant and equipment under operating lease arrangements for a term from 1 year to 25 years.

As at December 31, 2017, the Group had total minimum lease payments under non-cancellable operating leases falling due as follows:

	2016	2017
Commitments due:
No later than one year	1,378	1,272
Later than one year and not later than two years	734	875
Later than two years and not later than five years	1,316	1,616
Later than five years	3,878	3,406
	7,306	7,169

The above table includes a commitment of approximately RMB3,366 million (December 31, 2016: RMB3,211 million) to the CNOOC Group.

31.      COMMITMENTS AND CONTINGENCIES (continued)

(iii)     Contingencies

(i)Two oil spill accidents ( the “Penglai 19-3 Oilfield Oil Spill Accidents”) occurred on June 4, and June 17, 2011 respectively at Platforms B and C of the Penglai 19-3 oilfield, which is being operated under a production sharing contract (the “PSC”) among CNOOC China Limited, a subsidiary of the Company, and two subsidiaries of ConocoPhillips, a U.S. based oil company, among which ConocoPhillips China Inc. (the “COPC”) was the operator and responsible for the daily operations of the oilfield when the Penglai 19-3 Oilfield Oil Spill Accidents occurred.

On August 10, 2015, the Company received a Notice Calling for Responses from the Qingdao Maritime Court of the People’s Republic of China (the “Qingdao Maritime Court”) for a public interest action filed by China Biodiversity Conservation and Green Development Foundation (the “Plaintiff”) in relation to the Penglai 19-3 Oilfield Oil Spill Accidents (the “Lawsuit”). The Lawsuit is lodged against COPC and CNOOC China Limited. On February 2, 2018, CNOOC China Limited received a ruling dated December 28, 2017 issued by Qingdao Maritime Court (the "Ruling"). Pursuant to the Marine Environment Protection Law of the People’s Republic of China amended in 2016, Qingdao Maritime Court ruled that the Plaintiff was not an appropriate entity to file Lawsuit, and rejected it. As none of the parties to the Lawsuit appealed within the time limit, the Ruling came into effect. Therefore, CNOOC China Limited bears no liability for the Lawsuit.

The Company is of the view that there was no material financial impact of the Penglai 19-3 Oilfield Oil Spill Accidents on the Company.

(ii)As a Chinese Resident Enterprise, the Company may be liable to pay taxes on the deemed interest income for the funding provided to its overseas subsidiaries starting from January 1, 2008. The Company has prepared contemporaneous documentation in accordance with applicable PRC tax laws and regulations and is currently awaiting confirmation from its in-charge tax authority.

The Group is subject to tax in numerous jurisdictions around the world. There are audits in progress and items under review. Difference in positions taken by taxation authorities over the interpretation and application of tax laws and regulations may increase the Group'stax liability. Management has assessed the possible future outcome of matters that are currently under dispute. The Company believes that an adequate provision for future tax liability has been included in the consolidated financial statements based on available information.

In addition to the matters mentioned above, the Group is dealing with a number of other lawsuits and arbitrations that arise in the ordinary course of business. While the results of these legal proceedings cannot be ascertained at this stage, the Company believes these proceedings are not expected to have a material effect on the consolidated financial statements.

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FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2017

FINANCIAL INSTRUMENTS [abstract]

Disclosure of financial instruments

32.      FINANCIAL INSTRUMENTS

Fair value of financial instruments

The Group enters into contracts to purchase and sell crude oil, natural gas and other energy commodities, and use derivative contracts, including futures, forwards, swaps and options for hedging and trading purposes (collectively derivative contracts). The Group also uses derivatives to manage foreign currency risk for non-trading purposes.

For purposes of estimating the fair value of the derivative contracts, wherever possible, the Group utilizes quoted market price and, if not available, estimates from third-party brokers. These brokers’ estimates are corroborated with multiple sources and/or other observable market data utilizing assumptions that market participants would use when pricing the assets or liabilities, including assumptions about risk and market liquidity.

The carrying values of the Group’s cash and cash equivalents, time deposits, trade receivables, other current assets, short-term loans, trade and accrued payables, other payables and accrued liabilities approximated to their fair values at the reporting date due to the short maturity of these instruments.

The carrying amount of the Group’s non-current non-publicly traded equity investments represents an appropriate estimate of their fair values, as sufficient information is not available recently to measure their fair values as at December 31, 2017 and 2016.

The fair value of the Group's long term bank loans with floating interest rates approximated to the carrying amount as at December 31, 2017 and 2016.

The estimated fair value of the Group's long term guaranteed notes was approximately RMB128,315 million as at December31, 2017 (2016: RMB140,135 million), which was determined by reference to the market price as at December 31, 2017.

32.      FINANCIAL INSTRUMENTS (continued)

Fair value hierarchy

The Group uses the following hierarchy that reflects the significance of the inputs used in making the fair value measurement:

Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities. Active markets are those in which transaction occur in sufficient frequency and volume to provide pricing information on an on-going basis.

Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options, including those that have prices similar to quoted market prices, private equity funds and corporate wealth management products. The Group obtains information from sources of independent price publications, over-the-counter broker quotes and the fund management’s quotations as at the reporting date.

Level 3: fair value measurements are those derived from valuation techniques that include inputs for the asset or liability that are not based on observable market data (unobservable inputs), or where the observable data does not support the majority of the instruments fair value.

As at December 31, 2017 and December 31, 2016, the Group held the following financial instruments measured at fair value for each hierarchy respectively:

Assets measured at fair value	December 31 2017	Level 1	Level 2	Level 3
Other financial assets-current
Corporate wealth management products	66,229	-	66,229	-
Money market funds	8,115	8,115	-	-
Derivative financial assets – current	-	-	-	-
Equity investments
Non-publicly traded investments- current	14	-	14	-
Publicly traded investments-non current	781	781	-	-
	75,139	8,896	66,243	-
Liabilities measured at fair value
Derivative financial liabilities – current	-	-	-	-

32.      FINANCIAL INSTRUMENTS (continued)

Fair value hierarchy (continued)

Assets measured at fair value	December 31 2016	Level 1	Level 2	Level 3
Other financial assets-current
Corporate wealth management products	46,958	-	46,958	-
Money market funds	5,931	5,931	-	-
Derivative financial assets – current	428	-	428	-
Equity investments
Non-publicly traded investments- current	15	-	15	-
Publicly traded investments-non current	1,391	1,391	-	-
	54,723	7,322	47,401	-
Liabilities measured at fair value
Derivative financial liabilities – current	(426)	-	(426)	-

For financial assets and liabilities arising from derivative contracts, inputs may be readily observable, market-corroborated or generally unobservable. The Group utilizes valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. To value longer term transactions and transactions in less active markets for which pricing information is not generally available, unobservable inputs may be used.

No amounts have been transferred between the different levels of the fair value hierarchy for the year.

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CONCENTRATION OF CUSTOMERS

12 Months Ended

Dec. 31, 2017

CONCENTRATION OF CUSTOMERS [abstract]

Disclosure of concentration of customers

33.      CONCENTRATION OF CUSTOMERS

A substantial portion of the Group's oil and gas commodities sales to third-party customers is made to a small number of customers on credit. Details of the gross sales to these top five third party customers are as follows:

	2015	2016	2017
China Petroleum & Chemical Corporation*	14,692	9,659	15,488
PetroChina Company Limited*	5,502	6,923	11,957
BP p.l.c.	3,093	2,843	3,108
Phillips 66	N/A	N/A	2,631
Royal Dutch Shell PLC	6,917	3,661	2,627
EOG Resources, Inc.	3,746	2,660	N/A

*    These transactions are with other state-owned enterprises.

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FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES

12 Months Ended

Dec. 31, 2017

FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES [abstract]

Disclosure of financial risk management objectives and policies

34.      FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES

The Group's principal financial instruments comprise bank loans, long term guaranteed notes, equity investment and other financial assets, cash and short term deposits. The Group has various other financial assets and liabilities such as trade receivables, trade and accrued payables, which arise directly from its operations.

The Group is exposed to credit risk, oil and gas price risk, currency risk, interest rate risk and liquidity risk.

The Group's senior management oversees the management of these risks. The Group's senior management is supported by various departments that advise on financial risks and the appropriate financial risks governance framework for the Group. Those departments provide assurance to the Group's senior management that the Group's financial risk-taking activities are governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite.

34.      FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES (continued)

(i)Credit risk

The carrying amounts of the Group's cash and cash equivalents, time deposits, money market funds and corporate wealth management products, trade receivables and other receivables, and other current assets except for prepayments represent the Group's maximum exposure to credit risk in relation to its financial assets.

The significant portion of the Group's trade receivables is related to the sale of oil and natural gas to third party customers. The Group performs ongoing credit evaluations of the customers' financial condition and collateral may be required from customers. The Group made an impairment allowance on doubtful receivables and actual losses have been within management's expectation.

Concentrations of credit risk are managed by customer/counterparty and by geographical region. At December 31, 2017, the Group has certain concentrations of credit risk as 0.16% (2016: 1%) and 7.63% (2016: 5%) of the Group's trade receivables were due from the Group's largest third-party customer and the five largest third-party customers, respectively.

No other financial assets carry a significant exposure to credit risk.

(ii)Oil and gas price risk

Since the Group makes reference to international oil prices to determine its realized oil price, fluctuations in international oil price would have a significant impact on the Group's sales revenue, profit, assets value and cashflow. In addition, certain of the Group's natural gas sales contracts contain price adjustment provisions. Any changes in international oil prices, inflation rate and domestic natural gas price policies may result in changes in natural gas prices, which will affect the Group's profitability. In North America, the majority of the Group's oil and gas production is sold under short-term contracts, exposing the Group to the risk of price movements. Other energy contracts the Group enters into also expose the Group to oil and gas price risk between the time the Group purchases and sells contracted volumes.

(iii)Currency risk

Substantially all of the Group's oil and gas sales are denominated in Renminbi and United States dollars ("US dollars"). Starting from July 21, 2005, China reformed the exchange rate regime by moving into a managed floating exchange rate regime based on market supply and demand with reference to a basket of currencies. Renminbi would no longer be pegged to the US dollars. From January 1, 2017 to December 31, 2017 (the last working day in 2017), Renminbi has appreciated by approximately 6.16% (December 31, 2016: depreciated by approximately 6.39%) against the US dollars. At December 31, 2017, approximately 82% (December 31, 2016: 88%, December 31, 2015: 89%) of the Group's cash and cash equivalents and time deposits with maturity over three months were denominated in Renminbi, and the remaining amounts were substantially denominated in US dollars and Hong Kong dollars. The Group also has exposures to currencies other than the US dollars, such as Canadian dollar and British Pounds as such exposures are considered insignificant.

34.      FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES (continued)

(i)Currency risk(continued)

Management has assessed the Group's exposure to foreign currency risk by using a sensitivity analysis on the change in foreign exchange rate of the US dollars, to which the Group is mainly exposed to as at December 31, 2017 and 2016. Based on management's assessment at December 31, 2017, a 5% strengthening/weakening of RMB against US dollars would have increased/decreased the profit for the year of the Group by 0.06% (December 31, 2016: 6.63%) and the equity of the Group by 0.31% (December 31, 2016: 0.46%). This analysis has been determined assuming that the change in foreign exchange rates had occurred at the end of the reporting period and had been applied to the foreign currency balances to which the Group has significant exposure with all other variables held constant.  The analysis is performed on the same basis for 2016.

Senior management is closely monitoring the Group's net exposure to foreign currency risk. The appreciation of Renminbi against the US dollars may have the following impact on the Group. On one hand, since the benchmark oil and gas prices are usually in US dollars against Renminbi, the Group's oil and gas sales may decrease due to the depreciation of the US dollars against Renminbi. On the other hand, the depreciation of the US dollars against Renminbi will also decrease the Group's costs for imported equipment and materials, most of which are denominated in the US dollars. In addition, the debt repayment by the Group will decrease since all of the Group’s interest-bearing debts are also denominated in the US dollars.

(ii)Interest rate risk

The interest rate risk is closely monitored by the Group's senior management. As at the end of 2017, the interest rates for 95.5% of the Group's debts were fixed. Apart from borrowing for Tangguh LNG Project, all of the Group's long term debts are fixed rate. The weighted average term of the Group's debt balance outstanding was approximately 9.35 years. The fixed interest rates can reduce the volatility of finance costs under uncertain environments and the Group's exposure to changes in interest rates is not expected to be material.

(iii)Liquidity risk

The Group manages its liquidity risk by regularly monitoring its liquidity requirements and its compliance with debt covenants to ensure that it maintains sufficient cash and cash equivalents, and readily realizable equity investments and other financial assets, and adequate time deposits to meet its liquidity requirements in the short and long term. In addition, bank facilities have been put in place for contingency purposes.

The Group's trade and accrued payables, other payables and accrued liabilities are all due for settlement within six months after the reporting date.

34.      FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES (continued)

(iv)Capital management

The primary objectives of the Group's capital management are to safeguard the Group's ability to continue as a going concern and to maintain healthy capital ratios in order to support its business and maximize shareholders' value.

The Group manages its capital structure and makes adjustments to it in light of changes in economic conditions. To maintain or adjust the capital structure, the Group may return capital to shareholders, raise new debt or issue new shares. No changes were made in the objectives, policies or processes for managing capital during the years end December 31, 2015, 2016 and 2017.

The Group monitors capital on the basis of the debt to capital ratio, which is calculated as interest-bearing debts divided by total capital (equity attributable to owners of the parent plus interest-bearing debts).

	2015	2016	2017
Interest-bearing debts	164,645	150,476	132,250
Equity attributable to owners of the parent	386,041 386,041	382,371	379,975
Total capital	550,686	532,847	512,225
Gearing ratio	29.9%	28.2%	25.8%

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CHARGE OF ASSETS

12 Months Ended

Dec. 31, 2017

CHARGE OF ASSETS [abstract]

Disclosure of charge of assets

35.      CHARGE OF ASSETS

CNOOC NWS Private Limited, a wholly-owned subsidiary of the Group, together with the other joint venture partners and the operator of the NWS Project, signed a Deed of Cross Charge and an Extended Deed of Cross Charge whereby certain liabilities incurred or to be incurred, if any, by the Company in respect of the NWS Project are secured by its interest in the NWS Project.

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2017

SUBSEQUENT EVENTS [abstract]

Disclosure of subsequent events

36.      SUBSEQUENT EVENTS

The Group has no significant subsequent events needed to be disclosed in the consolidated financial statements.

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APPROVAL OF THE FINANCIAL STATEMENTS

12 Months Ended

Dec. 31, 2017

APPROVAL OF THE FINANCIAL STATEMENTS [abstract]

Disclosure of approval of the financial statements

37.      APPROVAL OF THE FINANCIAL STATEMENTS

The consolidated financial statements were approved and authorized for issue by the Board of Directors on March 29, 2018.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2017

Significant accounting policies [abstract]

Basis of preparation

These consolidated financial statements have been prepared under the historical cost convention, except for as detailed in the accounting policies notes hereafter. These consolidated financial statements are presented in Renminbi ("RMB") and all values are rounded to the nearest million except when otherwise indicated.

Basis of consolidation

Basis of consolidation

The consolidated financial statements include the financial statements of the Company and its subsidiaries for the year ended December 31, 2017.

The results of subsidiaries are consolidated from the date of acquisition, being the date on which the Group obtains control, and continue to be consolidated until the date that such control ceases. The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.

The results of subsidiaries are included in the Company's statement of profit or loss and other comprehensive income to the extent of dividends received and receivable. The Company's interests in subsidiaries are stated at cost less any impairment losses.

All intra-group balances, income and expenses and unrealized gains and losses and dividends resulting from intra-group transactions are eliminated in full.

The three years ended

Re: the client want to keep consistent with the disclosure in last year's 20-F, which was "December 31, 2016".

Business combinations and goodwill

Business combinations and goodwill

Business combinations 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 the Group, liabilities assumed by the Group to the former owners of the acquiree and the equity interests issued by the Group in exchange for control of the acquiree.  For each business combination, the Group elects whether it measures 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 related costs incurred are included in profit or loss.

When the Group acquires a business, it assesses the financial assets acquired and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree.

If the business combination is achieved in stages, the Group's previously held equity interest in the acquiree is remeasured to fair value at the acquisition date through profit or loss.

Any contingent consideration to be transferred by the acquirer is recognized at fair value at the acquisition date. Contingent consideration classified as an asset or liability is measured at subsequent reporting dates in accordance with IFRS 9/HKFRS 9 (2009) or IAS 39/HKAS 39, with the corresponding gain or loss being recognized in profit or loss. Contingent consideration that is classified as equity is not remeasured and subsequent settlement is accounted for within equity.

Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the amount recognized for non-controlling interests and any fair value of the Group's previously held equity interests in the acquiree over the identifiable net assets acquired and liabilities assumed. If the sum of this consideration and other items is lower than the fair value of the net assets of the business acquired, the difference is recognized in profit or loss as a gain on bargain purchase.

3.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Business combinations and goodwill(continued)

After initial recognition, goodwill is measured at cost less any accumulated impairment losses.  Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the carrying value may be impaired. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group's cash-generating units, or groups of cash-generating units, that are expected to benefit from the synergies of the combination, irrespective of whether other assets or liabilities of the Group are assigned to those units or groups of units.

Impairment is determined by assessing the recoverable amount of the exploration and production ("E&P") segment, using value in use, to which the goodwill relates. Where the recoverable amount of the cash-generating unit (group of cash-generating units) is less than the carrying amount, an impairment loss on goodwill is recognized. An impairment loss recognized for goodwill is not reversed in a subsequent period.

Where goodwill has been allocated to a cash-generating unit (or group of cash-generating units) and part of the operation within that unit is disposed of, the goodwill associated with the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on the disposal. Goodwill disposed of in these circumstances is measured based on the relative value of the operation disposed of and the portion of the cash-generating unit retained.

Subsidiaries

Subsidiaries are all those entities over which the Group has power over the investee such that the Group is able to direct the relevant activities, has exposure or rights to variable returns from its involvement with the investee and has the ability to use its power over the investee to affect the amount of the investor's returns.

Associates

Based on the Group's ownership percentage (considering its direct ownership as well as potentially exercisable or convertible shares) and other contractual rights, the Group has significant influence over its associates, rather than the power to control.

The Group's investments in associates are stated in the consolidated statement of financial position at the Group's share of net assets under the equity method of accounting, less any impairment losses. Adjustments are made to bring into line any dissimilar accounting policies that may exist. Under the equity method, an investment in an associate is initially recognized in the consolidated statement of financial position at cost and adjusted thereafter to recognize the Group's share of the profit or loss and other comprehensive income of the associate. Unrealized gains and losses resulting from transactions between the Group and its associates are eliminated to the extent of the Group's investments in the associates, except where unrealized losses provide evidence of an impairment of the asset transferred. Goodwill arising from the acquisition of associates is included as part of the Group's investments in associates and is not individually tested for impairment.

Joint arrangements

Certain of the Group's 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 control

Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control.

Joint operations

Some arrangements have been assessed by the Group 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 the Group's interests in production sharing arrangements and certain joint operation.

The Group entered into numerous production sharing arrangements or similar agreements in China and overseas countries. The Group's participating interest may vary in each arrangement. The Group, as one of the title owners under certain exploration and/or production licenses or permits, is required to bear exploration (with some exceptions in China), development and operating costs together with other co-owners based on each owner's participating interest. Once production occurs, a certain percentage of the annual production or revenue is first distributed to the local government, which, in most cases, with the nature of royalty and other taxes or expenses, and the rest of the annual production or revenue is allocated among the co-owners.

The Group accounts for the assets, liabilities, revenues and expenses relating to its interest in a joint operation in accordance with the IFRSs/HKFRSs applicable to the particular assets, liabilities, revenues and expenses.

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.

The Group's investments in joint ventures are stated in the consolidated statement of financial position at the Group's share of net assets under the equity method of accounting, less any impairment losses. Adjustments are made to bring into line any dissimilar accounting policies that may exist. Under the equity method, an investment in a joint venture is initially recognized in the consolidated statement of financial position at cost and adjusted thereafter to recognize the Group's share of the profit or loss and other comprehensive income of the joint venture. Where the profit sharing ratios are different to the Group's equity interest, the share of post-acquisition results of the joint ventures is determined based on the agreed profit sharing ratio. Unrealized gains and losses resulting from transactions between the Group and its joint ventures are eliminated to the extent of the Group's investments in the joint ventures, except where unrealized losses provide evidence of an impairment of the asset transferred. Goodwill arising from the acquisition of joint ventures is included as part of the Group's investments in joint ventures and is not individually tested for impairment.

Related parties

A party is considered to be related to the Group if:

(a)the party is a person or a close member of that person's family and that person

(i)has control or joint control of the Group;

(ii)has significant influence over the Group; or

(iii)is a member of the key management personnel of the Group or of a parent of the Group;

(b)the party is an entity where any of the following conditions applies:

(i)the entity and the Group are members of the same group;

(ii)one entity is an associate or joint venture of the other entity (or of a parent, subsidiary or fellow subsidiary of the other entity);

(iii)the entity and the Group are joint ventures of the same third party;

(iv)one entity is a joint venture of a third entity and the other entity is an associate of the third entity;

(v)the entity is a post-employment benefit plan for the benefit of employees of either the Group or an entity related to the Group;

(vi)the entity is controlled or jointly controlled by a person identified in (a); and

(vii)a person identified in (a)(i) has significant influence over the entity or is a member of the key management personnel of the entity (or of a parent of the entity).

Impairment of non-financial assets other than goodwill

Where an indication of impairment exists, or when annual impairment testing for an asset is required (other than inventories, deferred tax assets, financial assets and goodwill), the asset's recoverable amount is estimated. An asset's recoverable amount is the higher of the asset's or cash-generating unit's value in use and its fair value less costs of disposal, and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets, in which case the recoverable amount is determined for the cash-generating unit to which the asset belongs.

An impairment loss is recognized only if the carrying amount of an asset exceeds its recoverable amount. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. An impairment loss is charged to profit or loss in the period in which it arises in those expense categories consistent with the function of the impaired asset.

An assessment is made at the end of each reporting period as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss of an asset other than goodwill is reversed only if there has been a change in the estimates used to determine the recoverable amount of that asset, but not to an amount higher than the carrying amount that would have been determined (net of any depreciation/amortization) had no impairment loss been recognized for the asset in prior years. A reversal of such an impairment loss is credited to profit or loss in the period in which it arises.

Property, plant and equipment

Property, plant and equipment comprise oil and gas properties, and vehicles and office equipment and others.

(a)Oil and gas properties

For oil and gas properties, the successful efforts method of accounting is adopted. The Group capitalizes the initial acquisition costs of oil and gas properties. Impairment of initial acquisition costs is recognized based on exploratory experience and management judgement and charged to profit and loss as exploration expenses. Upon discovery of commercial reserves, acquisition costs are transferred to proved properties. The costs of drilling and equipping successful exploratory wells, all development expenditures 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 are capitalized. The costs of unsuccessful exploratory wells and all other exploration costs are expensed as incurred.

The Group carries exploratory well costs as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Group is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expenses. Exploratory wells that discover potentially economic reserves in areas where major capital expenditure will be required before production would begin and when the major capital expenditure depends upon the successful completion of further exploratory work remain capitalized and are reviewed periodically for impairment.

Producing oil and gas properties are depreciated on a unit-of-production basis over the proved developed reserves. Common facilities that are built specifically to service production directly attributed to designated oil and gas properties are depreciated 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.

Capitalized acquisition costs of proved properties are depreciated on a unit-of-production method over the total proved reserves of the relevant oil and gas properties.

(a)Vehicles, office equipment and others

Vehicles, office equipment and others are stated at cost less accumulated depreciation and impairment losses. The straight-line method is adopted to depreciate the cost less any estimated residual value of these assets over their expected useful lives. The useful lives of vehicles, office equipment and other assets are in line with their beneficial periods.

Where parts of an item of property, plant and equipment have different useful lives, the cost of that item is allocated on a recoverable basis among the parts and each part is depreciated separately.

Residual values, useful lives and the depreciation method are reviewed and, adjusted if appropriate, at each reporting date.

Any gains and losses on disposals of property, plant and equipment (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) are recognized in profit or loss.

Intangible assets (other than goodwill)

The intangible assets of the Group comprise software, gas processing rights of the NWS Project, marketing transportation and storage contracts, drilling rig contracts and seismic data usage rights. Intangible assets with finite lives are carried at cost, less accumulated amortization and accumulated impairment losses. The cost of intangible assets acquired in a business combination is the fair value as at the date of acquisition. Intangible assets with finite lives except for gas processing rights, are amortized on the straight-line basis over the useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization period and the amortization method for an intangible asset with a finite useful life are reviewed at least at each financial year end.

The intangible assets regarding software have been amortized on the straight-line basis over their respective useful lives. The intangible asset regarding the gas processing rights has been amortized upon the commercial production of the liquefied natural gas on a unit-of-production basis over the total proved reserves of the relevant asset. The intangible assets regarding the marketing transportation and storage contracts and drilling rig contracts are amortized over the life of the contracts on the straight-line basis. The intangible assets related to the seismic data usage rights are amortized over the estimated useful life of the seismic data.

Major maintenance and repairs

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets and overhaul costs. Where an asset or part of an asset that was separately depreciated and is replaced, and it is probable that future economic benefits associated with the item will flow to the Group, the replacement expenditure is capitalized. Where part of the asset was not separately considered as a component, the replacement value is used to estimate the carrying amount of the replaced assets which is immediately written off. All other maintenance costs are expensed as incurred.

Research and development costs

All research costs are expensed as incurred.

Expenditure (other than that relating to oil and gas properties discussed above) incurred on projects to develop new products is capitalized and deferred only when the Group can demonstrate the technical feasibility of completing the intangible asset so that it will be available for use or sale, its intention to complete and its ability to use or sell the asset, how the asset will generate future economic benefits, the availability of resources to complete the project and the ability to measure reliably the expenditure during the development. Product development expenditure which does not meet these criteria is expensed when incurred.

Financial assets

All recognized financial assets are subsequently measured in their entirety at either amortized cost or fair value, depending on the classification of the financial assets.

(a)   Financial assets at amortized cost

Debt instruments and hybrid contracts that meet the following conditions are subsequently measured at amortized cost less impairment loss:

•  the asset is held within a business model whose objective is to hold assets in order to collect contractual cash flows; and

•  the contractual terms of the instrument give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

All other financial assets are subsequently measured at fair value.

The effective interest method is a method of calculating the amortized cost of a debt instrument and of allocating interest income over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees and points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the debt instrument, or, where appropriate, a shorter period, to the net carrying amount on initial recognition. Interest income for debt instruments measured subsequently at amortized cost is recognized in profit or loss in accordance with the policies set out for "Revenue Recognition" below.

(a)   Financial assets at fair value through profit or loss (FVTPL)

Investments in equity instruments are classified as at FVTPL, unless the Group designates such investment that is not held for trading as at FVTOCI on initial recognition.

A financial asset is held for trading if it has been acquired principally for the purpose of selling it in the near term or it is a derivative that is not designated and effective as a hedging instrument.

Debt instruments that do not meet the amortized cost criteria (see (a) above) are measured at FVTPL. In addition, debt instruments that meet the amortized cost criteria but are designated as at FVTPL are measured at FVTPL. A debt instrument may be designated as at FVTPL upon initial recognition if such designation eliminates or significantly reduces a measurement or recognition inconsistency that would arise from measuring assets or liabilities or recognizing the gains and losses on them on different bases.

Financial assets at FVTPL are measured at fair value at the end of each reporting period, with any gains or losses arising on remeasurement recognized in profit or loss.

(b)  Financial assets at fair value through other comprehensive income (FVTOCI)

On initial recognition, the Group can make an irrevocable election (on an instrument-by-instrument basis) to designate investments in equity instruments as at FVTOCI.  The Group has investments in certain equity instruments (publicly traded or non-publicly traded), the purpose of which are not held for trading, but held for medium or long-term strategic purpose. Therefore, those investments in equity securities are designated as at FVTOCI.

Investments in equity instruments at FVTOCI are initially measured at fair value plus transaction costs. Subsequently, they are measured at fair value with gains and losses arising from changes in fair value recognized in other comprehensive income and accumulated in the other reserves. The cumulative gain or loss will not be reclassified to profit or loss on disposal of the investments.

Dividends on these investments in equity instruments are recognized in profit or loss when the Group’s right to receive the dividends is established in accordance with IAS 18/HKAS 18 Revenue, unless the dividends clearly represent a recovery of part of the cost of the investment.

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.

An analysis of fair values of financial instruments and further details as to how they are measured are provided in note 32.

Impairment of financial assets

The Group assesses at each reporting date whether there is any objective evidence that a financial asset, other than those at FVTPL and FVTOCI, or a group of financial assets may be impaired.

In relation to trade and other receivables, a provision for impairment is made when there is objective evidence (such as the probability of insolvency or significant financial difficulties of the debtor and significant changes in the technological, market, economic or legal environment that have an adverse effect on the debtor) that the Group will not be able to collect all of the amounts due under the original terms of an invoice.

If there is objective evidence that an impairment loss on financial assets measured at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset's carrying amount and the present value of estimated future cash flows (excluding future credit losses that have not been incurred) discounted at the financial asset's original effective interest rate (the effective interest rate computed at initial recognition). The carrying amount of the asset is reduced either directly or through the use of an allowance account. The amount of the impairment loss is recognized in profit or loss.

If, in a subsequent year, the amount of the estimated impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized, the previously recognized impairment loss is reduced either directly or by adjusting the allowance account. Any subsequent reversal of an impairment loss is recognized in profit or loss, to the extent that the carrying value of the asset does not exceed amortized cost at the reversal date.

Derecognition of financial assets

A financial asset (or, where applicable a part of a financial asset or part of a group of similar financial assets) is derecognized when:

(i)    The contractual rights to receive cash flows from the asset have expired; or

(ii)   the Group has transferred its rights to receive cash flows from the asset, or the Group retains the contractual rights to receive the cash flows from the asset, but has assumed an obligation to pay the received cash flows in full without material delay to a third party under a "pass-through" arrangement; and either (a) has transferred substantially all the risks and rewards of the asset, or (b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has no control of the asset.

When the Group has transferred its rights to receive cash flows from an asset or has entered into a pass-through arrangement, it evaluates if and to what extent it has retained the risk and rewards of ownership of the asset. When it has neither transferred nor retained substantially all the risks and rewards of the asset nor transferred control of the asset, the Group continues to recognize the transferred asset to the extent of the Group's continuing involvement. In that case, the Group also recognizes an associated liability. The transferred asset and the associated liability are measured on a basis that reflects the rights and obligations that the Group has retained.

Financial liabilities at amortized cost (including interest-bearing loans and borrowings)

Financial liabilities including trade and accrued payables, other payables and accrued liabilities, and interest-bearing loans and borrowings are initially stated at fair value less directly attributable transaction costs and are subsequently measured at amortized cost, using the effective interest method. The related interest expense is recognized within "Finance costs" in profit or loss.

Gains and losses are recognized in profit or loss when the liabilities are derecognized as well as through the amortization process.

Financial guarantee contracts

A financial guarantee contract is recognized initially at its fair value including transaction costs that are directly attributable to the issue of the guarantee. Subsequent to initial recognition, the liability is measured at the higher of the best estimate of the expenditure required to settle the present obligation at the reporting date and the amount recognized less cumulative amortization.

Derecognition of financial liabilities

Financial liabilities are derecognized when the obligations under the liabilities are discharged, cancelled, or have expired.

When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and a recognition of a new liability, and the difference between the respective carrying amounts is recognized in profit or loss.

Offsetting of financial instruments

Financial assets and liabilities are offset and the net amount reported in the consolidated statement of financial position, if and only if, there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, or to realize the assets and settle the liabilities simultaneously.

Inventories and supplies

Inventories primarily consist of oil and supplies, including items for repairs and maintenance of oil and gas properties. Inventories are stated at the lower of cost and net realizable value. Costs of inventories and supplies represent purchase or production cost of goods and are determined on a weighted average basis.

Cash and cash equivalents

Cash and cash equivalents comprise cash at banks and on hand and short term deposits with an original maturity of three months or less.

Provisions

(a)General

A provision is recognized 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 "Finance costs" in profit or loss.

(b)Dismantlement liability

Dismantlement liability is recognized when the Group has a present legal or constructive obligation as a result of the past events, and it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of the obligation can be made. A corresponding amount equivalent to the provision is also recognized as part of the cost of the related property, plant and equipment. The amount recognized is 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. The unwinding of the discount on the dismantlement provision is included as a finance cost.

Income tax

Income tax comprises current and deferred tax. Income tax is recognized in the consolidated statement of profit or loss and other comprehensive income, either as an expense as it relates to operating activities or as a component of the applicable categories of other comprehensive income or expense.

Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantially enacted, by the reporting date, in the countries where the Group operates and generates taxable income.

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 the accounting profit nor taxable profit or loss; andin respect of taxable temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, 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.

Deferred tax assets are recognized for all deductible temporary differences, the carryforward of unused tax credits and any unused tax losses to the extent that it is probable that taxable profit and taxable temporary differences will be available against which the deductible temporary differences, the carryforward of unused tax credits and unused tax losses can be utilized, except:

·when the deferred tax assets relating to the deductible temporary differences arise 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 the accounting profit nor taxable profit or loss; and

·in respect of deductible temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, deferred tax assets are only recognized to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized.

The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized. Unrecognized deferred tax assets are reassessed at each reporting date and are recognized to the extent that it is probable that sufficient taxable profit and taxable temporary differences will be available to allow all or part of the deferred tax asset to be utilized.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the reporting date.

Deferred tax assets and deferred tax liabilities are offset if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority.

Revenue recognition

Revenue is recognized when it is probable that the economic benefits will flow to the Group and when the revenue can be measured reliably, on the following bases:

(a)Oil and gas sales

Oil and gas sales represent the invoiced value of sales of oil and gas attributable to the interests of the Group, net of royalties, obligations to governments and other mineral interest owners. Revenue from the sale of oil and gas is recognized when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. Revenue from the production of oil and gas in which the Group has a joint interest with other producers is recognized based on the Group’s working interest and the terms of the relevant production sharing contracts. Differences between production sold and the Group’s share of production are not significant.

Oil and gas lifted and sold by the Group above or below the Group's participating interests in the production sharing contracts results in overlifts and underlifts. The Group records these transactions in accordance with the entitlement method under which overlifts are recorded as liabilities and underlifts are recorded as assets at year-end oil prices. Settlement will be in kind or in cash when the liftings are equalised or in cash when production ceases.

The Group has entered into gas sale contracts with customers, which contain take-or-pay clauses. Under these contracts, the Group makes a long term supply commitment in return for a commitment from the buyer to pay for minimum quantities, whether or not it takes delivery. These commitments contain protective (force majeure) and adjustment provisions. If a buyer has a right to get a "make up" delivery at a later date, revenue recognition is deferred. If no such option exists according to the contract terms, revenue is recognized when the take-or-pay penalty is triggered.

(a)Marketing revenues

Marketing revenues principally represent the sales of oil and gas from the foreign partners under the production sharing contracts and revenues from the trading of oil and gas through the Company’s subsidiaries. The cost of the oil and gas sold is included in “Crude oil and product purchases” in the consolidated statement of profit or loss and other comprehensive income. In addition, the Group’s marketing activities in North America involves entering into contracts to purchase and sell crude oil, natural gas and other energy commodities, and use derivative contracts, including futures, forwards, swaps and options for hedging and trading purposes (collectively derivative contracts). Any change in the fair value is also included in marketing revenue.

(b)Other income

Other income mainly represents project management fees charged to foreign partners, handling fees charged to customers, [the sales of third party diluents to third parties] and gains from disposal of oil and gas properties and is recognized when the services have been rendered or the properties have been disposed of. Reimbursement of insurance claims is recognized when the compensation becomes receivable.

(c)Dividend income

Dividend income is recognized when the Group's right to receive payment is established.

(d)Interest income

Interest income is recognized as it accrues using the effective interest method.

The Group presents taxes collected from customers in the consolidated statement of profit or loss and other comprehensive income on a net basis.

Share-based payment transactions

Share-based payment transactions

Employees (including directors) of the Group receive remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments ("equity-settled transactions").

The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which they are granted. The fair value is determined by using the Black-Scholes option pricing model, further details of which are given in note 26.

The cost of equity-settled transactions is recognized, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled. The cumulative expense recognized for equity-settled transactions at the end of the each reporting period until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The charge or credit to profit or loss for a period represents the movement in the cumulative expense recognized as at the beginning and end of that period.

No expense is recognized for awards that do not ultimately vest for the Group.

No equity-settled award was cancelled or modified during the years ended December 31, 2015, 2016 and 2017.

The dilutive effect of outstanding options is reflected as additional share dilution in the computation of earnings per share.

Retirement and termination benefits

The Group participates in defined contribution plans in accordance with local laws and regulations for full-time employees in the PRC and other countries in which it operates. The Group's contributions to these defined contribution plans are charged to profit or loss in the year to which they relate.

Borrowing costs

Borrowing costs consist of interest and other costs that an entity incurs in connection with the borrowing of funds. Borrowing costs directly relating to the acquisition, construction or production of a qualifying asset that necessarily takes a substantial period of time to get ready for its intended use or sale are capitalized as part of the cost of the respective assets. All other borrowing costs are expensed in the period in which they are incurred.

Foreign currencies

These consolidated financial statements are presented in RMB. Each entity in the Group maintains its books and records in its own functional currency. Foreign currency transactions recorded by the entities of the Group are initially recorded using their respective exchange rates ruling at the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are retranslated at the exchange rates ruling at the end of the reporting period. All differences arising on settlement or translation of monetary items are taken to profit or loss. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rates at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined. The gain or loss arising on retranslation of a non-monetary item is treated consistently with the recognition of the gain or loss on change in fair value of the item.

The functional currencies of certain entities within the Group are currencies other than RMB. As at the end of the reporting period, the assets and liabilities of these entities are translated into the presentation currency of the Group at the exchange rates ruling at the reporting date, and their statement of profit or loss and other comprehensive income are translated into RMB at the weighted average exchange rates for the year. The resulting exchange differences are included in the cumulative translation reserve. On disposal of a foreign operation, the deferred cumulative amount recognized in equity relating to that particular foreign operation is recognized in profit or loss.

Operating leases

Leases where substantially all the rewards and risks of ownership of assets remain with the lessor are accounted for as operating leases. Where the Group is the lessee, rentals payable under operating leases are charged to profit or loss on the straight-line basis over the lease terms.

Prepaid land lease payments under operating leases in China are initially stated at cost and subsequently amortized on the straight-line basis over the lease terms.

Contingencies

A contingent liability is disclosed when the existence of an obligation will only be confirmed by future events or when the amount of the obligation cannot be measured reliably.

A contingent asset is not recognized in the financial statements, but is disclosed when an inflow of economic benefits is probable.

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OIL AND GAS SALES (Tables)

12 Months Ended

Dec. 31, 2017

OIL AND GAS SALES [abstract]

Schedule of oil and gas sales

	2015	2016	2017
Gross sales	150,618	124,648	156,304
Less: Royalties	(2,646)	(2,398)	(3,226)
PRC government’s share of oil	(1,375)	(925)	(1,190)
Oil and gas sales	146,597	121,325	151,888

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SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2017

SEGMENT INFORMATION [abstract]

Schedule of segment financial information

	E&P			Trading business			Corporate			Eliminations			Consolidated
	2015	2016	2017	2015	2016	2017	2015	2016	2017	2015	2016	2017	2015	2016	2017
External revenue	137,243	114,935	142,429	33,777	30,986	43,618	417	569	343	-	-	-	171,437	146,490	186,390
Intersegment revenue*	12,339	10,676	14,737	(12,339)	(10,676)	(14,737)	85	113	84	(85)	(113)	(84)	-	-	-
Total revenue	149,582	125,611	157,166	21,438	20,310	28,881	502	682	427	(85)	(113)	(84)	171,437	146,490	186,390
Segment profit/(loss) for the year	15,695	(346)	23,863	879	656	808	6,048	30,701	6,391	(2,376)	(30,374)	(6,385)	20,246	637	24,677
Amounts included in the measure of        segment profit or loss
Operating expenses	(28,372)	(23,220)	(24,282)	-	-	-	-	-	-	-	9	-	(28,372)	(23,211)	(24,282)
Taxes other than income tax	(10,748)	(6,901)	(7,169)	7	-	-	(29)	(40)	(41)	-	-	-	(10,770)	(6,941)	(7,210)
Exploration expenses	(9,973)	(7,393)	(6,896)	-	-	-	-	-	-	73	34	15	(9,900)	(7,359)	(6,881)
Depreciation, depletion and amortization	(72,665)	(68,333)	(60,834)	(324)	(144)	(67)	(509)	(470)	(423)	59	40	67	(73,439)	(68,907)	(61,257)
Impairment and provision	(2,690)	(12,180)	(9,161)	(56)	9	-	-	-	31	-	-	-	(2,746)	(12,171)	(9,130)
Selling and administrative expenses	(3,644)	(4,920)	(4,966)	(340)	(296)	(269)	(1,733)	(1,307)	(1,654)	12	30	28	(5,705)	(6,493)	(6,861)
Interest income	147	217	315	-	1	-	1,028	1,805	1,571	(302)	(1,122)	(1,233)	873	901	653
Finance costs	(3,407)	(3,384)	(3,274)	(1)	(1)	(1)	(3,369)	(4,183)	(3,011)	659	1,322	1,242	(6,118)	(6,246)	(5,044)
Share of profits/(losses) of   associates and a joint venture	(117)	(63)	(88)	-	-	-	2,020	(13)	943	-	-	-	1,903	(76)	855
Income tax (expense)/credit	44	3,811	(11,236)	(8)	(24)	(3)	3,080	2,125	(441)	-	-	-	3,116	5,912	(11,680)
Other segment information
Investments in associates and a joint     venture	800	737	655	-	-	-	27,613	29,258	28,491	-	-	-	28,413	29,995	29,146
Others	532,765	497,413	457,780	3,336	1,898	3,588	344,037	342,810	340,329	(244,189)	(234,435)	(213,624)	635,949	607,686	588,073
Segment assets	533,565	498,150	458,435	3,336	1,898	3,588	371,650	372,068	368,820	(244,189)	(234,435)	(213,624)	664,362	637,681	617,219
Segment liabilities	(364,056)	(331,339)	(301,167)	(2,243)	(947)	(2,375)	(145,475)	(138,352)	(124,794)	233,453	215,328	191,092	(278,321)	(255,310)	(237,244)
Capital expenditure	66,122	49,122	52,790	11	-	-	386	395	421	-	-	-	66,519	49,517	53,211

Schedule of geographical areas

	PRC			Canada			Others			Consolidated
	2015	2016	2017	2015	2016	2017	2015	2016	2017	2015	2016	2017
Property, plant and equipment	193,359	174,853	162,027	105,383	103,173	95,552	155,399	154,439	138,289	454,141	432,465	395,868
Investments in associates and a joint venture	3,499	3,451	3,680	816	-	-	24,098	26,544	25,466	28,413	29,995	29,146
Other non-current assets	7,087	6,593	8,502	694	731	605	47	98	141	7,828	7,422	9,248

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PROFIT/(LOSS) BEFORE TAX (Tables)

12 Months Ended

Dec. 31, 2017

PROFIT/(LOSS) BEFORE TAX [abstract]

Schedule of profit loss before tax

	2015	2016	2017
Crediting:
Interest income from bank deposits	(873)	(901)	(653)
Investment income:
– Fair value changes on other financial assets	(2,398)	(2,774)	(2,409)
Insurance compensation on disposal of property, plant and equipment	(560)	(520)	(110)
Charging:
Auditors’ remuneration:
– Audit fee	45	47	51
– Other fees	12	6	5
	57	53	56
Employee wages, salaries, allowances and social security costs	6,924	6,403	6,517
Impairment and provision:
- Property, plant and equipment	2,358	10,768	8,639
- Trade receivables	4	1,439	212
- Others	384	(36)	279
	2,746	12,171	9,130
Depreciation, depletion and amortization:
– Property, plant and equipment	72,293	68,303	60,802
– Intangible assets	1,306	1,020	854
– Less: Net amount capitalized	(160)	(416)	(399)
	73,439	68,907	61,257
Operating lease rentals:
– Office properties	438	485	639
– Plant and equipment	2,448	1,747	1,560
	2,886	2,232	2,199
Repairs and maintenance	5,034	4,052	4,800
Research and development costs	1,629	1,424	1,739
Loss on disposal of property, plant and equipment	718	78	116

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FINANCE COSTS (Tables)

12 Months Ended

Dec. 31, 2017

FINANCIAL COSTS [abstract]

Schedule of financial costs

	2015	2016	2017
Interest on bank loans	291	217	169
Interest on other loans	4,701	5,249	5,207
Other borrowing costs	76	25	18
Total borrowing costs	5,068	5,491	5,394
Less: Amount capitalized in property, plant and equipment (note 13)	(1,385)	(1,430)	(2,495)
	3,683	4,061	2,899
Other finance costs:
Unwinding of discount on provision for dismantlement (note 25)	2,435	2,185	2,145
	6,118	6,246	5,044

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KEY MANAGEMENT PERSONNEL'S REMUNERATION (Tables)

12 Months Ended

Dec. 31, 2017

KEY MANAGEMENT PERSONNEL'S REMUNERATION [abstract]

Schedule of directors' remuneration

		Salaries			Total
		allowances	Performance	Pension	paid/payable
		and benefits	related	scheme	during
	Fees (1)	in kind(1)	bonuses (1)	contributions	the year
	RMB’000	RMB’000	RMB’000	RMB’000	RMB’000
2015
Executive directors:
Li Fanrong(4)	-	170	470	117	757
Wu Guangqi(5)(7)	-	170	470	117	757
Subtotal	-	340	940	234	1,514
Non-executive directors:
Wang Yilin(2)	-	-	-	-	-
Yang Hua(2)(4)(10)	-	-	-	-	-
Lv Bo(7)	-	-	-	-	-
Wang Jiaxiang(3)	-	-	-	-	-
Subtotal	-	-	-	-	-
Independent non-executive
directors:
Chiu Sung Hong	899	-	-	-	899
Lawrence J. Lau	763	-	-	-	763
Tse Hau Yin, Aloysius	899	-	-	-	899
Kevin G. Lynch	763	-	-	-	763
Subtotal	3,324	-	-	-	3,324
Total	3,324	340	940	234	4,838

		Salaries			Total
		allowances	Performance	Pension	paid/payable
		and benefits	related	scheme	during
	Fees (1)	in kind (1)	bonuses(1)	contributions	the year
	RMB’000	RMB’000	RMB’000	RMB’000	RMB’000
2016
Executive directors:
Yang Hua(2)(4)(10)	-	-	-	-	-
Yuan Guagnyu(4)(8)	-	94	78	70	242
Li Fanrong(4)	-	92	454	59	605
Subtotal	-	186	532	129	847
Non-executive directors:
Liu Jian(6)	-	-	-	-	-
Wu Guangqi(5)(7)	-	92	454	59	605
Lv Bo(7)	-	-	-	-	-
Subtotal	-	92	454	59	605
Independent non-executive
directors:
Chiu Sung Hong	957	-	-	-	957
Lawrence J. Lau	812	-	-	-	812
Tse Hau Yin, Aloysius	957	-	-	-	957
Kevin G. Lynch	812	-	-	-	812
Subtotal	3,538	-	-	-	3,538
Total	3,538	278	986	188	4,990
2017
Executive directors:
Yuan Guangyu(4)(8)	-	197	455	134	786
Xu Keqiang(9)	-	146	162	94	402
Subtotal	-	343	617	228	1,188
Non-executive directors:
Yang Hua(2)(4)(10)	-	-	-	-	-
Liu Jian(6)	-	-	-	-	-
Wu Guangqi(5)(7)	-	-	-	-	-
Subtotal	-	-	-	-	-
Independent non-executive
directors:
Chiu Sung Hong	972	-	-	-	972
Lawrence J. Lau	824	-	-	-	824
Tse Hau Yin, Aloysius	972	-	-	-	972
Kevin G. Lynch	824	-	-	-	824
Subtotal	3,592	-	-	-	3,592
Total	3,592	343	617	228	4,780

Schedule of other key management personnel's (excluding Directors') remuneration

	2015	2016	2017
Short term employee benefits	8	7	9
Pension scheme contributions	1	1	1
Amount paid/payable during the year	9	8	10
Share options*	-	-	-
	9	8	10

Schedule of bands of the remuneration and related number of members of other key management personnel (excluding Directors)

	Number of employees
	2015	2016	2017
Nil to RMB 2,000,000	10	10	12
	10	10	12

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FIVE HIGHEST PAID EMPLOYEES (Tables)

12 Months Ended

Dec. 31, 2017

FIVE HIGHEST PAID EMPLOYEES [abstract]

Schedule of remuneration of five highest paid emloyees

	2015	2016	2017
Basic salaries, allowances and benefits in kind(1)	22	23	21
Performance-related bonuses	17	14	19
Pension scheme contributions	1	1	1
Amount paid/payable during the year	40	38	41

Schedule of remuneration bands of five highest paid employees

	2015	2016	2017
RMB5,500,001 to RMB6,000,000	-	1	-
RMB6,000,001 to RMB6,500,000	-	-	1
RMB7,000,001 to RMB7,500,000	3	-	1
RMB7,500,001 to RMB8,000,000	-	3	-
RMB8,000,001 to RMB8,500,000	-	-	1
RMB9,000,001 to RMB9,500,000	2	1	1
RMB10,000,001 to RMB10,500,000	-	-	1
	5	5	5

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TAX (Tables)

12 Months Ended

Dec. 31, 2017

TAX [abstract]

Schedule of analysis of tax (credit)/expense in consolidated statement of profit or loss and other comprehensive income

	2015	2016	2017
Current tax
Provision for PRC enterprise income tax on the estimated taxable profits for the year	9,990	7,547	11,472
Provision for overseas enterprise income tax on the estimated taxable profits for the year	3,501	2,983	4,390
Deferred tax
Temporary differences in the current year	(12,585)	(14,595)	(7,558)
Effect of changes in tax rates	(4,022)	(1,847)	3,376
Income tax (credit)/expense for the year	(3,116)	(5,912)	11,680

Schedule of reconciliation of the PRC statutory corporate income tax rate to effective income tax rate of the Group

	2015	2016	2017
	%	%	%
PRC statutory enterprise income tax rate	25.0	25.0	25.0
Effect of different tax rates for overseas subsidiaries	(5.8)	34.8	(1.6)
Effect of changes in tax rates	(23.5)	35.0	9.4
Tax credit from the government	(11.5)	8.3	(2.7)
Tax reported in equity-accounted entities	(0.4)	1.0	(0.2)
Tax losses previously not recognized	(1.9)	5.3	-
Others	(0.1)	2.7	2.2
Group’s effective income tax rate	(18.2)	112.1	32.1

Schedule of movements of deferred tax liabilities net of deferred tax assets

	2015	2016	2017
At January 1	14,312	(1,948)	(19,174)
Credit to the profit or loss	(12,585)	(14,595)	(7,558)
Changes in tax rates	(4,022)	(1,847)	3,376
Charge to equity	141	(226)	7
Exchange differences	206	(558)	1,143
At December 31	(1,948)	(19,174)	(22,206)

Schedule of principal components of deferred tax balances

	2016	2017
Deferred tax assets
Property, plant and equipment	1,681	7,312
Provision for dismantlement	9,325	9,669
Losses available for offsetting against future taxable profit	21,163	16,529
Fair value of long term borrowings	1,969	1,771
Others	1,389	1,178
	35,527	36,459
Deferred tax liabilities
Property, plant and equipment	(16,208)	(13,670)
Fair value changes on other financial assets	(139)	(232)
Others	(6)	(351)
	(16,353)	(14,253)
Net deferred tax assets	19,174	22,206
Of which – deferred tax assets	24,844	25,509
deferred tax liabilities	(5,670)	(3,303)

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EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2017

EARNINGS PER SHARE [abstract]

Schedule of earnings per share

	2015	2016	2017
Earnings
Profit for the purpose of basic and diluted earnings per share calculation	20,246	637	24,677
Number of shares
Number of ordinary shares for the purpose of basic earnings per share calculation	44,647,455,984	44,647,455,984	44,647,455,984
Effect of dilutive potential ordinary shares under the share option schemes	37,363,069	11,684,504	4,101,969
Weighted average number of ordinaryshares for the purpose of diluted earningsper share	44,684,819,053	44,659,140,488	44,651,557,953
Earnings per share:
Basic (RMB Yuan)	0.45	0.01	0.55
Diluted (RMB Yuan)	0.45	0.01	0.55

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DIVIDENDS (Tables)

12 Months Ended

Dec. 31, 2017

DIVIDENDS [abstract]

Schedule of dividends

	2015	2016	2017
Dividend per ordinary share:
2017 interim dividend - HK$0.20 (2016: interim dividend HK$0.12, 2015: interim dividend    HK$0.25) per ordinary share	9,145	4,673	7,601
2016 final dividend - HK$0.23 (2015: final dividend HK$0.25, 2014: final dividend    HK$0.32) per ordinary share	11,274	9,571	8,847
2017 final dividend proposed at HK$0.3 (2016: final dividend proposed at HK$0.23, 2015: final dividend proposed at HK$0.25) per ordinary share by the Board of Directors - not recognized as a liability as at the end of the year	9,397	9,096	10,830

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PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2017

PROPERTY, PLANT AND EQUIPMENT [abstract]

Schedule of property, plant and equipment

	Oil and gas properties	Vehicles and office equipment and others	Total
Cost:
At January 1, 2016	803,986	5,296	809,282
Additions	44,302	236	44,538
Disposals and write-offs	(6,365)	(37)	(6,402)
Exchange differences	25,703	205	25,908
At December 31, 2016	867,626	5,700	873,326
At January 1, 2017	867,626	5,700	873,326
Additions	48,937	99	49,036
Disposals and write-offs	(2,577)	(914)	(3,491)
Exchange differences	(24,985)	(148)	(25,133)
At December 31, 2017	889,001	4,737	893,738
Accumulated depreciation, depletion and amortization and impairment:
At January 1, 2016	(353,824)	(1,317)	(355,141)
Depreciation charge for the year	(67,906)	(397)	(68,303)
Impairment	(10,768)	-	(10,768)
Disposals and write-offs	3,532	34	3,566
Exchange differences	(10,157)	(58)	(10,215)
At December 31, 2016	(439,123)	(1,738)	(440,861)
At January 1, 2017	(439,123)	(1,738)	(440,861)
Depreciation charge for the year	(60,442)	(360)	(60,802)
Impairment	(8,639)	-	(8,639)
Disposals and write-offs	1,185	258	1,443
Exchange differences	10,932	57	10,989
At December 31, 2017	(496,087)	(1,783)	(497,870)
Net book value:
At December 31, 2016	428,503	3,962	432,465
At December 31, 2017	392,914	2,954	395,868

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INTANGIBLE ASSETS (Tables)

12 Months Ended

Dec. 31, 2017

INTANGIBLE ASSETS [abstract]

Schedule of intangible assets

	Gas processing rights under NWS Project	Drilling rig contracts and seismic data usage rights	Marketing transportation and storage contracts	Software and others	Goodwill	Total
Cost:
At January 1, 2016	1,191	1,596	1,527	2,861	13,805	20,980
Additions	-	-	-	197	-	197
Disposal	-	-	-	(387)	-	(387)
Exchange differences	82	109	104	67	943	1,305
At December 31, 2016	1,273	1,705	1,631	2,738	14,748	22,095
At January 1, 2017	1,273	1,705	1,631	2,738	14,748	22,095
Additions	-	-	-	206	-	206
Disposal	-	(1,662)	(54)	(199)	-	(1,915)
Exchange differences	(74)	(43)	(93)	(57)	(856)	(1,123)
At December 31, 2017	1,199	-	1,484	2,688	13,892	19,263
Accumulated amortization:
At January 1, 2016	(621)	(958)	(1,096)	(1,882)	-	(4,557)
Amortization charge for the year	(51)	(326)	(135)	(508)	-	(1,020)
Disposal	-	-	-	386	-	386
Exchange differences	(57)	(80)	(81)	(42)	-	(260)
At December 31, 2016	(729)	(1,364)	(1,312)	(2,046)	-	(5,451)
At January 1, 2017	(729)	(1,364)	(1,312)	(2,046)	-	(5,451)
Amortization charge for the year	(46)	(332)	(57)	(419)	-	(854)
Disposal	-	1,662	54	199	-	1,915
Exchange differences	43	34	76	44	-	197
At December 31, 2017	(732)	-	(1,239)	(2,222)	-	(4,193)
Net book value:
At December 31, 2016	544	341	319	692	14,748	16,644
At December 31, 2017	467	-	245	466	13,892	15,070

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INVESTMENTS IN ASSOCIATES (Tables)

12 Months Ended

Dec. 31, 2017

INVESTMENTS IN ASSOCIATES [abstract]

Schedule of particulars of principal associates

		Nominal value
		of ordinary shares issued and	Percentageof equity
	Placeof	paid-up/registered	attributable to
Name of associates	establishment	capital	the Group	Principal activities
Shanghai Petroleum	Shanghai, PRC	RMB900 million	30%	Production, processing and technology consultation of oil,
Corporation Limited				gas and relevant products
				in the PRC
CNOOC Finance	Beijing, PRC	RMB4 billion	31.8%	Provision of deposit, transfer,
Corporation Limited				settlement, loan, discounting
				and other financing services to
				CNOOC and its member entities

Schedule of Group's investments in associates

	2016	2017
Share of net assets	3,695	4,067

Schedule of summarized financial information of the Group's associates in the consolidated financial statements

	2015	2016	2017
Profit/(loss) for the year	256	(609)	302
Other comprehensive income/(expense)	74	(127)	36
Total comprehensive income/(expense)	330	(736)	338

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INVESTMENT IN A JOINT VENTURE (Tables)

12 Months Ended

Dec. 31, 2017

INVESTMENT IN A JOINT VENTURE [abstract]

Schedule of particulars of a joint venture

Name of entity	Place of establishment	Nominal value of ordinary shares issued and paid-up/registered capital	Percentage of equity attributableto the Group	Principal activities
Bridas Corporation	British Virgin Islands	US$ 102,325,582	50%	Investment holding

Schedule of summarized financial information of a joint venture

	2016		2017
Current assets		9,201	11,614
Non-current assets		66,992	63,660
Current liabilities		(6,866)	(6,630)
Non-current liabilities		(16,727)	(18,486)
	2015	2016		2017
Revenue	31,231	28,371	29,879
Depreciation, depletion and amortization	(3,535)	(3,988)	(3,742)
Interest income	288	388	313
Finance costs	(799)	(704)	(550)
Profit before tax	4,194	1,226	2,215
Income tax expense	(900)	(160)	(1,109)
Profit after tax	3,294	1,066	1,106
Total comprehensive income	3,294	1,066	1,106

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EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS (Tables)

12 Months Ended

Dec. 31, 2017

EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS [abstract]

Schedule of equity investments

	2016	2017
Current:
Non-publicly traded investments
Private equity funds classified at FVTOCI	15	14
	15	14

Non-current:
Publicly traded investments
Equity investment in MEG Energy Corporation (“MEG”) classified at FVTOCI(1)	1,356	766
Other equity investment classified at FVTPL	35	15
	1,391	781
Non-publicly traded investments
Private equity fund in Kerogen Energy Fund  classified at FVTOCI(2)	2,875	2,759
	4,266	3,540

Schedule of other financial assets

	2016	2017
Current:
Non-publicly traded investments classified at FVTPL:
Corporate wealth management products (1)	46,958	66,229
Money market funds (2)	5,931	8,115
	52,889	74,344

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INVENTORIES AND SUPPLIES (Tables)

12 Months Ended

Dec. 31, 2017

INVENTORIES AND SUPPLIES [abstract]

Schedule of inventories and supplies

	2016	2017
Materials and supplies	7,288	6,278
Oil in tanks	1,594	1,540
Less: Provision for inventory obsolescence	(173)	(464)
	8,709	7,354

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OTHER PAYABLES AND ACCRUED LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2017

OTHER PAYABLES AND ACCRUED LIABILITIES [abstract]

Schedule of other payables and accrued liabilities

	2016	2017
Accrued payroll and welfare payable	1,509	1,490
Provision for retirement benefits	683	630
Accrued expenses	449	381
Advances from customers	3,272	3,096
Special oil gain levy payable	-	55
Royalties payable	240	75
Provision for dismantlement (note 25)	462	1,180
Other payables	8,251	7,199
	14,866	14,106

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LOANS AND BORROWINGS (Tables)

12 Months Ended

Dec. 31, 2017

LOANS AND BORROWINGS [abstract]

Schedule of current loans and borrowings

		2016			2017
	Effective interest rate and final maturity	Loans	Notes	Total	Loans	Notes	Total
Short-term loans and borrowings
General loans****	LIBOR+0.35% to 0.75% per annum with maturity within one year	10,361	-	10,361	8,779	-	8,779
		10,361	-	10,361	8,779	-	8,779
Loans and borrowings due within one year
For Tangguh LNG Project**	LIBOR+0.19% to 0.335% per annum with maturity within one year	215	-	215	212	-	212
Notes*		-	9,102	9,102	-	4,901	4,901
		215	9,102	9,317	212	4,901	5,113
		10,576	9,102	19,678	8,991	4,901	13,892

Schedule of non-current loans and borrowings

		2016			2017
	Effective interest rate andfinal maturity	Loans	Notes	Total	Loans	Notes	Total
For Tangguh LNG Project**	LIBOR+0.19% to 0.335% per annum with maturity through to 2021	758	-	758	502	-	502
For Tangguh LNG III Project ***	LIBOR+1.37% to 3.45% per annum with maturity through 2021 to 2029	327	-	327	777	-	777
Notes*		-	129,713	129,713	-	117,079	117,079
		1,085	129,713	130,798	1,279	117,079	118,358

Schedule of detailed information about notes

Issued by	Maturity	Coupon Rate	Outstanding Principal Amount
			December 31, 2017	December 31,2016
			USD million	USD million
CNOOC Finance (2003) Limited	Due in 2033	5.500%	300	300
CNOOC Finance (2011) Limited	Due in 2021	4.25%	1,500	1,500
CNOOC Finance (2011) Limited	Due in 2041	5.75%	500	500
CNOOC Finance (2012) Limited	Due in 2022	3.875%	1,500	1,500
CNOOC Finance (2012) Limited	Due in 2042	5.000%	500	500
CNOOC Finance (2013) Limited	Due in 2018	1.750%	750	750
CNOOC Finance (2013) Limited	Due in 2023	3.000%	2,000	2,000
CNOOC Finance (2013) Limited	Due in 2043	4.250%	500	500
CNOOC Nexen Finance (2014) ULC	Matured in 2017	1.625%	-	1,250
CNOOC Nexen Finance (2014) ULC	Due in 2024	4.25%	2,250	2,250
CNOOC Nexen Finance (2014) ULC	Due in 2044	4.875%	500	500
Nexen	Matured in 2017	5.65%	-	62
Nexen	Due in 2019	6.2%	300	300
Nexen	Due in 2028	7.4%	200	200
Nexen	Due in 2032	7.875%	500	500
Nexen	Due in 2035	5.875%	790	790
Nexen	Due in 2037	6.4%	1,250	1,250
Nexen	Due in 2039	7.5%	700	700
CNOOC Finance (2015) U.S.A. LLC	Due in 2025	3.500%	2,000	2,000
CNOOC Finance (2015) Australia Pty Ltd	Due in 2020	2.625%	1,500	1,500
CNOOC Finance (2015) Australia Pty Ltd	Due in 2045	4.200%	300	300

Schedule of maturities of long-term bank loans

	2016	2017
Repayable:
Within one year	215	212
After one year but within two years	225	212
After two years but within three years	225	212
After three years but within four years	225	108
After four years but within five years	97	61
After five years	313	686
	1,300	1,491
Amount due within one year shown under current liabilities	(215)	(212)
	1,085	1,279

Schedule of supplemental information with respect to the long-term bank loans

			Maximum	Average	Weighted
		Weighted	amount	amount	average
		average	outstanding	outstanding	interest rate
For the year ended	Balance	interest rate	during the	during the	during the
December 31	at year end	at year end	year	year (1)	year (2)
2016	1,300	1.74%	1,369	1,199	1.29%
2017	1,491	2.52%	1,491	1,396	2.13%

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PROVISION FOR DISMANTLEMENT (Tables)

12 Months Ended

Dec. 31, 2017

PROVISION FOR DISMANTLEMENT [abstract]

Schedule of provision for dismantlement

	2016	2017
At January 1	50,063	50,888
New projects(1)	1,395	1,244
Revision(1)	(2,072)	421
Utilization	(398)	(440)
Deletions	(33)	-
Unwinding of discount(2) (note 7)	2,185	2,145
Exchange differences	(252)	(185)
At December 31	50,888	54,073
Current portion of dismantlement included in other payables and accrued liabilities (note 23)	(462)	(1,180)
At December 31	50,426	52,893

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SHARE CAPITAL (Tables)

12 Months Ended

Dec. 31, 2017

SHARE CAPITAL [abstract]

Schedule of share capital

		Issued share capital  equivalent of
	Number of shares	RMB million
Issued and fully paid:
Ordinary shares with no par value as at January 1, 2016, as at December 31, 2016 and as at December 31, 2017	44,647,455,984	43,081

Schedule of details of share options outstanding

	2016		2017
	Number of share options	Weighted average exercise price	Number of share options	Weighted average exercise price
		HK$		HK$
Outstanding at the beginning of the year	262,592,000	10.56	187,529,000	11.40
Granted during the year	-	-	-	-
Forfeited during the year	(37,893,000)	11.30	(22,506,000)	12.43
Expired during the year	(37,170,000)	5.56	(35,104,000)	7.29
Exercised during the year	-	-	-	-
Outstanding at the end of the year	187,529,000	11.40	129,919,000	12.34
Exercisable at the end of the year	187,529,000	11.40	129,919,000	12.34

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RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2017

China National Offshore Oil Corporation Group [member]

Disclosure of transactions between related parties [line items]

Schedule of provision of exploration, oil and gas development, oil and gas production as well as marketing, management and ancillary services by the CNOOC Group to the Group

	2015	2016	2017
Provision of exploration and support services	7,457	4,357	5,912
- Inclusive of amounts capitalized under property, plant and equipment	4,158	2,364	3,392
Provision of oil and gas development and support services	22,733	14,214	16,317
Provision of oil and gas production and support services (note a)	8,384	7,250	8,894
Provision of marketing, management and ancillary services (note b)	954	994	1,450
FPSO vessel leases (note c)	1,770	1,551	1,383
	41,298	28,366	33,956

Schedule of sales of petroleum and natural gas products by the Group to the CNOOC Group

	2015	2016	2017
Sales of petroleum and natural gas products (other than long-term sales of natural gas and liquefied natural gas) (note d)	105,401	88,682	109,518
Long term sales of natural gas and liquefied natural gas (note e)	10,557	8,663	9,837
	115,958	97,345	119,355

Schedule of a summary of significant related party transactions and the balances arising from related party transactions

	2016	2017
Amount due to CNOOC
- included in other payables and accrued liabilities	215	193
Amount due to other related parties
- included in trade and accrued payables	15,091	16,651
	15,306	16,844
Borrowings from CNOOC (note g)	4,811	4,532
Amounts due from other related parties
– included in trade receivables	13,090	12,401
– included in other current assets	173	513
	13,263	12,914

CNOOC Finance Corporation Limited [member]

Disclosure of transactions between related parties [line items]

Schedule of interest income received by the Group

	2015	2016	2017
Interest income from deposits in CNOOC Finance	629	564	360

Schedule of deposits balances made by the Group

	2016	2017
Deposits in CNOOC Finance	19,437	19,465

A joint venture [member]

Disclosure of transactions between related parties [line items]

Schedule of a summary of significant related party transactions and the balances arising from related party transactions

	2016	2017
Amount due from a joint venture
– included in other current assets	135	126

State-owned enterprises [member]

Disclosure of transactions between related parties [line items]

Schedule of a summary of significant related party transactions and the balances arising from related party transactions

	2016	2017
Cash and cash equivalents	6,612	3,824
Time deposits with maturity over three months	108	13
Specified dismantlement fund accounts (note 18)	6,088	7,555
	12,808	11,392

China United Coalbed Methane Corporation Limited [member]

Disclosure of transactions between related parties [line items]

Schedule of a summary of significant related party transactions and the balances arising from related party transactions

	2016	2017
Accumulated investment	1,647	1,940

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NOTE TO THE CONSOLIDATED STATEMENT OF CASH FLOWS (Tables)

12 Months Ended

Dec. 31, 2017

CONSOLIDATED STATEMENTS OF CASH FLOWS [abstract]

Schedule of reconciliation of profit/(loss) before tax to cash generated from operations

	2015	2016	2017
Profit/(loss) before tax	17,130	(5,275)	36,357
Adjustments for:
Interest income	(873)	(901)	(653)
Finance costs	6,118	6,246	5,044
Exchange losses/(gains), net	143	790	(356)
Share of (profits)/losses of associates	(256)	609	(302)
Share of profit of a joint venture	(1,647)	(533)	(553)
Investment income	(2,398)	(2,774)	(2,409)
Impairment and provision	2,746	12,171	9,130
Depreciation, depletion and amortization	73,439	68,907	61,257
Loss on disposal and write-off of property, plant and equipment	2,115	2,304	1,937
Others	70	-	-
Subtotal	96,587	81,544	109,452
Decrease/(increase) in trade receivables and other current assets	7,932	(2,820)	(1,073)
Decrease in inventories and supplies	1,427	922	1,464
(Decrease)/increase in trade and accrued payables and other payables	(9,851)	2,491	782
Cash generated from operations	96,095	82,137	110,625

Schedule of of reconciliation of liabilities arising from financing activities

	Loans and borrowings	Interest payable	Dividend payable	Total
	(Note 24)	(Note 23)
At January 1, 2017	150,476	1,244	-	151,720
Financing cash flows	(9,669)	(5,154)	(16,448)	(31,271)
Foreign exchange translation	(8,911)	51	(52)	(8,912)
Finance costs	354	5,040	-	5,394
Dividends declared	-	-	16,500	16,500
At December 31, 2017	132,250	1,181	-	133,431

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2017

COMMITEMENTS AND CONTINGENCIES [abstract]

Schedule of capital commitments

	2016	2017
Contracted, but not provided for (1)	46,515	46,704

Schedule of capital commitments of a joint venture

	2016	2017
Contracted, but not provided for	360	691

Schedule of total minimum lease payments under non-cancellable operating leases

	2016	2017
Commitments due:
No later than one year	1,317	1,630
Later than one year and not later than   two years	896	1,048
Later than two years and not later than   five years	1,534	1,274
Later than five years	1,963	1,774
	5,710	5,726

Schedule of office properties commitments of a joint venture

	2016	2017
Commitments due:
No later than one year	25	18
Later than one year and not later than two years	17	12
Later than two years and not later than five years	26	16
Later than five years	51	23
	119	69

Schedule of minimum lease payments under non-cancallable operating leases of plant and equipment

	2016	2017
Commitments due:
No later than one year	1,378	1,272
Later than one year and not later than two years	734	875
Later than two years and not later than five years	1,316	1,616
Later than five years	3,878	3,406
	7,306	7,169

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FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2017

FINANCIAL INSTRUMENTS [abstract]

Schedule of financial instruments measured at fair value for each hierarchy

Assets measured at fair value	December 31 2017	Level 1	Level 2	Level 3
Other financial assets-current
Corporate wealth management products	66,229	-	66,229	-
Money market funds	8,115	8,115	-	-
Derivative financial assets – current	-	-	-	-
Equity investments
Non-publicly traded investments- current	14	-	14	-
Publicly traded investments-non current	781	781	-	-
	75,139	8,896	66,243	-
Liabilities measured at fair value
Derivative financial liabilities – current	-	-	-	-

Assets measured at fair value	December 31 2016	Level 1	Level 2	Level 3
Other financial assets-current
Corporate wealth management products	46,958	-	46,958	-
Money market funds	5,931	5,931	-	-
Derivative financial assets – current	428	-	428	-
Equity investments
Non-publicly traded investments- current	15	-	15	-
Publicly traded investments-non current	1,391	1,391	-	-
	54,723	7,322	47,401	-
Liabilities measured at fair value
Derivative financial liabilities – current	(426)	-	(426)	-

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CONCENTRATION OF CUSTOMERS (Tables)

12 Months Ended

Dec. 31, 2017

CONCENTRATION OF CUSTOMERS [abstract]

Schedule of details of gross sales to top five third party customers

	2015	2016	2017
China Petroleum & Chemical Corporation*	14,692	9,659	15,488
PetroChina Company Limited*	5,502	6,923	11,957
BP p.l.c.	3,093	2,843	3,108
Phillips 66	N/A	N/A	2,631
Royal Dutch Shell PLC	6,917	3,661	2,627
EOG Resources, Inc.	3,746	2,660	N/A

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FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES (Tables)

12 Months Ended

Dec. 31, 2017

FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES [abstract]

Schedule of capital management on the basis of the debt to capital ratio

	2015	2016	2017
Interest-bearing debts	164,645	150,476	132,250
Equity attributable to owners of the parent	386,041 386,041	382,371	379,975
Total capital	550,686	532,847	512,225
Gearing ratio	29.9%	28.2%	25.8%

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CORPORATE INFORMATION (Details) ¥ in Millions		12 Months Ended
		Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2017 SGD ($)	Dec. 31, 2017 GBP (£)	Dec. 31, 2017 ZAR (R)	[2]	Jun. 19, 2017 ZAR (R)	Dec. 31, 2016 CNY (¥)
Disclosure of subsidiaries [line items]
Nominal value of ordinary shares issued and paid-up/registered capital		¥ 43,081	$ 6,621,000,000						¥ 43,081
CNOOC China Limited [member]
Disclosure of subsidiaries [line items]
Name of entity		CNOOC China Limited
Place of establishment		Tianjin, PRC
Nominal value of ordinary shares issued and paid-up/registered capital | ¥		¥ 20,000
Percentage of equity attributable to the Group		100.00%
China Offshore Oil (Singapore) International Pte Ltd [member]
Disclosure of subsidiaries [line items]
Name of entity		China Offshore Oil (Singapore) International Pte Ltd
Place of establishment		Singapore
Nominal value of ordinary shares issued and paid-up/registered capital				$ 3,000,000
Percentage of equity attributable to the Group		100.00%
CNOOC International Limited [member]
Disclosure of subsidiaries [line items]
Name of entity		CNOOC International Limited
Place of establishment		British Virgin Islands
Nominal value of ordinary shares issued and paid-up/registered capital			20,000,000,002
Percentage of equity attributable to the Group		100.00%
CNOOC Finance (2003) Limited [member]
Disclosure of subsidiaries [line items]
Name of entity		CNOOC Finance (2003) Limited
Place of establishment		British Virgin Islands
Nominal value of ordinary shares issued and paid-up/registered capital			1,000
Percentage of equity attributable to the Group		100.00%
CNOOC Finance (2011) Limited [member]
Disclosure of subsidiaries [line items]
Name of entity		CNOOC Finance (2011) Limited
Place of establishment		British Virgin Islands
Nominal value of ordinary shares issued and paid-up/registered capital			1,000
Percentage of equity attributable to the Group		100.00%
CNOOC Finance (2012) Limited [member]
Disclosure of subsidiaries [line items]
Name of entity		CNOOC Finance (2012) Limited
Place of establishment		British Virgin Islands
Nominal value of ordinary shares issued and paid-up/registered capital			1,000
Percentage of equity attributable to the Group		100.00%
CNOOC Finance (2013) Limited [member]
Disclosure of subsidiaries [line items]
Name of entity		CNOOC Finance (2013) Limited
Place of establishment		British Virgin Islands
Nominal value of ordinary shares issued and paid-up/registered capital			1,000
Percentage of equity attributable to the Group		100.00%
CNOOC Deepwater Development Limited [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC Deepwater Development Limited
Place of establishment	[1]	Zhuhai, PRC
Nominal value of ordinary shares issued and paid-up/registered capital | ¥	[1]	¥ 20,300
Percentage of equity attributable to the Group	[1]	100.00%
CNOOC Southeast Asia Limited [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC Southeast Asia Limited
Place of establishment	[1]	Bermuda
Nominal value of ordinary shares issued and paid-up/registered capital	[1]		12,000
Percentage of equity attributable to the Group	[1]	100.00%
CNOOC SES Ltd. [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC SES Ltd.
Place of establishment	[1]	Malaysia
Nominal value of ordinary shares issued and paid-up/registered capital	[1]		1
Percentage of equity attributable to the Group	[1]	100.00%
CNOOC Muturi Limited [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC Muturi Limited
Place of establishment	[1]	Isle of Man
Nominal value of ordinary shares issued and paid-up/registered capital	[1]		7,780,770
Percentage of equity attributable to the Group	[1]	100.00%
CNOOC NWS Private Limited [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC NWS Private Limited
Place of establishment	[1]	Singapore
Nominal value of ordinary shares issued and paid-up/registered capital	[1]			$ 2
Percentage of equity attributable to the Group	[1]	100.00%
CNOOC Exploration & Production Nigeria Limited [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC Exploration & Production Nigeria Limited
Place of establishment	[1]	Nigeria
Nominal value of ordinary shares issued and paid-up/registered capital (as a string)		NGN10 million
Percentage of equity attributable to the Group	[1]	100.00%
CNOOC Iraq Limited [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC Iraq Limited
Place of establishment	[1]	British Virgin Islands
Nominal value of ordinary shares issued and paid-up/registered capital	[1]		1
Percentage of equity attributable to the Group	[1]	100.00%
CNOOC Canada Energy Ltd. [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC Canada Energy Ltd.
Place of establishment	[1]	Canada
Nominal value of ordinary shares issued and paid-up/registered capital (as a string)	[1]	100 common shares without a par value 103,000 preferred shares without a par value
Percentage of equity attributable to the Group	[1]	100.00%
CNOOC Uganda Ltd [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC Uganda Ltd
Place of establishment	[1]	Uganda
Nominal value of ordinary shares issued and paid-up/registered capital (as a string)		1 million Uganda Shilling
Percentage of equity attributable to the Group	[1]	100.00%
Nexen Energy ULC [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	Nexen Energy ULC
Place of establishment	[1]	Canada
Nominal value of ordinary shares issued and paid-up/registered capital (as a string)	[1]	13,671,421,700 common shares without a par value
Percentage of equity attributable to the Group	[1]	100.00%
Nexen Petroleum U.K. Limited [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	Nexen Petroleum U.K. Limited
Place of establishment	[1]	England and Wales
Nominal value of ordinary shares issued and paid-up/registered capital | £	[1]				£ 98,009,131
Percentage of equity attributable to the Group	[1]	100.00%
Nexen Petroleum Nigeria Limited [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	Nexen Petroleum Nigeria Limited
Place of establishment	[1]	Nigeria
Nominal value of ordinary shares issued and paid-up/registered capital (as a string)		NGN30 million
Percentage of equity attributable to the Group	[1]	100.00%
OOGC America LLC [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	OOGC America LLC
Place of establishment	[1]	USA
Percentage of equity attributable to the Group	[1]	100.00%
Nexen Petroleum Offshore U.S.A. Inc. [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	Nexen Petroleum Offshore U.S.A. Inc.
Place of establishment	[1]	USA
Nominal value of ordinary shares issued and paid-up/registered capital	[1]		15,830
Percentage of equity attributable to the Group	[1]	100.00%
Nexen Oil Sands Partnership [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	Nexen Oil Sands Partnership
Place of establishment	[1]	Canada
Percentage of equity attributable to the Group	[1]	100.00%
CNOOC PETROLEUM BRASIL LTDA [member]
Disclosure of subsidiaries [line items]
Name of entity	[1],[2]	CNOOC PETROLEUM BRASIL LTDA
Place of establishment	[1],[2]	Brazil
Nominal value of ordinary shares issued and paid-up/registered capital | R	[1]					R 2,965,600,000		R 2,436,000,000
Percentage of equity attributable to the Group	[1],[2]	100.00%
CNOOC Nexen Finance (2014) ULC [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC Nexen Finance (2014) ULC
Place of establishment	[1]	Canada
Nominal value of ordinary shares issued and paid-up/registered capital (as a string)	[1]	100 common shares without a par value
Percentage of equity attributable to the Group	[1]	100.00%
CNOOC Finance (2015) U.S.A. LLC [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC Finance (2015) U.S.A. LLC
Place of establishment	[1]	USA
Percentage of equity attributable to the Group	[1]	100.00%
CNOOC Finance (2015) Australia Pty Ltd [member]
Disclosure of subsidiaries [line items]
Name of entity	[1]	CNOOC Finance (2015) Australia Pty Ltd
Place of establishment	[1]	Australia
Nominal value of ordinary shares issued and paid-up/registered capital	[1]		$ 1
Percentage of equity attributable to the Group	[1]	100.00%

[1] All subsidiaries are indirectly held through CNOOC International Limited, except CNOOC Deepwater Development Limited which is indirectly held through CNOOC China Limited.

[2] The registered capital of CNOOC PETROLEUM BRASIL LTDA increased from R$2,436,000,000 to R$2,965,600,000 on 20 June 2017.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Cash and cash equivalents (Details)	12 Months Ended
	Dec. 31, 2017
Maximum [member]
Disclosure of cash and cash equivalents [line items]
Original maturity of short term deposits, classified as cash and cash equivalents	3 months

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Share-based payment transactions (Details) - CNY (¥)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Significant accounting policies [abstract]
Expense recognized for awards that do not ultimately vest for the Group	¥ 0
Equity-settled award, cancelled or modified, in share-based payment transactions	¥ 0	¥ 0	¥ 0

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OIL AND GAS SALES (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
OIL AND GAS SALES [abstract]
Gross sales	¥ 156,304		¥ 124,648	¥ 150,618
Less: Royaties	(3,226)		(2,398)	(2,646)
PRC government's share of oil	(1,190)		(925)	(1,375)
Oil and gas sales	¥ 151,888	$ 23,345	¥ 121,325	¥ 146,597

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SEGMENT INFORMATION - Segment results (Details) ¥ in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
Disclosure of operating segments [line items]
External revenue		¥ 186,390		¥ 146,490	¥ 171,437
Intersegment revenue	[1]	0		0	0
Total revenue		186,390	$ 28,648	146,490	171,437
Segment profit/ (loss) for the year		24,677		637	20,246
Amounts included in the measure of segment profit or loss
Operating expenses		(24,282)	(3,732)	(23,211)	(28,372)
Taxes other than income tax		(7,210)	(1,108)	(6,941)	(10,770)
Exploration expenses		(6,881)	(1,058)	(7,359)	(9,900)
Depreciation, depletion and amortization		(61,257)	(9,415)	(68,907)	(73,439)
Impairment and provision		(9,130)	(1,403)	(12,171)	(2,746)
Selling and administrative expenses		(6,861)	(1,055)	(6,493)	(5,705)
Interest income		653	100	901	873
Finance costs		(5,044)	(775)	(6,246)	(6,118)
Share of profits/ (losses) of associates and a joint venture		855		(76)	1,903
Income tax credit/(expense)		(11,680)	$ (1,795)	5,912	3,116
Other segment information
Investments in associates and a joint venture		29,146		29,995	28,413
Others		588,073		607,686	635,949
Segment assets		617,219		637,681	664,362
Segment liabilities		(237,244)		(255,310)	(278,321)
Capital expenditure		53,211		49,517	66,519
E&P [member]
Disclosure of operating segments [line items]
External revenue		142,429		114,935	137,243
Intersegment revenue	[1]	14,737		10,676	12,339
Total revenue		157,166		125,611	149,582
Segment profit/ (loss) for the year		23,863		(346)	15,695
Amounts included in the measure of segment profit or loss
Operating expenses		(24,282)		(23,220)	(28,372)
Taxes other than income tax		(7,169)		(6,901)	(10,748)
Exploration expenses		(6,896)		(7,393)	(9,973)
Depreciation, depletion and amortization		(60,834)		(68,333)	(72,665)
Impairment and provision		(9,161)		(12,180)	(2,690)
Selling and administrative expenses		(4,966)		(4,920)	(3,644)
Interest income		315		217	147
Finance costs		(3,274)		(3,384)	(3,407)
Share of profits/ (losses) of associates and a joint venture		(88)		(63)	(117)
Income tax credit/(expense)		(11,236)		3,811	44
Other segment information
Investments in associates and a joint venture		655		737	800
Others		457,780		497,413	532,765
Segment assets		458,435		498,150	533,565
Segment liabilities		(301,167)		(331,339)	(364,056)
Capital expenditure		52,790		49,122	66,122
Trading business [member]
Disclosure of operating segments [line items]
External revenue		43,618		30,986	33,777
Intersegment revenue	[1]	(14,737)		(10,676)	(12,339)
Total revenue		28,881		20,310	21,438
Segment profit/ (loss) for the year		808		656	879
Amounts included in the measure of segment profit or loss
Operating expenses		0		0	0
Taxes other than income tax		0		0	0
Exploration expenses		0		0	0
Depreciation, depletion and amortization		(67)		(144)	(324)
Impairment and provision		0		9	(56)
Selling and administrative expenses		(269)		(296)	(340)
Interest income		0		1	0
Finance costs		(1)		(1)	(1)
Share of profits/ (losses) of associates and a joint venture		0		0	0
Income tax credit/(expense)		(3)		(24)	(8)
Other segment information
Investments in associates and a joint venture		0		0	0
Others		3,588		1,898	3,336
Segment assets		3,588		1,898	3,336
Segment liabilities		(2,375)		(947)	(2,243)
Capital expenditure		0		0	11
Corporate [member]
Disclosure of operating segments [line items]
External revenue		343		569	417
Intersegment revenue	[1]	84		113	85
Total revenue		427		682	502
Segment profit/ (loss) for the year		6,391		30,701	6,048
Amounts included in the measure of segment profit or loss
Operating expenses		0		0	0
Taxes other than income tax		(41)		(40)	(29)
Exploration expenses		0		0	0
Depreciation, depletion and amortization		(423)		(470)	(509)
Impairment and provision		31		0	0
Selling and administrative expenses		(1,654)		(1,307)	(1,733)
Interest income		1,571		1,805	1,028
Finance costs		(3,011)		(4,183)	(3,369)
Share of profits/ (losses) of associates and a joint venture		943		(13)	2,020
Income tax credit/(expense)		(441)		2,125	3,080
Other segment information
Investments in associates and a joint venture		28,491		29,258	27,613
Others		340,329		342,810	344,037
Segment assets		368,820		372,068	371,650
Segment liabilities		(124,794)		(138,352)	(145,475)
Capital expenditure		421		395	386
Eliminations [member]
Disclosure of operating segments [line items]
External revenue		0		0	0
Intersegment revenue	[1]	(84)		(113)	(85)
Total revenue		(84)		(113)	(85)
Segment profit/ (loss) for the year		(6,385)		(30,374)	(2,376)
Amounts included in the measure of segment profit or loss
Operating expenses		0		9	0
Taxes other than income tax		0		0	0
Exploration expenses		15		34	73
Depreciation, depletion and amortization		67		40	59
Impairment and provision		0		0	0
Selling and administrative expenses		28		30	12
Interest income		(1,233)		(1,122)	(302)
Finance costs		1,242		1,322	659
Share of profits/ (losses) of associates and a joint venture		0		0	0
Income tax credit/(expense)		0		0	0
Other segment information
Investments in associates and a joint venture		0		0	0
Others		(213,624)		(234,435)	(244,189)
Segment assets		(213,624)		(234,435)	(244,189)
Segment liabilities		191,092		215,328	233,453
Capital expenditure		¥ 0		¥ 0	¥ 0

[1] Certain oil and gas produced by the E and P segment are sold via the trading business segment. For the Group's chief operating decision maker's assessment of segment performance, these revenues are reclassified back to E and P segment.

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SEGMENT INFORMATION - Geographical information (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)	Dec. 31, 2017 USD ($)
Disclosure of geographical areas [line items]
Property, plant and equipment	¥ 395,868	¥ 432,465	¥ 454,141	$ 60,844
Investments in associates and a joint venture	29,146	29,995	28,413
Other non-current assets	¥ 9,248	¥ 7,422	¥ 7,828	$ 1,421
PRC [member]
Disclosure of geographical areas [line items]
Ratio of revenue from customers in different locations to Group's revenues	65.00%	70.00%	73.00%
Property, plant and equipment	¥ 162,027	¥ 174,853	¥ 193,359
Investments in associates and a joint venture	3,680	3,451	3,499
Other non-current assets	¥ 8,502	¥ 6,593	¥ 7,087
Outside the PRC [member] | Maximum [member]
Disclosure of geographical areas [line items]
Ratio of revenue from customers in different locations to Group's revenues	10.00%	10.00%	10.00%
Canada [member]
Disclosure of geographical areas [line items]
Property, plant and equipment	¥ 95,552	¥ 103,173	¥ 105,383
Investments in associates and a joint venture	0	0	816
Other non-current assets	605	731	694
Others [member]
Disclosure of geographical areas [line items]
Property, plant and equipment	138,289	154,439	155,399
Investments in associates and a joint venture	25,466	26,544	24,098
Other non-current assets	¥ 141	¥ 98	¥ 47

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SEGMENT INFORMATION - Information about major customers (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
Disclosure of major customers [line items]
Revenue	¥ 186,390	$ 28,648	¥ 146,490	¥ 171,437
China Petroleum & Chemical Corporation [member]
Disclosure of major customers [line items]
Revenue	15,488		9,659	14,692
China Petroleum & Chemical Corporation [member] | The E&P segment and the trading business segment [member]
Disclosure of major customers [line items]
Revenue	¥ 15,488		¥ 9,659	¥ 14,692

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PROFIT/(LOSS) BEFORE TAX (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
Crediting:
Interest income from bank deposits	¥ (653)		¥ (901)	¥ (873)
Investment income:
Fair value changes on other financial assets	(2,409)	$ (370)	(2,774)	(2,398)
Insurance compensation on disposal of property, plant and equipment	(110)		(520)	(560)
Auditors' remuneration
Audit fee	51		47	45
Other fees	5		6	12
Auditors' remuneration	56		53	57
Employee wages, salaries, allowances and social security costs	6,517		6,403	6,924
Impairment and provision:
Property, plant and equipment	8,639		10,768	2,358
Trade receivables	212		1,439	4
Others	279		(36)	384
Total impairment and provision	9,130	1,403	12,171	2,746
Depreciation, depletion and amortization:
Property, plant and equipment	60,802		68,303	72,293
Intangible assets	854		1,020	1,306
Net amount capitalized	(399)		(416)	(160)
Total depreciation, depletion and amortization	61,257	$ 9,415	68,907	73,439
Operating lease rentals:
Plant and equipment	639		485	438
Office properties	1,560		1,747	2,448
Operating lease rentals	2,199		2,232	2,886
Repairs and maintenance	4,800		4,052	5,034
Research and development costs	1,739		1,424	1,629
Loss on disposal of property, plant and equipment	¥ 116		¥ 78	¥ 718

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FINANCE COSTS (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
FINANCIAL COSTS [abstract]
Interest on bank loans	¥ 169		¥ 217	¥ 291
Interest on other loans	5,207		5,249	4,701
Other borrowing costs	18		25	76
Total borrowing costs	5,394		5,491	5,068
Less: Amount capitalized in property, plant and equipment (note 13)	(2,495)		(1,430)	(1,385)
Borrowing costs recognised as expense	2,899		4,061	3,683
Other finance costs:
Unwinding of discount on provision for dismantlement (note 25)	2,145		2,185	2,435
Total finance costs	¥ 5,044	$ 775	¥ 6,246	¥ 6,118

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FINANCE COSTS - Narrative (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Minimum [member]
Disclosure of detailed information about finance costs [line items]
Effective interest rates used to determine the amount of related borrowing costs for capitalization	0.95%	0.7566%	0.735%
Maximum [member]
Disclosure of detailed information about finance costs [line items]
Effective interest rates used to determine the amount of related borrowing costs for capitalization	7.875%	7.875%	7.875%

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KEY MANAGEMENT PERSONNEL'S REMUNERATION - Directors' remuneration (Details) ¥ in Thousands		12 Months Ended
		Dec. 31, 2017 CNY (¥) option	Dec. 31, 2016 CNY (¥) option	Dec. 31, 2015 CNY (¥) option
Disclosure of transactions between related parties [line items]
Pension scheme contributions		¥ 651,000	¥ 695,000	¥ 613,000
Directors [member]
Disclosure of transactions between related parties [line items]
Fees	[1]	3,592	3,538	3,324
Salaries, allowances and benefits in kind	[1]	343	278	340
Performance related bonuses	[1]	617	986	940
Pension scheme contributions		228	188	234
Total paid/payable during the year		¥ 4,780	¥ 4,990	¥ 4,838
Number of directors exercising any share option | option		0	0	0
Number of new share option was granted to Directors in respect of their services to the Group under the applicable share option schemes of the Company | option		0	0	0
Executive directors [member]
Disclosure of transactions between related parties [line items]
Fees	[1]	¥ 0	¥ 0	¥ 0
Salaries, allowances and benefits in kind	[1]	343	186	340
Performance related bonuses	[1]	617	532	940
Pension scheme contributions		228	129	234
Total paid/payable during the year		1,188	847	1,514
Executive directors [member] | Li Fanrong [member]
Disclosure of transactions between related parties [line items]
Fees	[1],[2]		0	0
Salaries, allowances and benefits in kind	[1],[2]		92	170
Performance related bonuses	[1],[2]		454	470
Pension scheme contributions	[2]		59	117
Total paid/payable during the year	[2]		605	757
Executive directors [member] | Wu Guangqi [member]
Disclosure of transactions between related parties [line items]
Fees	[1],[3],[4]			0
Salaries, allowances and benefits in kind	[1],[3],[4]			170
Performance related bonuses	[1],[3],[4]			470
Pension scheme contributions	[3],[4]			117
Total paid/payable during the year	[3],[4]			757
Executive directors [member] | Yang Hua [member]
Disclosure of transactions between related parties [line items]
Fees	[1],[2],[5],[6]		0
Salaries, allowances and benefits in kind	[1],[2],[5],[6]		0
Performance related bonuses	[1],[2],[5],[6]		0
Pension scheme contributions	[2],[5],[6]		0
Total paid/payable during the year	[2],[5],[6]		0
Executive directors [member] | Yuan Guangyu [member]
Disclosure of transactions between related parties [line items]
Fees	[1],[2],[7]	0	0
Salaries, allowances and benefits in kind	[1],[2],[7]	197	94
Performance related bonuses	[1],[2],[7]	455	78
Pension scheme contributions	[2],[7]	134	70
Total paid/payable during the year	[2],[7]	786	242
Executive directors [member] | Xu Keqiang [member]
Disclosure of transactions between related parties [line items]
Fees	[1],[8]	0
Salaries, allowances and benefits in kind	[1],[8]	146
Performance related bonuses	[1],[8]	162
Pension scheme contributions	[8]	94
Total paid/payable during the year	[8]	402
Non-executive directors [member]
Disclosure of transactions between related parties [line items]
Fees	[1]	0	0	0
Salaries, allowances and benefits in kind	[1]	0	92	0
Performance related bonuses	[1]	0	454	0
Pension scheme contributions		0	59	0
Total paid/payable during the year		0	605	0
Non-executive directors [member] | Wu Guangqi [member]
Disclosure of transactions between related parties [line items]
Fees	[1],[3],[4]	0	0
Salaries, allowances and benefits in kind	[1],[3],[4]	0	92
Performance related bonuses	[1],[3],[4]	0	454
Pension scheme contributions	[3],[4]	0	59
Total paid/payable during the year	[3],[4]	0	605
Non-executive directors [member] | Wang Yilin [member]
Disclosure of transactions between related parties [line items]
Fees	[1],[6]			0
Salaries, allowances and benefits in kind	[1],[6]			0
Performance related bonuses	[1],[6]			0
Pension scheme contributions	[6]			0
Total paid/payable during the year	[6]			0
Non-executive directors [member] | Yang Hua [member]
Disclosure of transactions between related parties [line items]
Fees	[1],[2],[5],[6]	0		0
Salaries, allowances and benefits in kind	[1],[2],[5],[6]	0		0
Performance related bonuses	[1],[2],[5],[6]	0		0
Pension scheme contributions	[2],[5],[6]	0		0
Total paid/payable during the year	[2],[5],[6]	0		0
Non-executive directors [member] | Lv Bo [member]
Disclosure of transactions between related parties [line items]
Fees	[1],[4]		0	0
Salaries, allowances and benefits in kind	[1],[4]		0	0
Performance related bonuses	[1],[4]		0	0
Pension scheme contributions	[4]		0	0
Total paid/payable during the year	[4]		0	0
Non-executive directors [member] | Wang Jiaxiang [member]
Disclosure of transactions between related parties [line items]
Fees	[1],[9]			0
Salaries, allowances and benefits in kind	[1],[9]			0
Performance related bonuses	[1],[9]			0
Pension scheme contributions	[9]			0
Total paid/payable during the year	[9]			0
Non-executive directors [member] | Liu Jian [member]
Disclosure of transactions between related parties [line items]
Fees	[1],[10]	0	0
Salaries, allowances and benefits in kind	[1],[10]	0	0
Performance related bonuses	[1],[10]	0	0
Pension scheme contributions	[10]	0	0
Total paid/payable during the year	[10]	0	0
Independent non-executive directors [member]
Disclosure of transactions between related parties [line items]
Fees	[1]	3,592	3,538	3,324
Salaries, allowances and benefits in kind	[1]	0	0	0
Performance related bonuses	[1]	0	0	0
Pension scheme contributions		0	0	0
Total paid/payable during the year		3,592	3,538	3,324
Independent non-executive directors [member] | Chiu Sung Hong [member]
Disclosure of transactions between related parties [line items]
Fees	[1]	972	957	899
Salaries, allowances and benefits in kind	[1]	0	0	0
Performance related bonuses	[1]	0	0	0
Pension scheme contributions		0	0	0
Total paid/payable during the year		972	957	899
Independent non-executive directors [member] | Lawrence J. Lau [member]
Disclosure of transactions between related parties [line items]
Fees	[1]	824	812	763
Salaries, allowances and benefits in kind	[1]	0	0	0
Performance related bonuses	[1]	0	0	0
Pension scheme contributions		0	0	0
Total paid/payable during the year		824	812	763
Independent non-executive directors [member] | Tse Hau Yin, Aloysius [member]
Disclosure of transactions between related parties [line items]
Fees	[1]	972	957	899
Salaries, allowances and benefits in kind	[1]	0	0	0
Performance related bonuses	[1]	0	0	0
Pension scheme contributions		0	0	0
Total paid/payable during the year		972	957	899
Independent non-executive directors [member] | Kevin G. Lynch [member]
Disclosure of transactions between related parties [line items]
Fees	[1]	824	812	763
Salaries, allowances and benefits in kind	[1]	0	0	0
Performance related bonuses	[1]	0	0	0
Pension scheme contributions		0	0	0
Total paid/payable during the year		¥ 824	¥ 812	¥ 763

[1] Fees, salaries, allowances, benefits in kind and performance related bonuses represent the gross amount (before applicable individual salary tax) paid/payable to individual directors.

[2] On 15 June 2016, Mr. Yang Hua was re-designated as an Executive Director and appointed as the Chief Executive Officer of the Company. Mr. Yuan Guangyu was appointed as an Executive Director and the President of the Company. Mr. Li Fanrong resigned as an Executive Director, the Chief Executive Officer and the President of the Company.

[3] On 15 June 2016, Mr. Wu Guangqi was re-designated as a Non-executive Director of the Company and resigned as the Compliance Officer of the Company.

[4] On 20 December 2016, Mr. Wu Guangqi was appointed as a member of the Remuneration Committee of the Company. Mr. Lv Bo resigned as a Non-executive Director and a member of the Remuneration Committee of the Company.

[5] On 18 April 2017, Mr. Yang Hua was re-designated as a Non-executive Director of the Company. Mr. Yang Hua resigned as the Chief Executive Officer of the Company and he remains as the Chairman of the Board.

[6] On May 19, 2015, Mr. Yang Hua was appointed as Chairman of the Board and Chairman of the Nomination Committee of the Company and has no longer served as Vice-chairman of the Board. Mr. Wang Yilin resigned as Chairman of the Board, Chairman of the Nomination Committee and Nnon-executive ddirector of the Company.

[7] On 18 April 2017, Mr. Yuan Guangyu was appointed as the Chief Executive Officer of the Company. Mr. Yuan Guangyu resigned as the President of the Company.

[8] On 18 April 2017, Mr. Xu Keqiang was appointed as an Executive Director and the President of the Company.

[9] On September 23, 2015, Mr. Wang Jiaxiang retired as a non-executive director of the Company.

[10] On 20 December 2016, Mr. Liu Jian was appointed as the Vice Chairman and a Non-executive Director of the Company.

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KEY MANAGEMENT PERSONNEL'S REMUNERATION - Other key management personnel's (excluding Directors') remuneration (Details) ¥ in Millions		12 Months Ended
		Dec. 31, 2017 CNY (¥) option	Dec. 31, 2016 CNY (¥) option	Dec. 31, 2015 CNY (¥) option
Disclosure of transactions between related parties [line items]
Pension scheme contributions		¥ 651	¥ 695	¥ 613
Amount paid/payable during the year		6,517	6,403	6,924
Other key management personnel (excluding Directors) [member]
Disclosure of transactions between related parties [line items]
Short term employee benefits		9	7	8
Pension scheme contributions		1	1	1
Amount paid/payable during the year		10	8	9
Share options	[1]	0	0	0
Other key management personnel's (excluding Directors') remuneration		¥ 10	¥ 8	¥ 9
Number of other key management personnel exercising any share option | option		0	0	0

[1] This item represents the fair value of share options measured according to the Group's accounting policy as set out in note 3. No other key management personnel exercised any share option in 2015, 2016 or 2017.

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KEY MANAGEMENT PERSONNEL'S REMUNERATION - Bands of remuneration and related number of members of other key management personnel (excluding Directors) (Details) - Other key management personnel (excluding Directors) [member] - employee	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of transactions between related parties [line items]
Number of employees	12	10	10
Nil to RMB 2,000,000 [member]
Disclosure of transactions between related parties [line items]
Number of employees	12	10	10

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FIVE HIGHEST PAID EMPLOYEES - Details of remuneration (Details) ¥ in Millions		12 Months Ended
		Dec. 31, 2017 CNY (¥) employee director	Dec. 31, 2016 CNY (¥) employee director	Dec. 31, 2015 CNY (¥) employee director
Disclosure Of Highest Paid Employees [line items]
Number of Directors who received an amount which falls within the category of the five highest paid employees | director		0	0	0
Pension scheme contributions		¥ 651	¥ 695	¥ 613
Amount paid/payable during the year		¥ 6,517	¥ 6,403	¥ 6,924
Highest paid employees [member]
Disclosure Of Highest Paid Employees [line items]
Number of highest paid employees | employee		5	5	5
Salaries, allowances and benefits in kind	[1]	¥ 21	¥ 23	¥ 22
Performance related bonuses		19	14	17
Pension scheme contributions		1	1	1
Amount paid/payable during the year		¥ 41	¥ 38	¥ 40

[1] Salaries, allowances, and benefits in kind represent the gross amount (before applicable individual salary tax) paid/payable to individual employees.

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FIVE HIGHEST PAID EMPLOYEES - Number of highest paid employees in each remuneration band (Details) - Highest paid employees [member] - employee	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Highest Paid Employees [line items]
Number of highest paid employees	5	5	5
RMB5,500,001 to RMB6,000,000 [member]
Disclosure Of Highest Paid Employees [line items]
Number of highest paid employees	0	1	0
RMB6,000,001 to RMB6,500,000 [member]
Disclosure Of Highest Paid Employees [line items]
Number of highest paid employees	1	0	0
RMB7,000,001 to RMB7,500,000 [member]
Disclosure Of Highest Paid Employees [line items]
Number of highest paid employees	1	0	3
RMB7,500,001 to RMB8,000,000 [member]
Disclosure Of Highest Paid Employees [line items]
Number of highest paid employees	0	3	0
RMB8,000,001 to RMB8,500,000 [member]
Disclosure Of Highest Paid Employees [line items]
Number of highest paid employees	1	0	0
RMB9,000,001 to RMB9,500,000 [member]
Disclosure Of Highest Paid Employees [line items]
Number of highest paid employees	1	1	2
RMB10,000,001 to RMB10,500,000 [member]
Disclosure Of Highest Paid Employees [line items]
Number of highest paid employees	1	0	0

XML

TAX - Income tax - Narrative (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Disclosure of detailed information about income tax rate [line items]
Income tax rate		25.00%	25.00%	25.00%
CNOOC China Limited [member]
Disclosure of detailed information about income tax rate [line items]
Income tax rate		25.00%	25.00%	25.00%
CNOOC Deepwater Development Limited [member]
Disclosure of detailed information about income tax rate [line items]
Income tax rate		15.00%	15.00%	15.00%
Period of high and new technology enterprises, before re-applying		3 years
Hong Kong [member]
Disclosure of detailed information about income tax rate [line items]
Income tax rate		16.50%	16.50%	16.50%
PRC [member]
Disclosure of detailed information about income tax rate [line items]
Income tax rate		25.00%	25.00%	25.00%	25.00%	25.00%	25.00%	25.00%	25.00%	25.00%	25.00%
U.S. government [member]
Disclosure of detailed information about income tax rate [line items]
Income tax rate	21.00%	35.00%	35.00%	35.00%
U.K. government [member] | North Sea oil and gas activites [member]
Disclosure of detailed information about income tax rate [line items]
Income tax rate		40.00%	40.00%	50.00%
Maximum [member] | Outside the PRC [member]
Disclosure of detailed information about income tax rate [line items]
Income tax rate		50.00%	50.00%	56.00%
Minimum [member] | Outside the PRC [member]
Disclosure of detailed information about income tax rate [line items]
Income tax rate		10.00%	10.00%	10.00%

XML

TAX - Analysis of tax expense/(credit) in the Group's consolidated statement of profit or loss and other comprehensive income (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
Deferred tax
Temporary differences in the current year	¥ (7,558)		¥ (14,595)	¥ (12,585)
Effect of changes in tax rates	3,376		(1,847)	(4,022)
Income tax (credit)/expense for the year	11,680	$ 1,795	(5,912)	(3,116)
PRC [member]
Current tax
Provision for enterprise income tax on the estimated taxable profits for the year	11,472		7,547	9,990
Outside the PRC [member]
Current tax
Provision for enterprise income tax on the estimated taxable profits for the year	¥ 4,390		¥ 2,983	¥ 3,501

XML

TAX - Reconciliation of the PRC statutory corporate income tax rate to the effective income tax rate (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
TAX [abstract]
PRC statutory enterprise income tax rate	25.00%	25.00%	25.00%
Effect of different tax rates for overseas subsidiaries	(1.60%)	34.80%	(5.80%)
Changes in tax rates	9.40%	35.00%	(23.50%)
Tax credit from the government	(2.70%)	8.30%	(11.50%)
Tax reported in equity-accounted entities	(0.20%)	1.00%	(0.40%)
Tax losses previously not recognized	0.00%	5.30%	(1.90%)
Others	2.20%	2.70%	(0.10%)
Group's effective income tax rate	32.10%	112.10%	(18.20%)

XML

TAX - Movements of deferred tax liabilities net of deferred tax assets (Details) - CNY (¥) ¥ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
TAX [abstract]
Balance at beginning of period	¥ (19,174)	¥ (1,948)	¥ 14,312
Credit to the profit or loss	(7,558)	(14,595)	(12,585)
Effect of changes in tax rates	3,376	(1,847)	(4,022)
Charge to equity	7	(226)	141
Exchange differences	1,143	(558)	206
Balance at end of period	¥ (22,206)	¥ (19,174)	¥ (1,948)

XML

TAX - Principal components of deferred tax balances (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2015 CNY (¥)	Dec. 31, 2014 CNY (¥)
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	¥ 36,459	¥ 35,527
Deferred tax liabilities	(14,253)	(16,353)
Net deferred tax assets	22,206	19,174		¥ 1,948	¥ (14,312)
Of which - deferred tax assets	25,509	24,844	$ 3,921
Of which - deferred tax liabilities	(3,303)	(5,670)	$ (508)
Carry-forward tax losses	87,623	82,288
Tax losses for which deferred tax asset recognised	75,018	68,061
Unrecognized tax losses	12,605	14,227
Unused tax credits	¥ 4,990	5,761
Uganda [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Expiry date	No fixed expiry date
Unrecognized tax losses	¥ 3,181	3,207
Nigeria [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Expiry date	No fixed expiry date
Unused tax credits	¥ 4,587	4,807
Countries excluding NG [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Expiry date	Bewteen 2026 and 2036
Maximum [member] | U.S. government [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Expiry date	P20Y
Maximum [member] | Canada [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Expiry date	P20Y
Maximum [member] | Countries excluding UG [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Expiry date	P20Y
Minimum [member] | U.S. government [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Expiry date	P8Y
Minimum [member] | Canada [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Expiry date	P8Y
Minimum [member] | Countries excluding UG [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Expiry date	P5Y
Property, plant and equipment [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	¥ 7,312	1,681
Deferred tax liabilities	(13,670)	(16,208)
Provision for dismantlement [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	9,669	9,325
Losses available for offsetting against future taxable profit [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	16,529	21,163
Fair value of long term borrowings [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	1,771	1,969
Others [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	1,178	1,389
Deferred tax liabilities	(351)	(6)
Fair value changes on other financial assets [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	¥ (232)	¥ (139)

XML

TAX - Other taxes (Details)	1 Months Ended	4 Months Ended	6 Months Ended		8 Months Ended	12 Months Ended
	Dec. 31, 2014	Apr. 30, 2016	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of detailed information about taxes other than income tax [line items]
Production tax rate						5.00%
Export tariff rate						5.00%
City construction tax rate lower						1.00%
City construction tax rate higher						7.00%
Educational surcharge rate						3.00%
Local educational surcharge rate						2.00%
Oil and gas sale activities [member]
Disclosure of detailed information about taxes other than income tax [line items]
Production tax rate		5.00%
Gas sales [member]
Disclosure of detailed information about taxes other than income tax [line items]
VAT rate			11.00%
Maximum [member] | Oil and gas sale activities [member]
Disclosure of detailed information about taxes other than income tax [line items]
VAT rate			17.00%	17.00%	17.00%
Resource tax rate	6.00%					6.00%	6.00%	6.00%
Maximum [member] | Other income [member]
Disclosure of detailed information about taxes other than income tax [line items]
VAT rate		17.00%			17.00%	17.00%
Business tax rate		5.00%
Minimum [member] | Oil and gas sale activities [member]
Disclosure of detailed information about taxes other than income tax [line items]
VAT rate				13.00%	13.00%
Resource tax rate	5.00%					5.00%	5.00%	5.00%
Minimum [member] | Other income [member]
Disclosure of detailed information about taxes other than income tax [line items]
VAT rate		3.00%			3.00%	3.00%
Business tax rate		3.00%

XML

TAX - Special Oil Gain Levy (Details)	12 Months Ended
	Dec. 31, 2017 $ / barrel	Dec. 31, 2016 $ / barrel	Dec. 31, 2015 $ / barrel	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)	Dec. 31, 2007 USD ($)	Dec. 31, 2006 USD ($)
Maximum [member]
Disclosure of detailed information about special oil gain levy [line items]
Progressive rates	40.00%	40.00%	40.00%	40.00%	40.00%	40.00%	40.00%	40.00%	40.00%	40.00%	40.00%	40.00%
Minimum [member]
Disclosure of detailed information about special oil gain levy [line items]
Progressive rates	20.00%	20.00%	20.00%	20.00%	20.00%	20.00%	20.00%	20.00%	20.00%	20.00%	20.00%	20.00%
Threshold of Special Oil Gain Levy	65	65	65	40	40	40	40	40	40	40	40	40

XML

EARNINGS PER SHARE (Details) ¥ / shares in Units, $ / shares in Units, ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥) ¥ / shares shares	Dec. 31, 2017 USD ($) $ / shares shares	Dec. 31, 2016 CNY (¥) ¥ / shares shares	Dec. 31, 2015 CNY (¥) ¥ / shares shares
Earnings
Profit for the basic and diluted earnings per share calculation	¥ 24,677	$ 3,793	¥ 637	¥ 20,246
Number of shares
Number of ordinary shares for the purpose of basic earnings per share calculation	44,647,455,984	44,647,455,984	44,647,455,984	44,647,455,984
Effect of dilutive potential ordinary shares under the share option schemes	4,101,969	4,101,969	11,684,504	37,363,069
Weighted average number of ordinary shares for the purpose of diluted earnings per share	44,651,557,953	44,651,557,953	44,659,140,488	44,684,819,053
EARNINGS PER SHARE ATTRIBUTABLE TO OWNERS OF THE PARENT [abstract]
Basic (RMB Yuan) | (per share)	¥ 0.55	$ 0.085	¥ 0.01	¥ 0.45
Diluted (RMB Yuan) | (per share)	¥ 0.55	$ 0.085	¥ 0.01	¥ 0.45

XML

DIVIDENDS (Details) ¥ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 $ / shares	Dec. 31, 2016 CNY (¥)	Dec. 31, 2016 $ / shares	Dec. 31, 2015 CNY (¥)	Dec. 31, 2015 $ / shares	Dec. 31, 2014 $ / shares	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Dividend per ordinary share:
Interim dividend | ¥	¥ 7,601		¥ 4,673		¥ 9,145
Final dividends | ¥	8,847		9,571		11,274
Final dividend proposed by the Board of Directors - not recognized as a liability as at the end of the year | ¥	¥ 10,830		¥ 9,096		¥ 9,397
Interim dividend per ordinary share | $ / shares		$ 0.20		$ 0.12		$ 0.25
Final dividend per ordinary share | $ / shares				0.23		0.25	$ 0.32
Final dividend proposed per ordinary share | $ / shares		$ 0.3		$ 0.23		$ 0.25
Corporate income tax rate	10.00%		10.00%		10.00%		10.00%	10.00%	10.00%	10.00%	10.00%	10.00%

XML

PROPERTY, PLANT AND EQUIPMENT (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
Disclosure of detailed information about property, plant and equipment [line items]
Balance at beginning of period	¥ 432,465		¥ 454,141
Depreciation charge for the year	(60,802)		(68,303)	¥ (72,293)
Impairment	(8,639)		(10,768)	(2,358)
Balance at end of period	395,868	$ 60,844	432,465	454,141
Cost [member]
Disclosure of detailed information about property, plant and equipment [line items]
Balance at beginning of period	873,326		809,282
Additions	49,036		44,538
Disposals and write-offs	(3,491)		(6,402)
Exchange differences	(25,133)		25,908
Balance at end of period	893,738		873,326	809,282
Accumulated depreciation, depletion and amortization and impairment [member]
Disclosure of detailed information about property, plant and equipment [line items]
Balance at beginning of period	(440,861)		(355,141)
Depreciation charge for the year	(60,802)		(68,303)
Impairment	(8,639)		(10,768)
Disposals and write-offs	1,443		3,566
Exchange differences	10,989		(10,215)
Balance at end of period	(497,870)		(440,861)	(355,141)
Oil and gas properties [member]
Disclosure of detailed information about property, plant and equipment [line items]
Balance at beginning of period	428,503
Balance at end of period	392,914		428,503
Oil and gas properties [member] | Cost [member]
Disclosure of detailed information about property, plant and equipment [line items]
Balance at beginning of period	867,626		803,986
Additions	48,937		44,302
Disposals and write-offs	(2,577)		(6,365)
Exchange differences	(24,985)		25,703
Balance at end of period	889,001		867,626	803,986
Oil and gas properties [member] | Accumulated depreciation, depletion and amortization and impairment [member]
Disclosure of detailed information about property, plant and equipment [line items]
Balance at beginning of period	(439,123)		(353,824)
Depreciation charge for the year	(60,442)		(67,906)
Impairment	(8,639)		(10,768)
Disposals and write-offs	1,185		3,532
Exchange differences	10,932		(10,157)
Balance at end of period	(496,087)		(439,123)	(353,824)
Vehicles and office equipment and others [member]
Disclosure of detailed information about property, plant and equipment [line items]
Balance at beginning of period	3,962
Balance at end of period	2,954		3,962
Vehicles and office equipment and others [member] | Cost [member]
Disclosure of detailed information about property, plant and equipment [line items]
Balance at beginning of period	5,700		5,296
Additions	99		236
Disposals and write-offs	(914)		(37)
Exchange differences	(148)		205
Balance at end of period	4,737		5,700	5,296
Vehicles and office equipment and others [member] | Accumulated depreciation, depletion and amortization and impairment [member]
Disclosure of detailed information about property, plant and equipment [line items]
Balance at beginning of period	(1,738)		(1,317)
Depreciation charge for the year	(360)		(397)
Impairment	0		0
Disposals and write-offs	258		34
Exchange differences	57		(58)
Balance at end of period	¥ (1,783)		¥ (1,738)	¥ (1,317)

XML

PROPERTY, PLANT AND EQUIPMENT - Narrative (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)	Jun. 30, 2016 CNY (¥)
Disclosure of detailed information about property, plant and equipment [line items]
Additions in respect of interest capitalized in property, plant and equipment (note 8)	¥ 2,495		¥ 1,430	¥ 1,385
Impairment loss recognized on Long Lake project	8,639		10,768	2,358
Exploration expenses	6,881	$ 1,058	7,359	9,900
Depreciation, depletion and amortization charge	¥ 60,802		¥ 68,303	72,293
Maximum [member]
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate for value in use calculations after tax	12.00%	12.00%	11.00%
Derived pre-tax discount rate	15.00%	15.00%	11.00%
Minimum [member]
Disclosure of detailed information about property, plant and equipment [line items]
Discount rate for value in use calculations after tax	8.00%	8.00%	8.00%
Derived pre-tax discount rate	8.00%	8.00%	9.00%
Long Lake project [member]
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss recognized on Long Lake project			¥ 7,358
Estimated recoverable amount					¥ 33,902
Oil and gas properties [member]
Disclosure of detailed information about property, plant and equipment [line items]
Depreciation charge for the year in respect of a depreciation charge on dismantlement cost capitalized in oil and gas properties	¥ 636		¥ 1,609	¥ 3,465
Oil and gas properties [member] | North America [member]
Disclosure of detailed information about property, plant and equipment [line items]
Exploration expenses	71
Depreciation, depletion and amortization charge	¥ 1,588

XML

INTANGIBLE ASSETS (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	¥ 16,644
Amortization charge for the year	(854)		¥ (1,020)	¥ (1,306)
Balance at end of year	15,070	$ 2,316	16,644
Cost [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	22,095		20,980
Additions	206		197
Disposal	(1,915)		(387)
Exchange differences	(1,123)		1,305
Balance at end of year	19,263		22,095	20,980
Accumulated amortization [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	(5,451)		(4,557)
Amortization charge for the year	(854)		(1,020)
Disposal	1,915		386
Exchange differences	197		(260)
Balance at end of year	(4,193)		(5,451)	(4,557)
Gas processing rights under NWS Project [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	544
Balance at end of year	467		544
Gas processing rights under NWS Project [member] | Cost [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	1,273		1,191
Additions	0		0
Disposal	0		0
Exchange differences	(74)		82
Balance at end of year	1,199		1,273	1,191
Gas processing rights under NWS Project [member] | Accumulated amortization [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	(729)		(621)
Amortization charge for the year	(46)		(51)
Disposal	0		0
Exchange differences	43		(57)
Balance at end of year	(732)		(729)	(621)
Drilling rig contracts and seismic data usage rights [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	341
Balance at end of year	¥ 0		341
Drilling rig contracts and seismic data usage rights [member] | Maximum [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Useful lives or amortisation rates, intangible assets other than goodwill	P5Y	P5Y
Drilling rig contracts and seismic data usage rights [member] | Minimum [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Useful lives or amortisation rates, intangible assets other than goodwill	P3Y	P3Y
Drilling rig contracts and seismic data usage rights [member] | Cost [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	¥ 1,705		1,596
Additions	0		0
Disposal	(1,662)		0
Exchange differences	(43)		109
Balance at end of year	0		1,705	1,596
Drilling rig contracts and seismic data usage rights [member] | Accumulated amortization [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	(1,364)		(958)
Amortization charge for the year	(332)		(326)
Disposal	1,662		0
Exchange differences	34		(80)
Balance at end of year	0		(1,364)	(958)
Marketing transportation and storage contracts [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	319
Balance at end of year	¥ 245		319
Marketing transportation and storage contracts [member] | Maximum [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Useful lives or amortisation rates, intangible assets other than goodwill	P20Y	P20Y
Marketing transportation and storage contracts [member] | Cost [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	¥ 1,631		1,527
Additions	0		0
Disposal	(54)		0
Exchange differences	(93)		104
Balance at end of year	1,484		1,631	1,527
Marketing transportation and storage contracts [member] | Accumulated amortization [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	(1,312)		(1,096)
Amortization charge for the year	(57)		(135)
Disposal	54		0
Exchange differences	76		(81)
Balance at end of year	(1,239)		(1,312)	(1,096)
Software and others [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	692
Balance at end of year	¥ 466		692
Software and others [member] | Maximum [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Useful lives or amortisation rates, intangible assets other than goodwill	P5Y	P5Y
Software and others [member] | Minimum [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Useful lives or amortisation rates, intangible assets other than goodwill	P3Y	P3Y
Software and others [member] | Cost [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	¥ 2,738		2,861
Additions	206		197
Disposal	(199)		(387)
Exchange differences	(57)		67
Balance at end of year	2,688		2,738	2,861
Software and others [member] | Accumulated amortization [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	(2,046)		(1,882)
Amortization charge for the year	(419)		(508)
Disposal	199		386
Exchange differences	44		(42)
Balance at end of year	(2,222)		(2,046)	(1,882)
Goodwill [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	14,748
Balance at end of year	13,892		14,748
Goodwill [member] | Cost [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	14,748		13,805
Additions	0		0
Disposal	0		0
Exchange differences	(856)		943
Balance at end of year	13,892		14,748	13,805
Goodwill [member] | Accumulated amortization [member]
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Balance at beginning of year	0		0
Amortization charge for the year	0		0
Disposal	0		0
Exchange differences	0		0
Balance at end of year	¥ 0		¥ 0	¥ 0

XML

INVESTMENTS IN ASSOCIATES - Particulars of principal associates (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)
Disclosure of associates [line items]
Nominal value of ordinary shares issued and paid-up/registered capital	¥ 43,081	$ 6,621	¥ 43,081
Shanghai Petroleum Corporation Limited [member]
Disclosure of associates [line items]
Name of associates	Shanghai Petroleum Corporation Limited
Place of establishment	Shanghai, PRC
Nominal value of ordinary shares issued and paid-up/registered capital	¥ 90
Percentage of equity attributable to the Group	30.00%
CNOOC Finance Corporation Limited [member]
Disclosure of associates [line items]
Name of associates	CNOOC Finance Corporation Limited
Place of establishment	Beijing, PRC
Nominal value of ordinary shares issued and paid-up/registered capital	¥ 4,000
Percentage of equity attributable to the Group	31.80%

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INVESTMENTS IN ASSOCIATES - The Group's investments in associates (Details) - CNY (¥) ¥ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of associates [line items]
Share of net assets	¥ 29,146	¥ 29,995	¥ 28,413
Associates [member]
Disclosure of associates [line items]
Share of net assets	¥ 4,067	¥ 3,695

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INVESTMENTS IN ASSOCIATES - Summarized financial information of the Group's associates in the consolidated financial statements (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
Disclosure of associates [line items]
Segment profit/ (loss) for the year	¥ 24,677		¥ 637	¥ 20,246
Other comprehensive income/(expense)	(10,573)	$ (1,625)	9,846	6,614
Dividend received from the associates	116	$ 18	135	164
Associates [member]
Disclosure of associates [line items]
Segment profit/ (loss) for the year	302		(609)	256
Other comprehensive income/(expense)	36		(127)	74
Total comprehensive income/(expense)	338		(736)	¥ 330
Dividend received from the associates	¥ 116		¥ 135

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INVESTMENT IN A JOINT VENTURE - Particulars of the joint venture (Details) ¥ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)
Disclosure of joint ventures [line items]
Nominal value of ordinary shares issued and paid-up/registered capital	¥ 43,081	$ 6,621,000,000	¥ 43,081
Bridas Corporation [member]
Disclosure of joint ventures [line items]
Name of entity	Bridas Corporation
Place of establishment	British Virgin Islands
Nominal value of ordinary shares issued and paid-up/registered capital		$ 102,325,582
Percentage of equity attributable to the Group	50.00%

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INVESTMENT IN A JOINT VENTURE - Summarized financial information of the joint venture (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)	Dec. 31, 2015 USD ($)	Dec. 31, 2017 USD ($)
Disclosure of joint ventures [line items]
Current assets	¥ 138,838,000,000		¥ 122,045,000,000			$ 21,339
Non-current assets	478,381,000,000		515,636,000,000			73,526
Current liabilities	61,412,000,000		67,090,000,000			9,439
Non-current liabilities	175,832,000,000		188,220,000,000			$ 27,025
Revenue	186,390,000,000	$ 28,648	146,490,000,000	¥ 171,437,000,000
Depreciation, depletion and amortization	(61,257,000,000)	(9,415)	(68,907,000,000)	(73,439,000,000)
Interest income	653,000,000	100	901,000,000	873,000,000
Finance costs	(5,044,000,000)	(775)	(6,246,000,000)	(6,118,000,000)
Profit before tax	36,357,000,000	5,588	(5,275,000,000)	17,130,000,000
Income tax expense	(11,680,000,000)	(1,795)	5,912,000,000	3,116,000,000
Profit after tax	24,677,000,000		637,000,000	20,246,000,000
Dividends received from a joint venture	243,000,000	37	0	32,000,000
Joint ventures [member]
Disclosure of joint ventures [line items]
Current assets	11,614,000,000		9,201,000,000
Non-current assets	63,660,000,000		66,992,000,000
Current liabilities	(6,630,000,000)		(6,866,000,000)
Non-current liabilities	(18,486,000,000)		(16,727,000,000)
Revenue	29,879,000,000		28,371,000,000	31,231,000,000
Depreciation, depletion and amortization	(3,742,000,000)		(3,988,000,000)	(3,535,000,000)
Interest income	313,000,000		388,000,000	288,000,000
Finance costs	(550,000,000)		(704,000,000)	(799,000,000)
Profit before tax	2,215,000,000		1,226,000,000	4,194,000,000
Income tax expense	(1,109,000,000)		(160,000,000)	(900,000,000)
Profit after tax	1,106,000,000		1,066,000,000	3,294,000,000
Total comprehensive income/(expense)	1,106,000,000		1,066,000,000	3,294,000,000
Dividends received from a joint venture	¥ 243,000,000	$ 36	¥ 0	¥ 32,000,000	$ 5

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EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS - Equity investments (Details) ¥ in Millions, $ in Millions		Dec. 31, 2017 CNY (¥)		Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)
Equity investments
Current equity investments		¥ 14		$ 2	¥ 15
Non-current equity investments		3,540		$ 544	4,266
Non-current: Publicly traded investments [member]
Equity investments
Non-current equity investments		781			1,391
Equity investments classified at FVTOCI [member] | Current: Non-publicly traded investments [member]
Equity investments
Current equity investments		14			15
Equity investments classified at FVTOCI [member] | Non-current: Publicly traded investments [member] | MEG Energy Corporation ("MEG") [member]
Equity investments
Non-current equity investments classified at FVTOCI		766	[1]		1,356	[2]
Equity investments classified at FVTOCI [member] | Non-current: Non-publicly traded investments [member] | Kerogen Energy Fund [member]
Equity investments
Non-current equity investments classified at FVTOCI	[2]	2,759			2,875
Equity investment classified at FVTPL [member] | Non-current: Publicly traded investments [member]
Equity investments
Other equity investments classified at FVTPL		¥ 15			¥ 35

[1] MEG is principally engaged in the exploitation and production of oil sands. The investment in MEG is designated by the Group as at FVTOCI. As at December 31, 2017, the investment in MEG was stated at the quoted market price.

[2] Kerogen Energy Fund is principally engaged in the investment in the oil and gas industry. The equity investment in Kerogen Energy Fund is designated by the Group as at FVTOCI. The cost of this non-publicly traded equity investment represents an appropriate estimate of its fair value as at January 1, 2017 and December 31, 2017, as sufficient information is not available recently to measure its fair value.

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EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS - Other financial assets (Details) ¥ in Millions, $ in Millions		Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)
Disclosure of financial assets [line items]
Other financial assets		¥ 74,344	$ 11,426	¥ 52,889
Other financial assets classified at FVTPL [member] | Current: Non-publicly traded investments [member]
Disclosure of financial assets [line items]
Other financial assets		74,344		52,889
Other financial assets classified at FVTPL [member] | Corporate wealth management products [member]
Disclosure of financial assets [line items]
Other financial assets	[1]	66,229		46,958
Other financial assets classified at FVTPL [member] | Money market funds [member]
Disclosure of financial assets [line items]
Other financial assets	[2]	¥ 8,115		¥ 5,931

[1] The corporate wealth management products will mature from January 8, 2018 to November 6, 2018 (2016: January 10, 2017 to December 5, 2017).

[2] The money market funds can be redeemed at any time.

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EQUITY INVESTMENTS AND OTHER FINANCIAL ASSETS - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
Disclosure of financial assets [line items]
The fair value changes on the Group's investment recognized directly in other comprehensive expense	¥ 542,000,000	$ 83	¥ 461,000,000	¥ 1,573,000,000
Other financial assets [member]
Disclosure of financial assets [line items]
The gains of ther Group's other financial assets recognized in the profit or loss for the year	2,409,000,000		2,774,000,000	2,398,000,000
Equity investments [member]
Disclosure of financial assets [line items]
The fair value changes on the Group's investment recognized directly in other comprehensive expense	542,000,000		461,000,000	1,573,000,000
Financial assets past due [member] | Other financial assets [member]
Disclosure of financial assets [line items]
Equity investments and other financial assets past due or impaired	0		0	0
Financial assets past due [member] | Equity investments [member]
Disclosure of financial assets [line items]
Equity investments and other financial assets past due or impaired	0		0	0
Financial assets impaired [member] | Other financial assets [member]
Disclosure of financial assets [line items]
Equity investments and other financial assets past due or impaired	0		0	0
Financial assets impaired [member] | Equity investments [member]
Disclosure of financial assets [line items]
Equity investments and other financial assets past due or impaired	¥ 0		¥ 0	¥ 0

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OTHER NON-CURRENT ASSETS (Details) - CNY (¥) ¥ in Millions	Dec. 31, 2017	Dec. 31, 2016
OTHER NON-CURRENT ASSETS [abstract]
Specified dismantlement fund accounts	¥ 7,555	¥ 6,088

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INVENTORIES AND SUPPLIES (Details) $ in Millions	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)
INVENTORIES AND SUPPLIES [abstract]
Material and supplies	¥ 6,278,000,000		¥ 7,288,000,000
Oil in tanks	1,540,000,000		1,594,000,000
Less: Provision for inventory obsolescence	(464,000,000)		(173,000,000)
Total inventories and supplies	¥ 7,354,000,000	$ 1,130	¥ 8,709,000,000

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TRADE RECEIVABLES (Details) - Maximum [member]	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of detailed information about trade receivables [line items]
Credit term	30 days
Age of trade receivables	1 year	1 year

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CASH AND CASH EQUIVALENTS AND TIME DEPOSITS WITH MATURITY OVER THREE MONTHS (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of detailed information about cash and cash equivalents and time deposits with maturity over three months [line items]
Weighted average effective interest rates of the Group's bank deposits	2.23%	2.95%	2.61%
Maximum [member]
Disclosure of detailed information about cash and cash equivalents and time deposits with maturity over three months [line items]
Maturity of current deposits and time deposits	7 days	7 days	7 days

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TRADE AND ACCRUED PAYABLES (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Maximum [member]
Disclosure of detailed information about trade and accrued payables [line items]
Age of trade and accrued payables	P6M	P6M

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OTHER PAYABLES AND ACCRUED LIABILITIES (Details) ¥ in Millions, $ in Millions	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)
OTHER PAYABLES AND ACCRUED LIABILITIES [abstract]
Accrued payroll and welfare payable	¥ 1,490		¥ 1,509
Provision for retirement benefits	630		683
Accruals expenses	381		449
Advances from customers	3,096		3,272
Special oil gain levy payable	55		0
Royalties payable	75		240
Provision for dismantlement	1,180		462
Other payables	7,199		8,251
Other payables and accrued liabilities	¥ 14,106	$ 2,137	¥ 14,866

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LOANS AND BORROWINGS - Current (Details) - CNY (¥) ¥ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Disclosure of current loans and borrowings [line items]
Loans		¥ 8,991	¥ 10,576
Notes		4,901	9,102
Total		13,892	19,678
Short-term loans and borrowings [member]
Disclosure of current loans and borrowings [line items]
Loans		8,779	10,361
Notes		0	0
Total		8,779	10,361
General loans [member]
Disclosure of current loans and borrowings [line items]
Loans	[1]	8,779	10,361
Notes	[1]	0	0
Total	[1]	¥ 8,779	¥ 10,361
General loans [member] | Minimum [member]
Disclosure of current loans and borrowings [line items]
Effective interest rate	[1]	0.35%	0.35%
General loans [member] | Maximum [member]
Disclosure of current loans and borrowings [line items]
Effective interest rate	[1]	0.75%	0.75%
Final maturity	[1]	P1Y	P1Y
Loans and borrowings due within one year [member]
Disclosure of current loans and borrowings [line items]
Loans		¥ 212	¥ 215
Notes		4,901	9,102
Total		5,113	9,317
For Tangguh LNG Project [member]
Disclosure of current loans and borrowings [line items]
Loans	[2]	212	215
Notes	[2]	0	0
Total	[2]	¥ 212	¥ 215
For Tangguh LNG Project [member] | Minimum [member]
Disclosure of current loans and borrowings [line items]
Effective interest rate	[2]	0.19%	0.19%
For Tangguh LNG Project [member] | Maximum [member]
Disclosure of current loans and borrowings [line items]
Effective interest rate	[2]	0.335%	0.335%
Final maturity	[2]	P1Y	P1Y
Notes [member]
Disclosure of current loans and borrowings [line items]
Loans		¥ 0	¥ 0
Notes		4,901	9,102
Total		¥ 4,901	¥ 9,102

[1] As at December 31, 2017, US$650 million bank loans (2016: US$800 million) were guaranteed by the Company. As at December 31, 2017, US$694 million shareholder loans (2016: US$694 million) of the Group were included in general loans. For details please refer to Note 28(v).

[2] In connection with the Tangguh LNG Project in Indonesia, the Company delivered a guarantee dated October 29, 2007, in favor of Mizuho Corporate Bank, Ltd., which acts as the facility agent for and on behalf of various international commercial banks under a US$884 million commercial loan agreement. The Company guarantees the payment obligations of the trustee borrower under the subject loan agreement and is subject to a maximum cap of approximately US$135,163,308.28. A letter of credit agreement was signed between the Company and Talisman Energy Inc. ("Talisman") with execution of the agreement in respect of the sale of a 3.05691% interest of the Company in the Tangguh LNG Project to Talisman. Accordingly, Talisman has delivered valid and unexpired standby letters of credit to the Company (as the beneficiary) as a counter-guarantee to offset the exposure of the Company's guarantee for the aforesaid interest of 3.05691% in respect of the Tangguh LNG Project financing. The amount of the standby letters of credit was US$30 million. In February 2017, the standby letters of credit were withdrawn as the Company transferred the 3.05691% guarantee obligations to BP Corporation North America Inc..

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LOANS AND BORROWINGS - Non-current (Details) ¥ in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2017 CNY (¥)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2017 USD ($)
Disclosure of non-current loans and borrowings [line items]
Loans		¥ 1,279	¥ 1,085
Notes		117,079	129,713
Total		¥ 118,358	¥ 130,798	$ 18,191
For Tangguh LNG Project [member]
Disclosure of non-current loans and borrowings [line items]
Final maturity	[1]	With maturity through to 2021.	With maturity through to 2021.
Loans	[1]	¥ 502	¥ 758
Notes	[1]	0	0
Total	[1]	¥ 502	¥ 758
For Tangguh LNG Project [member] | Minimum [member]
Disclosure of non-current loans and borrowings [line items]
Effective interest rate	[1]	0.19%	0.19%
For Tangguh LNG Project [member] | Maximum [member]
Disclosure of non-current loans and borrowings [line items]
Effective interest rate	[1]	0.335%	0.335%
For Tangguh LNG III Project [member]
Disclosure of non-current loans and borrowings [line items]
Final maturity	[2]	With maturity through 2021 to 2029.	With maturity through 2021 to 2029.
Loans	[2]	¥ 777	¥ 327
Notes	[2]	0	0
Total	[2]	¥ 777	¥ 327
For Tangguh LNG III Project [member] | Minimum [member]
Disclosure of non-current loans and borrowings [line items]
Effective interest rate	[2]	1.37%	1.37%
For Tangguh LNG III Project [member] | Maximum [member]
Disclosure of non-current loans and borrowings [line items]
Effective interest rate	[2]	3.45%	3.45%
Notes [member]
Disclosure of non-current loans and borrowings [line items]
Loans		¥ 0	¥ 0
Notes		117,079	129,713
Total		¥ 117,079	¥ 129,713

[1] In connection with the Tangguh LNG Project in Indonesia, the Company delivered a guarantee dated October 29, 2007, in favor of Mizuho Corporate Bank, Ltd., which acts as the facility agent for and on behalf of various international commercial banks under a US$884 million commercial loan agreement. The Company guarantees the payment obligations of the trustee borrower under the subject loan agreement and is subject to a maximum cap of approximately US$135,163,308.28. A letter of credit agreement was signed between the Company and Talisman Energy Inc. ("Talisman") with execution of the agreement in respect of the sale of a 3.05691% interest of the Company in the Tangguh LNG Project to Talisman. Accordingly, Talisman has delivered valid and unexpired standby letters of credit to the Company (as the beneficiary) as a counter-guarantee to offset the exposure of the Company's guarantee for the aforesaid interest of 3.05691% in respect of the Tangguh LNG Project financing. The amount of the standby letters of credit was US$30 million. In February 2017, the standby letters of credit were withdrawn as the Company transferred the 3.05691% guarantee obligations to BP Corporation North America Inc..

[2] In connection with the financing for the third LNG process train of Tangguh LNG Project in Indonesia, the Company delivered two guarantees dated August 3, 2016, in favor of Mizuho Bank, Ltd., which acts as the facility agent for and on behalf of various international commercial banks and Indonesian local commercial banks under two commercial loan agreements with aggregate loan amount of US$2,145 million. The Company guarantees the payment obligations of the trustee borrower under the subject loan agreements and is subject to an aggregate maximum cap of approximately US$573 million.

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LOANS AND BORROWINGS - Details of notes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of detailed information about borrowings [line items]
Coupon Rate	2.52%	1.74%
CNOOC Finance (2003) Limited [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Finance (2003) Limited	CNOOC Finance (2003) Limited
Maturity	Due in 2033	Due in 2033
Coupon Rate	5.50%	5.50%
Outstanding Principal Amount	$ 300	$ 300
CNOOC Finance (2011) Limited [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Finance (2011) Limited	CNOOC Finance (2011) Limited
Maturity	Due in 2021	Due in 2021
Coupon Rate	4.25%	4.25%
Outstanding Principal Amount	$ 1,500	$ 1,500
CNOOC Finance (2011) Limited (note two) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Finance (2011) Limited	CNOOC Finance (2011) Limited
Maturity	Due in 2041	Due in 2041
Coupon Rate	5.75%	5.75%
Outstanding Principal Amount	$ 500	$ 500
CNOOC Finance (2012) Limited [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Finance (2012) Limited	CNOOC Finance (2012) Limited
Maturity	Due in 2022	Due in 2022
Coupon Rate	3.875%	3.875%
Outstanding Principal Amount	$ 1,500	$ 1,500
CNOOC Finance (2012) Limited (note two) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Finance (2012) Limited	CNOOC Finance (2012) Limited
Maturity	Due in 2042	Due in 2042
Coupon Rate	5.00%	5.00%
Outstanding Principal Amount	$ 500	$ 500
CNOOC Finance (2013) Limited [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Finance (2013) Limited	CNOOC Finance (2013) Limited
Maturity	Due in 2018	Due in 2018
Coupon Rate	1.75%	1.75%
Outstanding Principal Amount	$ 750	$ 750
CNOOC Finance (2013) Limited (note two) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Finance (2013) Limited	CNOOC Finance (2013) Limited
Maturity	Due in 2023	Due in 2023
Coupon Rate	3.00%	3.00%
Outstanding Principal Amount	$ 2,000	$ 2,000
CNOOC Finance (2013) Limited (note three) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Finance (2013) Limited	CNOOC Finance (2013) Limited
Maturity	Due in 2043	Due in 2043
Coupon Rate	4.25%	4.25%
Outstanding Principal Amount	$ 500	$ 500
CNOOC Nexen Finance (2014) ULC [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Nexen Finance (2014) ULC	CNOOC Nexen Finance (2014) ULC
Maturity	Matured in 2017	Matured in 2017
Coupon Rate	1.625%	1.625%
Outstanding Principal Amount	$ 0	$ 1,250
CNOOC Nexen Finance (2014) ULC (note two) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Nexen Finance (2014) ULC	CNOOC Nexen Finance (2014) ULC
Maturity	Due in 2024	Due in 2024
Coupon Rate	4.25%	4.25%
Outstanding Principal Amount	$ 2,250	$ 2,250
CNOOC Nexen Finance (2014) ULC (note three) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Nexen Finance (2014) ULC	CNOOC Nexen Finance (2014) ULC
Maturity	Due in 2044	Due in 2044
Coupon Rate	4.875%	4.875%
Outstanding Principal Amount	$ 500	$ 500
Nexen (note one) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	Nexen	Nexen
Maturity	Matured in 2017	Matured in 2017
Coupon Rate	5.65%	5.65%
Outstanding Principal Amount	$ 0	$ 62
Nexen (note two) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	Nexen	Nexen
Maturity	Due in 2019	Due in 2019
Coupon Rate	6.20%	6.20%
Outstanding Principal Amount	$ 300	$ 300
Nexen (note three) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	Nexen	Nexen
Maturity	Due in 2028	Due in 2028
Coupon Rate	7.40%	7.40%
Outstanding Principal Amount	$ 200	$ 200
Nexen (note four) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	Nexen	Nexen
Maturity	Due in 2032	Due in 2032
Coupon Rate	7.875%	7.875%
Outstanding Principal Amount	$ 500	$ 500
Nexen (note five) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	Nexen	Nexen
Maturity	Due in 2035	Due in 2035
Coupon Rate	5.875%	5.875%
Outstanding Principal Amount	$ 790	$ 790
Nexen (note six) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	Nexen	Nexen
Maturity	Due in 2037	Due in 2037
Coupon Rate	6.40%	6.40%
Outstanding Principal Amount	$ 1,250	$ 1,250
Nexen (note seven) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	Nexen	Nexen
Maturity	Due in 2039	Due in 2039
Coupon Rate	7.50%	7.50%
Outstanding Principal Amount	$ 700	$ 700
CNOOC Finance (2015) U.S.A. LLC [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Finance (2015) U.S.A. LLC	CNOOC Finance (2015) U.S.A. LLC
Maturity	Due in 2025	Due in 2025
Coupon Rate	3.50%	3.50%
Outstanding Principal Amount	$ 2,000	$ 2,000
CNOOC Finance (2015) Australia Pty Ltd [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Finance (2015) Australia Pty Ltd	CNOOC Finance (2015) Australia Pty Ltd
Maturity	Due in 2020	Due in 2020
Coupon Rate	2.625%	2.625%
Outstanding Principal Amount	$ 1,500	$ 1,500
CNOOC Finance (2015) Australia Pty Ltd (note two) [member]
Disclosure of detailed information about borrowings [line items]
Notes of loans and borrowings issued by entities	CNOOC Finance (2015) Australia Pty Ltd	CNOOC Finance (2015) Australia Pty Ltd
Maturity	Due in 2045	Due in 2045
Coupon Rate	4.20%	4.20%
Outstanding Principal Amount	$ 300	$ 300

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LOANS AND BORROWINGS - Narrative (Details)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Aug. 03, 2016 USD ($) agreement	Oct. 29, 2007 USD ($)
General loans [member]
Disclosure of detailed information about borrowings [line items]
Bank loans guaranteed by the Company	$ 650,000,000	$ 800,000,000
Shareholder loans of the Group	$ 694,000,000	$ 694,000,000
Tangguh LNG Project [member] | Mizuho Corporate Bank, Ltd. [member]
Disclosure of detailed information about borrowings [line items]
Aggregate loan amount under commercial loan agreements				$ 884,000,000
Tangguh LNG Project [member] | Mizuho Corporate Bank, Ltd. [member] | Maximum [member]
Disclosure of detailed information about borrowings [line items]
Aggregate maximum cap under the subject loan agreement				$ 135,163,308.28
Tangguh LNG Project [member] | Talisman Energy Inc. [member]
Disclosure of detailed information about borrowings [line items]
Percentage of equity interest sold with execution of a letter of credit agreement				3.05691%
Amount of standby letters of credit				$ 30,000,000
Third LNG process train of Tangguh LNG Project [member] | Mizuho Corporate Bank, Ltd. [member]
Disclosure of detailed information about borrowings [line items]
Aggregate loan amount under commercial loan agreements			$ 2,145,000,000
Number of commercial loan agreements | agreement			2
Third LNG process train of Tangguh LNG Project [member] | Mizuho Corporate Bank, Ltd. [member] | Maximum [member]
Disclosure of detailed information about borrowings [line items]
Aggregate maximum cap under the subject loan agreement			$ 573,000,000

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LOANS AND BORROWINGS - Maturities of long term bank loans (Details) - CNY (¥) ¥ in Millions	Dec. 31, 2017	Dec. 31, 2016
Repayable:
Total long term bank loans	¥ 1,491	¥ 1,300
Amount due within one year shown under current liabilities	(212)	(215)
Long term bank loans repayable after one year	1,279	1,085
Within one year [member]
Repayable:
Total long term bank loans	212	215
After one year but within two years [member]
Repayable:
Total long term bank loans	212	225
After two years but within three years [member]
Repayable:
Total long term bank loans	212	225
After three years but within four years [member]
Repayable:
Total long term bank loans	108	225
After four years but within five years [member]
Repayable:
Total long term bank loans	61	97
After five years [member]
Repayable:
Total long term bank loans	¥ 686	¥ 313

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LOANS AND BORROWINGS - Supplemental information with respect to long term bank loans (Details) - CNY (¥) ¥ in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of detailed information about long term bank loans [line items]
Total long term bank loans	¥ 1,491	¥ 1,300
Interest rate	2.52%	1.74%
Weighted average [member]
Disclosure of detailed information about long term bank loans [line items]
Total long term bank loans	¥ 1,396	¥ 1,199
Interest rate	2.13%	1.29%
Maximum [member]
Disclosure of detailed information about long term bank loans [line items]
Total long term bank loans	¥ 1,491	¥ 1,369

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PROVISION FOR DISMANTLEMENT (Details) - CNY (¥)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Minimum [member]
Disclosure of other provisions [line items]
Discount rate used for calculating provision for dismantlement		4.00%	4.00%	4.00%
Maximum [member]
Disclosure of other provisions [line items]
Discount rate used for calculating provision for dismantlement		5.00%	5.00%	5.00%
Provision for dismantlement [member]
Disclosure of other provisions [line items]
Balance at beginning of year		¥ 50,888,000,000	¥ 50,063,000,000
New projects	[1]	1,244,000,000	1,395,000,000
Revision	[1]	421,000,000	(2,072,000,000)
Utilization		(440,000,000)	(398,000,000)
Deletions		0	(33,000,000)
Unwinding of discount (note 7)	[2]	2,145,000,000	2,185,000,000
Exchange differences		(185,000,000)	(252,000,000)
Balance at end of year		54,073,000,000	50,888,000,000
Current portion of dismantlement included in other payables and accrued liabilities (note 23)		(1,180,000,000)	(462,000,000)
Balance at end of year, provision for dismantlement		¥ 52,893,000,000	¥ 50,426,000,000

[1] The amounts are included in the additions of oil and gas properties in note 13.

[2] The discount rates used for calculating the provision for dismantlement are within the range of 4% to 5% (2016: 4% to 5%, 2015: 4% to 5%).

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SHARE CAPITAL - Issued share capital (Details) ¥ / shares in Units, ¥ in Millions, $ in Millions	Dec. 31, 2017 CNY (¥) ¥ / shares shares	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 CNY (¥) ¥ / shares shares	Dec. 31, 2015 CNY (¥) ¥ / shares shares
Disclosure of classes of share capital [line items]
Issued share capital equivalent	¥ 43,081	$ 6,621	¥ 43,081
Ordinary shares [member]
Disclosure of classes of share capital [line items]
Number of shares | shares	44,647,455,984	44,647,455,984	44,647,455,984	44,647,455,984
Issued share capital equivalent | ¥	¥ 43,081		¥ 43,081	¥ 43,081
Par value | ¥ / shares	¥ 0		¥ 0	¥ 0

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SHARE CAPITAL - Share option schemes - Narrative (Details)		12 Months Ended
	Dec. 31, 2005 CNY (¥) year	Dec. 31, 2017 CNY (¥)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)	Dec. 31, 2005 $ / shares
Disclosure of terms and conditions of share-based payment arrangement [line items]
Ratio of number of shares issued upon exercise of options granted to total issued capital		0.29%	0.42%	0.59%
Maximum [member]
Disclosure of terms and conditions of share-based payment arrangement [line items]
Ratio of number of shares issued upon exercise of options granted to total issued capital					10.00%
2005 Share Option Scheme [member]
Disclosure of terms and conditions of share-based payment arrangement [line items]
Period of share option scheme adopted	12 months
Consideration payable by a grantee for the grant of options | $ / shares					$ 1.00
Number of trading days preceding date of grant to determine average closing price of shares	5 days
Options granted under share option schemes	¥ 0	¥ 0	¥ 0	¥ 0
Expense from equity-settled share-based payment transactions in which goods or services received did not qualify for recognition as assets		¥ 0	¥ 0	¥ 0
2005 Share Option Scheme [member] | Maximum [member]
Disclosure of terms and conditions of share-based payment arrangement [line items]
Ratio of number of shares issued upon exercise of options granted to total issued capital					1.00%
Exercise periods for the options granted from the date of grant | year	10

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SHARE CAPITAL - Details of share option schemes (Details)	12 Months Ended
	Dec. 31, 2017 CNY (¥) shares	Dec. 31, 2017 HKD ($) shares year	Dec. 31, 2016 CNY (¥) shares	Dec. 31, 2016 HKD ($) shares year	Dec. 31, 2015 CNY (¥) shares year	Dec. 31, 2015 HKD ($) shares year
SHARE CAPITAL [abstract]
Number of share options outstanding at the beginning of the year	187,529,000	187,529,000	262,592,000	262,592,000
Number of share options granted during the year	0	0	0	0
Number of share options forfeited during the year	(22,506,000)	(22,506,000)	(37,893,000)	(37,893,000)
Number of share options expired during the year	(35,104,000)	(35,104,000)	(37,170,000)	(37,170,000)
Number of share options exercised during the year	0	0	0	0
Number of share options outstanding at the end of the year	129,919,000	129,919,000	187,529,000	187,529,000	262,592,000	262,592,000
Number of share options exercisable at the end of the year		129,919,000		187,529,000
Weighted average exercise price outstanding at the beginning of the year | $		$ 11.4		$ 10.56
Weighted average exercise price granted during the year | $		0		0
Weighted average exercise price forfeited during the year | $		12.43		11.30
Weighted average exercise price expired during the year | $		7.29		5.56
Weighted average exercise price exercised during the year | $		0		0
Weighted average exercise price outstanding at the end of the year | $		12.34		11.4		$ 10.56
Weighted average exercise price exercisable at the end of the year | $		$ 12.34		$ 11.4
Share options, cancelled or modified, in share-based payment transactions | ¥	¥ 0		¥ 0		¥ 0
Ratio of the share options outstanding under share option schemes to the Company's shares in issue at the date of approval of consolidated financial statements for issuance		0.29%		0.42%	0.59%	0.59%
Weighted average remaining contractual life of share options outstanding at the end of the year | year		1.52		2.11	2.74	2.74
Additional ordinary shares	129,919,000	129,919,000	187,529,000	187,529,000
Additional share capital | ¥	¥ 1,339,702,913		¥ 1,912,814,087

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RESERVES (Details) - CNY (¥)	Dec. 31, 2017	Dec. 31, 2016
Safety fund reserve	¥ 0	¥ 0
CNOOC China Limited [member]
General reserve fund	¥ 60,000,000,000	¥ 10,000,000,000

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RELATED PARTY TRANSACTIONS - Narrative (Details)	36 Months Ended
	Dec. 31, 2019
Comprehensive framework agreement [member] | China National Offshore Oil Corporation Group [member]
Disclosure of transactions between related parties [line items]
Term of agreements	3 years

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RELATED PARTY TRANSACTIONS - A summary of significant related party transactions (Details) ¥ in Millions, $ in Millions		12 Months Ended						60 Months Ended
		Dec. 31, 2017 CNY (¥)		Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)		Dec. 31, 2015 CNY (¥)	Dec. 01, 2019	Sep. 01, 2019	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2014 CNY (¥)	Dec. 01, 2014 USD ($)	Sep. 01, 2014 USD ($)
Provision of exploration, oil and gas development, oil and gas production as well as marketing, management and ancillary services by the CNOOC Group to the Group
Provision of exploration and support services		¥ 6,881		$ 1,058	¥ 7,359		¥ 9,900
Provision of marketing, management and ancillary services (note b)		6,861		$ 1,055	6,493		5,705
Transactions and balances with CNOOC Finance Corporation Limited ("CNOOC Finance") (note f)
Interest income from deposits in CNOOC Finance		653			901		873
Balances with the CNOOC Group
Amount due to CNOOC - included in other payables and accrued liabilities		193			215					$ 30
Amount due to other related parties - included in trade and accrued payables		16,651			15,091					2,559
Borrowings from CNOOC (note g)		4,532	[1]		4,811	[1]				697
Amounts due from other related parties - included in other current assets		7,874			5,977					1,211
Transactions and balances with other state-owned enterprises
Cash and cash equivalents		12,572			13,735		11,867			1,932		¥ 14,918
Time deposits with maturity over three months		15,380			16,830					$ 2,364
Specified dismantlement fund accounts (note 18)		¥ 7,555			¥ 6,088
Coalbed Methane Resources Exploration and Development Cooperation Agreement with China United Coalbed Methane Corporation Limited
Interest rate		2.52%			1.74%					2.52%	1.74%
China National Offshore Oil Corporation Group [member]
Provision of exploration, oil and gas development, oil and gas production as well as marketing, management and ancillary services by the CNOOC Group to the Group
Provision of exploration and support services		¥ 5,912			¥ 4,357		7,457
Inclusive of amounts capitalized under property, plant and equipment		3,392			2,364		4,158
Provision of oil and gas development and support services		16,317			14,214		22,733
Provision of oil and gas production and support services (note a)	[2]	8,894			7,250		8,384
Provision of marketing, management and ancillary services (note b)	[3]	1,450			994		954
FPSO vessel leases (note c)	[4]	1,383			1,551		1,770
Total expenses arising from povision of exploration, oil and gas development, oil and gas production as well as marketing, management and ancillary services by the CNOOC Group to the Group		33,956			28,366		41,298
Sales of petroleum and natural gas products by the Group to the CNOOC Group
Sales of petroleum and natural gas products (other than long term sales of natural gas and liquefied natural gas) (note d)	[5]	109,518			88,682		105,401
Long term sales of natural gas and liquefied natural gas (note e)	[6]	9,837			8,663		10,557
Total revenue from sales of petroleum and natural gas products by the Group to the CNOOC Group		119,355			97,345		115,958
Balances with the CNOOC Group
Amounts payable, related party transactions		16,844			15,306
CNOOC [member]
Balances with the CNOOC Group
Amount due to CNOOC - included in other payables and accrued liabilities		193			215
Borrowings from CNOOC (note g)		4,532			4,811
Coalbed Methane Resources Exploration and Development Cooperation Agreement with China United Coalbed Methane Corporation Limited
Term of uncommitted revolving loan facility								5 years
Outstanding Principal Amount | $													$ 600
Interest rate													0.95%
Withdrawal amount of the loan | $										$ 564	$ 564
CNOOC [member] | CNOOC International Limited [member]
Coalbed Methane Resources Exploration and Development Cooperation Agreement with China United Coalbed Methane Corporation Limited
Term of uncommitted revolving loan facility									5 years
Outstanding Principal Amount | $														$ 135
Interest rate														0.95%
Withdrawal amount of the loan | $										$ 130	$ 130
Other related parties [member]
Balances with the CNOOC Group
Amount due to other related parties - included in trade and accrued payables		16,651			15,091
Amounts due from other related parties - included in trade receivables		12,401			13,090
Amounts due from other related parties - included in other current assets		513			173
Amounts receivable, related party transactions		12,914			13,263
CNOOC Finance Corporation Limited [member]
Transactions and balances with CNOOC Finance Corporation Limited ("CNOOC Finance") (note f)
Interest income from deposits in CNOOC Finance	[7]	360			564		¥ 629
Deposits in CNOOC Finance	[7]	¥ 19,465			19,437
Coalbed Methane Resources Exploration and Development Cooperation Agreement with China United Coalbed Methane Corporation Limited
Proportion of ownership interest in associate		31.80%		31.80%
Maximum daily outstanding balance for deposits from related parties		¥ 19,500			22,000
A joint venture [member]
Balance with a joint venture
Amount due from a joint venture - included in other current assets		126			135
State-owned enterprises [member]
Transactions and balances with other state-owned enterprises
Cash and cash equivalents		3,824			6,612
Time deposits with maturity over three months		13			108
Specified dismantlement fund accounts (note 18)		7,555			6,088
Total cash in bank and time deposits with certain state-owned banks in the PRC		¥ 11,392			12,808
Minimum [member] | China National Offshore Oil Corporation Group [member]
Coalbed Methane Resources Exploration and Development Cooperation Agreement with China United Coalbed Methane Corporation Limited
Term of long term sale contracts		5 years		5 years
Maximum [member] | China National Offshore Oil Corporation Group [member]
Coalbed Methane Resources Exploration and Development Cooperation Agreement with China United Coalbed Methane Corporation Limited
Term of long term sale contracts		20 years		20 years
Coalbed Methane Resources Exploration and Development Cooperation Agreement [member] | China United Coalbed Methane Corporation Limited [member]
Coalbed Methane Resources Exploration and Development Cooperation Agreement with China United Coalbed Methane Corporation Limited
Accumulated investment		¥ 1,940			¥ 1,647

[1] In September 2014, CNOOC provided CNOOC International Limited, a wholly-owned subsidiary of the Company a five-year uncommitted revolving loan facility for general purposes, with the principal amount of US$135 million of 0.95% per annum. As at December 31, 2017, the withdrawal amount of the loan was US$130 million (December 31, 2016: US$130 million); In December 2014, CNOOC provided the Company a five-year uncommitted revolving loan facility for general purposes, with the principal amount of US$600 million of 0.95% per annum. As at December 31, 2017, the withdrawal amount of the loan was US$564 million (December 31, 2016: US$564 million).

[2] These represent the services for production operations, the provision of various facilities and ancillary services, such as provision of different types of materials, medical and employee welfare services, maintenance and repair of major equipment and supply of water, electricity and heat to the Group, some of which may not be available from independent third parties or available on comparable terms.

[3] These include marketing, administration and management, management of oil and gas operations and integrated research services as well as other ancillary services relating to exploration, development, production and research activities of the Group.In addition, the CNOOC Group leased certain premises to the Group for use as office premises and staff quarters out of which they provided management services to certain properties.

[4] CNOOC Energy Technology and Services Limited leased FPSO vessels to the Group for use in oil production operations.

[5] The sales include crude oil, condensate oil, liquefied petroleum gas, natural gas and liquefied natural gas to the CNOOC Group. Individual sales contracts were entered into from time to time between the Group and the CNOOC Group.

[6] It is the market practice for sales terms to be determined based on the estimated reserves and production profile of the relevant gas fields. The long term sales contracts usually last for 5 to 20 years.

[7] CNOOC Finance is a 31.8% owned associate of the Company and also a subsidiary of CNOOC. Under the financial services framework agreement with CNOOC Finance dated December 1, 2016, CNOOC Finance continues to provide to the Group settlement, depository, discounting, loans and entrustment loans services. The agreement is effective from January 1, 2017 to December 31, 2019. The depository services were exempted from independent shareholders' approval requirements under the Listing Rules. The Group's maximum daily outstanding balance for deposits stated in CNOOC Finance (including accrued interest but excluding funds placed for the purpose of extending entrustment loans pursuant to the entrustment loan services) in 2017 was RMB19,500 million (2016: RMB22,000 million).

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RETIREMENT BENEFITS (Details) - CNY (¥) ¥ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of retirement benefits
Pension costs charged to the consolidated statement of profit or loss and other comprehensive income	¥ 651	¥ 695	¥ 613
State-managed retirement benefit plan [member] | Minimum [member] | PRC [member]
Disclosure of retirement benefits
Ratio of contribution to salaries of employees	11.00%
State-managed retirement benefit plan [member] | Maximum [member] | PRC [member]
Disclosure of retirement benefits
Ratio of contribution to salaries of employees	22.00%
Defined contribution mandatory provident fund [member] | Hong Kong [member]
Disclosure of retirement benefits
Ratio of contribution to salaries of employees	5.00%

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NOTE TO THE CONSOLIDATED STATEMENT OF CASH FLOWS (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
Reconciliation of profit/(loss) before tax to cash generated from operations
Profit (loss) before tax	¥ 36,357	$ 5,588	¥ (5,275)	¥ 17,130
Adjustment for:
Interest income	(653)		(901)	(873)
Financial costs	5,044		6,246	6,118
Exchange losses/(gains), net	(356)	(55)	790	143
Share of (profits)/losses of associates	(302)	(46)	609	(256)
Share of profit of a joint venture	(553)	(85)	(533)	(1,647)
Investment income	(2,409)	(370)	(2,774)	(2,398)
Impairment and provision	9,130		12,171	2,746
Depreciation, depletion and amortization	61,257		68,907	73,439
Loss on disposal and write-off of property, plant and equipment	1,937		2,304	2,115
Others	0		0	70
Subtotal	109,452		81,544	96,587
Decrease/(increase) in trade receivables and other current assets	(1,073)		(2,820)	7,932
Decrease in inventories and supplies	1,464		922	1,427
(Decrease)/increase in trade and accrued payables and other payables	782		2,491	(9,851)
Cash generated from operations	¥ 110,625	$ 17,003	¥ 82,137	¥ 96,095

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NOTE TO THE CONSOLIDATED STATEMENT OF CASH FLOWS - RECONCILIATION OF LIABILITIES ARISING FROM FINANCING ACTIVITIES (Details) - CNY (¥) ¥ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Liabilities arising from financing activities at beginning of period	¥ 151,720
Financing cash flows	(31,271)
Foreign exchange translation	(8,912)
Finance costs	5,394	¥ 5,491	¥ 5,068
Dividends declared	16,500
Liabilities arising from financing activities at end of period	133,431	151,720
Loans and borrowings [member]
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Liabilities arising from financing activities at beginning of period	150,476
Financing cash flows	(9,669)
Foreign exchange translation	(8,911)
Finance costs	354
Dividends declared	0
Liabilities arising from financing activities at end of period	132,250	150,476
Interest payable [member]
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Liabilities arising from financing activities at beginning of period	1,244
Financing cash flows	(5,154)
Foreign exchange translation	51
Finance costs	5,040
Dividends declared	0
Liabilities arising from financing activities at end of period	1,181	1,244
Dividend payable [member]
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Liabilities arising from financing activities at beginning of period	0
Financing cash flows	(16,448)
Foreign exchange translation	(52)
Finance costs	0
Dividends declared	16,500
Liabilities arising from financing activities at end of period	¥ 0	¥ 0

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COMMITMENTS AND CONTINGENCIES - Capital commitments (Details) - CNY (¥) ¥ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Capital commitments
Contracted, but not provided for	[1]	¥ 46,704	¥ 46,515
Period of estimated payments included in capital commitments with respect to the Group's exploration and production licenses		5 years	5 years
Unutilized banking facilities		¥ 53,749	¥ 60,697
China National Offshore Oil Corporation Group [member]
Capital commitments
Contracted, but not provided for		4,030	2,482
A joint venture [member]
Capital commitments
Contracted, but not provided for		¥ 691	¥ 360

[1] The capital commitments contracted, but not provided for, include the estimated payments to the Ministry of Land and Resources of the PRC for the next five years with respect to the Group's exploration and production licenses.

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COMMITMENTS AND CONTINGENCIES - Operating lease commitments (Details) - CNY (¥) ¥ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Office properties
Commitments due:
Total minimum lease payments under non-cancellable operating leases	¥ 5,726	¥ 5,710
Office properties | CNOOC Group [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	1,218	639
Office properties | A joint venture [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	69	119
Office properties | Not later than one year [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	1,630	1,317
Office properties | Not later than one year [member] | A joint venture [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	18	25
Office properties | Later than one year and not later than two years [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	1,048	896
Office properties | Later than one year and not later than two years [member] | A joint venture [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	12	17
Office properties | Later than two years and not later than five years [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	1,274	1,534
Office properties | Later than two years and not later than five years [member] | A joint venture [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	16	26
Office properties | After five years [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	1,774	1,963
Office properties | After five years [member] | A joint venture [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	23	51
Property plant and equipment
Commitments due:
Total minimum lease payments under non-cancellable operating leases	7,169	7,306
Property plant and equipment | CNOOC Group [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	3,366	3,211
Property plant and equipment | Not later than one year [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	1,272	1,378
Property plant and equipment | Later than one year and not later than two years [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	875	734
Property plant and equipment | Later than two years and not later than five years [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	1,616	1,316
Property plant and equipment | After five years [member]
Commitments due:
Total minimum lease payments under non-cancellable operating leases	¥ 3,406	¥ 3,878
Minimum [member] | Office properties
Disclsoure of operating lease commitments
Lease term	6 months	6 months
Minimum [member] | Property plant and equipment
Disclsoure of operating lease commitments
Lease term	1 year	1 year
Maximum [member] | Office properties
Disclsoure of operating lease commitments
Lease term	20 years	20 years
Maximum [member] | Property plant and equipment
Disclsoure of operating lease commitments
Lease term	25 years	25 years

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FINANCIAL INSTRUMENTS - Fair value of financial instruments - Narrative (Details) - CNY (¥) ¥ in Millions	Dec. 31, 2017	Dec. 31, 2016
FINANCIAL INSTRUMENTS [abstract]
Estimated fair value of the Group's long term guaranteed notes	¥ 128,315	¥ 140,135

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FINANCIAL INSTRUMENTS - Fair value hierarchy - Assets (Details) - CNY (¥) ¥ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	¥ 617,219	¥ 637,681	¥ 664,362
At fair value [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	75,139	54,723
At fair value [member] | Corporate wealth management products [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	66,229	46,958
At fair value [member] | Money market funds [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	8,115	5,931
At fair value [member] | Derivative financial assets - current [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	0	428
At fair value [member] | Non-publicly traded investments - current [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	14	15
At fair value [member] | Publicly traded investments-non current [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	781	1,391
At fair value [member] | Level 1 [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	8,896	7,322
At fair value [member] | Level 1 [member] | Money market funds [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	8,115	5,931
At fair value [member] | Level 1 [member] | Publicly traded investments-non current [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	781	1,891
At fair value [member] | Level 2 [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	66,243	47,401
At fair value [member] | Level 2 [member] | Corporate wealth management products [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	66,229	46,958
At fair value [member] | Level 2 [member] | Derivative financial assets - current [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value		428
At fair value [member] | Level 2 [member] | Non-publicly traded investments - current [member]
Disclosure of fair value measurement of assets [line items]
Assets measured at fair value	¥ 14	¥ 15

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FINANCIAL INSTRUMENTS - Fair value hierarchy - Liabilities (Details) - CNY (¥) ¥ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of fair value measurement of liabilities [line items]
Liabilities measured at fair value	¥ (237,244)	¥ (255,310)	¥ (278,321)
At fair value [member] | Derivative financial liabilities - current [member]
Disclosure of fair value measurement of liabilities [line items]
Liabilities measured at fair value	¥ 0	(426)
At fair value [member] | Level 2 [member] | Derivative financial liabilities - current [member]
Disclosure of fair value measurement of liabilities [line items]
Liabilities measured at fair value		¥ (426)

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FINANCIAL INSTRUMENTS - Fair value hierarchy - Transfer between different levels of fair value hierarchy (Details)	12 Months Ended
	Dec. 31, 2017 CNY (¥)
FINANCIAL INSTRUMENTS [abstract]
Amounts transferred between different levels of fair value hierarchy	¥ 0

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CONCENTRATION OF CUSTOMERS (Details) ¥ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 CNY (¥)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 CNY (¥)	Dec. 31, 2015 CNY (¥)
Disclosure of major customers [line items]
Revenue	¥ 186,390	$ 28,648	¥ 146,490	¥ 171,437
China Petroleum and Chemical Corporation [member]
Disclosure of major customers [line items]
Revenue	15,488		9,659	14,692
PetroChina Company Limited [member]
Disclosure of major customers [line items]
Revenue	11,957		6,923	5,502
BP p.l.c. [member]
Disclosure of major customers [line items]
Revenue	3,108		2,843	3,093
Phillips 66 [member]
Disclosure of major customers [line items]
Revenue	2,631
Royal Dutch Shell PLC [member]
Disclosure of major customers [line items]
Revenue	¥ 2,627		3,661	6,917
EOG Resources, Inc. [member]
Disclosure of major customers [line items]
Revenue			¥ 2,660	¥ 3,746

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FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES - Credit risk (Details) - Credit risk [member] - CNY (¥)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of nature and extent of risks arising from financial instruments [line items]
Other financial assets	¥ 0	¥ 0
The Group's largest third-party customer [member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Percentage of trade receivables, benchmark to measure concentration of credit risk	0.16%	1.00%
The five largest third-party customers [member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Percentage of trade receivables, benchmark to measure concentration of credit risk	7.63%	5.00%

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FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES - Currency risk (Details) - Currency risk [member]	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of nature and extent of risks arising from financial instruments [line items]
Percentage of appreciation in Renminbi against US dollars	6.16%	6.39%
Percentage of Group's cash and cash equivalents and time deposits with maturity over three months denominated in Renminbi	82.00%	88.00%	89.00%
Strengthening/weakening of RMB against US dollars	5.00%	5.00%
Percentage of increase/decrease in the profit for the year	0.06%	6.63%
Percentage of increase/decrease in the equity of the Group	0.31%	0.46%

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FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES - Interest rate risk (Details) - Interest rate risk [member]	12 Months Ended
	Dec. 31, 2017
Disclosure of nature and extent of risks arising from financial instruments [line items]
Percentage of Group's debts that interest rates are fixed	95.50%
Weighted average term of Group's debt balance outstanding	9 years 4 months 6 days

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FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES - Liquidity risk (Details)	12 Months Ended
	Dec. 31, 2017
Maximum [member] | Liquidity risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Settlement term of trade and accrued payables, other payables and accrued liabilities	6 months

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FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES - Capital management (Details) - CNY (¥) ¥ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capital management
Changes made in the objectives, policies or processes for managing capital	No changes were made in the objectives, policies or processes for managing capital during the years end December 31, 2017.	No changes were made in the objectives, policies or processes for managing capital during the years end December 31, 2016.	No changes were made in the objectives, policies or processes for managing capital during the years end December 31, 2015.
Interest-bearing debts	¥ 132,250	¥ 150,476	¥ 164,645
Equity attributable to owners of the parent	379,975	382,371	386,041
Total capital	¥ 512,225	¥ 532,847	¥ 550,686
Gearing ratio	25.80%	28.20%	29.90%