Edgar Filing: CNOOC LTD

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

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015

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

For the transition period from _________________ to _______________

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

中國海洋石油有限公司

(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

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.

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 is 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ý Accelerated filer ¨ Non-accelerated filer ¨

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.

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Page

TERMS AND CONVENTIONS		4
FORWARD-LOOKING STATEMENTS		9
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	15
C.	Reasons for the Offer and Use of Proceeds	15
D.	Risk Factors	15

ITEM 4. INFORMATION ON THE COMPANY

A.	History and Development	20
B.	Business Overview	21
C.	Organizational Structure	56
D.	Property, plants and equipment	57

ITEM 4A. unresolved staff comments		57
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS		58

A.	Operating Results	58
B.	Liquidity and Capital Resources	70
C.	Research and Development, Patents and Licenses, etc.	73
D.	Trend Information	73
E.	Off-Balance Sheet Arrangements	73
F.	Tabular Disclosure of Contractual Obligations	74
G.	SAFE HARBOR	74

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A.	Directors and Senior Management	74
B.	Compensation	82
C.	Board Practice	83
D.	Employees	85
E.	Share Ownership	86

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A.	Major Shareholders	87
B.	Related Party Transactions	87
C.	Interests of Experts and Counsel	91

ITEM 8. FINANCIAL INFORMATION

A.	Consolidated Statements and Other Financial Information	91
B.	Significant Changes	93

ITEM 9. THE OFFER AND LISTING		93
ITEM 10. ADDITIONAL INFORMATION		94

A.	Share Capital	94
B.	Memorandum and Articles of Association	94
C.	Material Contracts	97
D.	Exchange Controls	98
E.	Taxation	98
F.	Dividends and Paying Agents	102
G.	Statement by Experts	102
H.	Documents on Display	102
I.	Subsidiary Information	102

ITEM 11. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK		102
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES		104

A.	DEBT SECURITIES	104
B.	WARRANTS AND RIGHTS	104
C.	OTHER SECURITIES	104
D.	American Depositary shares	104

PART II		106
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES		106
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS		106

A.	MATERIAL MODIFICATIONS TO THE INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS	106
B.	MATERIAL MODIFICATIONS TO THE RIGHTS OF REGISTERED SECURITIES BY ISSUING OR MODIFYING ANY OTHER CLASS OF SECURITIES	106
C.	WITHDRAWAL OR SUBSTITUTION OF A MATERIAL AMOUNT OF THE ASSETS SECURING ANY REGISTERED SECURITIES	106
D.	CHANGE OF TRUSTEES OR PAYING AGENTS FOR ANY REGISTERED SECURITIES	106
E.	USE OF PROCEEDS	106

ITEM 15. CONTROLS AND PROCEDURES		106
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT		107
ITEM 16B. CODE OF ETHICS		107
ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES		107
ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES		108
ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS		108
ITEM 16f. Change in Registrant’s Certifying Accountant		108
ITEM 16g. Corporate Governance		108
Item 16H. MINE SAFETY DISCLOSURE		109
PART III		109
ITEM 17. FINANCIAL STATEMENTS		109
ITEM 18. FINANCIAL STATEMENTS		109
ITEM 19. EXHIBITS		109

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TERMS AND CONVENTIONS

Definitions

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

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

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

“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;

“Nexen” are to Nexen Energy ULC and the companies under its management, unless otherwise expressly provided or the context of this annual report otherwise requires;

“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.

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Conventions

We publish our financial statements in Renminbi. Unless otherwise indicated, we have translated amounts from Renminbi into U.S. dollars solely for the convenience of the reader at the noon buying rate for cable transfers of Renminbi per U.S. dollar certified for customs purposes by the Federal Reserve Bank of New York, as set forth in the H.10 weekly statistical release of the Federal Reserve Board on December 31, 2015 of US$1.00=Rmb 6.4778. 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, 2015 of US$1.00=HK$ 7.7507. 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, 2015 of US$1.00=Cdn$ 1.3839. 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, 2015, 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 2013, 2014 and 2015, approximately 52%, 52% and 62%, 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 2013, 2014 and 2015 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 field 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.

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“LNG” means liquefied natural gas.

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

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

(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.

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(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, 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;

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BOE means barrels-of-oil equivalent;

mcf means thousand cubic feet;

mmcf means million cubic feet;

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

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

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FORWARD-LOOKING STATEMENTS

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

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

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

wells to be drilled or reworked,

development projects,

exploration prospects,

estimates of proved oil and gas reserves,

development and drilling potential,

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

business strategy,

production of oil and gas,

development of undeveloped reserves,

expansion and growth of our business and operations,

oil and gas prices and demand,

future earnings and cash flow, and

our estimated financial information.

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

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

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

Our consolidated financial statements for the years ended December 31, 2013, 2014 and 2015 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

Selected Financial Data

The following tables present selected historical financial data of our company as of and for the years ended December 31, 2011, 2012, 2013, 2014 and 2015. 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, 2011, 2012, 2013, 2014 and 2015 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, 2011, 2012, 2013, 2014 and 2015 have been prepared and presented in accordance with IFRS.

	Year ended December 31,
	2011			2012		2013			2014			2015			2015
	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		189,279			194,774		226,445			218,210			146,597			22,630
Marketing revenues		50,469			50,771		55,495			50,263			21,422			3,307
Other income		1,196			2,082		3,917			6,161			3,418			528
Total operating revenues		240,944			247,627		285,857			274,634			171,437			26,465

Expenses:
Operating expenses		(18,264	)		(21,445	)	(30,014	)		(31,180	)		(28,372	)		(4,380	)
Taxes other than income tax		(10,332	)		(15,632	)	(15,937	)		(11,842	)		(10,770	)		(1,663	)
Exploration expenses		(5,220	)		(9,043	)	(17,120	)		(11,525	)		(9,900	)		(1,528	)
Depreciation, depletion and amortization		(30,521	)		(32,903	)	(56,456	)		(58,286	)		(73,439	)		(11,337	)
Special oil gain levy		(31,982	)		(26,293	)	(23,421	)		(19,072	)		(59	)		(9	)
Impairment and provision		(22	)		(31	)	45			(4,120	)		(2,746	)		(424	)
Crude oil and product purchases		(50,307	)		(50,532	)	(53,386	)		(47,912	)		(19,840	)		(3,063	)
Selling and administrative expenses		(2,854	)		(3,377	)	(7,859	)		(6,613	)		(5,705	)		(881	)
Others		(835	)		(1,230	)	(3,206	)		(3,169	)		(3,150	)		(486	)
Total expenses		(150,337	)		(160,486	)	(207,354	)		(193,719	)		(153,981	)		(23,771	)

Profit from operating activities		90,607			87,141		78,503			80,915			17,456			2,694
Interest income		1,196			1,002		1,092			1,073			873			135
Finance costs		(1,707	)		(1,603	)	(3,457	)		(4,774	)		(6,118	)		(944	)
Exchange gains, net		637			359		873			1,049			(143	)		(22	)
Investment income		1,828			2,392		2,611			2,684			2,398			370
Share of profits of associates		320			284		133			232			256			40
Share of profits/(losses) of a joint venture		247			(311	)	762			774			1,647			254
Non-operating income/(expenses), net		(563	)		908		334			560			761			117

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	Year ended December 31,
	2011			2012			2013			2014			2015		2015
	Rmb			Rmb			Rmb			Rmb			Rmb		US$
	(in millions, except per share and per ADS data)

Profit before tax		92,565			90,172			80,851			82,513			17,130		2,644
Income tax expense		(22,310	)		(26,481	)		(24,390	)		(22,314	)		3,116		481
Profit for the year		70,255			63,691			56,461			60,199			20,246		3,125

Earnings per share (basic)⁽²⁾		1.57			1.43			1.26			1.35			0.45		0.07
Earnings per share (diluted) ⁽³⁾		1.57			1.42			1.26			1.35			0.45		0.07
Earnings per ADS (basic) ⁽²⁾		157.28			142.66			126.46			134.83			45.35		7.00
Earnings per ADS (diluted) ⁽³⁾		156.63			142.14			126.07			134.57			45.31		6.99

Dividend per share
Interim		0.204			0.122			0.198			0.198			0.205		0.03
Proposed final		0.227			0.259			0.252			0.254			0.210		0.03

	As of December 31,
	2011		2012		2013		2014		2015		2015
	Rmb		Rmb		Rmb		Rmb		Rmb		US$
	(in millions)
Statement of Financial Position Data:
Cash and cash equivalents		23,678		55,024		14,318		14,918		11,867		1,832
Available-for sale financial assets⁽¹⁾		27,576		61,795		51,103		54,030		-		-
Other financial assets⁽¹⁾		-		-		-		-		71,806		11,085
Held-to-maturity financial assets		23,467		-		-		-		-		-
Current assets		131,923		170,894		146,552		140,708		140,211		21,645
Property, plant and equipment, net		220,567		252,132		419,102		463,222		454,141		70,107
Investments in associates		2,822		3,857		4,094		4,100		4,324		668
Investments in a joint venture		20,175		20,160		20,303		21,150		24,089		3,719
Intangible assets		1,033		973		17,000		16,491		16,423		2,535
Available-for-sale financial assets		7,365		7,051		6,798		5,337		-		-
Equity investments⁽¹⁾		-		-		-		-		3,771		582
Total assets		384,264		456,070		621,473		662,859		664,362		102,560
Current loans and borrowings		19,919		28,830		49,841		31,180		33,585		5,185
Current liabilities		70,216		82,437		128,948		103,498		84,380		13,026
Long term loans and borrowings		18,076		29,056		82,011		105,383		131,060		20,232
Total non-current liabilities		51,192		63,853		150,905		179,751		193,941		29,939
Total liabilities		121,408		146,290		279,853		283,249		278,321		42,965
Capital stock		43,078		43,078		43,081		43,081		43,081		6,651
Shareholders’ equity		262,856		309,780		341,620		379,610		386,041		59,595

__________

(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 2011 to 2015 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 44,668,570,359 and 446,685,704, respectively, for 2011, 44,646,305,984 and 446,463,060, respectively, for 2012, 44,646,825,847 and 446,468,258, respectively, for 2013, and 44,647,455,984 and 446,474,560, respectively, for 2014, and44,647,455,984 and 446,474,560, respectively, for 2015, 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 2011 to 2015 have been computed, after considering the dilutive effect of the shares underlying our share option schemes by using 44,853,615,010 shares and 448,536,150 ADSs for 2011, 44,808,042,330 shares and 448,080,423 ADSs for 2012, 44,787,119,089 shares and 447,871,191 ADSs for 2013, and 44,734,774,504 shares and 447,347,745 ADSs for 2014 and 44,684,819,053 shares and 446,848,191 ADSs for 2015.

	Year ended December 31,
	2011		2012		2013		2014		2015		2015
	Rmb		Rmb		Rmb		Rmb		Rmb		US$
	(in millions, except percentages and ratios)
Other Financial Data:
Capital expenditures paid⁽¹⁾		36,823		54,331		79,716		95,673		67,674		10,447

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Cash provided by/(used for):
Operating activities	116,171		92,574		110,891		110,508		80,095		12,365
Investing activities	(99,036	)	(63,797	)	(170,032	)	(90,177	)	(76,495	)	(11,809	)
Financing activities	(20,246	)	2,584		18,601		(19,486	)	(6,893	)	(1,064	)
Gearing ratio⁽²⁾	12.6	%	15.7	%	27.8	%	26.5	%	29.9	%	29.9	%

__________

(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.

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)
2011	6.2939	6.4475	6.6364	6.2939
2012	6.2301	6.2990	6.3879	6.2221
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
October 2015	6.3180	—	6.3591	6.3180
November 2015	6.3883	—	6.3945	6.3180
December 2015	6.4778	—	6.4896	6.3883
January 2016	6.5752	—	6.5932	6.5219
February 2016	6.5525	—	6.5795	6.5154
March 2016	6.4480	—	6.5500	6.4480

__________

(1)

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

On March 31, 2016, 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 6.4480 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.

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	Noon Buying Rate
Period	End		Average⁽¹⁾		High		Low
	(HK$ per US$1.00)
2011		7.7663		7.7793		7.8087		7.7634
2012		7.7507		7.7556		7.7699		7.7493
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
October 2015		7.7496		—		7.7503		7.7495
November 2015		7.7526		—		7.7526		7.7498
December 2015		7.7507		—		7.7527		7.7496
January 2016		7.7876		—		7.8270		7.7505
February 2016		7.7763		—		7.7969		7.7700
March 2016		7.7563		—		7.7745		7.7528

__________

(1)

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

On March 31, 2016, 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$7.7563 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)
2011	1.0168	0.9857	1.0605	0.9448
2012	0.9958	0.9994	1.0417	0.971
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
October 2015	1.3082	—	1.3242	1.2901
November 2015	1.3332	—	1.3360	1.3093
December 2015	1.3839	—	1.3989	1.3357
January 2016	1.4074	—	1.4592	1.3970
February 2016	1.3522	—	1.4039	1.3522
March 2016	1.2969	—	1.3466	1.2962

(1)

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

On March 31, 2016, 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$1.2969 to US$1.00.

Capitalization and Indebtedness

Not applicable.

Reasons for the Offer and Use of Proceeds

Not applicable.

Risk Factors

Although we have established the risk management system to identify, analyze, evaluate and respond to risks, our business activities are 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 changes 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.

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.

Economic conditions, energy costs, geopolitical issues and the availability and cost of credit resulted in a severe and prolonged global economic downturn period. The complex economic outlook may materially and adversely affect our business and financial conditions.

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

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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.

Our financial performance is subject to the tax and fiscal regime of host countries in which we operate. Any changes in the tax and fiscal regime in these countries may increase our tax burden and have an adverse effect on our financial performance. For example, in October 2015, Organization for Economic Co-operation and Development (OECD) published the "Base Erosion and Profit Shifting Project" (BEPS Project) final report with 15 action items, to enhance multilateral cooperation, pursuant to which the participating countries will amend their tax laws and tax treaties, and strengthen their supervision on the corporate tax planning and transfer pricing activities, which may cause risks to the Company on global transfer pricing activities.

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. For example, the over-supply of natural gas in China may negatively impact our development, operation and revenue of natural gas projects.

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 gas gathering systems in place. Over time, we expect that a growing share of our CO₂ emissions will be subject to supervision and result in an increase in our costs. Furthermore, the public’s continued and increased attention to climate changes, including activities organized by non-governmental and political organizations, is likely to lead to implementation of additional regulations on reducing greenhouse gas emissions. 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 hydrocarbons.

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

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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.

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. Our reputation may be adversely affected.

We maintain various insurance policies for our operations against potential losses. For detailed information on our insurance coverage, see “Item 4—Information on the Company—Business Overview—Operating Hazards and Uninsured Risks.” 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, corruption and corporate governance laws may expose us to various risks.

Laws and regulations of the host countries or regions in which we operate, such as laws on anti-corruption, anti-fraud and corporate governance, are constantly changing and strengthening, especially in the United States, United Kingdom, Canada and China. The compliance with these laws and regulations may increase our cost. If the Company, our employees, executives or directors 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

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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 2015, China Oilfield Services Limited (COSL), one of our non-controlled affiliates, continued to provide certain drilling and other related services in Iran under renewed subcontracting agreements entered into in 2009, as it did in 2014. 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 55.0% of our proved reserves were undeveloped as of December 31, 2015. 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. For example, we strive to rely on technologies and innovations to enhance our competiveness in the development of unconventional oil and gas resources, including oil sands, shale oil and gas and coalbed methane, and deep water exploration and development. 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. We may face risks in failing to meet the required environmental standards if our technologies in unconventional oil and gas operations are not sophisticated.

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 related party transactions with CNOOC and its affiliates.

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CNOOC indirectly owns or controls 64.44% of our shares as of March 31, 2016. As a result, CNOOC is able to control our board composition, or our Board, determine the time and amount in 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 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 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 loss and reputation harm. We may not be insured against 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.

Aboriginal people in Canada have claimed aboriginal title and rights to the lands and mineral resources in 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 forms of partnerships or in joint ventures in which we may have limited ability 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

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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 depreciation of the Renminbi against the U.S. dollar may result in double effects. The appreciation of the U.S. dollar against the Renminbi may increase the Company’s revenue in the sales of oil and gas, but it may increase 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, as 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 may not be inspected fully by the Public Company Accounting Oversight Board and, as such, you may be 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 fully 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 full 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

History and Development

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

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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.”

Business Overview

Overview

We are an upstream company specializing in the exploration, development and production of oil and natural gas. We are the dominant oil and natural gas producer in offshore China and, in terms of reserves and production, we are also one of the largest independent oil and natural gas exploration and production companies in the world. As of the end of 2015, we had net proved reserves of approximately 4.32 billion BOE (including approximately 0.3 billion BOE in our equity method investees). In 2015, we had a total net oil and gas production of 1,358,022 BOE per day (including net oil and gas production of approximately 50,357 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

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We have a large net proved reserve base spread across offshore China and globally. As of December 31, 2015, we had approximately 4.32 billion BOE of net proved reserves. Our core operating area, offshore China, contributed to approximately 53.9% of our net proved reserves, while overseas contributed to the balance of 46.1%.

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, 2015, approximately 55.0% of our net proved reserves were classified as net proved undeveloped. Our large proved reserve base gives us the opportunity to achieve substantial production growth.

Sizable operating areas in offshore China with demonstrated exploration potential

We are the dominant oil and gas producer in offshore China, a region that we believe has substantial exploration upside. As of December 31, 2015, our total major exploration areas acreage in offshore China was approximately 257,292 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 2015, we and our foreign partners have together drilled a total of 123 exploratory wells in offshore China, of which 64 were wildcat wells. During the same year, we and our foreign partners made 14 new discoveries in offshore China.

Successful independent exploration and development track record

We have a strong record of growing our reserves base for oil and natural gas, both independently and with our foreign partners through PSCs. In recent years, we have been adding reserves and production mainly through independent exploration and development. As of the end of 2015, in offshore China, approximately 85.7% of our net proved reserves were independent and approximately 73.8% of our production came from independent projects.

In 2015, in offshore China, our independent exploration resulted in 14 new discoveries. We also successfully appraised 20 oil and gas structures. On the development front, our major new development projects progressed smoothly with 5 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

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management team and staff members have worked closely with international partners both within and outside China through numerous joint operations.

We have a proven track record of complying with a high level of corporate governance standard, which was recognized by the industry. For example, we were awarded the “2015 Best CSR” and “2015 Best Investor Relations Company” by Corporate Governance Asia Magazine and the “2015 Corporate Governance awards – Platinum” by The Asset in 2015.

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 31 December 2015, approximately 55.0% 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

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.

Aiming to reduce operating cost, we plan to actively promote the regional development of oil and gas fields and apply cutting-edge offshore engineering, drilling and production technologies to our operations. In 2015, we emphasized the “Year of Quality and Efficiency” program, with efforts to control costs and increase efficiency. Operating expense per BOE lowered for the second consecutive year.

Currently, we have a healthy financial position. Under low oil price environment, we attached more importance to cash flow management and continued to balance capex, dividend payment and debt financing.

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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 2013, 2014 and 2015 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,
	2013			2014			2015
Net Production⁽²⁾:
Oil (daily average bbls/day)		912,603			955,647			1,124,047
Gas (daily average mmcf/day)		1,247.4			1,330.1			1,363.6
Oil equivalent (BOE/day)		1,127,967			1,184,977			1,358,022

Net Proved Reserves (end of period):
Oil (mmbbls)		2,290.2			2,258.5			2,015.0
Gas (bcf)		6,323.3			6,730.8			6,992.9
Synthetic Oil (mmbbls)		736.4			749.9			815.3
Bitumen (mmbbls)		33.8			31.4			0.0
Total (million BOE)		4,138.7			4,185.0			4,016.0
Total with equity method investees (million BOE)⁽²⁾		4,427.6			4,478.0			4,315.5
Annual reserve replacement ratio⁽¹⁾		337	%		111	%		65	%
Annual reserve replacement ratio⁽²⁾		327	%		112	%		67	%
Estimated reserve life (years)		10.5			10.1			8.4
Estimated reserve life (years)⁽²⁾		10.8			10.4			8.7
Standardized measure of discounted future net cash flow (million Rmb)		389,022			401,098			185,251

__________

(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, 2015

	2013		2014		Crude Oil		Natural Gas		Synthetic Oil		Total
	(mmboe)		(mmboe)		(mmbbls)		(bcf)		(mmbbls)		(mmboe)
Developed
Offshore China
Bohai		533.7		583.7		564.0		234.7		—		603.1
Western South China Sea		210.8		173.5		70.8		581.5		—		169.0
Eastern South China Sea		176.4		279.8		164.9		810.1		—		299.9
East China Sea		5.9		20.5		9.2		130.2		—		30.9
Subtotal		926.8		1,057.5		808.8		1,756.5		—		1,102.9
Overseas
Asia (excluding China)		98.9		90.9		39.8		439.4		—		118.8
Oceania		44.4		80.0		9.8		273.0		—		63.3
Africa		58.9		47.1		52.7		—		—		52.7
North America (excluding Canada)		116.7		121.4		85.2		166.2		—		112.6
Canada		241.4		258.2		0.0		119.3		196.7		216.6
South America		1.7		1.8		1.6		—		—		1.6
Europe		132.6		124.6		94.5		8.0		—		95.8
Subtotal		694.6		724.1		283.6		1,006.0		196.7		661.4
Total Developed		1,621.3		1,781.6		1,092.5		2,762.5		196.7		1,764.3

Undeveloped
Offshore China
Bohai		646.1		608.1		344.3		146.7		—		368.7
Western South China Sea		438.7		425.2		78.4		2,551.1		—		503.6
Eastern South China Sea		366.3		243.7		192.1		141.4		—		215.7
East China Sea		64.4		152.2		6.9		758.8		—		133.4
Subtotal		1,515.5		1,429.2		621.8		3,598.1		—		1,221.5
Overseas
Asia (excluding China)		141.7		108.5		20.0		406.3		—		90.1
Oceania		47.7		25.9		4.8		116.2		—		27.5
Africa		96.5		95.5		113.9		—		—		113.9
North America (excluding Canada)		116.5		154.5		154.2		109.0		—		172.1
Canada		561.4		562.0		—		—		618.6		618.6
Europe		38.0		27.9		7.9		0.8		—		8.0
Subtotal		1,001.8		974.2		300.7		632.3		618.6		1,030.3
Total Undeveloped		2,517.3		2,403.4		922.5		4230.4		618.6		2,251.7

TOTAL PROVED		4,138.7		4,185.0		2,015.0		6,992.9		815.3		4,016.0
Equity method investees		288.9		293.0		200.1		576.9		—		299.5
Total with equity method investees		4,427.6		4,478.0		2,215.0		7,569.8		815.3		4,315.5

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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.

Total Net Proved Crude and Liquids Reserves
(mmbbls)

	As of December 31,				As of December 31, 2015
	2013		2014		Developed			Undeveloped			Total
Offshore China
Bohai		1,087.6		1,111.7		564.0			344.3			908.3
Western South China Sea		228.3		210.0		70.8			78.4			149.3
Eastern South China Sea		357.0		351.9		164.9			192.1			357.0
East China Sea		19.8		18.0		9.2			6.9			16.1
Subtotal		1,692.6		1,691.6		808.8			621.8			1,430.6
Overseas
Asia (excluding China)		83.6		47.4		39.8			20.0			59.8
Oceania		15.9		16.6		9.8			4.8			14.5
Africa		155.4		142.5		52.7			113.9			166.6
North America (excluding Canada)		175.0		209.3		85.2			154.2			239.5
Canada		770.3		781.4		196.7	⁽¹⁾		618.6	⁽²⁾		815.3
South America		1.7		1.8		1.6			—			1.6
Europe		166.0		149.1		94.5			7.9			102.3
Subtotal		1,367.8		1,348.2		480.3			919.3			1,399.6
Total		3,060.4		3,039.8		1,289.1			1,541.1			2,830.2
Equity method entities		199.3		200.4		104.9			95.2			200.1
Total with equity method investees		3,259.7		3,240.1		1,394.0			1,636.3			3,030.3

__________

(1)

Including Synthetic oil 196.7 mmbbls.

(2)

Including Synthetic oil 618.6 mmbbls.

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Total Net Proved Natural Gas Reserves
(bcf)

	As of December 31,				As of December 31, 2015
	2013		2014		Developed		Undeveloped		Total
Offshore China
Bohai		552.9		480.8		234.7		146.7		381.4
Western South China Sea		2,505.4		2318.1		581.5		2,551.1		3,132.6
Eastern South China Sea		1,114.2		1029.6		810.1		141.4		951.6
East China Sea		303.1		928.3		130.2		758.8		889.0
Subtotal		4,475.6		4756.8		1,756.5		3,598.1		5,354.6
Overseas
Asia (excluding China)		889.4		861.2		439.4		406.3		845.8
Oceania		386.0		455.7		273.0		116.2		389.2
Africa		—		—		—		—		—
North America (excluding Canada)		349.6		403.9		166.2		109.0		275.2
Canada		195.0		233.0		119.3		—		119.3
South America		—		—		—		—		—
Europe		27.8		20.2		8.0		0.8		8.8
Subtotal		1,847.7		1,974.0		1,006.0		632.3		1,638.3
Total		6,323.3		6,730.8		2,762.5		4,230.4		6,992.9
Equity method investees		519.9		537.3		418.3		158.6		576.9
Total with equity method investees		6, 843.2		7,268.1		3,180.8		4,389.0		7,569.8

Total Net Proved Reserves
(million BOE)

	As of December 31,				As of December 31, 2015
	2013		2014		Developed		Undeveloped		Total
Offshore China
Bohai		1,179.7		1,191.8		603.1		368.7		971.8
Western South China Sea		649.6		598.7		169.0		503.6		672.6
Eastern South China Sea		542.7		523.5		299.9		215.7		515.6
East China Sea		70.4		172.7		30.9		133.4		164.2
Subtotal		2,442.3		2,486.8		1,102.9		1,221.5		2,324.3
Overseas
Asia (excluding China)		240.6		199.4		118.8		90.1		208.9
Oceania		92.0		106.0		63.3		27.5		90.8
Africa		155.4		142.5		52.7		113.9		166.6
North America (excluding Canada)		233.2		275.9		112.6		172.1		284.8
Canada		802.8		820.2		216.6		618.6		835.2
South America		1.7		1.8		1.6		0.0		1.6
Europe		170.6		152.5		95.8		8.0		103.8
Subtotal		1,696.4		1,698.3		661.4		1,030.3		1,691.7
Total		4,138.7		4,185.0		1,764.3		2,251.7		4,016.0
Equity method investees		288.9		293.0		176.9		122.6		299.5
Total with equity method investees		4,427.6		4,478.0		1,941.2		2,374.3		4,315.5

Proved Reserves

As of December 31, 2015, we had proved reserves of 4,315.5 million BOE, including 2,215.0 million barrels of crude oil, 815.3 million barrels of synthetic oil and 7,569.8 bcf of natural gas, representing a decrease of 162.5 million BOE as compared to proved reserves of 4,478.0 million BOE as of December 31, 2014.

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The changes in our proved reserves mainly include:

l An increase of 653.5 million BOE due to new discoveries and extensions, of which 73.3 million BOE are developed and 580.2 million BOE are undeveloped, details of which are described below:

Offshore China: the discoveries and extensions of oil and gas reserves in the amount of 515.1 million BOE, which are primarily attributable to fields such as Bozhong 34-9, Luda 21-2, Caofeidian6-4, Lingshui17-2 and Liuhua20-2 etc.; and

Ø »

Overseas: the discoveries and extensions of oil and gas reserves in the amount of 138.4 million BOE, which are primarily attributable to onshore and offshore fields in the United States.

l A decrease of 322.7 million BOE due to revision of previous estimates;

l The production of 495.7 million BOE in 2015.

Proved Undeveloped Reserves (PUD)

As of December 31, 2015, we had proved undeveloped reserves of 2,374.3 million BOE, including 1,017.7 million barrels of crude oil, 618.6 million barrels of synthetic oil and 4,389.0 bcf of natural gas, representing an decrease of 162.1 million BOE as compared to proved undeveloped reserves of 2,536.3 million BOE as of December 31, 2014.

The changes in our proved undeveloped reserves mainly include:

l A decrease of 345.6 million BOE due to PUD converted to Proved Developed reserves (PD);

l A decrease of 396.6 million BOE due to revision of previous estimates;

l An increase of 580.2 million BOE due to new discoveries and extensions, details of which are described below:

Offshore China: the discoveries and extensions of oil and gas reserves in the amount of 471.6 million BOE, which are primarily attributable to fields such as Bozhong34-9, Luda 21-2, Caofeidian6-4, Lingshui17-2 and Liuhua20-2 etc.; and

Overseas: the discoveries and extensions of oil and gas reserves in the amount of 108.6 million BOE which are primarily attributable to oil sands and shale gas fields in Canada, and onshore and offshore fields in the United States.

In 2015, we had in total 345.6 million BOE PUD reserves converted to PD, or the PUD conversion rate was 13.6%.

In 2015, we spent approximately US$4.1 billion on developing proved undeveloped reserves into proved developed reserves. US$3.7 billion, or 90%, were spent on 26 major development projects in Bohai, Eastern South China Sea, Western South China Sea and Eastern South China Sea in offshore China and Nigeria, the United Kingdom and the U.S. The remaining 10% was spent mainly on the infill drilling programs in offshore China and Indonesia.

As of December 31, 2015, 52.0 million BOE of our proved undeveloped reserves were first booked before 2011. 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) 19.7 million BOE in Bohai, including Jinzhou 20-2N oil field which is scheduled to be jointly developed with newly discovered extensions; and (iii) 24.6 million BOE in Western South China

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Sea, including Wenchang 9-2/9-3/10-3 gas fields whose ODP was amended due to gas market change and expected to be online 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 2013, 2014 and 2015, approximately 52%, 52% and 62 % 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 2015, we engaged Ryder Scott Company, L.P. and Gaffney, Cline & Associates (Consultants) Pte Ltd. 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. Of the total net proved oil and gas reserves evaluated by our internal reserve evaluation staff, we engaged independent third party consulting firms Ryder Scott Company, L.P., McDaniel & Associates Consultants Ltd. and DeGolyer and MacNaughton to perform annual audits for over 65% of the internally evaluated reserves to provide validation of our processes and estimates. For each independent third party consulting firm, a report of third party letter has been prepared which summarizes the work undertaken, the assumptions, data, methods and procedures they used and concludes with their opinion concerning the reasonableness of the estimated reserves quantities or reserves processes. These reports have been included as appendices to this document.

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

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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 South China Sea, Eastern South China Sea and East China Sea, either independently or in cooperation with foreign partners through production sharing contracts (“PSCs”). As of the end of 2015, approximately 53.9% of the Company’s net proved reserves and approximately 65.2% of its net production were derived from offshore China.

In its independent operations, the Company has been adding more reserves and production mainly through independent exploration and development in offshore China. As of the end of 2015, approximately 85.7% of the Company’s net proved reserves and approximately 73.8% of its net production in offshore China were derived from independent projects.

In its PSC operations, CNOOC, the Company’s controlling shareholder, has the exclusive right to explore and develop oil and natural gas in offshore China in cooperation with foreign partners through PSCs. CNOOC has transferred to the Company all of its rights and obligations under all 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.

Overseas, following years of overseas development, the Company has essentially completed the layout of its global portfolio. Overseas assets account for over 50% of the Company’s total assets. 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 and various other countries.

In 2015, growth momentum of the world economy was sluggish. The downward pressure of the Chinese economy continued while international oil prices remained low. The Company and the entire oil and gas industry faced severe market situation and difficult business environment.

For this reason, the Company continued to implement the “Year of Quality and Efficiency” program and carried out effective measures to maintain healthy and sustainable development.

In 2015, the Company persisted with strategies formulated at the beginning of the year, which includes, maintaining prudent financial policy and investment decision; strengthening cost control and continuing to improve quality and efficiency; ensuring safe operation of producing projects; keeping sanctioned projects on schedule with stringent quality control.

In 2015, the Company significantly reduced its capital expenditure. However, the Company still reached its production and business targets in spite of all difficulties. The Company managed to maintain appropriate exploration expenditures and intensive exploration activities, and achieved successful results.

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Seven new projects planned in early 2015 all came on stream. The high end of production target was met with a total volume of 495.7 million BOE. To ensure sustainable development in the future, the Company steadily pushed ahead the construction of more than 20 projects. All in cost per BOE was US$39.82, representing a decline for the second consecutive year. The Company has maintained a healthy financial position with a net profit of Rmb 20.25 billion for the year. Meanwhile, health, safety and environmental protection performance remained stable.

Looking forward to 2016, the recovery of the global economy is expected to remain weak; low international oil prices will prevail, and the external operating environment is likely to remain tough. In spite of this, the Company remains confident and persistent. We will further strengthen our operating strategies under a low-oil-price environment, which include: maintaining prudent financial policy; continuing to lower costs and increase efficiency through technology and management innovation; ensuring safe operation and strict compliance with regulations; focusing on return by balancing short-term benefit and long-term development.

In 2016, the capital expenditure of the Company will be no more than Rmb 60 billion. To maintain its competitive financial position, the Company will continue to strengthen cost controls and focus more on cash flow management. Our production target for 2016 is 470-485 million BOE with four new projects to come on stream. Meanwhile, the Company will maintain its high standards in health, safety and environmental protection.

Exploration

In 2015, the Company ensured its exploration spending in its core area, offshore China, and prioritized mature areas and rolling areas, and made appropriate adjustment on the number of high cost wells such as deepwater wells; overseas, the Company collaborated with its partners to optimize exploration program and focused on areas with high success rates. During the year, breakthroughs were made in both offshore China and overseas exploration. Due to significant decrease in international oil prices, the reserve replacement ratio for the Company is 67% for 2015.

In offshore China, the exploration activities of the Company remained at a high level. In 2015, a total of approximately 13.0 thousand kilometers of 2D Seismic Data was acquired independently; a total of approximately 16.5 thousand square kilometers of 3D Seismic Data was acquired independently and through PSC, and 123 exploration wells were drilled. In addition, the Company completed 19 unconventional wells onshore China. 14 new discoveries were made and 20 oil and gas structures were successfully appraised. The success rate of independent exploration wells in offshore China is 45-67%.

In 2015, the Company continued to implement a proactive exploration strategy in offshore China, resulting in successful achievements including the following:

Firstly, effectively completed the appraisal of three mid-to-large sized oil fields. The oil and gas structures of Caofeidian 6-4, Luda 16-3/Luda 16-3 South and Bozhong 34-9 in Bohai were successfully appraised, most of which being light oil.

Secondly, remarkable achievements were made in rolling and expanding exploration in the North Slope of East Sag in Baiyun Trough in Eastern South China Sea. Two discoveries of Liuhua 20-2 and Liuhua 21-2 were made which significantly enhanced the overall efficiency of exploration and development in the region.

Thirdly, breakthroughs were made in the expansion and new layer exploration in the central valley channels in Western South China Sea, with the discovery of Lingshui 18-1, and successful appraisal of the oil and gas structure of Lingshui 25-1.

Fourthly, with existing production facilities, the rolling exploration in Bohai has led to remarkable results, with the successful appraisal of Bozhong 34-1N oil and gas structure. Aiming at high-abundance and high-quality reserves, the Company strengthened the integrated exploration and development in Wushi Trough in Western South China Sea, and successfully appraised a number of oil

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fields around Wushi 17-2, which enhanced the development efficiency of the region.

Such achievements have further consolidated the position of offshore China as the core area of the Company and demonstrated the Company’s unique strength in offshore China.

For overseas exploration, the Company continued to focus on key areas and optimized its investment portfolio strategies for sustainable development. New discoveries included REZ in Algeria and Ukot South in Nigeria. In addition, three oil and gas structures were successfully appraised, including MAS and OGB in Algeria and Libra in Brazil, demonstrating the Company’s favorable exploration progress overseas.

Furthermore, the Company has enhanced its management through optimizing exploration portfolio and projects, improving management processes and operational organization and reinforcing on-site operation management, integration of development and exploration and overseas management. Specific measures carried out included: communicating actively with contractors to lower service prices; reinforcing the refined management of exploration wells and reducing costs by focusing on details; enhancing operational efficiency through technological innovation; and reinforcing the integration of exploration and development to enhance the overall benefits for the Company through effective control of exploration costs.

In 2015, the Company utilized technological innovation to break through bottlenecks in exploration. The Company also increased operational efficiency through technological innovations such as Single Trip Triple Large Coring. Breakthroughs were made in the sampling process of heavy oil in Bohai. The well logging and testing for high-pressure-high-temperature wells also made progress.

The Company’s major exploration activities in 2015 are set out in the table below:

	Exploration Wells				New Discoveries		Successful Appraisal Wells		Seismic Data
	Independent		PSC		New Discoveries		Successful Appraisal Wells		2D (km)		3D (km2)
	Wildcat	Appraisal	Wildcat	Appraisal	Independent	PSC	Independent	PSC	Independent	PSC	Independent	PSC
Offshore China
Bohai	18	32	3	0	7	0	28	0	0	0	1,780	0
Eastern South China Sea	20	7	1	0	2	0	2	0	5,368	0	4,014	0
Western South China Sea	16	15	3	0	5	0	7	0	6,611	0	7,984	1,441
East China Sea	1	5	2	0	0	0	4	0	1,017	0	1,294	0
Subtotal	55	59	9	0	14	0	41	0	12,996	0	15,072	1,441
Overseas	0	0	8	5	0	2	0	5	0	3,792	0	0
Total	55	59	17	5	14	2	41	5	12,996	3,792	15,072	1,441

In 2016, the Company will prioritize offshore China, and balance among mature areas, rolling areas and new areas. We will focus on high-quality blocks and conventional oil and gas exploration overseas. The Company will continue to maintain heavy exploration workload to ensure mid- to long-term sustainable development.

Engineering Construction, Development and Production

In 2015, the Company successfully completed its production target and reached the high end of the target set early this year. The Company carefully organized its operational resources and made smooth

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progress in engineering construction. There were more than 20 projects under construction in 2015. Currently, seven projects planned for 2015 came on stream.

In 2015, the Company’s net oil and gas production reached 495.7 million BOE, representing an increase of 14.6% year over year and hit the high end of the production target of 475-495 million BOE. To date, new projects planned for 2015, Jinzhou 9-3 comprehensive adjustment, Bozhong 28/34 comprehensive adjustment, Kenli 10-1 oil field, Dongfang 1-1 phase I adjustment and Luda 10-1 comprehensive adjustment, commenced production in the year; Weizhou 11-4N oilfield phase II and Weizhou 12-2 oilfield joint development project were announced to commence production early 2016.

In 2015, the Company’s development and production faced tremendous pressure due to the continuous slump in international oil prices. Therefore, while ensuring production safety, the Company focused on enhancing efficiency and lowering costs in its development and production operations, and was able to achieve its annual development and production targets during the year.

Firstly, we focused on return in feasibility study projects and significantly reduced development investments. We achieved this mainly by optimizing designs and investment.

Secondly, we strictly controlled the quality of geology and reservoirs designs and promoted the risk-resistance capacity of new projects. This will help us ensure that various development indicators are achieved for infill drilling, comprehensive adjustment projects and new oil and gas fields.

Thirdly, we conducted special programs to lower operating expenses and established a long-term mechanism to solidify the achievements, which resulted in the successful control of operating costs. By utilizing market mechanisms, service and supply costs have also been lowered.

Fourthly, the number of projects and production expenditures were effectively controlled through project screening, budget controls and process management. Meanwhile, through changes in the performance review system of business units, their motivation of cost control was strengthened.

Looking forward to 2016, the workload of onshore construction and offshore installation will remain stable. A total of four new projects are expected to commence production, including Kenli 10-4 oilfield, Panyu 11-5 oilfield, Weizhou 6-9/6-10 oilfield comprehensive adjustment project and Enping 18-1 oilfield. Among them, Kenli 10-4 oilfield already commenced production in January 2016. In addition, it is expected that nearly 20 new projects will be under construction in 2016 and support the Company’s sustainable growth in the future.

In 2016, the Company’s development and production are expected to face a harsh external environment due to pressure from international oil prices. The Company will undertake its various tasks with emphasis on the following areas:

Firstly, we will drive the feasibility study for major early-stage projects to further lower cost and enhance efficiency. We will strictly control the quality of geological reservoir designs of early-stage projects and strengthen the study on the producing reserves and recoverable reserves.

Secondly, we will further develop the potential of mature oil fields and slow down its production decline. With oil reservoirs as the focus, we will intensify the basic work of improving water injection and liquid production structures through the meticulous study of mature oil fields and reformation of management concepts.

Thirdly, we will strengthen the post evaluation of the ODP project, infill drilling and workover, establish scientific assessment criteria, and explore the potential to further reduce costs and enhance efficiency.

Through the above key measures, the Company will prioritize return, strive to achieve its annual production target and lay a solid foundation for its long-term sustainable growth.

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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 2015, the reserve and daily production volume in Bohai were 971.8 million BOE and 500,719 BOE/day, respectively, representing approximately 22.5% and 36.9% of the Company’s total reserves and daily production, respectively. The operation 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 2015, the Company made seven successful discoveries in Bohai, namely Penglai 7-6, Luda 16-3, Caofeidian 6-1, Penglai 31-3 South, Bozhong 29-4 West, Nanbao 35-2 South and West Bozhong 34-1 North. Successful results were made in frontier exploration in Miaoxinan Uplift; light crude oil discovery was made in Guantao Group in Southeast Ring of Dabozhong and contributed to the sustainable development of the Company. In addition, the Company also successfully appraised 13 oil and gas structures, including Caofeidian 6-4, Bozhong 34-9, Luda 16-3, Luda 16-3 South, Bozhong 34-1 North, Bozhong 29-1, Qinhuangdao 27-3, Kenli 10-1, Caofeidian 6-1, Bozhong 26-3, Jinzhou 20-5, Bozhong 26-3 and Bozhong 19-4. Among which, Caofeidian 6-4, Luda 16-3/Luda 16-3 South and Bozhong 34-9 structures were proved to be mid-to-large sized oilfields after appraisals. Bozhong 34-1 North represents the fruitful results that arose from the concept of integration of exploration and development, which helped enhance the value of regional development.

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

For development and production, new projects including Jinzhou 9-3 comprehensive adjustment, Qinhuangdao 32-6 comprehensive adjustment, Kenli 10-1 oilfield, Bozhong 28/34 oilfields comprehensive adjustment and Luda 10-1 oilfield comprehensive adjustment commenced production during the year, adding impetus to the Company’s production growth.

Western South China Sea

Western South China Sea is one of the most important natural gas production areas for the Company. Currently, the typical water depth of the Company’s operation area in this region ranges from 40 to 120 meters. As of the end of 2015, the reserves and daily production volume in Western South China Sea reached 672.6 million BOE and 143,676 BOE/day, respectively, representing approximately 15.6% and 10.6% of the Company’s total reserves and daily production, respectively.

In 2015, the Company made five new independent discoveries in Western South China Sea, namely Wushi 16-1 West, Wushi 17-5, Wushi 16-9, Lingshui 18-1 and Lingshui 18-2. Of which, Lingshui 18-2 is a new natural gas discovery obtained from the new layer of the central valley channels and was tested with high production capacity. Five successful appraisals were made, namely Wushi 16-9, Wushi 16-1 West, Weizhou 6-8, Wushi 17-5 and Lingshui 25-1. Of which, Lingshui 25-1 was confirmed to be a mid-to-large sized natural gas structure after appraisal; integration of exploration and development was promoted in Wushi Trough, with Wushi 16-9, Wushi 16-1 West and Wushi 17-5 being successfully appraised, enhancing the value of regional development.

For development, Dongfang 1-1 gas field phase I adjustment came on stream in 2015, Weizhou 12-2 oilfield joint development project and Weizhou 11-4 North oilfield phrase II were announced to start production at the beginning of 2016.

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Eastern South China Sea

Eastern South China Sea is one of the Company’s most important crude oil producing areas. Currently, the typical water depth of the Company’s operation area in this region ranges from 100 to 300 meters. The crude oil produced is mostly of light to medium gravity. As of the end of 2015, the reserves and daily production volume in Eastern South China Sea reached 515.6 million BOE and 229,679 BOE/ day, respectively, representing approximately 11.9% and 16.9% of the Company’s total reserves and daily production, respectively.

In 2015, the Company made favorable results in rolling and expanding exploration in the North Slope of East Sag in Baiyun Trough. Two independent discoveries were made, namely Liuhua 20-2 and Liuhua 21-2, improving the overall efficiency of exploration and development in the region. In addition, two successful appraisals were made, namely Liuhua 28-2 and Lufeng 14-4.

Benefitting from the contribution of a few new projects such as Liwan 3-1 gas field which commenced production in 2014, the production output in Eastern South China Sea increased significantly.

East China Sea

The typical water depth of the Company’s operation area in the East China Sea region is approximately 90 meters. As of the end of 2015, approximately 3.8% of the Company’s reserves and 0.9% of the Company’s production were derived from East China Sea.

Overseas

Asia (excluding China)

Asia (excluding China) was the first overseas region that the Company entered into and 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 2015, the reserves and daily production volume derived from Asia (excluding China) reached 208.9 million BOE and 70,987 BOE/day, respectively, representing approximately 4.8% and 5.2% of the Company’s total reserves and daily production, respectively.

Indonesia

As of the end of 2015, the Company’s asset portfolio in Indonesia consisted of three development and production blocks and a block under construction, among which, the Company acted as the operator for the Southeast Sumatra block, while the Madura Strait PSC was a joint operation block. In addition, the Company, as a non-operator, also holds working interests in the production sharing contracts in Malacca PSC.

The Company owns approximately 13.90% interest in the Tangguh LNG Project in Indonesia. In 2015, production volume of phase I of the Project remained stable. Currently, we are preparing for the development of the third LNG train of Phase II, which is expected to be completed and commence production in 2019.

Iraq

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

In 2015, faced with the severe security conditions in Iraq, as well as declining production of mature oilfields and other difficulties, the Company coordinated the development and production operations, strengthened its oil reservoir study, and adopted effective measures to increase production volume of mature wells. The newly drilled wells also achieved expected production levels. In 2015, the production of Missan oilfields increased steadily and averaged approximately 28,000 barrels per day.

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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 2015, the reserves and daily production volume derived from Oceania reached 90.8 million BOE and 21,673 BOE/day, respectively, representing approximately 2.1% and 1.6% of the Company’s total reserves and daily production, respectively.

Australia

The Company owns 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 2015, 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 and a joint research block in New Zealand.

Africa

Africa is one of the relatively large oil and gas reserves and production base for the Company. The Company’s assets in Africa are primarily located in Nigeria and Uganda. As of the end of 2015, the reserves and daily production volume derived from Africa reached 166.6 million BOE and 83,677 BOE/day, respectively, representing approximately 3.9% and 6.2% of the Company’s total reserves and daily production, respectively.

Nigeria

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

In 2015, the Akpo oilfield maintained stable production and its net production averaged approximately 64,000 barrels per day. The Egina project is currently at the construction stage, with construction of production facilities such as Christmas trees and FPSO undergoing.

In addition, Nexen Petroleum Nigeria Limited holds a 20% non-operating interest in Usan oilfield in the OML138 block in offshore Nigeria, together with a number of other discoveries and exploration targets. Nexen Petroleum Nigeria Limited made a new discovery in the area in 2015, namely Ukot South. Also, Nexen Petroleum Exploration & Production Nigeria Limited and Nexen Petroleum Deepwater Nigeria Limited hold an 18% non-operating interest in the OPL 223 and OML 139 PSC, respectively.

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

Uganda

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 Lake Albert Basin in Uganda, which is one of the most promising basins for oil and gas resources in Africa.

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In 2015, the Company, as the operator of EA 3A, took great efforts to promote the development of the Kingfisher oilfield. The field is still under research at the preliminary development stage, and has currently completed the Pre-FEED of the crude oil pipeline.

In 2015, the FDP/PRR preparation for all oil and gas fields (excluding Kingfisher) in the reserved areas in the EA 1 and EA 2 blocks, in accordance with the government’s review requirements, were completed and submitted to the government of Uganda for the application of production licenses, and is currently awaiting government’s approval.

Other Regions in Africa

Apart from Nigeria and Uganda, the Company also owns interests in several blocks in Equatorial Guinea, the Republic of the Congo, Algeria and the Gabonese Republic. In 2015, the Company made a new discovery in REZ structure in Algeria.

North America

North America has become the biggest overseas reserves and production region of the Company. The Company holds interests in oil and gas assets in the U.S., Canada and Trinidad and Tobago, as well as part of the shares of MEG Energy Corporation in Canada. As of the end of 2015, the Company’s reserves and daily production volume derived from North America reached 1,120.0 million BOE and 135,030 BOE/day, respectively, representing approximately 26.0% and 10.0% of the Company’s total reserves and daily production, respectively.

The U.S.

The Company currently holds 33.3% interest in two shale oil and gas projects in the U.S., namely the Eagle Ford and Niobrara shale oil and gas projects.

In 2015, along with the increasing number of wells drilled, the net production of the Eagle Ford project continued to increase and averaged approximately 60,000 BOE/day. At the same time, upon the identification of the core region of the Powder River Basin for the Niobrara project, the project began to make contribution to the Company. Under the current low oil price environment, our operators have slowed down asset development, which will impact our near-term production due to natural decline.

In addition, the Company owns interest in two major deep-water developments, Stampede and Appomattox, and a number of other exploration blocks in the U.S. Gulf of Mexico, through its wholly-owned subsidiary, Nexen Energy ULC (“Nexen”). The Company also owns interests in several exploration blocks in offshore Alaska.

Canada

Canada is one of the world’s major regions with rich oil sands resources, participation in oil sands development will be favorable to the sustainable growth of the Company. In Canada, the Company, through its subsidiary, Nexen, owns 100% working interest in the oil sands project located at the Long Lake as well as three other oil sands leases in the Athabasca region in northeastern Alberta. We also hold a 7.23% interest in the Syncrude project and a 25% interest in several other non-operated exploration and development leases.

In 2015, the Company continued the development of the Long Lake project. Its net production averaged approximately 30,000 BOE/day. For the oil sands project in Canada, under the low oil price environment, the Company will leverage on its overall advantages, lower cost and enhance efficiency, and control the pace of investment to provide a solid resource safeguard for its long-term development.

In addition, the Company holds approximately 12.39% of the shares of MEG Energy Corporation in Canada, which is listed on the Toronto Stock Exchange. The Company also owns a 60% interest in Northern Cross (Yukon) Limited, which owns oil and gas exploration blocks in the Yukon Province in

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Canada.

Other Regions in North America

The Company owns 12.5% interest in the 2C block and a 12.75% interest in the 3A block in Trinidad and Tobago, respectively, of which the 2C block is in production. The engineering construction of phase III of the natural gas project progressed smoothly, and is expected to come on stream in the second half of 2016.

South America

In South America, the Company mainly holds a 50% interest in Bridas Corporation (“Bridas”) and a 10% interest in the PSC of the Libra oilfield in Brazil, among which, the Company’s 50% interest in Bridas is accounted for by equity methods. As of the end of 2015, the Company’s reserves and daily production volume derived from South America reached 299.4 million BOE and 49,884 BOE/day, respectively, representing approximately 6.9% and 3.7% of the Company’s total reserves and daily production, respectively.

Argentina

The Company holds a 50% interest in Bridas and makes joint management decisions. Bridas holds 40% interest in Pan American Energy (“PAE”) in Argentina and 100% interest in AXION Refinery. Bridas engages in upstream oil and gas exploration and production activities as well as downstream refining activities in Argentina and other countries. The strength of upstream and downstream integration is gradually realized.

In 2015, the Company made considerable efforts to maintain normal operations and production in the operating areas and endeavored to overcome the bottleneck of operational resources, coordinate resources and improve operational efficiency. The production of Bridas increased slightly to approximately 49,000 BOE/day. The downstream refinery maintains a high level of operation capacity and research on facilities upgrade and expansion is currently conducting.

Brazil

The Company holds a 10% interest in the 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 km² and water depth of about 2,000 meters.

In 2015, a successful appraisal was made in the Libra project, which further reinforced the confidence in exploration and appraisal in the block.

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 in Brazil to seek a new growth point for production growth.

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 2015, the Company’s reserves and daily production volume derived from Europe reached 103.8 million BOE and 110,842 BOE/day, respectively, representing approximately 2.4% and 8.2% of the Company’s total reserves and daily production, respectively.

United Kingdom

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The Company’s asset portfolio in the North Sea consists of projects under production, development and exploration, mainly including: a 43.2% interest in the Buzzard oilfield, one of the largest oilfield in the North Sea, and a 36.5% interest in the Golden Eagle oilfield, making the Company the largest crude oil operator in the North Sea.

The United Kingdom is one of the Company’s key overseas areas, as several key projects such as Buzzard and Golden Eagle have contributed considerably to the Company’s production. In 2015, the net production of Buzzard oilfield averaged approximately 72,000 barrels per day. In the future, we will continue to intensify our efforts in the oil and gas development in the UK, and actively look for potential exploration and development blocks in order to achieve a stable and sustainable development in the region.

Other Regions in Europe

The Company holds a license issued by the government of Iceland for carrying out oil exploration operations in the Norwegian Sea, Northeast Iceland. The project is at exploration and appraisal stage and completed offshore 2D seismic data acquisition and related appraisal work.

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 2013, 2014 and 2015.

	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)
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		—		—		—

2014
Offshore China
Bohai		426,913		403,927		137.9		—		—		—

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Western South China Sea	138,972	80,493	341.7	—	—	—
Eastern South China Sea	163,970	141,166	136.8	—	—	—
East China Sea	5,678	1,206	26.8	—	—	—
Subtotal	735,533	626,791	643.3	98.19	7,573	9.73
Overseas
Asia (excluding China)	65,280	37,237	154.4	95.23	9,636	18.21
Oceania	26,092	4,297	111.2	100.08	3,163	9.41
Africa	76,838	76,838	—	96.91	—	9.19
North America (excluding Canada)	68,396	49,814	112.7	73.47	752	6.57
Canada	67,770	48,183	117.5	85.66	3,690	41.09
South America	1,058	1,058	—	86.36	5,120	14.80
Europe	96,370	87,918	50.7	97.79	7,206	12.69
Subtotal	401,804	305,345	546.6	91.62	5,120	16.45
Total	1,137,337	932,137	1,189.9	96.04	6,445	12.11
Equity method investees	47,640	23,510	140.2	—	—	—

2013
Offshore China
Bohai	413,650	392,413	127.4	—	—	—
Western South China Sea	132,284	75,606	330.5	—	—	—
Eastern South China Sea	166,778	141,545	151.4	—	—	—
East China Sea	5,072	872	25.2	—	—	—
Subtotal	717,784	610,435	634.5	106.86	6,323	10.06
Overseas
Asia (excluding China)	54,529	28,997	140.3	105.40	8,193	23.65
Oceania	23,909	4,533	98.2	118.48	3,151	9.61
Africa	77,343	77,343	—	108.29	—	7.54
North America (excluding Canada)	62,496	44,245	109.5	79.59	3,632	8.47
Canada	57,534	39,872	106.0	90.52	2,901	45.58
South America	960	960	—	97.62	—	13.98
Europe	88,241	83,460	28.7	103.58	9,700	12.38
Subtotal	365,010	279,409	482.7	99.67	5,067	17.42
Total	1,082,795	889,845	1,117.1	104.60	5,780	12.54
Equity method investees	45,173	22,758	130.2	—	—	—

Drilling and Other Exploratory and Development Activities

The following table sets forth our net exploratory wells and development wells drilled in the years of 2013, 2014 and 2015.

Net Exploratory Wells Drilled

Net Development Wells Drilled

Total

Productive

Dry

Total

Productive

Dry

2015

Offshore China

Independent

Bohai

129

—

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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
2014
Offshore China
Independent
Bohai	47	29	18	272	272	—
Western South China Sea	42	17	25	47	47	—
Eastern South China Sea	13	5	8	43	43	—
East China Sea	11	6	5	—	—	—
Subtotal	113	57	56	362	362	—
PSCs
Bohai	1	—	1	91.4	91.4	—
Western South China Sea	2	2	—	0.6	0.6	—
Eastern South China Sea	1	—	1	14.9	14.9	—
East China Sea	—	—	—	6.5	6.5	—
Subtotal	4	2	2	113.4	113.4	—
Overseas
Asia (excluding China)	1.3	0.1	1.2	11.1	11.1	—
Oceania	—	—	—	—	—	—
Africa	2.8	1.3	1.5	2.4	2.4	—
North America	1.0	0.1	0.9	365.8	365.8	—
South America	—	—	—	0.8	0.8	—
Europe	2.2	1.4	0.8	3.0	3.0	—
Subtotal	7.3	2.9	4.4	383.1	383.1	—

2013
Offshore China
Independent
Bohai	39	28	11	161	161	—
Western South China Sea	38	15	23	26	26	—
Eastern South China Sea	15	1	14	13	13	—
East China Sea	5	3	2	—	—	—
Subtotal	97	47	50	200	200	—
PSCs

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Bohai	—	—	—	67	67	—
Western South China Sea	3	—	3	8.4	8.4	—
Eastern South China Sea	—	—	—	29.5	29. 5	—
East China Sea	—	—	—	2.0	2.0	—
Subtotal	3	—	3	106.9	106.9	—
Overseas
Asia (excluding China)	1.9	1.5	0.4	8.5	8.5	—
Oceania	—	—	—	—	—	—
Africa	7.4	5.9	1.5	4.0	4.0	—
North America	0.9	0.3	0.6	186.7	186.4	—
South America	1.0	—	1.0	0.2	0.2	—
Europe	1.4	1.0	0.4	2.9	2.9	—
Subtotal	12.6	8.7	3.9	202.3	202.0	—

Present Activities

The following tables set forth our present activities as of December 31, 2015.

	Wells Being Drilled				Waterfloods Being Installed
	Gross		Net		Gross		Net
Offshore China
Bohai		6		5.5		618		551.5
Western South China Sea		3		3		25		25.0
Eastern South China Sea		8		8		—		—
East China Sea		10		5		—		—
Subtotal		27		21.5		643		576.5
Overseas
Asia (excluding China)		7		6.0		79		51.4
Oceania		—		—		—		—
Africa		2		0.7		16		7.2
North America		25		9.9		—		—
South America		1		0.1		24		4.8
Europe		1		0.8		1		0.4
Subtotal		36		17.4		120		63.7

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, 2015.

	Productive Wells								Developed Acreage (km²)				Undeveloped Acreage (km²)
	Crude and Liquids				Natural Gas
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Offshore China
Bohai		2,055		1,750.0		27		27.0		2,497		2,497		43,068		43,068
Western South China Sea		282		261.4		79		74.5		1,863		1,863		73,388		73,388
Eastern South China Sea		399		352.7		39		34.1		2,543		2,543		55,424		55,424

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East China Sea	20	6.9	52	22.7	85	85	85,413	85,413
Subtotal	2,756	2,370.9	197	158.3	6,988	6,988	257,292	257,292
Overseas
Asia (excluding China)	536	491.8	27	12.3	15,199	6,074	23,273	10,885
Africa	43	14.4	—	—	886	396	21,982	5,797
Oceania	—	—	50	2.5	4,115	218	41,766	33,333
North America	4,033	1,296.5	565	187.9	508	150	19,772	6,801
South America	4,545	896.5	384	76.5	67	7	2,840	795
Europe	154	76.6	4	1.8	116	61	14,197	7,674
Subtotal	9,311	2,775.8	1,030	281	20,893	6,906	123,830	65,285
Total	12,067	5,146.7	1,227	439.3	27,881	13,894	381,122	322,577

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 2015, the annual sales from our largest gas contract contributed to only approximately 2.0% of our total oil and gas sales and the total revenues from gas sales accounted for approximately 10.3% of our total revenues in 2015. 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 2015.

Sales and Marketing

Sales of Crude Oil

The Company sells its crude oil produced offshore China to the PRC market mainly through CNOOC China Limited, its wholly-owned subsidiary. The Company sells its 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, namely, heavy crude, medium crude and light crude, which are benchmarked by Duri, Daqing, and Tapis, respectively, all of which are the benchmarking crude oil prices in the Far East. The Company’s major customers in China are Sinopec, Petrochina and CNOOC. The crude oil produced overseas and sold in the international markets is benchmarked at the Brent and WTI oil prices.

The world economy lost its growth momentum and varied for different areas in 2015. The diversity in monetary policies in different countries led to a strong US dollar. While the global demand for oil increased moderately, international oil prices continued to plummet affected by oversupply of crude oil, which was mainly driven by increased production of US shale oil as well as from OPEC member states. As a result, the Company’s realized oil prices declined significantly. In 2015, the Company’s average realized oil price was US$51.27/barrel, representing a decline of 46.6% year over year.

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.

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	Year ended December 31,
		2013		2014		2015
Sales and Marketing Volumes (mmbbls)⁽¹⁾	Benchmark Prices
Light Crude	PLATTS Tapis⁽²⁾		12.4		10.6		22.9
Medium Crude	Daqing OSP⁽³⁾		126.7		130.4		162.4
Heavy Crude	ICP Duri⁽⁴⁾		128.3		125.2		138.2

__________

⁽¹⁾

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

⁽²⁾

Tapis is a light crude oil produced in Malaysia.

⁽³⁾

Daqing official selling price. Daqing is a medium crude oil produced in northeast China.

⁽⁴⁾

Duri is a heavy crude oil produced in Indonesia. The Indonesian crude price (“ICP”) Duri has been the sole benchmark price for heavy crude since 2006.

Sales of Natural Gas

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

The LNG sourced by the Company from the North West Shelf LNG Project in Australia and the Tangguh LNG Project in Indonesia is mainly based on long-term supply contracts and is sold to various customers in the Asia-Pacific region, including LNG Terminals in Dapeng, Guangdong and Putian, Fujian, China.

In 2015, the Company’s average realized natural gas price was US$6.39/mcf, representing a 0.8% decrease year over year, primarily due to two reasons: on one hand, production from new gas fields in offshore China commanded higher prices; on the other hand, realized gas price overseas decreased year over year as a result of significant decrease in natural gas prices in North America market, which offset the price increase in offshore China.

In China, the current oversupply of natural gas will adversely affect the development, operation and income of the Company’s natural gas business. To cope with the current shortage of natural gas demand from downstream users, the Company will coordinate related designs, approvals and gas price negotiations with downstream customers, with the aim of promoting a stable production of producing oil and gas fields and the development of oil and gas fields under construction.

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

	Year ended December 31,
	2013		2014		2015
Average Realized Prices
Crude and Liquids (US$/bbl)		104.60		96.04		51.27
Natural Gas (US$/mcf)		5.78		6.44		6.39

West Texas Intermediate (US$/bbl)		98.01		93.03		48.68

The international benchmark crude oil price, West Texas Intermediate, was US$37.13 per barrel as of December 31, 2015 and US$38.34 per barrel as of March 31, 2016.

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

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	Year ended December 31,
	2013			2014			2015
	(Rmb in millions, except percentages)
Revenues sourced in the PRC		191,764			178,822			124,427
Revenues sourced outside the PRC		94,093			95,812			47,010
Total revenues		285,857			274,634			171,437
% of revenues sourced outside the PRC		32.9	%		34.9	%		27.4	%

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 2015, the Company continued to implement its “technology-driven” strategy through further reforms in the scientific and technological systems, coordinated research resources and promoted research and production works in an orderly and effective manner. During the year, the Company continued to streamline the positions of different research institutes and to identify their respective responsibilities. In addition, measures were taken to coordinate the functions and systems of different institutes. The Company also established an unconventional oil and gas research institute. Pilot platforms such as the platform for the development of high temperature and high pressure reservoirs were put into use, providing basic requirements and protection for the Company’s independent technological innovations. Through such innovations, the Company was able to protect its increased reserves and production as well as to lower cost and enhance efficiency for its development projects. A series of research findings have been applied to increase production efficiency. In recognition of its achievements, a second prize was awarded to the Company for “Key Technological Application in Enhancing Oil Recovery of Offshore Heavy Polymer Flooding” from the National Technological Invention Award in 2015.

Major Scientific Project Development

In 2015, in order to provide key technological support for its sustainable development, the Company strengthened the management of technological projects and focused its efforts on areas such as exploration and development technology for deep water oil and gas fields, offshore heavy oil fields and fields with low porosity and permeability, onshore coalbed methane exploration technology , tapping technology of oil gas fields, offshore oil gas fields, development of high-temperature and high-pressure gas fields in South China Sea, etc.

In addition, the Company undertook a number of national and CNOOC’s science and technology projects such as the “Development of Large-scale Oil and Gas Fields and Coalbed Methane” and achieved know-how and new theories for geological explorations regarding the differences in oil and gas accumulation in active fault zones in Bohai as well as high-temperature and high-pressure natural gas accumulation. New exploration techniques were acquired, involving “low porosity, low permeability and low pressure” oil and gas reservoirs and deep oil and gas exploration as well as key developments of oil gas fields concerning improvements and comprehensive adjustments of maritime cluster well pattern and offshore heavy oil chemical flooding.

Innovative Development of Key Technologies

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Following the successful well logging in Lingshui 18-1-1 well, the Company made its first commercial discovery in Central Canyon Yinggehai in 2015 through technological innovation. Results from the mathematical modeling and physical modeling research of thermal recovery of heavy oil reservoirs offshore, which were developed in-house, were used in Nanbao 35-2 and Luda 27-2 oilfields. We have successfully developed the first comprehensive assessment system of log interpretation which helped reduce the cost of comprehensive assessment considerably. The Company developed for its own 7 series and 5 processing techniques for sand prevention, including the complete series of cased well and open well. The Company is at the forefront of technological development in the country.

Health, Safety and Environmental Protection (“HSE”)

The Company always places great emphasis on health, safety and environmental protection (HSE). “Safety and environmental protection come first, people oriented and well-equipped facilities” have been regarded as the core values of quality, health, safety and environmental protection (QHSE). To promote the culture of HSE, the Company strives to establish a comprehensive management system to improve employees’ awareness of HSE during operations, to strengthen their ability to identify safety risks as well as improve their risk management skills.

Since the end of 2014, the Work Safety Law of the People’s Republic of China (as amended) and the Environmental Protection Law of the People’s Republic of China (as amended) have imposed stricter supervision and management of work safety on enterprises, which brings about additional challenges for the Company in work safety, clean production and development. For this reason, the Company further reinforced its basic work of production safety through system improvement and management innovation. The Company’s key responsibilities were effectively put in place and its safety culture was clearly demonstrated. All in all, the operation of the health, safety and environmental protection system remained stable.

Offshore China, in view of new regulations recently implemented, the Company has carried out safety hazards investigations and employed third-party agencies to carry out safety and environmental compliance management and operational assessments in 2015 to identify management’s weaknesses and to provide recommendations for improvement. We reinforced the system of QHSE work, adhered to the mode of system management, coordinated and prepared annual audit inspections, organized system reviews for the 7 units under the Company, and strengthened management reviews of highly specialized contractors by external experts. During the year, the Company carried out a review on 35 contract helicopters and 11 diving contractors in 12 helicopter bases to obtain detailed management findings and effectively avoid HSE risks. During the year, the Company also conducted special safety inspections of offshore oil and gas, dangerous chemicals and inflammable and explosive materials, and full coverage inspections of “Five No-drillings” to track potential problems and to remediate potential risks.

In 2015, the Company advocated the implementation of “China National Offshore Oil Safety Signs behavior” actions and enacted rules relating to safety signs behavior in three levels of daily working lives, including leaders, employees and organization in order to arouse the safety awareness of employees in their everyday life and to promote security management.

Apart from this, the Company further strengthened its energy saving technological reforms to reinforce energy discharge management and achieved 129,000 tons of standard coal energy savings in 2015.

In 2015, the Company continued to strengthen overseas HSE management and enacted individual management plans for all highlighted overseas projects. We have now finished all HSE management plans for branches in Iraq, Indonesia, Uganda and we continued to integrate the HSE management within Nexen, gradually improved the HSE management and facilitated the implementation of corporate management requirements effectively by the following measures: competing focused reviews, organizing joint exercises, enhancing communication, and strengthening incident management.

The Company’s emergency response system were undergoing serious testing. On 15 July 2015, an emulsion leak from a pipeline was discovered within Nexen’s Long Lake operations, located in the

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south of Fort McMurray, Alberta, Canada. The estimated size of the leak was 5,000 m³ over an area of approximately 21,900 m²mostly within a compacted pipeline corridor. There were no injuries due to this incident. The affected wells were suspended and Nexen’s emergency response plan was activated. The Company places great emphasis on production safety and has taken measures to minimize the spill's impact to the environment and wildlife. Since the incident, the Company has been working together with relevant regulatory agencies in its conduct of clean-up and remediation work at the spill site. Nexen is cooperating with the investigation of the regulatory agencies.

The majority of the released bitumen in the spill area has been safely removed. Further continued remediation and clean-up work is underway and will be carried out in compliance with applicable regulatory requirements.

HSE regulatory standards were further enhanced with the help of information technology. Our Environmental Information System is able to monitor real-time pollutant emission while safety inspection systems are available for continuing investigation and management of safety risks.

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.

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, 2015, we have purchased a number of insurance policies with varying policy coverage and limits to meet our risk management requirements and cover our potential liabilities arising from accidents at any of our offshore and onshore locations. We maintain insurance for costs relating to property damage to our facilities, control of well including drilling relief wells, removal of wreck, pollution clean-up, liability for bodily injury and property damage to third parties. The policy limits and other terms and conditions of these insurance policies comply with all applicable laws and regulations in 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.”

Excluding Nexen’s operation and Nexen’s assets, we have maintained varied insurance policies for our 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 for our working interests. As for deep-water wells, we are

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insured for our working interest 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 Nexen, we are insured for amounts up to the replacement cost value of our assets for property damage and up to US$525 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$865 million. This cover protects against liability that arises from sudden and accidental pollution or from other causes. For declared deep-water wells, we are insured for our working interest share of up to US$850 million for costs related to control of the well.

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.

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.

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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,
	2013				2014				2015
	Rmb in millions		%		Rmb in millions		%		Rmb in millions		%
Exploration and production		229,860		80.4		223,741		81.5		149,582		87.3
Trading businesses		55,716		19.5		50,263		18.3		21,438		12.5
Corporate and elimination		281		0.1		630		0.2		417		0.2
Total operating revenues		285,857		100.0		274,634		100.0		171,437		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, 2015, approximately 73% 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 Land and Resources, the State Oceanic Administration, the National Development and Reform Commission and the State Administration of Work Safety 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 obtain approval of overall development plan from 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.

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

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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 31 December 2017, after being assessed as a high new technology enterprise.

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

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

production taxes at the rate of 5% on independent production and production under PSCs;

resource taxes at the rate of 5% (reduced tax rates may apply to specific products and fields) on the oil and gas sales revenue (excluding production taxes) 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. The resource tax rate has been changed from 5% to 6% since December 1, 2014;

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

business tax at the rates of 3% to 5% or value-added tax at the rate of 3% to 17% on other income;

city construction tax at the rates of 1% or 7% on the actual paid production taxes, business tax and value-added tax;

educational surcharge at the rate of 3% on the actual paid production taxes, business tax and value-added tax; and

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local educational surcharge at the rate of 2% on the actual paid production taxes, business tax and value-added tax.

We calculate our deferred tax to account for 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, 2013, 2014 and 2015, we had Rmb (22,633) million, Rmb (14,312) million and Rmb 1,948 million (US$ 301 million) respectively, in net deferred tax assets/ (liabilities). See note 12 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. The special oil gain levy is collected on a quarterly basis. For the years ended December 31, 2013, 2014 and 2015 we incurred approximately Rmb 23,421 million, Rmb 19,072 million and Rmb 59 million (US$9.1 million) for the Special Oil Gain Levy.

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. 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.

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

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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.

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.

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Percentage of annual gross production	Allocation
5.0%	Production tax payable to the PRC government⁽¹⁾

62.5%	For the payment of resource tax or recovery:
	1. Resource tax⁽²⁾payable to the PRC government
	2. Cost recovery oil⁽³⁾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); (4) recovery of development costs and deemed interest by us and foreign partner(s) based on participating interests; and (5) any excess, allocated to the remainder oil.

32.5%⁽⁴⁾	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 amount of crude oil equivalent to 62.5% of annual gross production minus the amount of crude oil for payment of resource tax shall be cost recovery oil.

(4)

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 sell such crude oil to us 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.

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.

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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.

Our subsidiaries domiciled outside of the PRC are subject to income tax rates ranging from 10% to 56%.

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 bureaus for our operations in China. The Environmental

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Protection Law of PRC was amended in 2014. Such amended Environmental Protection Law, which came into effect on January 1, 2015, strengthens the environmental protection regulation system including but not limited to the pollution permission management system, provides the environmental public interest litigation for the first time and increases the intensity of punishment against illegal actions. 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 bureau 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 bureau generally issues approvals and permits for projects using modern pollution control measurement technology.

The PRC national and local environmental laws and regulations impose fees for the discharge of waste substances above prescribed levels, require the payment of fines for serious violations and provide that the PRC national and local governments, State Oceanic Administration or national and local environmental protection bureaus 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, 2013, 2014 and 2015 of approximately Rmb 42,351 million, Rmb 52,889 million and Rmb 50,063 million (US$7,728 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

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, 2013, 2014 and 2015, we employed 17,553 persons, 21,046 persons and 20,585 persons, respectively. Of the 20,585 employees we employed as of December 31, 2015, approximately 75.2% were involved in oil exploration, development and production activities,

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approximately 3.6% 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 11% to 22% 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 contributions to a mandatory provident fund at a rate of 5% of the base salaries for full-time employees in Hong Kong.

For further details regarding retirement benefits, see note 31 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 2015, we held 61 core training workshops, which were attended by approximately 5,700 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.

Organizational Structure

CNOOC indirectly owned or controlled an aggregate of approximately 64.44% of our shares as of March 31, 2016. Accordingly, CNOOC continues to be able to exercise all the rights of a controlling shareholder, including electing our directors and voting to amend our articles of association. Although CNOOC has retained a controlling interest in us, the management of our business will be our directors’ responsibility.

The following chart sets forth our controlling entities and our directly wholly-owned subsidiaries as of March 31, 2016 and notes our significant indirectly-held subsidiaries.

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________

(1)

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

(2)

Owner of our overseas interests in oil 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 UK 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 100% owned subsidiaries with our company as their sole corporate director

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.

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ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

Operating Results

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

Overview

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

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

			Year ended December 31,
	2013		2014		2015
Average net realized prices:
Crude oil (US$ per bbl)		104.60		96.04		51.27
Natural gas (US$ per mcf)		5.78		6.44		6.39

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.

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

			Year ended December 31,
	2013		2014		2015
Net production of crude oil (bbl/day)⁽¹⁾		912,603		955,647		1,124,047
Net production of natural gas (mmcf/day)⁽¹⁾		1,247.4		1,330.1		1,363.6

(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 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.

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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 recoverable amount of assets require the use of estimates and assumptions. It is reasonably possible that the oil price assumption may change, which may then impact the estimated life of the field and may then require a material adjustment to the carrying value of tangible assets. The Company monitors internal and external indicators of impairment relating to its tangible and intangible assets.

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 expensed and included in administrative expenses.

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.

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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 finance costs in the consolidated statement of profit or loss and other comprehensive income.

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

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

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Deferred Tax

Deferred tax is provided, using the 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 sales of oil and gas purchased 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. In addition, our trading 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.

Results of Operations

Overview

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

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	Year ended December 31,
	2013				2014				2015
	(Rmb in millions, except percentages and production data )
Revenues:
Oil and gas sales:
Crude oil		211,838	74.1	%		200,991	73.2	%		128,929	75.2	%
Natural gas		14,607	5.1	%		17,219	6.3	%		17,668	10.3	%
Total oil and gas sales		226,445	79.2	%		218,210	79.5	%		146,597	85.5	%

Marketing revenues		55,495	19.4	%		50,263	18.3	%		21,422	12.5	%
Other income		3,917	1.4	%		6,161	2.2	%		3,418	2.0	%
Total revenues		285,857	100	%		274,634	100	%		171,437	100.0	%

Net production (million BOE)⁽¹⁾:
Crude oil		333.1	80.9	%		348.8	80.6	%		410.3	82.8	%
Natural gas		78.6	19.1	%		83.7	19.4	%		85.4	17.2	%
Total net production		411.7	100	%		432.5	100	%		495.7	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,
	2013			2014			2015
Operating Revenues:
Oil and gas sales		79.2	%		79.5	%		85.5	%
Marketing revenues		19.4	%		18.3	%		12.5	%
Other income		1.4	%		2.2	%		2.0	%
Total revenues		100.0	%		100.0	%		100.0	%
Expenses:
Operating expenses		(10.5	)%		(11.4	)%		(16.5	%)
Taxes other than income tax		(5.6	)%		(4.3	)%		(6.3	%)
Exploration expenses		(6.0	)%		(4.2	)%		(5.8	%)
Depreciation, depletion and amortization		(19.7	)%		(21.2	)%		(42.8	%)
Special oil gain levy		(8.2	)%		(6.9	)%		0.0	%
Impairment and provision		0.0	%		(1.5	)%		(1.6	%)
Crude oil and product purchases		(18.7	)%		(17.4	)%		(11.6	%)
Selling and administrative expenses		(2.7	)%		(2.4	)%		(3.3	%)
Others		(1.1	)%		(1.2	)%		(1.8	%)
Total expenses		(72.5	)%		(70.5	)%		(89.8	%)

Interest income		0.4	%		0.4	%		0.5	%
Finance costs		(1.2	)%		(1.7	)%		(3.6	%)
Exchange gain, net		0.3	%		0.4	%		(0.1	%)
Investment income		0.9	%		1.0	%		1.4	%
Share of profits of associates		0.0	%		0.1	%		0.1	%
Share of profits/(losses) of a joint venture		0.3	%		0.3	%		1.0	%
Non-operating income/(expenses), net		0.1	%		0.2	%		0.4	%
Profit before tax		28.3	%		30.0	%		10.0	%
Income tax expense		(8.5	)%		(8.1	)%		1.8	%
Profit for the year		19.8	%		21.9	%		11.8	%

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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 and purchased by us from our foreign partners under such contracts as well as from international oil and gas companies through our wholly owned subsidiary in Singapore. 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 our foreign partners and handling fees charged to end customers—both fees are recognized when the services are rendered. Reimbursement of insurance claims is recognized 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

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.

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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.

2015 versus 2014

Consolidated net profit

Our consolidated net profit decreased 66.4% to Rmb 20,246 million (US$3,125.4 million) in 2015 from Rmb 60,199 million in 2014, primarily as a result of the decrease in profitability under the low international oil price environment.

Revenues

Our oil and gas sales, realized prices and sales volume in 2015 are as follows:

	2015		2014		Change			Change (%)

Oil and gas sales (Rmb million)		146,597		218,210		(71,613	)		(32.8	%)
Crude and liquids		128,929		200,991		(72,062	)		(35.9	%)
Natural gas		17,668		17,219		449			2.6	%
Sales volume (million BOE)		480.1		415.6		64.5			15.5	%
Crude and liquids (million barrels)		404.0		340.6		63.4			18.6	%
Natural gas (bcf)		444		435		9			2.1	%
Realized prices
Crude and liquids (US$/barrel)		51.27		96.04		(44.77	)		(46.6	%)
Natural gas (US$/mcf)		6.39		6.44		(0.05	)		(0.8	%)
Net production (million BOE)		495.7		432.5		63.2			14.6	%
China		323.4		269.1		54.3			20.2	%
Overseas		172.3		163.4		8.9			5.4	%

In 2015, our net production was 495.7 million BOE (including our interest in equity-accounted investees), representing an increase of 14.6% from 432.5 million BOE in 2014, benefitting from the commencement of production of new oil and gas fields in offshore China. The decrease in crude and liquids sales was primarily due to significantly lower realised oil prices in 2015, which was partially offset by the increase in sales volume.

Operating expenses

Our operating expenses decreased 9.0% to Rmb 28,372 million (US$4,379.9 million) in 2015 from Rmb 31,180 million in 2014, and the operating expenses per BOE decreased 20.9% to Rmb 59.4 (US$9.18) per BOE in 2015 from Rmb 75.1 (US$12.11) per BOE in 2014, attributable from effective cost control and large increase in production. Operating expenses per BOE offshore China decreased 18.0% to Rmb 49.5 (US$7.64) per BOE in 2015 from Rmb 60.4 (US$9.73) per BOE in 2014. Overseas operating expenses per BOE decreased 21.4% to Rmb 80.2 (US$12.38) per BOE in 2015 from Rmb 102.1(US$16.45) per BOE in 2014.

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Taxes other than income tax

Our taxes other than income tax decreased 9.1% to Rmb 10,770 million (US$ 1,662.6 million) in 2015 from Rmb 11,842 million in 2014. The decrease was mainly due to the decrease in oil and gas revenue.

Exploration expenses

Our exploration expenses decreased 14.1% to Rmb 9,900 million (US$1,528.3 million) in 2015 from Rmb 11,525 million in 2014, among which dry hole expense decreased 16.7% to Rmb 4,740 million (US$731.7 million) in 2015 from Rmb 5,686 million in 2014, due to the decrease of exploration expenditure, less high-cost wells and less wells expenses which were written off according to subsequent reserve evaluation. Meanwhile, the seismic expense decreased as compared to 2014, resulting from the continuing efforts in lowering costs and enhancing efficiency under the circumstance of decreasing exploration expenditure budget.

Depreciation, depletion and amortization

Our depreciation, depletion and amortization increased 26.0% to Rmb 73,439 million (US$11,337.0 million) in 2015 from Rmb 58,286 million in 2014. Our average depreciation, depletion and amortization per BOE, excluding the dismantlement-related depreciation, depletion and amortization, increased 11.8% to Rmb 146.4 (US$22.61) per BOE in 2015 from Rmb 130.9 (US$21.10) per BOE in 2014, primarily as a result of the increased proportion of production of new oil and gas fields and adjustment projects in offshore China and North Sea in UK in recent years, which were developed under the environment of increasing prices of raw materials and services over the past few years. Meanwhile, the commencement of production of new development wells of shale oil and gas in the U.S. further increased the amortization rate per BOE.

The dismantlement-related depreciation, depletion and amortization costs decreased 10.3% to Rmb 3,545 million (US$547.2 million) in 2015 from Rmb 3,951 million in 2014. Our average dismantling costs per BOE decreased 22.0% to Rmb 7.43 (US$1.15) per BOE in 2015 from Rmb 9.52 (US$1.53) per BOE in 2014, primarily due to the decrease of the expected value of asset retirement obligations of producing oil and gas fields, which was estimated based on current services price. Under the environment of reducing capital expenditure in upstream industry, the service price of projects constructions and drilling wells decreased.

Special Oil Gain Levy

Our Special Oil Gain (SOG) Levy decreased 99.7% to Rmb 59 million (US$9.1 million) in 2015 from Rmb 19,072 million in 2014, primarily as a result of our decreased realised oil price in offshore China and the Chinese government increased the threshold of the SOG levy to US$65 with effect from 1 January 2015.

Impairment, provision and write off

Our impairment and provision decreased 33.3% to Rmb 2,746 million (US$423.9 million) in 2015 from Rmb 4,120 million in 2014. In 2015, certain oil and gas properties located in China, North America, South America and Africa were impaired, which was reflected by the impact of near term lower price. In addition, the Company wrote off some shale oil and gas assets in North America and certain unproved properties in Canada. Approximately Rmb 1,400 million was included in the depreciation, depletion and amortization charge of the year, and approximately Rmb 461 million was included in the exploration expenses, respectively. The reason is that the leasehold contracts of these blocks were overdue, and the Company withdraw from these blocks by considering lower economy of the project and falling short of expectation of the exploration result. Please refer to Note 15 to the Consolidated Financial Statement of this annual report.

Selling and administrative expenses

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Our selling and administrative expenses decreased 13.7% to Rmb 5,705 million (US$880.7 million) in 2015 from Rmb 6,613 million in 2014. Our selling and administrative expenses per BOE decreased 24.9% to Rmb 11.95 (US$1.85) per BOE in 2015 from Rmb 15.93 (US$2.57) per BOE in 2014. Such decreases were primarily due to lower expense resulting from the Company’s partial marketing business restructuring and Company’s vigorous efforts in lowering costs and enhancing efficiency in this year.

Finance costs/Interest income

Our finance costs increased 28.2% to Rmb 6,118 million (US$944.5 million) in 2015 from Rmb 4,774 million in 2014, primarily due to the increased interest expense from new issuance of guaranteed notes. Our interest income decreased 18.6% to Rmb 873 million (US$134.8 million) in 2015 from Rmb 1,073 million in 2014, primarily due to the reduced deposit scale under the declining market interest rate environment.

Exchange gains, net