20-F 1 dp89178_20f.htm FORM 20-F

UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION

 

Washington, D.C. 20549

 

 

 

FORM 20-F

 

(Mark One)

 

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

 

OR

 

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

 

OR

 

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

 

OR

 

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

 

Date of event requiring this shell company report ________________

 

Commission File Number 1-14966

 

CNOOC LIMITED

(Exact name of Registrant as specified in its charter)

 

N/A

(Translation of Registrant’s name into English)

 

 

Hong Kong

(Jurisdiction of incorporation or organization)

 

 

65th Floor, Bank of China Tower

One Garden Road, Central 

Hong Kong 

(Address of principal executive offices)

 

 

Jiewen Li

65th Floor, Bank of China Tower

One Garden Road, Central

Hong Kong

Tel +852 2213 2500

Fax +852 2525 9322

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

 

 

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

 

Title of each class Name of each exchange on which registered

American depositary shares, each representing 100 shares

Shares

 

New York Stock Exchange, Inc.

New York Stock Exchange, Inc.(1)

 

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

(Title of Class)

 

 

 

 

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

(Title of Class)

  

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

 

Shares 44,647,455,984

 

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

 

Yes ý     No ¨

 

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

 

Yes ¨     No ý

 

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

 

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

 

Yes ý     No ¨

 

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

 

Yes ¨     No ý

 

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

 

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

Emerging growth company ¨

 

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

 

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

 

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

 

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

 

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

 

Item 17 ¨     Item 18 ¨

 

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

 

Yes ¨     No ý 

 

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

 

 

 

Table of Contents

 

Page

 

TERMS AND CONVENTIONS 5
SPECIAL NOTE ON THE FINANCIAL INFORMATION AND CERTAIN STATISTICAL INFORMATION PRESENTED IN THIS ANNUAL REPORT 10
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS 11
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE 11
ITEM 3. KEY INFORMATION 11
A.   Selected Financial Data 11
B.   Capitalization and Indebtedness 14
C.   Reasons for the Offer and Use of Proceeds 14
D.   Risk Factors 14
ITEM 4. INFORMATION ON THE COMPANY 18
A.   History and Development 18
B.   Business Overview 20
C.   Organizational Structure 53
D.   Property, Plants and Equipment 54
ITEM 4A. unresolved staff comments 54
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS 54
A.  Operating Results 54
B.   Liquidity and Capital Resources 66
C.   Research and Development, Patents and Licenses, etc. 69
D.   Trend Information 69
E.   Off-Balance Sheet Arrangements 70
F.   Tabular Disclosure of Contractual Obligations 70
G.   Safe Harbor 70
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES 71
A.   Directors and Senior Management 71
B.   Compensation 79
C.   Board Practice 80
D.   Employees 82
E.   Share Ownership 82
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS 83
A.   Major Shareholders 83
B.   Related Party Transactions 84
C.   Interests of Experts and Counsel 88
ITEM 8. FINANCIAL INFORMATION 88
A.   Consolidated Statements and Other Financial Information 88
B.   Significant Changes 90
ITEM 9. THE OFFER AND LISTING 90
ITEM 10. ADDITIONAL INFORMATION 91
A.   Share Capital 91
B.   Memorandum and Articles of Association 91
C.   Material Contracts 94
D.   Exchange Controls 94
E.   Taxation 94
F.   Dividends and Paying Agents 99
G.   Statement by Experts 99
H.   Documents on Display 99
I.   Subsidiary Information 99
ITEM 11. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK 99
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES 100
A.   Debt Securities 100
B.   Warrants and Rights 100
C.   Other Securities 100
D.   American Depositary Shares 100
PART II 102
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES 102

 

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

 

4 

TERMS AND CONVENTIONS

  

Definitions

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

·“TSX” are to the Toronto Stock Exchange; and

 

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

 

Conventions

 

We publish our financial statements in Renminbi. Unless otherwise indicated, we have translated amounts from Renminbi into U.S. dollars solely for the convenience of the reader at the noon buying rate for cable transfers

 

5 

 

of Renminbi per U.S. dollar certified for customs purposes by the Federal Reserve Bank of New York, as set forth in the H.10 weekly statistical release of the Federal Reserve Board on December 29, 2017 of US$1.00=Rmb 6.5063. We have translated amounts in Hong Kong dollars solely for the convenience of the reader at the noon buying rate for cable transfers of Hong Kong dollars per U.S. dollar certified for customs purposes by the Federal Reserve Bank of New York, as set forth in the H.10 weekly statistical release of the Federal Reserve Board on December 31, 2017 of US$1.00=HK$ 7.8128. We have also translated amounts in Canadian dollars solely for the convenience of the reader at the noon buying rate for cable transfers of Canadian dollars per U.S. dollar certified for customs purposes by the Federal Reserve Bank of New York, as set forth in the H.10 weekly statistical release of the Federal Reserve Board on December 31, 2017 of US$1.00=Cdn$1.2517. We make no representation that the Renminbi amounts, Hong Kong dollar amounts or Canadian dollar amounts could have been, or could be, converted into U.S. dollars at those rates on December 31, 2017, or at all. For further information on exchange rates, see “Item 3—Key Information—Selected Financial Data.”

 

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

 

For the years 2015, 2016 and 2017, approximately 62%, 60% and 65% respectively, of our reserves were evaluated by our internal reserve evaluation staff, and the remaining were based upon estimates prepared by independent petroleum engineering consulting companies and reviewed by us. Our reserve data for 2015, 2016 and 2017 were prepared in accordance with the SEC’s final rules on “Modernization of Oil and Gas Reporting”, which became effective for accounting periods ended on or after December 31, 2009. Except as otherwise stated, all amounts of reserve and production in this report include our interests in equity method investees.

 

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

 

Glossary of Technical Terms

 

Unless otherwise indicated in the context, references to:

 

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

 

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

 

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

 

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

 

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

 

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

 

·“LNG” means liquefied natural gas.

 

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

 

·“proved oil and gas reserves” means those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating

 

6 

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

 

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

 

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geosciences, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

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

 

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

 

·“undeveloped oil and gas reserves” means reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 

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(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

 

For further definitions relating to reserves:

 

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

 

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

 

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

 

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

 

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

 

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

 

References to:

 

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

 

·mmbbls means million barrels;

 

·BOE means barrels-of-oil equivalent;

 

·mcf means thousand cubic feet;

 

·mmcf means million cubic feet;

 

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

 

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

 

 

8 


FORWARD-LOOKING STATEMENTS

 

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

 

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

 

·the amount and nature of future exploration, development and other capital expenditures,
  
·wells to be drilled or reworked,
  
·development projects,
  
·exploration prospects,
  
·estimates of proved oil and gas reserves,
  
·development and drilling potential,
  
·expansion and other development trends of the oil and gas industry,
  
·business strategy,
  
·production of oil and gas,
  
·development of undeveloped reserves,
  
·expansion and growth of our business and operations,
  
·oil and gas prices and demand,
  
·future earnings and cash flow, and
  
·our estimated financial information.

 

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

 

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

 

9 

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

 

Our consolidated financial statements for the years ended December 31, 2015, 2016 and 2017 included in this annual report on Form 20-F have been prepared in accordance with International Financial Reporting Standards, or IFRSs, as issued by the International Accounting Standards Board.

 

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

 

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

 

 

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PART I

 

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

 

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

 

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

 

Not applicable.

 

ITEM 3. KEY INFORMATION

 

A.Selected Financial Data

 

The following tables present selected historical financial data of our company as of and for the years ended December 31, 2013, 2014, 2015, 2016 and 2017. Except for amounts presented in U.S. dollars, the selected historical consolidated statement of financial position data and consolidated statement of profit or loss and other comprehensive income data as of and for the years ended December 31, 2013, 2014, 2015, 2016 and 2017 set forth below are derived from, should be read in conjunction with, and are qualified in their entirety by reference to, our consolidated financial statements and their notes under “Item 18—Financial Statements” and “Item 5—Operating and Financial Review and Prospects” in this annual report. As disclosed above under “Special Note on the Financial Information and Certain Statistical Information Presented in This Annual Report”, our consolidated financial statements as of and for the years ended December 31, 2013, 2014, 2015, 2016 and 2017 have been prepared and presented in accordance with IFRS.

 

  

Year ended December 31, 

  

2013 

 

2014 

 

2015 

 

2016 

 

2017 

 

2017 

  

Rmb 

 

Rmb 

 

Rmb 

 

Rmb 

 

Rmb 

 

US$ 

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

 

 

11 

  

As of December 31, 

  

2013 

 

2014 

 

2015 

 

2016 

 

2017 

 

2017 

  

Rmb 

 

Rmb 

 

Rmb 

 

Rmb 

 

Rmb 

 

US$ 

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

 

 

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

 

(2)Earnings per share (basic) and earnings per ADS (basic) for each year from 2013 to 2017 have been computed, without considering the dilutive effect of the shares underlying our share option schemes by dividing profit by the weighted average number of shares and the weighted average number of ADSs of 44,646,825,847 and 446,468,258, respectively, for 2013, and 44,647,455,984 and 446,474,560, respectively, for 2014, 44,647,455,984 and 446,474,560, respectively, for 2015, 44,647,455,984 and 446,474,560, respectively, for 2016, and 44,647,455,984 and 446,474,560, respectively, for 2017, in each case based on a ratio of 100 shares to one ADS.

 

(3)Earnings per share (diluted) and earnings per ADS (diluted) for each year from 2013 to 2017 have been computed, after considering the dilutive effect of the shares underlying our share option schemes by using 44,787,119,089 shares and 447,871,191 ADSs for 2013, 44,734,774,504 shares and 447,347,745 ADSs for 2014, 44,684,819,053 shares and 446,848,191 ADSs for 2015, 44,659,140,488 shares and 446,591,405 ADSs for 2016, and 44,651,557,953 shares and 446,515,580 ADSs for 2017.

 

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

 

 

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

 

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

 

12 

 

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

 

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

 

 

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

 

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

 

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

 

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

 

 

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

 

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

 

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

 

13 

 

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

 

 

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

 

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

 

B.Capitalization and Indebtedness

 

Not applicable.

 

C.Reasons for the Offer and Use of Proceeds

 

Not applicable.

 

D.Risk Factors

 

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

 

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

 

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

 

Despite the mild recovery of international oil prices, low oil and natural gas prices may adversely affect our business, revenue and earnings. Lower oil and natural gas prices may result in the write-off of higher cost reserves and other assets, reduction of the amount of oil and natural gas we can produce economically and termination of existing contracts that have become uneconomic. The prolonged slump in oil and natural gas prices may also impact our long-term investment strategy and operation capability for our projects.

 

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

 

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

 

14 

 

Our financial performance is affected by the tax and fiscal regimes of host countries in which we operate. Any changes in these regimes may result in increased costs, including the potential for additional or double taxation being imposed on our company in some circumstances. For example, the Organization for Economic Co-operation and Development (OECD)’s “Base Erosion and Profit Shifting Project” (BEPS Project) was initiated in 2015 to enhance multilateral cooperation and strengthen supervision on global corporate taxation and transfer pricing activities. Numerous countries have responded to the BEPS Project by implementing tax law changes and amending tax treaties at a rapid pace. Most recently, the U.S. has promulgated a significant tax reform with effect from January 1, 2018.

 

Oil and natural gas industry are very competitive.

 

We compete in the PRC and international markets with national oil companies, major integrated oil and gas companies and various other independent oil and gas companies for access to oil and gas resources, products, alternative energy, customers, capital financing, technology and equipment, personnel and business opportunities. Competition may result in shortage of these resources or over-supply of oil and gas, which could increase our cost or reduce our earnings, and adversely impact our business, financial condition and results of operations.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

15 

 

Every aspect of our daily operations exposes us to health, safety, security and environmental (HSSE) risks given the geographical area, operational diversity and technical complexity of our operations. Our operations include productions and transportations of oil and gas in difficult geographic or climate zones, as well as environmentally sensitive regions, such as Canada, the basins in Uganda or offshore, especially in deep water area. Our operations expose us and the areas in which we operate to a number of risks, including major process safety incidents, natural disasters, earthquakes, social unrest, health and safety lapses and crimes. If a major HSSE risk materialises, such as an explosion or hydrocarbon spill, this could result in casualties, environmental damage disruption of business activities and, depending on their cause and severity, material damage to our reputation, exclusion from bidding on mineral rights and eventually loss of our licence to operate. In certain circumstances, liabilities could be imposed without regard to our fault in the matter. Regulatory requirements for HSSE change constantly and may become more stringent over time. In the future, we may incur significant additional costs in complying with such requirements or bear liabilities such as fines, penalties, clean-up costs and third-party claims, as a result of breach of laws and regulations relating to HSSE matter.

 

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

 

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

 

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

 

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

 

We cannot predict the interpretation or implementation of government policies at the U.S. federal, state or local levels with respect to any current or future activities by CNOOC or its affiliates in countries or with individuals or entities that are the subject of U.S. sanctions. As a result of such activities by CNOOC, we could be prohibited from engaging in business activities in the U.S. or with U.S. individuals or entities, and U.S. transactions in our securities and distributions to U.S. individuals and entities with respect to our securities could also be prohibited. Pension or endowment funds of certain U.S. State and local governments or universities may sell our securities due to certain restrictions on investments in companies that engage in activities in sanctioned countries, such as Iran and Sudan. We may also be subject to negative media or investor attention, which may distract management, consume internal resources and affect investors’ perception of our company and investment in our company.

 

As required by the Iran Threat Reduction and Syria Human Rights Act of 2012, which added a disclosure requirement to the Securities Exchange Act of 1934, we are providing certain information regarding our non-controlled affiliates’ activities. To our knowledge, in 2017, China Oilfield Services Limited (COSL), one of our non-controlled affiliates, provided certain drilling and other related services in Iran. We cannot predict at this time whether U.S. sanctions will be imposed on any of our affiliates.

 

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

 

Our exploration and development activities involve inherent risks, including the risk of not discovering commercially productive oil or gas reservoirs and that the wells we drill may not be able to commence production or may not be sufficiently productive to generate a return of our partial or full investments. In addition, approximately

 

16 

 

57.6% of our proved reserves were undeveloped as of 31 December 2017. Our future success depends on our ability to develop these reserves in a timely and cost-effective manner. There are various risks in developing reserves, mainly including construction, operational, geophysical, geological and regulatory risks.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Our oil and gas transportation involves marine, land and pipeline transportation, which are subject to hazards such as capsizing, collision, acts of piracy and damage or loss from severe weather conditions, explosions, oil and gas spills and leakages. These hazards could result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations, risk of financial

 

17 

 

loss and reputation harm. We may not be able to arrange insurance coverage for all of these risks and uninsured losses and liabilities arising from these hazards could reduce the funds available to us for financing, exploration and investment, which may have a material adverse effect on our business, financial condition and results of operations.

 

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

 

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

 

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

 

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

 

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

 

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

 

Key sales customers – if any of our key customers reduced their crude oil purchases from us significantly, our results of operation could be adversely affected. In order to reduce reliance on a single customer, we adopt measures including signing annual sales contracts, developing sales plans, and participating in market competition so as to maintain a stable cooperation with customers.

 

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

 

We face currency risks and liquidity risks.

 

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

 

Liquidity risks – Certain restrictions on dividend distribution imposed by the laws of the host countries in which we operate may adversely and materially affect our cash flows. For instance, the dividend of our wholly owned subsidiaries in the PRC shall be distributed pursuant to the laws of the PRC and the articles and association, and we may face risks of not obtaining adequate cash flows from such subsidiaries. In addition, a ratings downgrade could potentially increase financing costs and adversely impact our ability to access financing, which could put pressure on the Company’s liquidity.

 

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

 

 Our independent registered public accounting firm that issues the audit reports included in our annual report filed with the SEC, as auditors of companies that are traded publicly in the United States and a firm registered with the U.S. Public Company Accounting Oversight Board, or the PCAOB, is required by the laws of the United States to undergo regular inspections by the PCAOB to assess its compliance with the laws of the United States and professional standards.

 

Because we have substantial operations within China and, without the approval of PRC authorities, the PCAOB is currently unable to conduct inspections of the work of our independent registered public accounting firm as it relates to those operations, our independent registered public accounting firm is not currently inspected by the PCAOB. This lack of PCAOB inspections in China prevents the PCAOB from regularly evaluating our independent registered public accounting firm’s audits and its quality control procedures. As a result, investors may be deprived of the benefits of PCAOB inspections.

 

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

 

ITEM 4. INFORMATION ON THE COMPANY

 

A.History and Development

 

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

 

18 

 

articles of association or any enactment or rule of law. Our registered office is located at 65th Floor, Bank of China Tower, One Garden Road, Central, Hong Kong, and our telephone number is 852-2213-2500.

 

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

 

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

 

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

 

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

 

CNOOC has undertaken to us that:

 

·we will enjoy the exclusive right to exercise all of CNOOC’s commercial and operational rights under PRC laws and regulations relating to the exploration, development, production and sales of oil and natural gas in offshore China;
  
·it will transfer to us all of its rights and obligations under any new PSCs and geophysical exploration operations, except those relating to its administrative functions;
  
·it will not engage or be interested, directly or indirectly, in oil and natural gas exploration, development, production and sales in or outside the PRC;
  
·we will be able to participate jointly with CNOOC in negotiating new PSCs and to set out our views to CNOOC on the proposed terms of new PSCs;
  
·we will have unlimited and unrestricted access to all data, records, samples and other original data owned by CNOOC relating to oil and natural gas resources;
  
·we will have an option to invest in LNG projects in which CNOOC invested or proposed to invest, and CNOOC will at its own expense help us to procure all necessary government approvals needed for our participation in these projects; and
  
·we will have an option to participate in other businesses related to natural gas in which CNOOC invested or proposed to invest, and CNOOC will procure all necessary government approvals needed for our participation in such business.
   

The undertakings from CNOOC will cease to have any effect:

  
·if we become a wholly owned subsidiary of CNOOC;
  
·if our securities cease to be listed on any stock exchange or automated trading system; or
  
·12 months after CNOOC or any other PRC government-controlled entity ceases to be our controlling shareholder.

 

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

 

19 

 

B.Business Overview

 

Overview

 

We are an upstream company specializing in oil and natural gas exploration, development and production. We are the dominant oil and natural gas producer in offshore China, and in terms of reserves and production, we are one of the largest independent oil and natural gas exploration and production companies in the world. As of the end of 2017, we had net proved reserves of approximately 4.84 billion BOE (including approximately 0.37 billion BOE in our equity method investees). In 2017, we achieved a total net oil and gas production of 1,288,128 BOE per day (including net oil and gas production of approximately 47,355 BOE per day in our equity method investees).

 

Competitive Strengths

 

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

 

·large and diversified asset base with significant exploitation opportunities;

 

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

 

·successful independent exploration and development track record;

 

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

 

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

 

Large and diversified asset base with significant exploitation opportunities

 

We have a large net proved reserve base spread across offshore China and globally. As of December 31, 2017, we had approximately 4.84 billion BOE of net proved reserves. Our core operating area, offshore China, contributed to approximately 54.0% of our net proved reserves, while overseas contributed to the balance of 46.0%.

 

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

 

As of December 31, 2017, approximately 57.6% of our net proved reserves were classified as net proved undeveloped. Our large proved reserve base gives us the opportunity to achieve substantial production growth.

 

Sizable operating areas in offshore China with demonstrated exploration potential

 

We are the dominant oil and gas producer in offshore China, a region that we believe has substantial exploration upside. As of December 31, 2017, our total major exploration areas acreage in offshore China was approximately 257 thousand km2. We believe that offshore China is relatively underexplored, compared to other prolific offshore exploration areas such as the shallow water of the U.S. Gulf of Mexico, providing us with substantial exploration upside.

 

We have maintained an active drilling exploration program, which continues to demonstrate the exploration potential of offshore China. During 2017, we and our foreign partners have together drilled a total of 116 exploratory wells in offshore China, of which 58 were wildcat wells. During the same year, we and our foreign partners made 17 new discoveries in offshore China.

 

Successful independent exploration and development track record

 

We have a strong record of growing our reserves base for oil and natural gas, both independently and with our foreign partners through PSCs. In recent years, we have been adding reserves and production mainly through

 

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

 

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

 

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

 

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

 

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

 

Experienced management team and a high level of corporate governance standard

 

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

 

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

 

Business Strategy

 

We intend to continue expanding our oil and gas exploration and production activities. The principal components of our strategy are as follows:

 

·focus on reserve and production growth;

 

·develop natural gas business; and

 

·maintain a prudent financial policy.

 

Focus on reserve and production growth

 

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

 

We increase our production primarily through the development of proved undeveloped reserves. As of December 31, 2017, approximately 57.6% of our proved reserves were classified as proved undeveloped, which provides a solid resource base for maintaining stable production in the future.

 

Develop natural gas business

 

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We will continue to develop the natural gas market, and continue to explore and develop natural gas fields. In the event that we invest in businesses and geographic areas where we have limited experience and expertise, we plan to structure our investments in the form of alliances or partnerships with partners possessing the relevant experience and expertise.

 

Maintain a prudent financial policy

 

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

 

In 2017, we continued our efforts to lower costs and enhance efficiency through innovation in technology and management. All-in cost decreased for the fourth consecutive year. Under low oil price environment, we attached more importance to cash flow management and maintained a healthy financial position.

 

Selected Operating and Reserves Data

 

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

 

Our reserve data for 2015, 2016 and 2017 were prepared in accordance with the SEC’s final rules on “Modernization of Oil and Gas Reporting”, which became effective for accounting periods ended on or after December 31, 2009.

 

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

 

 

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

 

(2)Including our interest in equity method investees.

 

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

 

Summary of Oil and Gas Reserves

 

22 

 

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

 

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

 

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

 

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Total Net Proved Crude and Liquids Reserves
(mmbbls)

 

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

 

 

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

 

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

 

Total Net Proved Natural Gas Reserves
(bcf)

 

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

 

24 

  

 Total Net Proved Reserves
(million BOE)

 

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

 

Proved Reserves

 

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

 

The changes in our proved reserves mainly include:

 

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

 

ØOffshore China: an increase of 338.6 million BOE caused either by technical factors, which were mainly due to better than expected production performance and increased reservoir recoveries from infill drilling or by changes in economic factors, primarily related to the increase in oil price;

 

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

  

ØOverseas: an increase of 542.9 million BOE caused either by technical factors, which were mainly due to better than expected production performance and increased reservoir recoveries from infill drilling or by changes in economic factors, primarily related to the increase in oil price;

 

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

 

25 

 

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

 

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

 

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

 

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

 

·The production of 469.9 million BOE in 2017.

 

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

 

Proved Undeveloped Reserves (PUD)

 

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

 

The changes in our proved undeveloped reserves mainly include:

 

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

 

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

 

ØOffshore China: an increase of 74.1 million BOE caused either by technical factors, which were mainly due to better than expected production performance and increased reservoir recoveries from infill drilling or by changes in economic factors, primarily related to the increase in oil price;

 

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

 

ØOverseas: an increase of 428.6 million BOE caused either by technical factors, which were mainly due to better than expected production performance and increased reservoir recoveries from infill drilling or by changes in economic factors, primarily related to the increase in oil price;

 

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

 

26 

 

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

 

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

 

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

  

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

 

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

 

As of December 31, 2017, 191.8 million BOE of our proved undeveloped reserves were first booked before 2012. These proved undeveloped reserves were mainly located in East China Sea, Bohai and Western South China Sea, including (i) 7.7 million BOE in East China Sea, which are under construction; (ii) 6.9 million BOE in Bohai, including Qinhuangdao 33-1S oil field which is scheduled to come on stream in 2019; and (iii) 177.2 million BOE in Western South China Sea, including Wenchang 9-2/9-3/10-3 and Dongfang 13-2 gas fields which will be put on stream in 2018. The development of proved undeveloped reserves relating to the above projects was not completed within five years from initial booking due to the specific circumstances associated with the relevant development activities and delivery obligations. The Company books proved reserves for which development is scheduled to commence after more than five years only if these proved reserves satisfy the SEC’s standards for attribution of proved status and the Company’s management has reasonable certainty that these proved reserves will be produced.

 

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

 

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

 

For 2015, 2016 and 2017, approximately 62%, 60%, and 65% respectively, of our reserves were evaluated by our internal reserves evaluation staff, and the remaining were based upon estimates prepared by independent petroleum engineering consulting companies and reviewed by us. Except as otherwise stated, all amounts of reserves in this report include our interests in equity method investees.

 

In 2017, we engaged Ryder Scott Company, L.P., Gaffney, Cline & Associates (Consultants) Pte Ltd. and RPS as independent third party consulting firms to perform annual estimates for our net proved oil and gas reserves under our consolidated subsidiaries. For each independent third party consulting firm, a report of third party letter has been prepared which summarizes the work undertaken, the assumptions, data, methods and procedures they used and provides their reserves estimate. These reports have been included as appendices to this document.

 

For Nexen-managed assets, all of the total net proved oil and gas reserves were evaluated by our internal reserve evaluation staff, which accounted for 29% of the company total net proved oil and gas reserves. And we also engaged independent third party consulting firms Ryder Scott Company, L.P., McDaniel & Associates Consultants Ltd. and DeGolyer and MacNaughton to conduct audits for internally evaluated reserves to provide validation of our

 

27 

 

processes and estimates. For each independent third party consulting firm, a report of third party letter has been prepared which summarizes the work undertaken, the assumptions, data, methods and procedures they used and concludes with their opinion concerning the reasonableness of the estimated reserves quantities or reserves processes. These reports have been included as appendices to this document. Approximately 35% net proved oil and gas reserves of the Domestic China and other overseas assets were estimated by these independent third party consulting firms and the remaining 36% of the Domestic China and other overseas assets were evaluated by our internal reserves evaluation staff.

 

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

 

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

 

The RMC’s main responsibilities are to:

 

·review our reserve policies;

 

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

 

·select our reserve estimators and auditors.

 

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

 

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

 

The RMC delegates its daily operation to our Reserves Office, which is led by our Chief Reserves Supervisor. The Reserves Office is mainly responsible for supervising reserves estimates and auditing. It reports to the RMC periodically and is independent from operating divisions such as the exploration, development and production departments. Our Chief Reserve Supervisor has over 30 years’ experience in the oil and gas industry.

 

Exploration, Development and Production

 

Summary

 

In offshore China, the Company engages in oil and natural gas exploration, development and production in Bohai, Western and Eastern South China Sea, and the East China Sea, either independently or in cooperation with foreign partners through production sharing contracts (“PSCs”). As of the end of 2017, approximately 54.0% of the Company’s net proved reserves and approximately 64.4% of its net production were derived from offshore China.

 

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

 

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

 

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foreign partners through PSCs. CNOOC has transferred to the Company all its rights and obligations in regard to the PSCs (except those relating to its management and regulatory function as a state-owned company), including new PSCs that will be signed in the future.

 

After years of hard work, we have established our presence in more than 20 countries and regions. Our overseas assets account for over 50% of the Company’s total assets. With its diversified portfolio of high-quality assets, the Company is an active participant in a number of world-class oil and gas projects and is regarded as a leading industry player. Currently, the Company holds interests in oil and natural gas blocks in Indonesia, Australia, Nigeria, Uganda, Argentina, the U.S., Canada, the United Kingdom, Brazil, Guyana and various other countries. As of the end of 2017, approximately 46.0% of the Company’s net proved reserves and approximately 35.6% of its net production were derived from overseas.

 

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

 

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

 

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

 

Looking forward to 2018, the global economy will continue its slow recovery. Despite a recovery in international oil prices, the external operating environment is filled with uncertainties. To this end, the Company remains confident of its prospects. We will further strengthen our operating strategies, which mainly include steadily increasing the Company’s oil and gas reserve and production levels, continuing to reinforce quality and efficiency enhancement, strengthening innovation and technology-driven philosophy, maintaining prudent financial policy and investment decision-making, and pursuing a green, healthy and environment-friendly development model.

 

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

 

Exploration

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

The Company’s major exploration activities in 2017 are set out in the table below:

 

 

Exploration Wells 

New Discoveries 

Successful Appraisal Wells 

Seismic Data 

 

Independent 

PSC 

       

2D (km) 

3D (km2) 

 

Wildcat 

Appraisal 

Wildcat 

Appraisal 

Independent 

PSC 

Independent 

PSC 

Independent 

PSC 

Independent 

PSC 

Offshore China                        
Bohai 22 38 1 0 9 0 28 0 0 0 742 0
Eastern South China Sea 16 7 1 0 2 0 3 1 2,248 2,169 3,545 683
Western South China Sea 16 12 0 0 6 0 7 0 0 0 3,131 1,028
East China Sea 2 1 0 0 0 0 0 0 0 0 1,934 0
Subtotal 56 58 2 0 17 0 38 1 2,248 2,169 9,352 1,711
Overseas 0 0 5 7 0 2 0 6 0 0 0 3,163
Total 56 58 7 7 17 2 38 7 2,248 2,169 9,352 4,874

 

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

 

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

  

Engineering Construction, Development and Production

 

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

 

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

 

In 2017, the Company’s development and production were driven by intensive and streamline management with emphasis on cost savings and efficiency enhancement, technology-driven strategy and sustainable development. Achievements in these areas included the following:

 

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

 

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

 

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

 

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

 

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

 

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

 

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Regional Overview

 

Offshore China

 

Bohai

 

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

 

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

 

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

 

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

 

Western South China Sea

 

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

 

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

 

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

 

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Eastern South China Sea

 

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

 

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

 

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

 

East China Sea

 

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

 

Others

 

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

 

Overseas

 

Asia (excluding China)

 

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

 

Indonesia

 

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

 

The Company owns an interest of approximately 13.90% in the Tangguh LNG Project in Indonesia. In 2017, production volume of Phase I of the Project remained stable. Currently, construction of the third LNG train of Phase II is in progress as planned, and is expected to reach completion and commence production in 2020.

 

Iraq

 

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

 

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

 

Oceania

 

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

 

Australia

 

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

 

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

 

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

 

Other Regions in Oceania

 

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

 

Africa

 

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

 

Nigeria

 

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

 

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

 

The Company also holds a 20% non-operating interest in Usan oilfield in the OML138 block in offshore Nigeria, and an 18% non-operating interest in the OPL 223 and OML 139 PSC respectively.

 

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

 

Uganda

 

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

 

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

 

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

 

Other Regions in Africa

 

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

 

North America

 

North America has become the Company’s largest overseas reserves and production region. The Company holds interests in oil and gas assets in the U.S., Canada and Trinidad and Tobago, as well as shares in MEG Energy Corporation in Canada. As of the end of 2017, the Company’s reserves and daily production volume in North America reached 1,260.6 million BOE and 132,675 BOE/day, respectively, representing approximately 26.0% of the Company’s total reserves and 10.3% of its daily production.

 

The U.S.

 

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

 

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

 

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

 

Canada

 

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

 

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

 

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

 

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

 

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Other Regions in North America

 

The Company owns 12.5% interest in the 2C block and a 17.12% interest in the 3A block in Trinidad and Tobago, respectively, of which the 2C block is in production. Phase III of the natural gas project yielded stable production and achieved favorable economic returns. The Company also owns a 100% exploration interest in the deepwater exploration block 1 and block 4 of the CINTURON PLEGADO PERDIDO in Mexico respectively.

 

South America

 

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

 

Argentina

 

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

 

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

 

Brazil

 

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

 

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

 

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

 

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

 

Guyana

 

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

 

Other Regions in South America

 

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

 

Europe

 

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

 

United Kingdom

 

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

 

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

 

Other Regions in Europe

 

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

 

Other Oil and Gas Data

 

Oil and Gas Production, Production Prices and Production Costs

 

The following table sets forth our net production, average sales price and average production cost (excluding ad valorem and severance taxes) in the years of 2015, 2016 and 2017.

 

   Net Production  Average Sales Price  Average Production Cost
   Total  Crude and Liquids  Gas  Crude and Liquids  Gas   
  

(BOE/day) 

 

(Bbls/day) 

 

(Mmcf/day) 

 

(US$/bbl) 

 

(US$/Mmcf) 

 

(US$/BOE) 

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

 

37 

 

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

  

Drilling and Other Exploratory and Development Activities

 

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

 

   Net Exploratory Wells Drilled  Net Development Wells Drilled
   Total  Productive  Dry  Total  Productive  Dry
2017                  
Offshore China                  
Independent                  
Bohai    60    37    21    33    33     
Western South China Sea    28    13    11    22    22     
Eastern South China Sea    23    5    18    12    12     
East China Sea    3    0    3    0    0     
Subtotal    114    55    53    67    67     
PSCs                        
Bohai    1        1    8.7    8.7     
Western South China Sea                         
Eastern South China Sea    1        1             
East China Sea                0.5    0.5     
Subtotal    2        2    9.2    9.2     
Overseas                        
Asia (excluding China)                16.5    16.5     
Oceania                -         
Africa    0.5    0.5        3.6    3.6     
North America    0.2        0.2    67.3    67.3     
South America    1.6    1.6    0.1             
Europe    0.6        0.6             
Subtotal    2.9    2.1    0.9    87.4    87.4     
                               
2016                              
Offshore China                              
Independent                              
Bohai    56    41    15    87    87     
Western South China Sea    27    9    18    24    24     
Eastern South China Sea    24    7    17    22    22     
East China Sea    4    1    3             
Subtotal    111    58    53    133    133     
PSCs                              
Bohai    1        1    1.5    1.5     
Western South China Sea    3        3             
Eastern South China Sea    1    1                 
East China Sea                6.5    6.5     
Subtotal    5    1    4    8.0    8.0     
Overseas                              
Asia (excluding China)                10.5    10.5     
Oceania                         
Africa    0.9    0.9        4.0    4.0     
North America    0.3        0.3    55.66    55.66     
South America    1.3    0.9    0.4    0.25    0.25     
Europe    0.4        0.4    2.19    2.19     
Subtotal    2.9    1.8    1.0    72.6    72.6     

 

38 

 

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

 

Present Activities

 

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

 

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

 

39 

 

Oil and Gas Properties, Wells, Operations, and Acreage

 

The following table sets forth our productive wells, developed acreage and undeveloped acreage as of December 31, 2017.

 

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

 

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

 

Delivery Commitment

 

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

 

Sales and Marketing

 

Sales of Crude Oil

 

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

 

The Company’s crude oil sales prices are mainly determined by the prices of international benchmark crude oil of similar quality, with certain premiums or discounts subject to prevailing market conditions. Although the prices are quoted in U.S. dollars, customers in China usually pay by Renminbi. The Company currently sells three types of crude oil in China: heavy crude, medium crude and light crude.

 

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

 

40 

 

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

 

   Year ended December 31,
   2015  2016  2017
Sales and Marketing Volumes (mmbbls)(1)         
Light Crude    22.9    20.8    26.3 
Medium Crude    162.4    162.6    147.4 
Heavy Crude    138.2    122.4    112.3 

 

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

 

Sales of Natural Gas

 

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

 

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

 

In 2017, stable and positive economic performance in China, the impact from the clean winter heating policy in northern China, as well as the policy of changing fuel from coal to gas, resulted in natural gas demand growth in China, which drove sales volume growth of high-priced natural gas. In addition, based on market condition, the Company gradually adjusted sale prices for natural gas users in certain areas through negotiation. In 2017, the Company’s average realized natural gas price was US$5.84/mcf, representing a 7.0% year-on-year increase.

 

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

 

   Year ended December 31,
   2015  2016  2017
Average Realized Prices         
Crude and Liquids (US$/bbl)    51.27    41.40    52.65 
Natural Gas (US$/mcf)    6.39    5.46    5.84 
                
West Texas Intermediate (US$/bbl)    48.68    43.35    50.80 

 

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

 

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

 

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

 

41 

 

Procurement of Services

 

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

 

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

 

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

 

Research and Development

 

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

 

Major Scientific and Technological Project Development

 

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

 

Construction of Scientific and Technological Innovative System

 

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

 

Health, Safety and Environmental Protection (“HSE”)

 

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

 

42 

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

43 

 

   Gross Man-hours (million)  Number of Recordable Cases  Rate of Recordable Cases  Number of Lost Workdays Cases  Rate of Lost Workdays Cases  Fatal Cases
Company staff    41    12    0.06    6    0.03    0 
Staff of the Company and direct contractors    109    48    0.08    17    0.03    2 

 

Operating Hazards and Uninsured Risks

 

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

 

The Company further strengthened safety in production, intensifying its efforts to identify and eliminate potential risks, giving special attention to preventing operational accidents in key and high-risk areas. It also improved the implementation of safety standards and deepened safety awareness across all levels of the organization. In 2017, the Company completed full system safety inspections, including the special supervision of safety production, a special safety check on storage tank fields and a year-end major check on safety production. For HSE risks in particular operating units, the Company organized special examinations. Through examinations and inspections, the Company effectively met CNOOC Limited’s management requirements, urged affiliated units to act in accordance with the law, and promoted the continuous improvement of HSE management.

 

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

 

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

 

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

 

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

 

As of December 31, 2017, we have purchased a number of insurance policies with varying policy coverage and limits to meet our risk management requirements and cover our potential liabilities arising from accidents at any of our offshore and onshore locations. We maintain insurance for costs relating to property damage to our facilities,

 

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control of well including drilling relief wells, removal of wreck, pollution clean-up, liability for bodily injury and property damage to third parties. The policy limits and other terms and conditions of these insurance policies comply with all applicable laws and regulations in the PRC and other relevant jurisdictions. However, we may not have sufficient coverage for some of the risks we face, either because insurance is not available or because of high premium costs. See “Item 3—Key Information—Risk Factors—Risks Relating to Our Operations—Extreme weather conditions may have a material adverse impact on us and could result in losses that are not covered by insurance.”

 

We have maintained varied insurance policies for our domestic assets and operational insurance policies and construction insurance policies, with different policy limits and deductibles. We also purchase operator’s extra-expense up to US$ 100 million and third-party liabilities insurance up to US$200 million. As for deep-water wells, we are insured up to US$250 million for costs related to control of the well. The deductible for each insurance policy mainly ranges from US$2 million to US$5 million for different types of insurance policies. For overseas operation and assets, we are insured for amounts up to the replacement cost value of our assets for property damage and up to US$525 in 2017 million for operators extra expense. Additionally, we purchase insurance covering liability for bodily injury and property damage to third parties with limits of up to US$1 billion in 2017. This cover protects against liability that arises from sudden and accidental pollution or from other causes.

 

For all of our offshore operations, we have conducted comprehensive environmental impact evaluations and adopted emergency plans to deal with potential oil spills. Pursuant to the requirements of the PRC government, the evaluations and plans for our offshore operations in the PRC have been reviewed and approved by the industry experts and have been filed with the PRC government. The evaluations and plans for our offshore operations overseas have complied with the legal and regulatory requirements of the relevant local jurisdictions.

 

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

 

Competition

 

Domestic Competition

 

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

 

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

 

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

 

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

 

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Foreign Competition

 

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

 

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

 

Segment Information

 

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

 

   Year ended December 31,
   2015  2016  2017
   Rmb in millions  %  Rmb in millions  %  Rmb in millions  %
Exploration and production    149,582    87.3    125,611    85.7    157,166    84.3 
Trading businesses    21,438    12.5    20,310    13.9    28,881    15.5 
Corporate and elimination    417    0.2    569    0.4    343    0.2 
Total operating revenues    171,437    100.0    146,490    100.0    186,390    100.0 

 

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

 

Regulatory Framework in the PRC

 

Government Control

 

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

 

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

 

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

 

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

 

Fiscal Regimes for Independent Operations

 

Taxation

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

We calculate our deferred tax to account for the losses available for offsetting against future taxable profit and the temporary differences between our tax base, which is used for income tax reporting and prepared in accordance with applicable tax guidelines, and our accounting base, which is prepared in accordance with applicable financial reporting requirements. The temporary differences include accelerated amortization allowances for oil and gas properties, which are partially offset by provisions for dismantlement and for impairment of property, plant and equipment and write-off of unsuccessful exploratory drilling. As of December 31, 2015, 2016 and 2017, we had Rmb 1,948 million, Rmb 19,174 million and Rmb 22,206 million (US$3,413 million) respectively, in net deferred tax assets/ (liabilities). See note 10 to our consolidated financial statements included elsewhere in this annual report.

 

Royalty

 

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

 

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

 

Special Oil Gain Levy

 

In March 2006, the PRC government imposed a special oil gain levy at progressive rates from 20% to 40% on any income derived from sales of locally produced crude oil by an oil exploration and production company at a price that exceeds US$40 per barrel. In December 2011, the PRC government increased the threshold of the special oil gain levy from US$40 per barrel to US$55 per barrel, with effect from November 1, 2011. In December 2014, the PRC government has decided to increase the threshold of the special oil gain levy from US$55 per barrel to US$65 per barrel, with effect from January 1, 2015. The special oil gain levy is collected on a quarterly basis. For the years ended December 31, 2015, 2016 and 2017 we incurred approximately Rmb 59 million, nil and Rmb 55 million for the Special Oil Gain Levy.

 

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

 

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

 

Realized Oil Price (US$/bbl)  

Rate of the Levy 

65-70 (Include 70)   20%
70-75 (Include 75)   25%
75-80 (Include 80)   30%
80-85 (Include 85)   35%
Above 85   40%

 

Fiscal Regimes for PSC Operations

 

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

 

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

 

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

 

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

 

Bidding Process

 

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

 

Terms of PSCs

 

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

 

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

 

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

 

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

 

Percentage of
annual gross
production 

Allocation 

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

For the payment of resource tax and recovery:

   
 

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

 

 

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

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

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

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

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

 

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

 

32.5%(3)

Remainder oil allocated according to the following formula:

 

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

 

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

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Regulatory Framework Overseas

 

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

 

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

 

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

 

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

 

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

 

Taxation

 

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

 

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

 

Environmental Regulation

 

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

 

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

 

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

 

The PRC and overseas environmental laws require offshore petroleum investors to pay abandonment costs. Our financial statements include provisions for costs associated with the dismantlement of oil and gas fields as of December 31, 2015, 2016 and 2017 of approximately Rmb 50,063 million, Rmb 50,888 million and Rmb 54,073 million (US$8,311 million), respectively.

 

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

 

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

 

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

 

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

 

Patents and Trademarks

 

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

 

Employees and Employee Benefits

 

During the years ended December 31, 2015, 2016 and 2017, we employed 20,585 persons, 19,718 persons and 19,030 persons, respectively. Of the 19,030 employees we employed as of December 31, 2017, approximately 82.7% were involved in oil exploration, development and production activities, approximately 5.5% were involved in accounting and finance work and the remainder were senior management and others. Part of the workers for the operation of the oil and gas fields, maintenance and ancillary service are hired on a contract basis.

 

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

 

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

 

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

 

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

 

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

 

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

 

For further details regarding retirement benefits, see note 29 to our consolidated financial statements included elsewhere in this annual report.

 

As an oil and gas exploration and production company operating in highly competitive markets, we depend in large part on our employees for effective and efficient operations. We devote significant resources to train our employees. During 2017, we held 40 core training workshops, which were attended by approximately 1,680 person-times of participants. To ensure smooth implementation of our overseas strategy, we have established an international human resources system to attract and retain talent in the international market. In order to enhance the planning and budget control of our labor costs, we have installed target benchmarks in performance appraisals to guide various business units to cut their labor costs and to increase the accuracy of their budgets.

 

C.Organizational Structure

 

CNOOC indirectly owned or controlled an aggregate of approximately 64.44% of our shares as of March 31, 2018. Accordingly, CNOOC continues to be able to exercise all the rights of a controlling shareholder, including electing our directors and voting to amend our articles of association. Although CNOOC has retained a controlling interest in us, the management of our business will be our directors’ responsibility.

 

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

 

 

________

 

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

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

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

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

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

 

D.Property, Plants and Equipment

 

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

 

ITEM 4A. unresolved staff comments

 

None.

 

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

 

A.Operating Results

 

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

 

Overview

 

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

 

Factors Affecting Our Results of Operations

 

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

 

Oil and Gas Prices

 

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

 

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

 

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

 

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

 

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

 

   Year ended December 31,
   2015  2016  2017
Average net realized prices:         
Crude oil (US$ per bbl)    51.27    41.40    52.65 
Natural gas (US$ per mcf)    6.39    5.46    5.84 

 

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Production and Sales Volumes

 

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

 

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

 

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

 

   Year ended December 31,
   2015  2016  2017
Net production of crude oil (bbl/day)(1)    1,124,047    1,083,101    1,064,986 
Net production of natural gas (mmcf/day)(1)    1,363.6    1,276.2    1,300.6 

 

 

(1)Including our interest in equity method investees.

 

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

 

Critical Accounting Policies

 

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

 

Oil and Gas Properties

 

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

 

The costs incurred in installing enhanced recovery facilities are capitalized together with the development costs of the relevant oil and gas properties. We treat the costs of unsuccessful exploratory wells and all other exploration costs as expenses when incurred. Productive oil and gas properties and other tangible and intangible costs of producing properties are depreciated using the unit-of-production method on a property-by-property basis under which the ratio of produced oil and gas to the estimated remaining proved developed reserves is used to determine the provision of depreciation, depletion and amortization. Common facilities that are built specifically to

 

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service production directly attributed to designated oil and gas properties are amortized based on the proved developed reserves of the respective oil and gas properties on a pro-rata basis. Common facilities that are not built specifically to service identified oil and gas properties are depreciated using the straight-line method over their estimated useful lives. Costs associated with significant development projects are not depreciated until commercial production commences and the reserves related to those costs are excluded from the calculation of depreciation. We amortize capitalized acquisition costs of proved properties by the unit-of-production method on a property-by-property basis based on the total estimated proved reserves.

 

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

 

Reserves Estimation

 

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

 

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

 

Impairment of Non-Financial Assets other than Goodwill

 

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

 

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

 

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

 

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

 

The sensitivity analysis for the impairment testing involves estimates and judgments to consider numerous assumptions comprehensively. Those assumptions interact on each other and interrelate with each other complexly and do not have fixed patterns along with the changes in price. Accordingly, the Company believes that the

 

57 

 

preparation of the sensitivity analysis for the impairment testing will be impracticable. Changes in assumptions could affect impairment charges and reversals in income statement, and the carrying amounts of assets in balance sheet.

 

Business Combinations and Goodwill

 

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

 

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

 

Joint Arrangements

 

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

 

Joint Operations

 

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

 

Joint Venture

 

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

 

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

 

Fair Value

 

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

 

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

 

Provisions

 

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

 

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

 

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

 

Deferred Tax

 

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

 

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

 

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

 

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

 

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

 

Recognition of Revenue from Oil and Gas Sales and Marketing

 

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

 

Our marketing revenues principally represent the sales of oil and gas from the foreign partners under our PSCs and revenues from the trading of oil and gas through our subsidiaries. The cost of the oil and gas sold is included in crude oil and product purchases.

 

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Results of Operations

 

Overview

 

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

 

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

 

 

(1)Including our interest in equity method investees.

 

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

 

   Year ended December 31,
   2015  2016  2017
Operating Revenues:      
Oil and gas sales    85.5%   82.8%   81.5%
Marketing revenues    12.5%   13.9%   15.5%
Other income    2.0%   3.3%   3.0%
Total revenues    100.0%   100.0%   100.0%
Expenses:               
Operating expenses    (16.5)%   (15.8)%   (13.0)%
Taxes other than income tax    (6.3)%   (4.7)%   (3.9)%
Exploration expenses    (5.8)%   (5.0)%   (3.7)%
Depreciation, depletion and amortization    (42.8)%   (47.0)%   (32.9)%
Special oil gain levy    0.0%   0.0%   0.0%
Impairment and provision    (1.6)%   (8.3)%   (4.9)%
Crude oil and product purchases    (11.6)%   (13.0)%   (14.8)%
Selling and administrative expenses    (3.3)%   (4.4)%   (3.7)%
Others    (1.8)%   (3.3)%   (3.2)%
Total expenses    (89.8)%   (101.6)%   (80.1)%
                
Interest income    0.5%   0.6%   0.4%
Finance costs    (3.6)%   (4.3)%   (2.7)%
Exchange gain, net    (0.1)%   (0.5)%   0.2%
Investment income    1.4%   1.9%   1.3%
Share of profits of associates    0.1%   (0.4)%   0.2%
Share of profits/(losses) of a joint venture    1.0%   0.4%   0.3%
Non(operating income/(expenses), net    0.4%   0.4%   0.0%
Profit before tax    10.0%   (3.6)%   19.5%
Income tax expense    1.8%   4.0%   (6.3)%
Profit for the year    11.8%   0.4%   13.2%

 

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Calculation of Revenues

 

China

 

We report total revenues, which consist of oil and gas sales, marketing revenues and other income, in our consolidated financial statements included elsewhere in this annual report. With respect to revenues derived from our offshore China operations, oil and gas sales represent gross oil and gas sales less royalties and share oil payable to the PRC government.

 

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

 

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

 

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

 

Indonesia

 

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

 

Iraq

 

The oil sales from Iraq consist of our participating interest in the Missan project.

 

Australia

 

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

 

Nigeria

 

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

 

Trinidad and Tobago

 

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

 

The U.S. and Canada

 

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

 

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

 

United Kingdom

 

The oil and gas sales from the United Kingdom consist of our participating interests in the Buzzard, Scott/Telford/Rochelle and Ettrick/Blackbird properties.

 

Unconsolidated Investees

 

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

 

2017 versus 2016

 

Consolidated net profit

 

Our consolidated net profit increased significantly to Rmb 24,677 million (US$3,792.8 million) in 2017 from Rmb 637 million in 2016, primarily as a result of the increase in profitability due to higher international oil price environment, as well as the combined effects of increased reserve and reduced costs as a result of adoption of efficient measures by the Company.

 

Revenues

 

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

 

  

2017 

 

2016 

 

Amount 

 

Change (%) 

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

 

 

*Excluding our interest in equity-accounted investees.

 

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

 

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Operating expenses

 

Our operating expenses increased 4.6% to Rmb 24,282 million (US$3,732.1 million) in 2017 from Rmb 23,211 million in 2016, the operating expenses per BOE increased 6.0% to Rmb 53.6 (US$8.24) per BOE in 2017 from Rmb 50.6 (US$7.29) per BOE in 2016, Operating expenses per BOE offshore China increased 11.6% to Rmb 49.2 (US$7.57) per BOE in 2017 from Rmb 44.1 (US$6.36) per BOE in 2016, mainly attributable to the increase in workload as the result of the Company adopting optimisation measures to increase production efficiency, as well as prices of refined oil, chemicals and other materials rose with oil price. Overseas operating expenses per BOE decreased 2.7% to Rmb 62.4 (US$9.59) per BOE in 2017 from Rmb 64.1 (US$9.23) per BOE in 2016.

 

Taxes other than income tax

 

Our taxes other than income tax increased 3.9% to Rmb 7,210 million (US$1,108.2 million) in 2017 from Rmb 6,941 million in 2016, mainly due to the increase in oil and gas sales.

 

Exploration expenses

 

Our exploration expenses decreased 6.5% to Rmb 6,881 million (US$1,057.6 million) in 2017 from Rmb 7,359 million in 2016, mainly because of less costs of uncertain wells from previous years being written off according to subsequent reserve evaluation as well as the decrease in write-off of expired leases in North American.

 

Depreciation, depletion and amortization

 

Our depreciation, depletion and amortization decreased 11.1% to Rmb 61,257 million (US$ 9,415.0 million) in 2017 from Rmb 68,907 million in 2016.

 

The dismantlement-related depreciation, depletion and amortization costs decreased 75.6 % to Rmb 383 million (US$58.9 million) in 2017 from Rmb 1,569 million in 2016. Our average dismantling costs per BOE decreased 75.1% to Rmb 0.85 (US$ 0.13) per BOE in 2017 from Rmb 3.42 (US$0.49) per BOE in 2016, primarily due to the decrease of the present value of asset retirement obligations brought by the increase of interest rate in the China market. Our depreciation, depletion and amortisation, excluding the dismantlement-related depreciation, depletion and amortization, decreased 9.6% to Rmb 60,874 million (US$9,356.2 million) in 2017 from Rmb 67,338 million in 2016. Our average depreciation, depletion and amortization per BOE, excluding the dismantlement-related depreciation, depletion and amortization, decreased 8.4% to Rmb 134.4 (US$20.66) per BOE in 2017 from Rmb 146.8 (US$21.14) per BOE in 2016, primarily due to the increase of reserve in producing oil and gas fields by taking effective measures to improve production performance and recovery rate as well as the decrease in amortization rate resulting from the recognized impairment of oil and gas assets in 2016.

 

Impairment and provision

 

Our impairment and provision decreased 25.0% to Rmb 9,130 million (US$1,403.3 million) in 2017 from Rmb 12,171 million in 2016, mainly due to the decrease of oil and gas assets impairment. The impairment loss of oil and gas assets recognized in 2017 mainly related to oil and gas fields located in China, Africa and North America and it was primarily due to the revision of the oil and gas price forecast and revision of reserve. In 2016, certain oil and gas properties located in North America, Europe and Africa were impaired, which was reflected by the revision of the oil price forecast and the adjustment in operating plan for the oil sand assets in Canada. Please refer to Note 13 to the Consolidated Financial Statement of this annual report.

 

Selling and administrative expenses

 

Our selling and administrative expenses increased 5.7% to Rmb 6,861 million (US$1,054.5 million) in 2017 from Rmb 6,493 million in 2016. Our selling and administrative expenses per BOE increased 7.1% to Rmb 15.15 (US$2.33) per BOE in 2017 from Rmb 14.15 (US$2.04) per BOE in 2016, due to the increase in transportation costs in Canada resulting from increased production and sales volume.

 

Finance costs/Interest income

 

63 

 

Our finance costs decreased 19.2% to Rmb 5,044 million (US$775.2 million) in 2017 from Rmb 6,246 million in 2016, primarily due to the increased capitalized interest cost arising from the increase in the scale of oil and gas assets under construction. Our interest income decreased 27.5% to Rmb 653 million (US$100.4 million) in 2017 from Rmb 901 million in 2016, primarily due to the decreased proportion of deposits with higher interest rates.

 

Exchange gains/losses, net

 

Our net exchange gains changed to Rmb 356 million (US$54.7 million) in 2017, while accounted net exchange losses of Rmb 790 million in 2016, primarily as a result of the increase in exchange gains arising from Rmb fluctuation against the U.S. dollars and Hong Kong dollars.

 

Investment income

 

Our investment income decreased 13.2% to Rmb 2,409 million (US$370.3 million) in 2017 from Rmb 2,774 million in 2016, primarily attributable to the decreased proportion of corporate wealth management products with higher interest rates.

 

Share of profits/losses of associates and a joint venture

 

Our share of profits of associates and a joint venture changed to Rmb 855 million (US$131.4 million) in 2017, while in 2016 we shared losses of Rmb 76 million, primarily attributable to losses from the sale of shares of Northern Cross (Yukon) Limited located in Canada in 2016.

 

Income tax expense/credit

 

Our income tax expense changed to Rmb 11,680 million (US$1,795.2 million) in 2017, while accounted income tax credit of Rmb 5,912 million in 2016, mainly because income tax expense increased as Company’s profitability increased in 2017, in addition, the U.S. government decreased the federal corporate income tax rate from 35% to 21% and resulted in a one-time write-off of net deferred tax asset and increased income tax expense.

 

2016 versus 2015

 

Consolidated net profit

 

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

 

Revenues

 

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

 

  

2016 

 

2015 

 

Amount 

 

Change (%) 

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

 

 

*Excluding our interest in equity-accounted investees.

 

64 

 

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

 

Operating expenses

 

Our operating expenses decreased 18.2% to Rmb 23,211 million in 2016 from Rmb 28,372 million in 2015, attributable from effective cost control. The operating expenses per BOE decreased 14.9% to Rmb 50.6 per BOE