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, 2016

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
SPECIAL NOTE ON THE FINANCIAL INFORMATION AND CERTAIN STATISTICAL INFORMATION PRESENTED IN THIS ANNUAL REPORT	10
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS	11
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE	11
ITEM 3. KEY INFORMATION	11
A. Selected Financial Data	11
B. Capitalization and Indebtedness	14
C. Reasons for the Offer and Use of Proceeds	14
D. Risk Factors	14
ITEM 4. INFORMATION ON THE COMPANY	19
A. History and Development	19
B. Business Overview	21
C. Organizational Structure	56
D. Property, plants and equipment	56
ITEM 4A. unresolved staff comments	57
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS	57
A. Operating Results	57
B. Liquidity and Capital Resources	69
C. Research and Development, Patents and Licenses, etc.	72
D. Trend Information	72
E. Off-Balance Sheet Arrangements	73
F. Tabular Disclosure of Contractual Obligations	73
G. Safe Harbor	73
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	73
A. Directors and Senior Management	73
B. Compensation	83
C. Board Practice	83
D. Employees	86
E. Share Ownership	86
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	87
A. Major Shareholders	87
B. Related Party Transactions	88
C. Interests of Experts and Counsel	92
ITEM 8. FINANCIAL INFORMATION	92
A. Consolidated Statements and Other Financial Information	92
B. Significant Changes	95
ITEM 9. THE OFFER AND LISTING	95
ITEM 10. ADDITIONAL INFORMATION	96
A. Share Capital	96
B. Memorandum and Articles of Association	96
C. Material Contracts	99
D. Exchange Controls	99
E. Taxation	99
F. Dividends and Paying Agents	104
G. Statement by Experts	104
H. Documents on Display	104
I. Subsidiary Information	104
ITEM 11. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK	104
Item 12. Description of Securities other than equity securities	105
A. Debt Securities	105
B. Warrants and Rights	106
C. Other Securities	106
D. American Depositary shares	106
PART II	107
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	107
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	108
A. Material Modifications to the Instruments Defining the Rights of Security Holders	108

B. Material Modifications to the Rights of Registered Securities by Issuing or Modifying any Other Class of Securities	108
C. Withdrawal or Substitution of a Material Amount of the Assets Securing any Registered Securities	108
D. Change of Trustees or Paying Agents for any Registered Securities	108
E. Use of Proceeds	108
ITEM 15. CONTROLS AND PROCEDURES	108
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT	109
ITEM 16B. CODE OF ETHICS	109
ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES	109
ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	110
ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	110
ITEM 16f. Change in Registrant’s Certifying Accountant	110
ITEM 16g. Corporate Governance	110
Item 16H. MINE SAFETY DISCLOSURE	110
PART III	111
ITEM 17. FINANCIAL STATEMENTS	111
ITEM 18. FINANCIAL STATEMENTS	111
ITEM 19. EXHIBITS	111

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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, 2016 of US$1.00=Rmb 6.9430. 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, 2016 of US$1.00=HK$ 7.7534. 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, 2016 of US$1.00=Cdn$1.3426. 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, 2016, 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 2014, 2015 and 2016, approximately 52%, 62% and 60%, 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 2014, 2015 and 2016 were prepared in accordance with the SEC’s final rules on “Modernization of Oil and Gas Reporting”, which became effective for accounting periods ended on or after December 31, 2009. Except as otherwise stated, all amounts of reserve and production in this report include our interests in equity method investees.

In calculating barrels-of-oil equivalent amounts, we have assumed that 6,000 cubic feet of natural gas equals one BOE, with the exception of natural gas from South America, Oceania, SES and Tangguh projects in Indonesia in Asia and Yacheng 13-1/13-4 gas fields in the Western South China Sea, where we have used energy equivalence for such conversion purpose.

Glossary of Technical Terms

Unless otherwise indicated in the context, references to:

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

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

“developed oil and gas reserves” are reserves of any category that can be expected to be recovered:

(i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving any well.

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

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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, 2014, 2015 and 2016 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, 2012, 2013, 2014, 2015 and 2016. 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, 2012, 2013, 2014, 2015 and 2016 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, 2012, 2013, 2014, 2015 and 2016 have been prepared and presented in accordance with IFRS.

	Year ended December 31,
	2012			2013			2014			2015			2016			2016
	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		194,774			226,445			218,210			146,597			121,325			17,475
Marketing revenues		50,771			55,495			50,263			21,422			20,310			2,925
Other income		2,082			3,917			6,161			3,418			4,855			699
Total operating revenues		247,627			285,857			274,634			171,437			146,490			21,099

Expenses:
Operating expenses		(21,445	)		(30,014	)		(31,180	)		(28,372	)		(23,211	)		(3,343	)
Taxes other than income tax		(15,632	)		(15,937	)		(11,842	)		(10,770	)		(6,941	)		(1,000	)
Exploration expenses		(9,043	)		(17,120	)		(11,525	)		(9,900	)		(7,359	)		(1,060	)
Depreciation, depletion and amortization		(32,903	)		(56,456	)		(58,286	)		(73,439	)		(68,907	)		(9,925	)
Special oil gain levy		(26,293	)		(23,421	)		(19,072	)		(59	)		—			—
Impairment and provision		(31	)		45			(4,120	)		(2,746	)		(12,171	)		(1,753	)
Crude oil and product purchases		(50,532	)		(53,386	)		(47,912	)		(19,840	)		(19,018	)		(2,739	)
Selling and administrative expenses		(3,377	)		(7,859	)		(6,613	)		(5,705	)		(6,493	)		(935	)
Others		(1,230	)		(3,206	)		(3,169	)		(3,150	)		(4,802	)		(691	)
Total expenses		(160,486	)		(207,354	)		(193,719	)		(153,981	)		(148,902	)		(21,446	)

Profit/(loss) from operating activities		87,141			78,503			80,915			17,456			(2,412	)		(347	)
Interest income		1,002			1,092			1,073			873			901			130
Finance costs		(1,603	)		(3,457	)		(4,774	)		(6,118	)		(6,246	)		(900	)
Exchange gains /(losses), net		359			873			1,049			(143	)		(790	)		(114	)
Investment income		2,392			2,611			2,684			2,398			2,774			399
Share of profits/(losses) of associates		284			133			232			256			(609	)		(88	)
Share of (losses)/ profits of a joint venture		(311	)		762			774			1,647			533			77
Non-operating income, net		908			334			560			761			574			83

Profit/(loss) before tax		90,172			80,851			82,513			17,130			(5,275	)		(760	)
Income tax (expense)/credit		(26,481	)		(24,390	)		(22,314	)		3,116			5,912			852

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	Year ended December 31,
	2012		2013		2014		2015		2016		2016
	Rmb		Rmb		Rmb		Rmb		Rmb		US$
	(in millions, except per share and per ADS data)
Profit for the year		63,691		56,461		60,199		20,246		637		92

Earnings per share (basic)⁽²⁾		1.43		1.26		1.35		0.45		0.01		0.002
Earnings per share (diluted)⁽³⁾		1.42		1.26		1.35		0.45		0.01		0.002
Earnings per ADS (basic)⁽²⁾		142.66		126.46		134.83		45.35		1.43		0.21
Earnings per ADS (diluted)⁽³⁾		142.14		126.07		134.57		45.31		1.43		0.21

Dividend per share
Interim		0.122		0.198		0.198		0.205		0.105		0.02
Proposed final		0.259		0.252		0.254		0.210		0.204		0.03

	As of December 31,
	2012		2013		2014		2015		2016		2016
	Rmb		Rmb		Rmb		Rmb		Rmb		US$
	(in millions)
Statement of Financial Position Data:
Cash and cash equivalents		55,024		14,318		14,918		11,867		13,735		1,978
Available-for sale financial assets⁽¹⁾		61,795		51,103		54,030		—		—		—
Other financial assets⁽¹⁾		—		—		—		71,806		52,889		7,618
Current assets		170,894		146,552		140,708		140,211		122,045		17,578
Property, plant and equipment, net		252,132		419,102		463,222		454,141		432,465		62,288
Investments in associates		3,857		4,094		4,100		4,324		3,695		532
Investments in a joint venture		20,160		20,303		21,150		24,089		26,300		3,788
Intangible assets		973		17,000		16,491		16,423		16,644		2,397
Available-for-sale financial assets		7,051		6,798		5,337		—		—		—
Equity investments⁽¹⁾		—		—		—		3,771		4,266		615
Total assets		456,070		621,473		662,859		664,362		637,681		91,845
Current loans and borrowings		28,830		49,841		31,180		33,585		19,678		2,834
Current liabilities		82,437		128,948		103,498		84,380		67,090		9,663
Long term loans and borrowings		29,056		82,011		105,383		131,060		130,798		18,839
Total non-current liabilities		63,853		150,905		179,751		193,941		188,220		27,109
Total liabilities		146,290		279,853		283,249		278,321		255,310		36,772
Capital stock		43,078		43,081		43,081		43,081		43,081		6,205
Shareholders’ equity		309,780		341,620		379,610		386,041		382,371		55,073

________________

(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 2012 to 2016 have been computed, without considering the dilutive effect of the shares underlying our share option schemes by dividing profit by the weighted average number of shares and the weighted average number of ADSs of 44,646,305,984 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, 44,647,455,984 and 446,474,560, respectively, for 2015, and 44,647,455,984 and 446,474,560, respectively, for 2016, 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 2012 to 2016 have been computed, after considering the dilutive effect of the shares underlying our share option schemes by using 44,808,042,330 shares and 448,080,423 ADSs for 2012, 44,787,119,089 shares and 447,871,191 ADSs for 2013, 44,734,774,504 shares and 447,347,745 ADSs for 2014, 44,684,819,053 shares and 446,848,191 ADSs for 2015, and 44,659,140,488 shares and 446,591,405 ADSs for 2016.

	Year ended December 31,
	2012			2013			2014			2015			2016			2016
	Rmb			Rmb			Rmb			Rmb			Rmb			US$
	(in millions, except percentages and ratios)
Other Financial Data:
Capital expenditures paid⁽¹⁾		54,331			79,716			95,673			67,674			51,347			7,396
Cash provided by/(used for):
Operating activities		92,574			110,891			110,508			80,095			72,863			10,494
Investing activities		(63,797	)		(170,032	)		(90,177	)		(76,495	)		(27,953	)		(4,026	)
Financing activities		2,584			18,601			(19,486	)		(6,893	)		(43,240	)		(6,228	)
Gearing ratio⁽²⁾		15.7	%		27.8	%		26.5	%		29.9	%		28.2	%		28.2	%

________________

(1)

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

(2)

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

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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)
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
2016		6.9430		6.6549		6.9580		6.4480
October 2016		6.7735		—		6.7819		6.6685
November 2016		6.8837		—		6.9195		6.7534
December 2016		6.9430		—		6.9580		6.8771
January 2017		6.8768		—		6.9575		6.8360
February 2017		6.8665		—		6.8821		6.8517
March 2017		6.8832		—		6.9132		6.8687

_______________

(1)

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

On March 31, 2017, 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 6.8832 to US$1.00.

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

	Noon Buying Rate
Period	End		Average⁽¹⁾		High		Low
	(HK$ per US$1.00)
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
2016		7.7534		7.7618		7.8270		7.7505
October 2016		7.7549		—		7.7600		7.7536
November 2016		7.7566		—		7.7581		7.7546
December 2016		7.7534		—		7.7674		7.7534
January 2017		7.7579		—		7.7580		7.7540
February 2017		7.7627		—		7.7627		7.7575
March 2017		7.7714		—		7.7714		7.7611

______________

(1)

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

On March 31, 2017, 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$7.7714 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.

	Noon Buying Rate
Period	End		Average⁽¹⁾		High		Low
	(Cdn$ per US$1.00)
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
2016		1.3426		1.3229		1.4592		1.2544
October 2016		1.3403		—		1.3403		1.3105
November 2016		1.3425		—		1.3581		1.3335
December 2016		1.3426		—		1.3555		1.3119
January 2017		1.3030		—		1.3437		1.3030
February 2017		1.3247		—		1.3247		1.3003
March 2017		1.3321		—		1.3504		1.3278

______________

(1)

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

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On March 31, 2017, 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$1.3321 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 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

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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 taxation planning and transfer pricing activities, which may cause risks to the Company on global transfer pricing activities. Global changes to tax laws may result in additional or double taxation being imposed on the Company in some circumstances.

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 assumption.

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 the Company’s products.

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

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

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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. 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 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 2016, China Oilfield Services

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Limited (COSL), one of our non-controlled affiliates, provided certain drilling and other related services in Iran and another non-controlled affiliate of ours was engaged in submarine cable installation and trenching services in Iran. We cannot predict at this time whether U.S. sanctions will be imposed on any of our affiliates.

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

Our exploration and development activities involve inherent risks, including the risk of not discovering commercially productive oil or gas reservoirs and that the wells we drill may not be able to commence production or may not be sufficiently productive to generate a return of our partial or full investments. In addition, approximately 51.2% of our proved reserves were undeveloped as of December 31, 2016. 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 connected party transactions with CNOOC and its affiliates.

Currently, CNOOC indirectly owns or controls 64.44% of our shares. As a result, CNOOC is able to control our board composition, or our Board, determine the time and amount in dividend payments, and

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

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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

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administration and development of PRC offshore petroleum operations with foreign oil and gas companies.

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

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

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

CNOOC has undertaken to us that:

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

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

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

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

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

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

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

The undertakings from CNOOC will cease to have any effect:

if we become a wholly owned subsidiary of CNOOC;

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

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

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

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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 2016, we had net proved reserves of approximately 3.9 billion BOE (including approximately 0.3 billion BOE in our equity method investees). In 2016, we had a total net oil and gas production of 1,302,922 BOE per day (including net oil and gas production of approximately 49,280 BOE per day in our equity method investees).

Competitive Strengths

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

large and diversified asset base with significant exploitation opportunities;

sizable operating areas in offshore China with demonstrated exploration potential;

successful independent exploration and development track record;

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

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

Large and diversified asset base with significant exploitation opportunities

We have a large net proved reserve base spread across offshore China and globally. As of December 31, 2016, we had approximately 3.9 billion BOE of net proved reserves. Our core operating area, offshore China, contributed to approximately 62.5% of our net proved reserves, while overseas contributed to the balance of 37.5%.

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

As of December 31, 2016, approximately 51.2% 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, 2016, our total major exploration areas acreage in offshore China was approximately 257,000 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 2016, we and our foreign partners have together drilled a total of 116 exploratory wells in offshore China, of which 53 were wildcat wells. During the same year, we and our foreign partners made 12 new discoveries in offshore China.

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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 2016, in offshore China, approximately 84.4% of our net proved reserves were independent and approximately 75.3% of our production came from independent projects.

In 2016, in offshore China, our independent exploration resulted in 12 new discoveries. We also successfully appraised 18 oil and gas structures. On the development front, our major new development projects progressed smoothly with four new projects on stream in offshore China.

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

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

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

Experienced management team and a high level of corporate governance standard

Our senior management team has extensive experience in the oil and gas industry. Most of our executives have been with CNOOC, our controlling shareholder, since its inception in 1982. Many of our management team and staff members have worked closely with international partners both within and outside China through numerous joint operations.

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 “2016 Corporate Governance awards – Platinum” and “2016 Corporate Awards - Best Initiatives in Environmental Responsibility” by The Asset magazine and the “Asia’s Best CSR (China)” and “Best Investor Relations Company (China)” by Corporate Governance Asia magazine.

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.

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We increase our production primarily through the development of proved undeveloped reserves. As of December 31, 2016, approximately 51.2% 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.

In 2016, we continued our efforts to lower costs and enhance efficiency through innovation in technology and management. Operating expenses per BOE decreased for the third consecutive year. Under low oil price environment, we attached more importance to cash flow management and maintained a healthy financial position.

Selected Operating and Reserves Data

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

Our reserve data for 2014, 2015 and 2016 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,
	2014			2015			2016
Net Production⁽²⁾:
Oil (daily average bbls/day)		955,647			1,124,047			1,083,101
Gas (daily average mmcf/day)		1,330.1			1,363.6			1,276.2
Oil equivalent (BOE/day)		1,184,977			1,358,022			1,302,922

Net Proved Reserves (end of period):
Oil (mmbbls)		2,258.5			2,015.0			2,015.4
Gas (bcf)		6,730.8			6,992.9			7,486.1
Synthetic Oil (mmbbls)		749.9			815.3			300.5
Bitumen (mmbbls)		31.4			0.0			0.0
Total (million BOE)		4,185.0			4,016.0			3,583.4
Total with equity method investees (million BOE)⁽²⁾		4,478.0			4,315.5			3,877.6
Annual reserve replacement ratio⁽¹⁾		111	%		65	%		6	%
Annual reserve replacement ratio⁽²⁾		112	%		67	%		8	%
Estimated reserve life (years)		10.1			8.4			7.8
Estimated reserve life (years)⁽²⁾		10.4			8.7			8.1
Standardized measure of discounted future net cash flow (million Rmb)		401,098			185,251			223,625

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(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

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“Item 4—Information on the Company—Business Overview—Exploration, Development and Production.”

Summary of Oil and Gas Reserves

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

	Net proved reserves at December 31,				Net proved reserves at December 31, 2016
	2014		2015		Crude Oil		Natural Gas		Synthetic Oil		Total
	(mmboe)		(mmboe)		(mmbbls)		(bcf)		(mmbbls)		(mmboe)
Developed
Offshore China
Bohai		583.7		603.1		564.2		219.9		—		600.8
Western South China Sea		173.5		169.0		84.8		478.0		—		165.5
Eastern South China Sea		279.8		299.9		157.8		764.4		—		285.2
East China Sea		20.5		30.9		8.1		160.5		—		34.9
Subtotal		1,057.5		1,102.9		814.9		1,622.8		—		1,086.4
Overseas
Asia (excluding China)		90.9		118.8		51.3		618.0		—		160.3
Oceania		80.0		63.3		9.7		267.5		—		62.1
Africa		47.1		52.7		40.7		0.0		—		40.7
North America (excluding Canada)		121.4		112.6		87.7		218.8		—		124.1
Canada		258.2		216.6		0.0		0.0		155.7		155.7
South America		1.8		1.6		1.5		0.0		—		1.5
Europe		124.6		95.8		80.5		6.9		—		81.7
Subtotal		724.1		661.4		271.3		1,111.2		155.7		626.1
Total Developed		1,781.6		1,764.3		1,086.2		2,733.9		155.7		1,712.5

Undeveloped
Offshore China
Bohai		608.1		368.7		339.6		58.8		—		349.4
Western South China Sea		425.2		503.6		83.5		3418.8		—		653.3
Eastern South China Sea		243.7		215.7		205.3		90.5		—		220.3
East China Sea		152.2		133.4		2.5		652.8		—		111.3
Subtotal		1,429.2		1,221.5		630.8		4,220.9		—		1,334.3
Overseas
Asia (excluding China)		108.5		90.1		26.0		334.4		—		84.7
Oceania		25.9		27.5		2.4		66.0		—		15.3
Africa		95.5		113.9		97.3		0.0		—		97.3
North America (excluding Canada)		154.5		172.1		172.6		130.8		—		194.4
Canada		562.0		618.6		0.0		0.0		144.8		144.8
Europe		27.9		8.0		0.1		0.0		—		0.1
Subtotal		974.2		1,030.3		298.4		531.2		144.8		536.6
Total Undeveloped		2,403.4		2,251.7		929.2		4,752.1		144.8		1,870.9

TOTAL PROVED		4,185.0		4,016.0		2,015.4		7,486.1		300.5		3,583.4
Equity method investees		293.0		299.5		195.3		574.0		—		294.2
Total with equity method investees		4,478.0		4,315.5		2,210.7		8,060.1		300.5		3,877.6

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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, 2016
	2014		2015		Developed			Undeveloped			Total
Offshore China
Bohai		1,111.7		908.3		564.2			339.6			903.8
Western South China Sea		210.0		149.3		84.8			83.5			168.3
Eastern South China Sea		351.9		357.0		157.8			205.3			363.1
East China Sea		18.0		16.1		8.1			2.5			10.6
Subtotal		1,691.6		1,430.6		814.9			630.8			1,445.7
Overseas
Asia (excluding China)		47.4		59.8		51.3			26.0			77.3
Oceania		16.6		14.5		9.7			2.4			12.0
Africa		142.5		166.6		40.7			97.3			138.0
North America (excluding Canada)		209.3		239.5		87.7			172.6			260.3
Canada		781.4		815.3		155.7	⁽¹⁾		144.8	⁽²⁾		300.5
South America		1.8		1.6		1.5			0.0			1.5
Europe		149.1		102.3		80.5			0.1			80.6
Subtotal		1,348.2		1,399.6		427.0			443.2			870.2
Total		3,039.8		2,830.2		1,241.9			1,074.0			2,315.9
Equity method entities		200.4		200.1		102.6			92.7			195.3
Total with equity method investees		3,240.1		3,030.3		1,344.6			1,166.6			2,511.2

_________________

(1)

Including Synthetic oil 155.7 mmbbls.

(2)

Including Synthetic oil 144.8 mmbbls.

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Total Net Proved Natural Gas Reserves
(bcf)

	As of December 31,				As of December 31, 2016
	2014		2015		Developed		Undeveloped		Total
Offshore China
Bohai		480.8		381.4		219.9		58.8		278.7
Western South China Sea		2,318.1		3,132.6		478.0		3,418.8		3,896.8
Eastern South China Sea		1,029.6		951.6		764.4		90.5		854.9
East China Sea		928.3		889.0		160.5		652.8		813.3
Subtotal		4,756.8		5,354.6		1,622.8		4,220.9		5,843.7
Overseas
Asia (excluding China)		861.2		845.8		618.0		334.4		952.4
Oceania		455.7		389.2		267.5		66.0		333.5
Africa		—		—		—		—		—
North America (excluding Canada)		403.9		275.2		218.8		130.8		349.6
Canada		233.0		119.3		—		—		—
South America		—		—		—		—		—
Europe		20.2		8.8		6.9		—		6.9
Subtotal		1,974.0		1,638.3		1,111.2		531.2		1,642.4
Total		6,730.8		6,992.9		2,733.9		4,752.1		7,486.1
Equity method investees		537.3		576.9		437.7		136.3		574.0
Total with equity method investees		7,268.1		7,569.8		3,171.6		4,888.5		8,060.1

Total Net Proved Reserves
(million BOE)

	As of December 31,				As of December 31, 2016
	2014		2015		Developed		Undeveloped		Total
Offshore China
Bohai		1,191.8		971.8		600.8		349.4		950.2
Western South China Sea		598.7		672.6		165.5		653.3		818.8
Eastern South China Sea		523.5		515.6		285.2		220.3		505.5
East China Sea		172.7		164.2		34.9		111.3		146.2
Subtotal		2,486.8		2,324.3		1,086.4		1,334.3		2,420.7
Overseas
Asia (excluding China)		199.4		208.9		160.3		84.7		245.0
Oceania		106.0		90.8		62.1		15.3		77.4
Africa		142.5		166.6		40.7		97.3		138.0
North America (excluding Canada)		275.9		284.8		124.1		194.4		318.6
Canada		820.2		835.2		155.7		144.8		300.5
South America		1.8		1.6		1.5		0.0		1.5
Europe		152.5		103.8		81.7		0.1		81.8
Subtotal		1,698.3		1,691.7		626.1		536.6		1,162.7
Total		4,185.0		4,016.0		1,712.5		1,870.9		3,583.4
Equity method investees		293.0		299.5		178.0		116.2		294.2
Total with equity method investees		4,478.0		4,315.5		1,890.6		1,987.1		3,877.6

Proved Reserves

As of December 31, 2016, we had proved reserves of 3,877.6 million BOE, including 2,210.7 million barrels of crude oil, 300.5 million barrels of synthetic oil and 8,060.1 bcf of natural gas, representing a decrease of 437.9 million BOE as compared to proved reserves of 4,315.5 million BOE as of December 31, 2015.

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The changes in our proved reserves mainly include:

l An increase of 383.8 million BOE due to new discoveries and extensions, of which 26.8 million BOE are developed and 357.1 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 316.7 million BOE, which are primarily attributable to fields such as Luda16-3, Caofeidian12-6, Lingshui25-1, Lingshui18-1 and Lufeng15-1 etc.; and

☐ Overseas: the discoveries and extensions of oil and gas reserves in the amount of 67.2 million BOE, which are primarily attributable to onshore fields in the United States.

l A decrease of 345.8 million BOE due to revision of previous estimates;

l The production of 476.9 million BOE in 2016.

Proved Undeveloped Reserves (PUD)

As of December 31, 2016, we had proved undeveloped reserves of 1,987.1 million BOE, including 1,021.9 million barrels of crude oil, 144.8 million barrels of synthetic oil and 4,888.5 bcf of natural gas, representing an decrease of 387.2 million BOE as compared to proved undeveloped reserves of 2,374.3 million BOE as of December 31, 2015.

The changes in our proved undeveloped reserves mainly include:

l A decrease of 222.8 million BOE due to PUD converted to Proved Developed reserves (PD);

l A decrease of 521.9 million BOE due to revision of previous estimates;

l An increase of 357.1 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 298.8 million BOE, which are primarily attributable to fields such as Luda16-3, Caofeidian12-6, Lingshui25-1, Lingshui18-1 and Lufen15-1 etc.; and

☐ Overseas: the discoveries and extensions of oil and gas reserves in the amount of 58.3 million BOE which are primarily attributable to onshore fields in the United States.

In 2016, we had in total 222.8 million BOE PUD reserves converted to PD, or the PUD conversion rate was 9%.

In 2016, we spent approximately Rmb 1.68billion on developing proved undeveloped reserves into proved developed reserves. Rmb 1.53 billion, or 91%, were spent on major development projects in Bohai, Eastern South China Sea, Western South China Sea and Eastern South China Sea in offshore China and Indonesia, Iraq, Nigeria, the United Kingdom and the U.S., etc. The remaining 9% was spent mainly on the infill drilling programs in offshore China and Nigeria.

As of December 31, 2016, 38.8 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) 6.5 million BOE in Bohai, including Qinghuangdao 33-1S oil field which is scheduled to come on stream in 2019; and (iii) 24.6 million BOE in Western South China 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

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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 2014, 2015 and 2016, approximately 52%, 62% and 60 % 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 2016, we engaged Ryder Scott Company, L.P., Gaffney, Cline & Associates (Consultants) Pte Ltd. and RPS as independent third party consulting firms to perform annual estimates for our net proved oil and gas reserves under our consolidated subsidiaries. For each independent third party consulting firm, a report of third party letter has been prepared which summarizes the work undertaken, the assumptions, data, methods and procedures they used and provides their reserves estimate. These reports have been included as appendices to this document. 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. and McDaniel & Associates Consultants Ltd. to perform annual audits for over 21% 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

select our reserve estimators and auditors.

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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 2016, approximately 62.5% 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 2016, approximately 84.4% of the Company’s net proved reserves and approximately 75.3% 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.

After years of hard work, we have established our presence in more than 20 countries and regions. Our overseas assets account for over 50% of the Company’s total assets. With its diversified portfolio of high-quality assets, the Company actively participates in numerous world-class oil and gas projects, becoming one of the world’s leading industry players. 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. As of the end of 2016, approximately 37.5% of the Company’s net proved reserves and approximately 34.8% of its net production were derived from overseas.

In 2016, the recovery of the global economy remained slow and uneven with divergent economic trends in major economies. International oil prices stayed at low level. The entire oil and gas industry and the Company still faced severe market situation and difficult business environment.

In 2016, the Company persisted with operating strategies formulated at the beginning of the year, which includes, maintaining prudent financial policy; continuing to lower costs and increase efficiency through innovation in technology and management; ensuring operation safety and compliance; focusing on return by balancing short-term benefit and long-term development. The Company further intensified the “Year of Quality and Efficiency” program, implemented various measures to improve quality and efficiency and established mechanism with long-lasting effect; and maintained the momentum of healthy and sustainable development.

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In 2016, the Company accomplished its production and business targets in spite of all difficulties. The Company managed to maintain appropriate exploration expenditures and carry out intensive exploration program, and achieved successful results while continuing to control total capital expenditure. Four new projects planned in early 2016 all came on stream. The production target was met with a total volume of 476.9 million BOE. To ensure sustainable development in the future, the Company steadily pushed ahead the construction of new projects with a total of approximately 20 projects under construction in the year. All in cost per BOE was US$34.67, representing a decline for the third consecutive year. The Company has maintained a healthy financial position with a net profit of Rmb 637 million for the year. Meanwhile, health, safety and environmental protection performance remained stable.

Looking forward to 2017, the global economy will continue to recover slowly and international oil prices are expected to stay at a relatively low level despite of a certain rebound. 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, which include: balancing short-term and mid- to-long term development; maintaining prudent financial policy and improving capital efficiency; and optimizing asset portfolio and focusing more on the returns of assets.

In 2017, the capital expenditure of the Company is anticipated to be Rmb 60-70 billion. To maintain its competitive financial position, the Company will continue to stress on efficiency, enhance investment return, strengthen cost controls and focus on cash flow management. Our production target for 2017 is 450-460 million BOE with five new projects to come on stream. Meanwhile, the Company will maintain its high standards in health, safety and environmental protection.

Exploration

In 2016, the Company strengthened the integration of exploration and development. We have prioritized the exploration of offshore China and struck a balance between mature areas, rolling areas and frontier areas. Overseas, we focused on high-quality blocks and conventional oil and gas. The Company strengthened value-driven exploration philosophy and mainly focused on searching for mid-to-large-sized oil and gas fields while reducing the proportion of high risk and high cost wells. In addition, the Company continued to maintain a reasonable proportion of exploration investment so as to ensure long-term sustainable development with a relatively high level of exploration activities. Due to the significant decrease in international oil prices, the reserve replacement ratio for the Company is 8% for 2016. Excluding economic revision, the reserve replacement ratio for the Company is 145%.

In offshore China, the exploration activities of the Company remained at a high level and a total of 115 exploration wells were drilled. In addition, the Company completed 17 unconventional wells onshore China. A total of 2,471 kilometers of 2D Seismic Data was acquired independently; a total of 11,347 square kilometers of 3D Seismic Data was acquired independently and through PSC. The Company made 12 new discoveries and successfully appraised 19 oil and gas structures in offshore China. The success rate of independent exploration wells in offshore China is 52-69%.

In 2016, the Company continued to implement a proactive exploration strategy in offshore China, resulting in successful achievements including the followings:

Firstly, we effectively completed the appraisal of four mid-to-large sized oilfields including Kenli 16-1, Caofeidian 12-6/6-2, Penglai 20-2/20-3 and Liuhua 21-2.

Secondly, progress was made in the deepwater natural gas exploration of Qiongdongnan Basin, with the structure of Lingshui 25-1 successfully appraised which expanded the reserve scale of the structure.

Thirdly, integration of exploration and development was realized using existing facilities and additional reserves were obtained at Jinzhou 25-1, Caofeidian 6-4, Weixinan oilfields, Wenchang 13-6, Panyu 4-1 and Xijiang 30-1.

Such achievements have further consolidated the position of offshore China as the core area of

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the Company and demonstrated the Company’s unique strength in offshore China.

Overseas, the Company drilled 14 exploration wells, acquired approximately 9,613 kilometers of 2D seismic data and approximately 23,980 square kilometers of 3D seismic data. For overseas exploration, the Company made two new discoveries and successfully appraised six oil and gas structures. Main achievements include the followings:

Firstly, five appraisal wells were successfully drilled with the Libra project in Brazil which further confirmed the reserve scale.

Secondly, Liza oilfield in Guyana was successfully appraised, which expanded to new layers and escalated reserve size; success was again made in the wildcat of the Payara structure.

Thirdly, successful in the exploration of the Owowo West structure in Nigeria which proved to be a large scale oil and gas reservoir and increased the economic value of the block.

In 2016, the Company adhered to its philosophies of “exploration management” overseas and continued to optimize exploration portfolio. While acquiring new exploration opportunities, the Company also successfully farmed out the interests in some overseas blocks, resulting in better returns for the Company.

During the year, the Company made continual improvement in optimizing exploration, reducing operating costs and enhancing efficiency through management; and strengthened geological research, raised operation standards and refined operation process management, which further improved operation efficiency and lowered exploration cost.

The Company’s major exploration activities in 2016 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	16	40	0	1	7	0	30	0	0	0	966	0

Eastern South China Sea	16	8	0	1	4	0	3	1	0	0	3,720	1,639

Western South China Sea	14	13	3	0	1	0	7	0	2,471	0	4,374	0

East China Sea	3	0	0	0	0	0	0	0	0	0	647	0

Subtotal	49	61	3	2	12	0	40	1	2,471	0	9,708	1,639

Overseas	0	0	2	12	0	2	0	7	0	9,613	0	23,980

Total	49	61	5	14	12	2	40	8	2,471	9,613	9,708	25,619

In 2017, the Company will continue to reinforce the integration of exploration and development, increase the ability and shorten the cycle of reserve monetization. For offshore China, it will further prioritize investment in mature areas while continuing to explore new areas. For overseas exploration, with its foothold on existing core projects, the Company will seek rolling development. It will continue to maintain a reasonable proportion of exploration investment in its total capital expenditure so as to ensure mid-and long-term sustainable development with a relatively high level of exploration activities.

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Engineering Construction, Development and Production

In 2016, the Company successfully completed its operation targets and the target of oil and gas production set early this year. The Company carefully organized its operational resources and made smooth progress in engineering construction.

In 2016, while ensuring safety in the development, production and operation, the Company took efficiency enhancement and cost reduction as the core mission and accomplished its development and production target for the year. The Company’s net oil and gas production reached 476.9 million BOE, which completed the production target of 470-485 million BOE set in the beginning of the year. The four new projects planned for 2016, including Kenli 10-4 oilfield, Panyu 11-5 oilfield, Weizhou 6-9/6-10 comprehensive adjustment and Enping 18-1 oilfield, all came on stream during the year.

In 2016, the Company’s development and production were driven by innovation and led by effectiveness, with emphasis on quality, performance and sustaining development. The achievements include the followings:

Firstly, we continued to maintain high production efficiency through refined management.

Secondly, we continuously conducted special programs to lower operating expenses and achieved significant result with operating expenses at US$7.29 per BOE, which decreased for three consecutive years.

Thirdly, we made in-depth optimization in the technological plan of development projects, achieving remarkable result in cost reduction and efficiency enhancement.

Fourthly, we lowered the failure rate of equipment and facilities by comprehensively implementing integrity management.

Looking forward to 2017, the workload of onshore construction and offshore installation will increase. A total of five new projects are expected to commence production, including Penglai 19-9 comprehensive adjustment, Enping 23-1 oilfields and Weizhou 12-2 oilfield Phase II in offshore China and BD gas field and Hangingstone project overseas. Among them, Penglai 19-9 comprehensive adjustment and Enping 23-1 oilfields have commenced production in January 2017. In addition, it is expected that over 20 new projects will be under construction in 2017, supporting the Company’s sustainable growth in the future.

In 2017, the Company’s development and production are expected to face a harsh external environment due to continued pressure from international oil prices. We will optimize development plans, strengthen integration, effectively connect engineering construction with development and production, while steadily pushing ahead development of key overseas areas. We will select and appraise infill drilling, closely monitor the trend of oil prices and maintain the flexibility on infill drilling.

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 2016, the reserve and daily production volume in Bohai were 950.2 million BOE and 477,380 BOE/day, respectively, representing approximately 24.5% and 36.6% 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 2016, the Company made seven successful discoveries in Bohai, namely

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Luda 29-1, Jinzhou 25-1 West, Caofeidian 12-6, Caofeidian 6-2, Bozhong 34-8, Penglai 20-2 and Qinhuangdao 31-4. In addition, the Company successfully appraised 10 oil and gas structures, including Caofeidian 12-6, Kenli 16-1, Penglai 7-6, Luda 21-2, Caofeidian 6-2, Penglai 31-3 South, Penglai 20-2, Bozhong 29-1, Caofeidian 6-4 and Penglai 20-3. Among which, Kenli 16-1, Caofeidian 12-6/6-2 and Penglai 20-2/20-3 structures were proved to be mid-to-large sized oilfields after appraisals. The Company fully implemented the integration of exploration and development and obtained new reserves around Jinzhou 25-1 and Caofeidian 6-4 oilfields.

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

For development and production, Kenli 10-4 oilfield commenced production during the year. Penglai 19-9 comprehensive adjustment commenced production in January 2017. Currently, there are a number of new projects under construction including Penglai 19-3 oilfield 1/3/8/9 comprehensive adjustment, Penglai 19-9 oilfield Phase II comprehensive adjustment and Bozhong 34-9 oilfield.

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 2016, the reserves and daily production volume in Western South China Sea reached 818.8 million BOE and 144,835 BOE/day, respectively, representing approximately 21.1% and 11.1% of the Company’s total reserves and daily production, respectively.

In 2016, the Company made one new independent discovery in Western South China Sea, namely Weizhou 6-13 North. Six independent successful appraisals were made, namely Weizhou 6-8, Weizhou 12-2, Weizhou 6-13 North, Wushi 17-5, Lingshui 25-1 and Wenchang 13-6. Among which, the successfully appraisal of Lingshui 25-1 represents progress made in the deepwater natural gas exploration of Qiongdongnan Basin. In addition, a PSC project, Panyu 10-4, was successfully appraised.

For development and production, Weizhou 6-9/6-10 comprehensive adjustment commenced production during the year. Weizhou 12-2 oilfield Phase II is planned to commenced production in 2017. Currently, new projects including Wenchang 9-2/9-3/10-3 gas fields, Weizhou 6-13 oilfield and Dongfang 13-2 gas field are under construction.

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 2016, the reserves and daily production volume in Eastern South China Sea reached 505.5 million BOE and 213,835 BOE/day, respectively, representing approximately 13.0% and 16.4% of the Company’s total reserves and daily production, respectively.

In 2016, the Company made four new independent discoveries in Eastern South China Sea, namely Huizhou 21-1 South, Panyu 4-1, Huizhou 19-10 and Xijiang 30-1, improving the overall efficiency of exploration and development in the region. Among which, Panyu 4-1 and Xijiang 30-1 are new reserves obtained through integrated exploration and development at the surrounding areas of the existing facilities. In addition, two successful appraisals of oil and gas structures were made, namely Liuhua 21-2 and Xijiang 30-1.

For development and production, Panyu 11-5 oilfield and Enping 18-1 oilfield commenced production during the year. Enping 23-1 oilfields commenced production in January 2017. Currently, Huizhou 33-1 oilfield and other new projects are under construction.

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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 2016, the reserves and daily production volume in East China Sea represented approximately 3.8 % and 1.1% of the Company’s total reserves and daily production, respectively.

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 2016, the reserves and daily production volume derived from Asia (excluding China) reached 245.0 million BOE and 75,780 BOE/day, respectively, representing approximately 6.3% and 5.8% of the Company’s total reserves and daily production, respectively.

Indonesia

As of the end of 2016, 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 which the BD gas field is planned to commence production in 2017. 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 2016, production volume of phase I of the Project remained stable. Currently, the investment decision for the third LNG train of phase II is completed, and the project is now in the construction stage and is expected to be completed and commence production in 2020.

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 2016, the Company continuously drilled development wells, increased workload, implementing water injection plan and reinforced management of operation and maintenance under the Iraq project, resulting in a steady increase of daily net production to approximately 33,000 barrels per day.

Oceania

Currently, the Company’s oil and gas assets in Oceania are mainly located in Australia and Papua New Guinea. As of the end of 2016, the reserves and daily production volume derived from Oceania reached 77.4 million BOE and 26,107 BOE/day, respectively, representing approximately 2.0% and 2.0% 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 2016, 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.

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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 2016, the reserves and daily production volume derived from Africa reached 138.0 million BOE and 80,297 BOE/day, respectively, representing approximately 3.6% 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 2016, the Akpo oilfield maintained stable production. Through infill drillings and optimization measures, its net production reached approximately 62,000 barrels per day, with record low operating cost per barrel. The Egina project is in the engineering construction stage and is currently drilling development wells and constructing production facilities such as FPSO.

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 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. In 2016, the new discovery was made in the exploration of Owowo West structure in deepwater Nigeria.

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.

In 2016, the Company, as the operator of EA 3A, made further optimization and research on the developing plan of the Kingfisher oilfield with cost reduction and efficiency enhancement as the core mission.

In 2016, government’s development and production licenses were obtained for eight oilfields in the EA1 and EA2 blocks. In 2016, the route plan of oil pipeline in Uganda was confirmed, laying the foundation for accelerated development of the oilfields.

Other Regions in Africa

Apart from Nigeria and Uganda, the Company also owns interests in several blocks in the Republic of The Congo, Algeria and the Gabonese Republic. In 2016, after drilling and appraisal, the REZ structure in Algeria was proven to be one of the major discoveries of the region in recent years.

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 2016, the Company’s reserves and daily production volume derived from North America reached 619.1 million BOE and 117,738 BOE/day, respectively, representing approximately 16.0% and 9.0% of the Company’s total

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reserves and daily production, respectively.

The U.S.

The Company currently holds 27% and 13% interest in two shale oil and gas projects in the U.S., namely the Eagle Ford and Niobrara shale oil and gas projects respectively.

In 2016, as the number of wells drilled decreased under the low oil price environment, the net production of the Eagle Ford project decreased and averaged approximately 53,000 BOE/day. Under the current low oil price environment, our operators have slowed down asset development, which would impact our near-term production.

In addition, the Company owns interest in two major deepwater 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”).

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 2016, the Company continued the development of the Long Lake project. Its net production averaged approximately 21,000 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.

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 was completed with production commenced in the second half of 2016. In addition, the Company owns 100% exploration interest in the deepwater exploration blocks 1 and 4 of the Perdido Fold Belt in Mexico.

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 2016, the Company’s reserves and daily production volume derived from South America reached 293.9 million BOE and 48,548 BOE/day, respectively, representing approximately 7.6% 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.

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In 2016, under the low oil price environment, the Company sought balance between production and returns, enhanced operating efficiency, optimized operating plans and innovated development plans. The daily net production of Bridas averaged approximately 48,000 BOE/day. The downstream refinery maintains a high level of operation capacity and is implementing quality improvement project according to clean energy requirements of the government.

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 2016, the Company drilled five appraisal wells in the Libra northwestern block which further increased the reserve.

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 driver for production growth.

Other Regions in South America

The Company also holds interests in several exploration and production blocks in Colombia and interests in Stabroek exploration block offshore Guyana.

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 2016, the Company’s reserves and daily production volume derived from Europe reached 81.8 million BOE and 104,473 BOE/day, respectively, representing approximately 2.1% and 8.0% of the Company’s total reserves and daily production, respectively.

United Kingdom

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 oilfields 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 2016, the net production of Buzzard oilfield averaged approximately 66,000 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 with potential 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. In 2016, the project is at exploration and appraisal stage and has preliminary completed the processing and interpretation of newly acquired 2D seismic data.

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 2014, 2015 and 2016.

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	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)
2016
Offshore China
Bohai		477,380		455,002		134.3		—		—		—
Western South China Sea		144,835		98,351		273.9		—		—		—
Eastern South China Sea		213,835		182,848		185.9		—		—		—
East China Sea		12,273		3,177		54.6		—		—		—
Subtotal		848,322		739,378		648.7		42.88		6,663		6.36
Overseas
Asia (excluding China)		75,780		48,577		150.2		33.17		6,243		11.45
Oceania		26,107		4,278		111.4		40.97		3,176		7.57
Africa		80,297		80,297		—		42.90		—		5.72
North America (excluding Canada)		69,290		48,078		127.3		34.81		2,390		4.63
Canada		48,448		40,304		48.9		28.24		1,345		24.24
South America		926		926		—		32.48		—		8.14
Europe		104,473		98,672		34.8		41.78		4,061		6.83
Subtotal		405,320		321,131		472.5		38.00		3,815		9.23
Total		1,253,643		1,060,509		1,121.2		41.40		5,463		7.29
Equity method investees		49,280		22,592		155.0		—		—		—

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

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Bohai	426,913	403,927	137.9	—	—	—
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	—	—	—

Drilling and Other Exploratory and Development Activities

The following table sets forth our net exploratory wells and development wells drilled in the years of 2014, 2015 and 2016.

	Net Exploratory Wells Drilled			Net Development Wells Drilled
	Total	Productive	Dry	Total	Productive	Dry
2016
Offshore China
Independent
Bohai	56	41	15	87.0	87.0	—
Western South China Sea	27	9	18	24.0	24.0	—
Eastern South China Sea	24	7	17	22.0	22.0	—
East China Sea	4	1	3	—	—	—
Subtotal	111	58	53	133.0	133.0	—
PSCs
Bohai	1	—	1	1.5	1.5	—
Western South China Sea	3	—	3	—	—	—
Eastern South China Sea	1	1	—	—	—	—
East China Sea	—	—	—	6.5	6.5	—
Subtotal	5	1	4	8.0	8.0	—
Overseas
Asia (excluding China)	—	—	—	10.5	10.5	—
Oceania	—	—	—	—	—	—
Africa	0.9	0.9	—	4.0	4.0	—
North America	0.3	—	0.3	55.66	55.66	—
South America	1.3	0.9	0.4	0.25	0.25	—
Europe	0.4	—	0.4	2.19	2.19	—
Subtotal	2.9	1.8	1.0	72.6	72.6	—

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

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Present Activities

The following tables set forth our present activities as of December 31, 2016.

	Wells Being Drilled				Waterfloods Being Installed
	Gross		Net		Gross		Net
Offshore China
Bohai		3.0		2.51		683		619.1
Western South China Sea		3.0		3.0		21		21
Eastern South China Sea		14.0		14.0		—		—
East China Sea		1.0		0.5		—		—
Subtotal		21.0		20.01		704		640.1
Overseas
Asia (excluding China)		2.0		1.7		1		1
Oceania		—		—		—		—
Africa		1.0		0.45		7		3.2
North America		36.0		12.33		—		—
South America		2.0		0.35		28		5.7
Europe		—		—		1		0.4
Subtotal		41.0		14.83		37		10.3

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, 2016.

	Productive Wells								Developed Acreage (km²)				Undeveloped Acreage (km²)
	Crude and Liquids				Natural Gas
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Offshore China
Bohai		2,108		1,730.1		27		27		2,636		2,636		43,068		43,068
Western South China Sea		308		287.4		81		76.5		1,941		1,941		73,388		73,388
Eastern South China Sea		421		376.7		39		22.1		2,643		2,643		55,424		55,424
East China Sea		21		8.2		69		31.8		85		85		85,413		85,413
Subtotal		2,858		2,402.2		216		157.4		7,305		7,305		257,293		257,293
Overseas
Asia (excluding China)		552		510.9		38		23.2		1,762		1,216		14,334		5,670
Africa		45		14.8		—		—		888		354		18,897		4,668
Oceania		—		—		53		2.8		3,240		172		41,766		25,140
North America		2,750		791.6		406		144		1,061		225		4,609		3,710
South America		4,604		909.1		429		86		5,604		1,121		29,799		7,505
Europe		70		30.8		1		0.4		89		38		18,568		12,979
Subtotal		8,021		2,257.1		927		256.1		12,643		3,125		127,973		59,672
Total		10,879		4,659.3		1,143		413.5		19,948		10,430		385,266		316,965

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 2016, the annual sales from our largest gas contract contributed to only approximately 3% of our total oil

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and gas sales and the total revenues from gas sales accounted for approximately 10.2 % of our total revenues in 2016. 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 2016.

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. Beginning in 2017, the benchmark price for crude oil sold in China is changed to Brent. 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.

In 2016, affected by the sustaining low international oil prices, the Company’s realized oil prices declined significantly. In 2016, the Company’s average realized oil price was US$41.40/barrel, representing a decline of 19.3% 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.

	Year ended December 31,
		2014		2015		2016
Sales and Marketing Volumes (mmbbls)⁽¹⁾	Benchmark Prices
Light Crude	PLATTS Tapis⁽²⁾		10.6		22.9		20.8
Medium Crude	Daqing OSP⁽³⁾		130.4		162.4		162.6
Heavy Crude	ICP Duri⁽⁴⁾		125.2		138.2		122.4

_____________________

⁽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.

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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 2016, the Company’s average realized natural gas price was US$5.46/mcf, representing a 14.6% decrease year over year, primarily due to the Chinese government’s onshore natural gas price reform in 2015, resulting in two decreases of overall prices in the onshore natural gas market in China. The Company gradually adjusted the sale prices for its major natural gas users through negotiation.

In China, the current oversupply of natural gas adversely affects the development, operation and income of the Company’s natural gas business. In view of the current natural gas market competition, the Company will coordinate the designs and approvals of relevant projects and the gas price negotiations with downstream users, with the aim of promoting the development of oil and gas fields under construction. Meanwhile, to cope with the current weak demand in specific regions, the Company will coordinate the price negotiations with downstream users to ensure the stable gas sales of producing oil and gas fields.

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

	Year ended December 31,
	2014		2015		2016
Average Realized Prices
Crude and Liquids (US$/bbl)		96.04		51.27		41.40
Natural Gas (US$/mcf)		6.44		6.39		5.46

West Texas Intermediate (US$/bbl)		93.03		48.68		43.35

The international benchmark crude oil price, West Texas Intermediate, was US$53.72 per barrel as of December 31, 2016 and US$50.56 per barrel as of March 31, 2017.

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

	Year ended December 31,
	2014			2015			2016
	(Rmb in millions, except percentages)
Revenues sourced in the PRC		178,822			124,427			102,861
Revenues sourced outside the PRC		95,812			47,010			43,629
Total revenues		274,634			171,437			146,490
% of revenues sourced outside the PRC		34.9	%		27.4	%		29.8	%

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.

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Research and Development

In 2016, the Company continued to implement its “technology-driven” strategy. It released and implemented the “Thirteenth Five-year” research and development plan and completed the top-level design of the “Thirteenth Five-year” key technology projects and top-level design for the establishment of research platform; continued to implement system for research coordination and strengthened the joint project development and mastering of core technology of different institutes. The Company actively initiated the “Quality and Efficiency Year 3.0” program. Through technological innovations, the Company was able to establish a solid foundation for reserve and production growth as well as cost control and efficiency enhancement. A series of research findings have been applied to increase production efficiency.

Major Scientific Project Development

In 2016, the Company focused on core business needs and undertook national oil and gas major projects and national key research and development programs. It continued to conduct core technological projects such as deep water oil and gas fields, offshore heavy oil fields and fields with low porosity and permeability. The “Geology theory and technology innovation on continental margin area in the north of South China Sea deep water and its important hydrocarbon discovery” was awarded National Scientific and Technological Progress Award (Second Class), while significant landmark achievements such as Differential Hydrocarbon Enrichment Mechanism of Active Fault Belts and the major Discovery of High Quality Oil Field Groups with Hundred Million Tons Reserves in Bohai, exploration technology and practice for large gas field in deep water area of Western South China Sea, Key Technology on infilling and optimization of clustering well pattern in offshore SZ36-1 oil fields, and key technology and application in enhanced oil recovery technology for offshore heavy oilfield by polymer flooding, which will provide technological support for the sustainable development of the Company.

Innovative Development of Key Technologies

Remarkable result was achieved in using key vector processing technologies for multi-component seismic data, with trial processing of the seismic data from two target areas of over 200 square kilometers in Bohai and Weixinan completed. Time-lapse Seismic Interpretation Technology was successfully applied in processing new data of the Xijiang 24-1 oil producing region. Operating efficiency was enhanced by key technological achievements such as intelligent zonal water injection technology on offshore oilfield and cuttings-carrying technology in highly deviated well drilling.

Health, Safety and Environmental Protection (“HSE”)

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

In 2016, the Company continued to improve HSE management, adhered to systematic management, completely upgraded the HSE internal control system and converted management documents covering overseas projects HSE and public health events and accidents into internal control system. In 2016, the Company strengthened safety supervising measures, implemented management and control of offshore production facilities according to the level of risks, established complete risk monitoring and control indicators including monitoring and control of major operating risks of well control and engineering construction, which effectively prevented major incidents. The Company also strengthened base-level frontline safety management, promoted the establishment of job responsibility list, improved the site patrol and inspection system and enhanced the protection ability in respect of safety production on site.

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For offshore China, in 2016, the Company coordinated annual audit inspection to promote HSE management, organized and conducted HSE system review and special review of high risk contractors such as diving contractors and helicopter contractors. Special production safety inspections were also carried out and self-inspection was organized utilizing information system for units under the Company according to “Six Provisions on Work Safety Announcement” and the implementation of remedial measures was supervised.

In 2016, the Company comprehensively enhanced the risk prevention ability of systems by improving emergency response management mechanism, integrating emergency response management information systems, improving ICS system establishment and comprehensively strengthening emergency response training and exercises to minimize the impact of emergencies. Early warning and emergency handling were properly made all the times. There were 13 typhoons affecting the normal production during the year, and the Company successfully avoided personal injury and death by initiating typhoon emergency plan.

In 2016, the Company paid more attention to the safety management of base-level units and held an essay writing activity of “Safety Management at the Base-level.” We summed up and refined the safety management experience of base-level units, and publicized and promoted effective safety management measures.

In 2016, the Company intensified the coordinated management of energy saving and emission reduction, released “Development Plan of Energy Saving and Emission Reduction for the Next Five Year,” made a thorough survey on energy saving and emission reduction in units under the Company, developed carbon emission monitoring and verification techniques and endeavoured to reduce emission of greenhouse gases. The consolidated energy consumption was 2,710,300 tons of standard coal, consolidated energy consumption for unit oil and gas produced was 0.0470 ton standard coal/ton, and energy saving of 162,200 tons of standard coal was achieved for the year.

Overseas, the Company organized and conducted a HSE review of the Nexen headquarters in Calgary and Long Lake oil sands facilities in Canada and a safety review on the facilities and equipment evaluation of the Indonesian SES oilfield delayed project and pushed further ahead the establishment and improvement of HSE management plans for overseas projects of units under the Company.

Operating Hazards and Uninsured Risks

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

The Company further strengthened safety in production, intensifying its efforts to identify and eliminate potential risks, giving special attention to preventing operational accidents in key and high-risk areas. It also improved the implementation of safety standards and deepened safety awareness across all levels of the organization. In 2016, the Company completed full system safety inspections, including the special supervision of safety production, a special safety check on storage tank fields and a year-end major check on safety production. For HSE risks in particular operating units, the Company organized special examinations. Through examinations and inspections, the Company effectively met CNOOC Limited’s management requirements, urged affiliated units to act in accordance with the law, and promoted the continuous improvement of HSE management. In 2016, 539 inspection teams were organized to conduct safety inspections in 1,027 working units, during which 10,498 hazards were discovered and eliminated.

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

Based on hazard identification and risk analysis, the Company continued to improve its emergency management mechanisms. In 2016, the Company further refined the crisis management plan, integrated emergency management information systems, developed a mobile application for emergency management, improved the ICS system, and strengthened emergency drills to improve the system’s risk resistance and reduce the effect of emergencies to the greatest extent possible.

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

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

As of December 31, 2016, 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.”

We have maintained varied insurance policies for our domestic assets and operational insurance policies and construction insurance policies, with different policy limits and deductibles. We also purchase operator’s extra-expense up to US$100 million and third-party liabilities insurance up to US$200 million for our working interests. As for deep-water wells, we are 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 overseas operation and asstes, we are insured for amounts up to the replacement cost value of our assets for property damage and up to US$400 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$485 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$750 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

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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.

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.

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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,
	2014				2015				2016
	Rmb in millions		%		Rmb in millions		%		Rmb in millions		%
Exploration and production		223,741		81.5		149,582		87.3		125,611		85.7
Trading businesses		50,263		18.3		21,438		12.5		20,310		13.9
Corporate and elimination		630		0.2		417		0.2		569		0.4
Total operating revenues		274,634		100.0		171,437		100.0		146,490		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, 2016, approximately 70.2% 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 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.

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

Fiscal Regimes for Independent Operations

Taxation

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

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

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

Our PRC subsidiary, CNOOC China Limited, as a wholly foreign-owned enterprise, is subject to an enterprise income tax rate of 25% under the prevailing tax rules and regulations. CNOOC Deepwater Development Limited is subject to corporate income tax at the rate of 15% for the three years ending December 31, 2017, after being assessed as a high new technology enterprise.

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

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

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

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

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

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

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

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

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

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

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

We calculate our deferred tax to account for the 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, 2014, 2015 and 2016, we had Rmb (14,312) million, Rmb 1,948 million and Rmb 19,174 million (US$2,761 million) respectively, in net deferred tax assets/(liabilities). See note 11 to our consolidated financial statements included elsewhere in this annual report.

Royalty

Royalties paid to the PRC government are based on our gross production from both independent operations and oil and gas fields under PSCs. The amount of the royalties varies up to 12.5% based on the annual production of the relevant property. The PRC government has provided us, among other companies, with a royalty exemption in each field for up to one million tons, or approximately seven million BOE, per year for our crude oil production and for up to 2 billion cubic meters (approximately 70.6 billion cubic feet or 11.8 million BOE) per year for our natural gas production. The limits in these exemptions apply to our total production from both independent properties and properties under PSCs.

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

Special Oil Gain Levy

In March 2006, the PRC government imposed a special oil gain levy at progressive rates from 20% to 40% on any income derived from sales of locally produced crude oil by an oil exploration and production company at a price that exceeds US$40 per barrel. In December 2011, the PRC government increased the threshold of the special oil gain levy from US$40 per barrel to US$55 per barrel, with effect from November 1, 2011. In December 2014, the PRC government has decided to increase the threshold of the special oil gain levy from US$55 per barrel to US$65 per barrel, with effect from January 1, 2015. The special oil gain levy is collected on a quarterly basis. For the years ended December 31, 2014, 2015 and 2016 we incurred approximately Rmb 19,072 million, Rmb 59 million and nil for the Special Oil Gain Levy.

As international oil prices, the exchange rate of Renminbi and our crude oil production fluctuate, we cannot ascertain the full impact of the Special Oil Gain Levy going forward.

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%

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75-80 (Include 80)	30%
80-85 (Include 85)	35%
Above 85	40%

Fiscal Regimes for PSC Operations

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

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

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

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

Bidding Process

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

Terms of PSCs

Term of Length. PSCs typically last for 30 years: (1) the exploration period is generally divided into three phases, with three years, two years and two years, respectively. During the exploration period, exploratory and appraisal work is conducted in order to discover petroleum and to enable the parties to determine the commercial viability of any petroleum discovery; (2) the development period begins when the relevant PRC regulatory authorities have approved the overall development program and ends when the design, construction, installation, drilling and related research work for the realization of petroleum production as planned have been completed; and (3) the production period begins when commercial production commences and usually lasts for 15 years for oil and 20 years for natural gas.

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

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

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

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

62.5%	For the payment of resource tax and recovery:
	1. Resource tax⁽²⁾ payable to the PRC government
	2. Cost recovery oil allocated according to the following priority: (1) recovery of current year operating costs by us and foreign partner(s); (2) recovery of current year abandonment costs accrued by us and foreign partner(s) ; (3) recovery of earlier exploration costs by foreign partner(s) or us (if any); and (4) recovery of development costs and deemed interest by us and foreign partner(s) based on participating interests. 3. Any excess after the payment of resource tax and recovery of costs mentioned above allocated to the remainder oil.

32.5%⁽³⁾	Remainder oil allocated according to the following formula: 1. (1-X) multiplied by 32.5% represents share oil payable to the PRC government; and 2. X multiplied by 32.5% represents remainder oil distributed according to each partner’s participating interest.

____________

(1)

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

(2)

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

(3)

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

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

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

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

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After the foreign partner has fully recovered its exploration and development costs under PSCs in which the foreign partner is the operator, we have the right to take over the operation of the particular oil or gas field. With the consent of the foreign partner, we may also take over the operation before the foreign partner has fully recovered its exploration and development costs.

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

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

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

Regulatory Framework Overseas

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

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

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

In Australia, the U.S., Canada, United Kingdom, Argentina and certain other countries, we conduct our operations through exploration and production permits, licenses or leases. We, as one of the title owners under these permits, licenses or leases, are required to bear all exploration, development and operating costs together with other co-owners. Once production occurs, a certain percentage of the annual production or revenue will first be distributed to the landowner, in most of cases in the form of royalty, severance tax and other payments, and the rest of the annual production or revenue will be allocated among the co-owners. Exploration, development and operating costs are deductible for the purpose of income tax calculation in accordance with local tax regulations.

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

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Taxation

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

Our subsidiaries domiciled outside of the PRC are subject to income tax rates ranging from 10% to 50%.

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 Marine Environment Protection Law of PRC was amended and came into effect on November 7, 2016. Such amended Marine Environment Protection Law strengthens the marine environment protection regulation system including but not limited to the regional restricted approval system of environmental impact assessment, provides marine ecological protection compensation system. We therefore face more stringent environmental supervision and law enforcement environment.

Government agencies set national or local environmental protection standards. The relevant State Oceanic Administration and/or environmental protection 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, 2014, 2015 and 2016 of approximately Rmb 52,889 million, Rmb 50,063 million and Rmb 50,888 million (US$7,329 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.

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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, 2014, 2015 and 2016, we employed 21,046 persons, 20,585 persons and 19,718 persons, respectively. Of the 19,718 employees we employed as of December 31, 2016, approximately 74.9 % were involved in oil exploration, development and production activities, approximately 3.4 % 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 30 to our consolidated financial statements included elsewhere in this annual report.

As an oil and gas exploration and production company operating in highly competitive markets, we depend in large part on our employees for effective and efficient operations. We devote significant resources to train our employees. During 2016, we held 64 core training workshops, which were attended by approximately 3,654 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.

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Organizational Structure

CNOOC indirectly owned or controlled an aggregate of approximately 64.44% of our shares as of March 31, 2017. 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, 2017 and notes our significant indirectly-held subsidiaries.

_______________

(1)

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

(2)

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

(3)

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

(4)

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

(5)

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

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.

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ITEM 4A. unresolved staff comments

None.

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.

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

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

	Year ended December 31,
	2014		2015		2016
Average net realized prices:
Crude oil (US$ per bbl)		96.04		51.27		41.40
Natural gas (US$ per mcf)		6.44		6.39		5.46

Production and Sales Volumes

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

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

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

	Year ended December 31,
	2014		2015		2016
Net production of crude oil (bbl/day)⁽¹⁾		955,647		1,124,047		1,083,101
Net production of natural gas (mmcf/day)⁽¹⁾		1,330.1		1,363.6		1,276.2

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(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

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commercial reserves, we transfer acquisition costs to proved properties and capitalize the costs of drilling and equipping successful exploratory wells, all development expenditure on construction, installation or completion of infrastructure facilities such as platforms, pipelines, processing plants and the drilling of development wells, and the building of enhanced recovery facilities, including those renewals and betterments that extend the economic lives of the assets, and the related borrowing costs.

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

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

Reserves Estimation

Oil and gas properties are depreciated on a unit-of-production basis at a rate calculated by reference to proved reserves. Commercial reserves are determined using estimates of oil in place, recovery factors and future oil prices, the latter having an impact on the proportion of the gross reserves which are attributable to the host government under the terms of the production sharing contracts. The level of estimated commercial reserves is also a key determinant in assessing whether the carrying value of any of the Company’s oil and gas properties has been impaired.

Pursuant to the oil and gas reserve estimation requirements under US SEC rules, the Company uses the average, first-day-of-the-month oil price during the 12-month period before the ending date of the period covered by the consolidated financial statements to estimate its proved oil and gas reserves.

Impairment of Non-Financial Assets other than Goodwill

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

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

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

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

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

Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method. The consideration transferred is measured at acquisition date fair value which is the sum of the acquisition date fair values of assets transferred by the Company, liabilities assumed by the Company to the former owners of the acquiree and the equity interests issued by the Company in exchange for control of the acquiree. For each business combination, the Company elects whether it measures the non-controlling interests in the acquiree either at fair value or at the proportionate share of the acquiree’s identifiable net assets. All other components of non-controlling interests are measured at fair value. Acquisition costs incurred are 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.

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.

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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.

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.

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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.

Results of Operations

Overview

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

	Year ended December 31,
	2014				2015				2016
	(Rmb in millions, except percentages and production data )
Revenues:
Oil and gas sales:
Crude oil		200,991	73.2	%		128,929	75.2	%		106,448	72.7	%
Natural gas		17,219	6.3	%		17,668	10.3	%		14,877	10.1	%
Total oil and gas sales		218,210	79.5	%		146,597	85.5	%		121,325	82.8	%

Marketing revenues		50,263	18.3	%		21,422	12.5	%		20,310	13.9	%
Other income		6,161	2.2	%		3,418	2.0	%		4,855	3.3	%
Total revenues		274,634	100	%		171,437	100	%		146,490	100	%

Net production (million BOE)⁽¹⁾:
Crude oil		348.8	80.6	%		410.3	82.8	%		396.4	83.1	%
Natural gas		83.7	19.4	%		85.4	17.2	%		80.5	16.9	%
Total net production		432.5	100	%		495.7	100	%		476.9	100	%

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(1)

Including our interest in equity method investees.

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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,
	2014			2015			2016
Operating Revenues:
Oil and gas sales		79.5	%		85.5	%		82.8	%
Marketing revenues		18.3	%		12.5	%		13.9	%
Other income		2.2	%		2.0	%		3.3	%
Total revenues		100.0	%		100.0	%		100.0	%
Expenses:
Operating expenses		(11.4	)%		(16.5	)%		(15.8	)%
Taxes other than income tax		(4.3	)%		(6.3	)%		(4.7	)%
Exploration expenses		(4.2	)%		(5.8	)%		(5.0	)%
Depreciation, depletion and amortization		(21.2	)%		(42.8	)%		(47.0	)%
Special oil gain levy		(6.9	)%		0.0	%		0.0	%
Impairment and provision		(1.5	)%		(1.6	)%		(8.3	)%
Crude oil and product purchases		(17.4	)%		(11.6	)%		(13.0	)%
Selling and administrative expenses		(2.4	)%		(3.3	)%		(4.4	)%
Others		(1.2	)%		(1.8	)%		(3.3	)%
Total expenses		(70.5	)%		(89.8	)%		(101.6	)%

Interest income		0.4	%		0.5	%		0.6	%
Finance costs		(1.7	)%		(3.6	)%		(4.3	)%
Exchange gain, net		0.4	%		(0.1	)%		(0.5	)%
Investment income		1.0	%		1.4	%		1.9	%
Share of profits of associates		0.1	%		0.1	%		(0.4	)%
Share of profits/(losses) of a joint venture		0.3	%		1.0	%		0.4	%
Non-operating income/(expenses), net		0.2	%		0.4	%		0.4	%
Profit before tax		30.0	%		10.0	%		(3.6	)%
Income tax expense		(8.1	)%		1.8	%		4.0	%
Profit for the year		21.9	%		11.8	%		0.4	%

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.

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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.

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.

2016 versus 2015

Consolidated net profit

Our consolidated net profit decreased 96.9% to Rmb 637 million (US$91.7 million) in 2016 from Rmb 20,246 million in 2015, primarily as a result of the decrease in profitability under the low international oil price environment and impairment charge.

Revenues

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

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	2016		2015		Change			Change (%)

Oil and gas sales (Rmb million)		121,325		146,597		(25,272	)		(17.2	)%
Crude and liquids		106,448		128,929		(22,481	)		(17.4	)%
Natural gas		14,877		17,668		(2,791	)		(15.8	)%
Sales volume (million BOE)*		458.3		480.1		(21.8	)		(4.5	)%
Crude and liquids (million barrels)		387.6		404.0		(16.4	)		(4.1	)%
Natural gas (bcf)		410		444		(34	)		(7.5	)%
Realized prices
Crude and liquids (US$/barrel)		41.40		51.27		(9.87	)		(19.3	)%
Natural gas (US$/mcf)		5.46		6.39		(0.93	)		(14.6	)%
Net production (million BOE)		476.9		495.7		(18.8	)		(3.8	)%
China		311.1		323.4		(12.3	)		(3.8	)%
Overseas		165.8		172.3		(6.5	)		(3.8	)%
* Excluding our interest in equity-accounted investees.

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

Operating expenses

Our operating expenses decreased 18.2% to Rmb 23,211 million (US$3,343.1 million) in 2016 from Rmb 28,372 million in 2015, attributable from effective cost control. The operating expenses per BOE decreased 14.9% to Rmb 50.6 (US$7.29) per BOE in 2016 from 59.4 (US$9.18) per BOE in 2015. Operating expenses per BOE offshore China decreased 10.9% to Rmb 44.1 (US$6.36) per BOE in 2016 from Rmb 49.5 (US$7.64) per BOE in 2015. Overseas operating expenses per BOE decreased 20.1% to Rmb 64.1 (US$9.23) per BOE in 2016 from Rmb 80.2 (US$12.38) per BOE in 2015.

Taxes other than income tax

Our taxes other than income tax decreased 35.6% to Rmb 6,941 million (US$999.7 million) in 2016 from Rmb 10,770 million in 2015. The decrease was mainly due to the decrease in oil and gas revenue. In addition, the transfer from 5% production tax to regular VAT in independent oil and gas fields in China brought further decrease.

Exploration expenses

Our exploration expenses decreased 25.7% to Rmb 7,359 million (US$1,059.9 million) in 2016 from Rmb 9,900 million in 2015, due to the dry hole expense decreased significantly compared to 2015 under strengthening intensify of exploration appraisal during the year and reducing the proportion of high risk and high cost wells. Meanwhile, the seismic expense decreased as compared to 2015 under the circumstance of increasing workload of 3D seismic data collection, resulting from continued strengthening of geological research and improvement in the operation standards.

Depreciation, depletion and amortization

Our depreciation, depletion and amortization decreased 6.2% to Rmb 68,907 million (US$9,924.7million) in 2016 from Rmb 73,439 million in 2015, resulting from the decrease of production volume. Our average depreciation, depletion and amortization per BOE, excluding the dismantlement-related depreciation, depletion and amortization, increased 0.2% to Rmb 146.8 (US$21.14) per BOE in 2016 from Rmb 146.4 (US$22.61) per BOE in 2015.

The dismantlement-related depreciation, depletion and amortization costs decreased 55.7 % to Rmb 1,569 million (US$226.0 million) in 2016 from Rmb 3,545 million in 2015. Our average

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dismantling costs per BOE decreased 54.0% to Rmb 3.42 (US$0.49) per BOE in 2016 from Rmb 7.43 (US$1.15) per BOE in 2015, primarily due to the fact that the expected dismantlement costs in independent oil and gas fields no longer included the relevant taxes after the replacement of business tax with VAT in China.

Impairment, provision and write off

Our impairment and provision increased 343.2% to Rmb 12,171 million (US$1,753.0 million) in 2016 from Rmb 2,746 million in 2015. In 2016, certain oil and gas properties located in North America, Europe and Africa were impaired, which was reflected by the revision of the estimation for the oil price forecast and the adjustment in operating plan for oil sand assets in Canada. Meanwhile, the Company wrote off certain oil and gas assets in North America due to the expired lease contracts. Approximately Rmb 823 million was included in the exploration expenses, and Rmb 605 million was included in the depreciation, depletion and amortization charge, respectively. Please refer to Note 14 to the Consolidated Financial Statement of this annual report. In addition, the Company had an approximately Rmb 1,403 million bad debt provision, which was classified as impairment and provision due to risk associated with the collection of Nigeria trade receivable. Please refer to Note 7 to the Consolidated Financial Statement of this annual report.

Selling and administrative expenses

Our selling and administrative expenses increased 13.8 % to Rmb 6,493 million (US$935.2million) in 2016 from Rmb 5,705 million in 2015 due to the increasing of transportation costs in North America resulting from technology improvement of some production facilities. Our selling and administrative expenses per BOE increased 18.4% to Rmb 14.15 (US$2.04) per BOE in 2016 from 11.95 (US$1.85) per BOE in 2015.

Exchange losses, net

Our net exchange losses increased 452.4% to Rmb 790 million (US$113.8 million) in 2016 from Rmb 143 million in 2015, primarily as a result of the increase in exchange losses as a result of Rmb, GBP and CAD fluctuation against the US dollars.

Investment income

Our investment income increased 15.7% to Rmb 2,774 million (US$399.5 million) in 2016 from Rmb 2,398 million in 2015, primarily attributable to the increase in return on corporate wealth management products and money market funds held by the Company.

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

Our share of losses of associates and a joint venture changed 104.0% to Rmb 76 million (US$10.9 million) in 2016, while in 2015 we shared profits of Rmb 1,903 million, primarily attributable to losses from sales of shares of Northern Cross (Yukon) Limited located in Canada and decreases in profitability of some associates and a joint venture due to continuous decline in oil price.

Income tax credit

Our income tax credit increased 89.7% to Rmb 5,912 million (US$851.5 million) in 2016 from Rmb 3,116 million in 2015, mainly because of an increase in deferred tax credit recognized on temporary differences and tax losses in overseas and a decrease in income tax expense due to decreased profit in China. In addition the UK government reduced the combined income tax rate on North Sea oil and gas activities from 50% to 40% and resulted in a one-time reversal of net deferred tax liability.

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2015 versus 2014

Consolidated net profit

Our consolidated net profit decreased 66.4% to Rmb 20,246 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 realized 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 in 2015 from Rmb 31,180 million in 2014, and the operating expenses per BOE decreased 20.9% to Rmb 59.4 per BOE in 2015 from Rmb 75.1 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 per BOE in 2015 from Rmb 60.4 per BOE in 2014. Overseas operating expenses per BOE decreased 21.4% to Rmb 80.2 per BOE in 2015 from Rmb 102.1 per BOE in 2014.

Taxes other than income tax

Our taxes other than income tax decreased 9.1% to Rmb 10,770 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 in 2015 from Rmb 11,525 million in 2014, among which dry hole expense decreased 16.7% to Rmb 4,740 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 in 2015

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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 per BOE in 2015 from Rmb 130.9 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 in 2015 from Rmb 3,951 million in 2014. Our average dismantling costs per BOE decreased 22.0% to Rmb 7.43 per BOE in 2015 from Rmb 9.52 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 in 2015 from Rmb 19,072 million in 2014, primarily as a result of our decreased realized 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 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

Our selling and administrative expenses decreased 13.7% to Rmb 5,705 million in 2015 from Rmb 6,613 million in 2014. Our selling and administrative expenses per BOE decreased 24.9% to Rmb 11.95 per BOE in 2015 from Rmb 15.93 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 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 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

Our net exchange losses changed 113.6% to Rmb 143 million in 2015, compared with exchange gains Rmb 1,049 million in 2014, primarily as a result of the increase in exchange loss as a result of Rmb, GBP and CAD fluctuation against the US dollars.

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Investment income

Our investment income decreased 10.7% to Rmb 2,398 million in 2015 from Rmb 2,684 million in 2014, primarily attributable to the decline in market rate of return on investment which was caused by the continuously decline interest rates promulgated by the People’s Bank of China.

Share of profits of associates/a joint venture

Our share of profits of associates/a joint venture increased 89.2% to Rmb 1,903 million in 2015 from Rmb 1,006 million in 2014, primarily attributable to the increase in profitability of joint venture resulting from local finance and tax benefit.

Income tax expense

Our income tax credit changed 114.0% to Rmb 3,116 million in 2015, compared with income tax expense of Rmb 22,314 million in 2014, mainly because the UK government decreased the combined income tax rate on North Sea oil and gas activities from 62% to 50% and resulted in a one-time reversal of net deferred tax liability. In addition, the lower profitability of overseas operations due to decreased oil prices resulted in a further decline in income tax expense. The effective tax rate changed to 18.2% in 2015 from 27.0% in 2014.

Liquidity and Capital Resources

Our primary source of cash during 2016 was cash flows from operating activities. We used cash primarily to fund capital expenditure and dividends. The following table summarizes our cash flows for the periods presented:

	Year ended December 31,
	2014			2015			2016
	(Rmb in millions)
Cash generated from (used for):
Operating activities		110,508			80,095			72,863
Investing activities		(90,177	)		(76,495	)		(27,953	)
Financing activities		(19,486	)		(6,893	)		(43,240	)
Net increase/(decrease) in cash and cash equivalents		845			(3,293	)		1,670

Cash Generated from operating activities

The cash inflow from operating activities decreased 9.0% to Rmb 72,863 million (US$10,494.5 million) in 2016 from Rmb 80,095 million in 2015, primarily attributable to the decrease in oil and gas sales cash inflows caused by the decline in international oil price.

Cash Used in Investing Activities

In 2016, our capital expenditure (excluding acquisition) decreased 24.1% to Rmb 51,347 million (US$7,395.5 million) from 2015, because the Company reduced its capital expenditure on the basis of improving quality and efficiency in response to the challenges of low oil prices. Our development expenditures in 2016 were primarily related to the capital expenditure of offshore China, block in offshore Nigeria, deep-water Gulf of Mexico and Iraq technical service contract project, as well as the expenses incurred for improving recovery factors of the oilfields in production. The Company had no significant acquisition during the year.

In addition, our cash used in investing activities was also attributable to the purchase of other financial assets of Rmb 62,900 million (US$9,059.5 million) this year. Our cash generated from investing activities was mainly from the proceeds from the sales of other financial assets in the amount of Rmb 81,675 million (US$11,763.6 million), and the decrease in our time deposits with maturity over three months in the amount of Rmb 1,180 million (US$170.0 million).

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Cash Used in Financing Activities

In 2016, the increase in net cash outflow from financing activities was mainly due to the repayment of bank borrowings of Rmb 23,412 million (US$3,372.0 million) and Rmb 4,866 million (US$700.8 million) from the repayment of guaranteed notes and the cash outflow of the distribution of dividends of Rmb 14,153 million (US$2,038.5 million), partially offset by the proceeds from bank loans of Rmb 4,293 million (US$618.3 million).

At the end of 2016, our total interest-bearing outstanding debt was Rmb 150,476 million (US$21,673.1 million), compared to Rmb164,645 million at the end of 2015. The decrease in debt in 2016 was primarily attributable to repayment of bank loans and guaranteed notes. Our gearing ratio, which is defined as interest-bearing debts divided by the sum of interest-bearing debts plus equity, was 28.2%, lower than that of 29.9% in 2015. The main reason for the decrease was the decreased scale of interest-bearing debts.

We have debt service obligations consisting of principal and interest payments on our outstanding indebtedness. The following table summarizes the maturities of our long-term debt (including the current portion) outstanding as of December 31, 2016.

	Debt maturities (principal only)
	Original currency			Total Rmb equivalents			Total US$ equivalents
Due by December 31,	US$
	(in millions, except percentages)
2017		1,342.1			9,318.2			1,342.1
2018-2019		1,113.9			7,733.6			1,113.9
2020-2021		3,043.7			21,132.7			3,043.7
2022 and beyond		13,823.2			95,974.3			13,823.2
Total		19,322.9			134,158.8			19,322.9
Percentage of total debt		92.8	%		92.8	%		92.8	%

As of December 31, 2016, we had total foreign currency debt of US$20,830 million, all of which is in U.S. dollars. As of March 31, 2017, we had total foreign currency debt of US$21,192 million, all of which is in U.S. dollars.

As of December 31, 2016, we had unutilized ba