Exhibit 15.2





INDEPENDENT LETTER





THE GREATER ANGOSTURA FIELDS,


BLOCK 2C, TRINIDAD & TOBAGO


ESTIMATED PROVED RESERVES AND FINANCIAL DATA, BASED ON SEC RULES








Prepared for





CNOOC LIMITED





As at 31stDecember, 2014

















February, 2015

















GAFFNEY, CLINE & ASSOCIATES (CONSULTANTS) PTE LTD














This summary letter is based on Gaffney, Cline & Associates’ official report and has been provided at the request of CNOOC Limited.














Gaffney, Cline & Associates

(Consultants) Pte. Ltd.

80 Anson Road

#31-01C Fuji Xerox Towers

Singapore 079907

Telephone: +65 6225 6951



www.gaffney-cline.comSML/YDH/dh/L0070/2015/PS-14-2093
28th February, 2015








CNOOC Limited


No. 25, Chaoyangmenbei Dajie


Dongcheng District


Beijing 100010, P.R. China





Gentlemen,





INDEPENDENT LETTER





THE GREATER ANGOSTURA FIELDS,


BLOCK 2C, TRINIDAD & TOBAGO


ESTIMATED PROVED RESERVES AND FINANCIAL DATA, BASED ON SEC RULES


As at 31stDecember, 2014




At the request of CNOOC Limited (CNOOC), Gaffney, Cline & Associates (GCA) has prepared an independent estimate of the proved reserves and financial data attributable to certain participating interests owned by CNOOC as at 31st December, 2014.  The reserves and income data were estimated based on Rules of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released 14th January, 2009 in the Federal Register, including all references to Regulation S-X and Regulation S-K (SEC Rules).  GCA’s independent study, completed on 28th February, 2015 and summarized herein, was prepared for public disclosure by CNOOC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC Rules.  In GCA’s opinion, the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose and have been carried out in line with the SEC Oil and Gas Reserves Definitions attached hereto an Attachment.




The subject properties in Block 2C are located 24 miles offshore east coast of Trinidad & Tobago.  Based on information provided by CNOOC, the Proved reserves estimates for properties evaluated by GCA for this report represent approximately 0.3 percent of CNOOC’s total net proved reserves as at 31st December, 2014. GCA is not in a position to verify this statement as it was not requested to review all CNOOC’s other oil and gas assets.




GCA prepared an independent assessment of the reserves based on data and interpretations provided by CNOOC.  GCA checked and verified the in place volume estimation.  GCA reviewed the well and reservoir performances employing Decline Curve Analysis (DCA) and material balance techniques.  Economic models were constructed based on terms of the PSC as provided by CNOOC, in order to calculate CNOOC’s Net Entitlement volumes, which are made up of CNOOC’s share of contractors revenue (Petroleum Cost Recovery and Profit Oil) converted to volumetric equivalents.




The oil price used for these computations was calculated with reference to the un-weighted 12-month arithmetic average of the first-day-of-the month Brent Crude Oil price for each month within the 12-month period (January to December, 2014).  Based on the data collated












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by GCA for 2014, the average Brent Crude Oil price was US$103.17/Bbl.  The price received for crude oil sales from Block 2C averaged US$104.23/Bbl in 2014, which represents a premium of US$1.06/Bbl to the reference Brent Crude Oil price.  This price differential was applied to the reference price for the calculation of reserves and revenues.  No price escalation, or cost inflation, has been included in the evaluation.




The gas prices used were based on the gas sales information for 2014 provided by CNOOC.  The gas price forecast was estimated at US$3.78/MMBtu, and this price was maintained for the life of the fields considered in this report.




Actual future prices may vary significantly from the prices required by SEC Rules; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The results of this study are summarized in the following table.  Reserves net to CNOOC are quoted as Net Entitlement Reserves reflecting the terms of the PSC.




Estimated Net Reserves and Financial Data


As at 31st December, 2014





ProvedDeveloped
Undeveloped
Total

ProvedProducing
Non-ProducingNet ReservesOil/Condensate – Mstb
513
0
58
571Gas – MMscf
39,558
0
31,240
70,798Income Data (M$)Future Gross Revenue
$  153,572
$  0
$  100,615
$  254,082Deductions
$   77,600
$  0
$  59,713
$   137,313Future Net Income (FNI)
$  75,972
$  0
$  40,902
$  116,769Discounted FNI @ 10%
$  61,637
$  0
$  23,189
$  84,826







Liquid hydrocarbons are expressed in thousands of standard (42 gallon) barrels (Mstb).  All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMscf) at standard temperature (60 °F) and pressure (14.7 psia).  In this report, the revenues, deductions and income data are expressed in thousands of US dollars (M$).




The future gross revenue represents CNOOC’s net entitlement under the PSC (Cost Recovery plus Profit Share).  Deductions represent CNOOC’s 12.5% share of project Capital Expenditure, Operating Expenditure and Abandonment Costs (ABEX).  Future Net Income represents CNOOC’s Profit Share, net of ABEX, under the terms of the PSC.




The results included herein were prepared in accordance with the disclosure requirements set forth in the SEC Rules and intended for public disclosure as an exhibit in filings made with the SEC by CNOOC.






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BASIS OF OPINION




This document reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by CNOOC, the limited scope of engagement, and the time permitted to conduct the evaluation.




In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein.  GCA has not independently verified any information provided by, or at the direction of, CNOOC, and has accepted the accuracy and completeness of this data.  GCA has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.




The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results.  The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.




In the preparation of this report, GCA has used definitions contained within Part 210 Rule 4-10(a) of Regulation S-X of the US Securities and Exchange Commission (see Attachment I).




There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows.  Oil and gas resources assessments must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way.  Estimates of oil and gas resources prepared by other parties may differ, perhaps materially, from those contained within this report.




The accuracy of any resource estimate is a function of the quality of the available data and of engineering and geological interpretation.  Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material.  Accordingly, resource estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.




Oil and condensate volumes are reported in thousands of standard barrels at stock tank conditions (Mstb). Gas volumes are reported in millions of cubic feet (MMscf) at standard conditions. Standard conditions are defined as 14.7 psia and 60° Fahrenheit.




GCA prepared an independent assessment of the reserves based on data and interpretations provided by CNOOC.




Definition of Reserves




Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce, or a revenue interest in, the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.






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GCA is not aware of any potential changes in regulations applicable to these fields that could affect the ability of CNOOC to produce the estimated reserves.




Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.  All categories of reserves volumes quoted herein have been derived within the context of an economic limit test (ELT) assessment (pre-tax and exclusive of accumulated depreciation amounts) prior to any Net Present Value (NPV) analysis.




Reserves net to CNOOC are quoted as Net Entitlement Reserves, reflecting the terms of the applicable Production Sharing Contract (PSC).  Lease fuel has been excluded from the reserve volumes.




GCA has not undertaken a site visit and inspection because it was not necessary and not required within the scope of work.  As such, GCA is not in a position to comment on the operations or facilities in place, their appropriateness and condition, or whether they are in compliance with the regulations pertaining to such operations.  Further, GCA is not in a position to comment on any aspect of health, safety, or environment of such operation.




This report has been prepared based on GCA’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties.  However, GCA is not in a position to attest to property title or rights, conditions of these rights (including environmental and abandonment obligations), or any necessary licenses and consents (including planning permission, financial interest relationships, or encumbrances thereon for any part of the appraised properties).





Use of Net Present Values




It should be clearly noted that the Net Present Values (NPV) contained herein do not represent a GCA opinion as to the market value of the subject property, nor any interest in it.  In assessing a likely market value, it would be necessary to take into account a number of additional factors (e.g., capability, technology, project approvals, capacity, infrastructure, commercial negotiations, market, and changes to regulatory landscape).




QUALIFICATIONS




In performing this study, GCA is not aware that any conflict of interest has existed.  As an independent consultancy, GCA is providing impartial technical, commercial, and strategic advice within the energy sector.  GCA’s remuneration was not in any way contingent on the contents of this report.




In the preparation of this document, GCA has maintained, and continues to maintain, a strict independent consultant-client relationship with CNOOC.  Furthermore, the management and employees of GCA have no interest in any of the assets evaluated or are related with the analysis performed, as part of this report.




Staff members who prepared this report hold appropriate professional and educational qualifications and have the necessary levels of experience and expertise to perform the work.




The qualifications of the technical person primarily responsible for overseeing this estimate are included in Attachment II.




This letter should not be used for purposes other than those for which it is intended.  This letter should not be reproduced, either in whole or part, without the written permission of GCA.  CNOOC will obtain GCA’s prior written or email approval for the use with third parties and context of the use with third parties of any results, statements or opinions expressed by GCA








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to CNOOC, which are attributed to GCA.  Such requirement of approval shall include, but not be confined to, statements or references in documents of a public or semi-public nature such as loan agreements, prospectuses, reserve statements, websites, press releases, etc.






As independent reserve engineers/advisors for CNOOC, GCA hereby confirms that it has granted and not withdrawn its consent to the references to GCA and to the inclusion of information contained in our report entitled “Executive Report for Reserves Estimation of the Greater Angostura Fields in Block 2C, Trinidad & Tobago as at 31stDecember, 2014” as of 28th February, 2015 prepared for CNOOC, and to the annexation of our report as an exhibit in CNOOC’s annual report on Form20-F for the fiscal year ended 31st December, 2014.







Yours faithfully,


GAFFNEY, CLINE & ASSOCIATES (CONSULTANTS) PTE LTD














/s/Hu Yundong


Project Manager – Dr Hu Yundong


Senior Advisor

















/s/ Stephen Lane


Project Reviewer - Stephen Lane


Technical Director











Attachments:


I.
SEC Reserves Definitions


II.
Technical Qualifications












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Attachment I





SEC Reserve Definitions























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U.S. SECURITIES AND EXCHANGE COMMISSION (SEC)


MODERNIZATION OF OIL AND GAS REPORTING1




Oil and Gas Reserves Definitions and Reporting




(a)           Definitions




(1)           Acquisition of properties.  Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.




(2)           Analogous reservoir.  Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery.  When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:




(i)
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);




(ii)
Same environment of deposition;




(iii)
Similar geological structure; and




(iv)
Same drive mechanism.




Instruction to paragraph (a)(2):  Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.




(3)           Bitumen.  Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.  In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.




(4)           Condensate.  Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.




(5)           Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.




(6)           Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:









1
Extracted from 17 CFR Parts 210, 211, 229, and 249 [Release Nos. 33-8995; 34-59192; FR-78; File No. S7-15-08] RIN 3235-AK00].




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




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




(7)           Development costs.Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:




(i)
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.




(ii)
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.




(iii)
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.




(iv)
Provide improved recovery systems.




(8)           Development project.  A development project is the means by which petroleum resources are brought to the status of economically producible.  As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.




(9)           Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.




(10)         Economically producible.  The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.  The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.




(11)         Estimated ultimate recovery (EUR).  Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.




(12)         Exploration costs.  Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic







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test wells.  Exploration costs may be incurred both before acquiring the related property (sometimes referred to in pail as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:




(i)
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.




(ii)
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.




(iii)
Dry hole contributions and bottom hole contributions.




(iv)
Costs of drilling and equipping exploratory wells.




(v)
Costs of drilling exploratory-type stratigraphic test wells.




(13)         Exploratory well.  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.




(14)         Extension well.  An extension well is a well drilled to extend the limits of a known reservoir.




(15)         Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.




(16)         Oil and gas producing activities.




(i)
Oil and gas producing activities include:




(A)
The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;




(B)
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;




(C)
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:






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(1)
Lifting the oil and gas to the surface; and




(2)
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and




(D)
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.




Instruction 1 to paragraph (a)(16)(i):  The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank.  If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:




a.
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and




b.
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.




Instruction 2 to paragraph (a)(16)(i):  For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.




(ii)
Oil and gas producing activities do not include:




(A)
Transporting, refining, or marketing oil and gas;




(B)
Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;




(C)
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or




(D)
Production of geothermal steam.




(17)         Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.




(i)
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.  When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.






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(ii)
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain.  Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.




(iii)
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.




(iv)
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.




(v)
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir.  Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.




(vi)
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology.  Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.




(18)         Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.




(i)
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves.  When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.




(ii)
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.  Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.






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(iii)
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.




(iv)
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.




(19)         Probabilistic estimate.  The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.




(20)         Production costs.




(i)
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities, they become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:




(A)
Costs of labor to operate the wells and related equipment and facilities.




(B)
Repairs and maintenance.




(C)
Materials, supplies, arid fuel consumed and supplies utilized in operating the wells and related equipment and facilities.




(D)
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.




(E)
Severance taxes.




(ii)
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.




(21)         Proved area.  The part of a property to which proved reserves have been specifically attributed.




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








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(i)
The area of the reservoir considered as proved includes:




(A)
The area identified by drilling and limited by fluid contacts, if any, and




(B)
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.




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




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




(iv)
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:




(A)
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and




(B)
The project has been approved for development by all necessary parties and entities, including governmental entities.




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






(23)         Proved properties.  Properties with proved reserves.




(24)         Reasonable certainty.  If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.  If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.






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(25)          Reliable technology.  Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.




(26)          Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.




Note to paragraph (a)(26):  Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results).  Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).






(27)          Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.




(28)          Resources.  Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations.  A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable.  Resources include both discovered and undiscovered accumulations.






(29)          Service well.  A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.




(30)          Stratigraphic test well.  A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.






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(31)          Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.




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




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




(iii)
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.






(32)          Unproved properties.  Properties with no proved reserves.









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Attachment II





Technical Qualifications















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TECHNICAL QUALIFICATIONS






GCA is an independent international energy advisory group of more than 50 years’ standing, whose expertise includes petroleum reservoir evaluation and economic analysis.




The report is based on information compiled by professional staff members who are full time employees of GCA.




Staff who participated in the compilation of this report include Mr. Stephen M. Lane, Mr. David S. Ahye, Mr. Chew Hai Hong, Mr. Andrew B. Duncan, Mr. Paul McGhee, Dr. Hu Yundong, Dr. Azlan Abdul Majid and Ms. Tianjiao Yan.  All hold degrees in geoscience, petroleum engineering or related discipline.




Mr. Lane holds a BSc (Hons) in Geology, is a member of the Society of Petroleum Engineers and is a very experienced Geoscientist and Petrophysicist with over 30 years’ background in providing geological and petrophysical expertise to clients worldwide.  He has particular involvement as lead petrophysicist/geologist and Project Manager in many oil and gas reserve certifications both for project finance and for SEC reporting purposes, frequent involvement in the valuation of E&P assets for acquisition and divestment purposes and production of public documents such as Competent Person’s Reports.




Mr. Ahye holds a B.Sc (Hons) in Chemical Engineering, is a member of the Society of Petroleum Engineers and the South East Asia Petroleum Exploration Society, and has more than 35 years industry experience worldwide.




Mr. Chew holds a BE (Hons) in Civil Engineering and an MBA, is a member of the Society of Petroleum Engineers, a fellow of Institution of Engineers Malaysia, and a professional engineer registered with the Board of Engineers Malaysia, and has more than 30 years petroleum industry experience.




Mr. Duncan holds a B.Sc in Civil Engineering, is a chartered member of the Institute of Mechanical Engineers, member of the Society of Petroleum Engineers and the Association of International Petroleum Negotiators, and has more than 30 years industry experience.




Mr. McGhee holds a B.Sc (Hons) in Chemical Engineering, is a member of the Society of Petroleum Engineers and the Association of International Petroleum Negotiators, and has more than 25 years industry experience.




Dr. Hu holds a PhD in Petroleum Geology, is a member of the Society of Petroleum Engineers and a Registered Mineral Reserve Evaluator of the P.R. China, and has more than 30 years industry experience in China.




Dr. Majid holds a PhD and a M.Eng. in Chemical Engineering, is a member of the Society of Petroleum Engineers and the Society of Professional Well Log Analysts, and has about 10 years of world-wide experience.




Ms. Yan holds a B.Sc in Economics and Mathematics and a M.Sc in Economics, is a member of the Society of Petroleum Engineers and the Association of International Petroleum Negotiators






AII.1









INDEPENDENT LETTER
 
 THE MISSAN OIL FIELDS IN EASTERN IRAQ
 ESTIMATED PROVED RESERVES AND FINANCIAL DATA, BASED ON SEC RULES
 
 
 Prepared for
 
 CNOOC LIMITED
 
 As at 31stDecember, 2014
 
 
 
 
 
 
 
 February, 2015
 
 
   
 
 GAFFNEY, CLINE & ASSOCIATES (CONSULTANTS) PTE LTD
 
 
 
 
 
 This summary letter is based on Gaffney, Cline & Associates’ official report and has been provided at the request of CNOOC Limited.
   
 
  Gaffney, Cline & Associates

(Consultants) Pte. Ltd.

80 Anson Road

#31-01C Fuji Xerox Towers

Singapore 079907

Telephone:  +65 6225 6951



www.gaffney-cline.comSML/YDH/dh/L0071/2015/PS-14-2092
28th February, 2015
 
 CNOOC Limited
 No. 25, Chaoyangmenbei Dajie
 Dongcheng District
 Beijing 100010, P.R. China
 
 
 Gentlemen:
 
 
 INDEPENDENT LETTER
 
 THE MISSAN OIL FIELDS IN EASTERN IRAQ
 ESTIMATED PROVED RESERVES AND FINANCIAL DATA, BASED ON SEC RULES
 As at 31stDecember, 2014
 
  At the request of CNOOC Limited (CNOOC), Gaffney, Cline & Associates (GCA) has prepared an independent estimate of the proved reserves and financial data attributable to certain participating interests owned by CNOOC as at 31st December, 2014.  The reserves and income data were estimated based on Rules of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released 14th January, 2009 in the Federal Register, including all references to Regulation S-X and Regulation S-K (SEC Rules).  GCA’s independent study, completed on 28th February, 2015 and summarized herein, was prepared for public disclosure by CNOOC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC Rules.  In GCA’s opinion, the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose and have been carried out in line with the SEC Oil and Gas Reserves Definitions attached hereto as an Attachment.
  The subject properties of the Missan Oil Fields (Missan) are located in eastern Iraq, 350km southeast of Baghdad.  Based on information provided by CNOOC, the Proved reserves estimates for properties evaluated by GCA for this report represent approximately 0.5 percent of CNOOC’s total net proved reserves as at 31st December, 2014. GCA is not in a position to verify this statement as it was not requested to review all CNOOC’s other oil and gas assets.
  CNOOC have signed a 20-year Technical Service Contract (TSC) with the Missan Oil Company of The Iraqi Ministry of Oil (MOC) for the rehabilitation of improved production and enhanced recovery of petroleum from Missan.  CNOOC is the lead contractor of, and holds a 63.75% participating interest in, the project.
  The oil reserves and financial data reported herein were estimated on the basis of SEC Rules.  GCA has classified as Reserves those hydrocarbon volumes that would be economically recoverable as a result of implementing the Rehabilitation Plan only.


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In line with the foregoing, the statement of reserves, presented herein, is based on a program that is expected to be superseded by the redevelopment activities proposed under the Enhanced Redevelopment Period (ERP) submitted by CNOOC in 2014.  As such, the volumes actually recovered under the enlarged plan are expected to be significantly greater than those presented.  However, should the ERP not be approved, it is possible that CNOOC would be seen as in default of the contract and there could be an early termination and a consequential reduction in reserves.
  Under the terms of the TSC, the Contractor is entitled to use any quantity of Associated Gas from the oil reservoirs necessary for Petroleum Operations and for power generation.  However, all Associated Gas that is not used in Petroleum Operations or for power generation “shall be delivered unprocessed to MOC”.  Thus, the contractor has no entitlement to any gas reserves.
  Economic models were constructed based on terms of the TSC as provided by CNOOC, in order to calculate CNOOC’s Net Entitlement volumes, which are made up of CNOOC’s share of Service Fees (Petroleum Cost Recovery and Remuneration Fees) plus Supplementary Fees, converted to volumetric equivalents.  The economic tests for the reserve volumes as at 31st December, 2014 were based on a prior twelve-month first-day-of-the-month average reference price for UK North Sea Brent crude of US$101.30/barrel, corrected for location and quality to an average sales price of US$94.38/Bbl.  No price escalation, or cost inflation, has been included in the evaluation.
  Future capital costs were derived from development plans prepared by CNOOC for the field.  Recent historical operating expense data were utilized as the basis for operating cost projections.  GCA found that CNOOC has projected sufficient capital investments and operating expenses to produce economically the projected volumes recoverable from the development activities planned under the Rehabilitation Plan of the contract.
  Actual future prices may vary significantly from the prices required by SEC Rules; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The results of this study are summarized in the following table.  Reserves net to CNOOC are quoted as Net Entitlement Reserves reflecting the terms of the TSC.
  Estimated Net Reserves and Financial Data
 As at 31st December, 2014
 
 ProvedDeveloped
Undeveloped
Total

ProvedProducing
Non-ProducingNet ReservesOil/Condensate – Mstb
4,789
0
19,225
24,014Income Data (M$)Future Gross Revenue
$ 556,012.1
$ 0
$ 1,691,514.0
$ 2,247,526.1Deductions
$ 480,788.7
$ 0
$ 1,645,657.6
$ 2,126,446.3Future Net Income (FNI)
$ 75,223.4
$ 0
$ 45,856.4
$ 121,079.8Discounted FNI @ 10%
$ 67,351.4
$ 0
-$ 42,545.6
$ 24,805.8
  Liquid hydrocarbons are expressed in thousands of standard (42 gallon) barrels (MBbl).  In this report, the revenues, deductions and income data are expressed in thousands of US dollars (M$).
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 The future gross revenue represents CNOOC’s net entitlement share of Service Fees (Petroleum Cost Recovery plus Remuneration Fees) due under the Technical Service Contract (TSC).  Deductions represent CNOOC’s 85% (i.e. 63.75%/75% of total project) share of project Capital Expenditure, Operating Expenditure, contractual Supplementary Costs, State partner ‘carry’ and Training Fees.  Future Net Income represents CNOOC’s Future Gross Revenue less costs incurred, and on a post-tax basis, under the terms of the TSC.
  The results included herein were prepared in accordance with the disclosure requirements set forth in the SEC Rules and intended for public disclosure as an exhibit in filings made with the SEC by CNOOC.
  BASIS OF OPINION
  This document reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by CNOOC, the limited scope of engagement, and the time permitted to conduct the evaluation.
  In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein.  GCA has not independently verified any information provided by, or at the direction of, CNOOC, and has accepted the accuracy and completeness of this data.  GCA has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.
  The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results.  The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.
  In the preparation of this report, GCA has used definitions contained within Part 210 Rule 4-10(a) of Regulation S-X of the US Securities and Exchange Commission (see Attachment I).
  There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows.  Oil and gas resources assessments must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way.  Estimates of oil and gas resources prepared by other parties may differ, perhaps materially, from those contained within this report.
  The accuracy of any resource estimate is a function of the quality of the available data and of engineering and geological interpretation.  Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material.  Accordingly, resource estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.
  Oil and condensate volumes are reported in thousands of standard barrels at stock tank conditions (MMstb). Standard conditions are defined as 14.7 psia and 60° Fahrenheit.
  GCA prepared an independent assessment of the reserves based on data and interpretations provided by CNOOC.
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  Definition of Reserves
 
 Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce, or a revenue interest in, the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
  GCA is not aware of any potential changes in regulations applicable to these fields that could affect the ability of CNOOC to produce the estimated reserves.
  Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.  All categories of reserves volumes quoted herein have been derived within the context of an economic limit test (ELT) assessment (pre-tax and exclusive of accumulated depreciation amounts) prior to any Net Present Value (NPV) analysis.
  Reserves net to CNOOC are quoted as Net Entitlement Reserves, reflecting the terms of the applicable Technical Service Contract (TSC).  Lease fuel has been excluded from the reserve volumes.
  GCA has not undertaken a site visit and inspection because it was not required within the scope of work.  As such, GCA is not in a position to comment on the operations or facilities in place, their appropriateness and condition, or whether they are in compliance with the regulations pertaining to such operations.  Further, GCA is not in a position to comment on any aspect of health, safety, or environment of such operation.
  This report has been prepared based on GCA’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties.  However, GCA is not in a position to attest to property title or rights, conditions of these rights (including environmental and abandonment obligations), or any necessary licenses and consents (including planning permission, financial interest relationships, or encumbrances thereon for any part of the appraised properties).
 
 Use of Net Present Values
  It should be clearly noted that the Net Present Values (NPV) contained herein do not represent a GCA opinion as to the market value of the subject property, nor any interest in it.  In assessing a likely market value, it would be necessary to take into account a number of additional factors (e.g., capability, technology, project approvals, capacity, infrastructure, commercial negotiations, market, and changes to regulatory landscape).
  QUALIFICATIONS
  In performing this study, GCA is not aware that any conflict of interest has existed.  As an independent consultancy, GCA is providing impartial technical, commercial, and strategic advice within the energy sector.  GCA’s remuneration was not in any way contingent on the contents of this report.
  In the preparation of this document, GCA has maintained, and continues to maintain, a strict independent consultant-client relationship with CNOOC.  Furthermore, the management and employees of GCA have no interest in any of the assets evaluated or are related with the analysis performed, as part of this report.
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  Staff members who prepared this report hold appropriate professional and educational qualifications and have the necessary levels of experience and expertise to perform the work.
  The qualifications of the technical person primarily responsible for overseeing this estimate are included in Attachment II.
  This letter should not be used for purposes other than those for which it is intended.  This letter should not be reproduced, either in whole or part, without the written permission of GCA.  CNOOC will obtain GCA’s prior written or email approval for the use with third parties and context of the use with third parties of any results, statements or opinions expressed by GCA to CNOOC, which are attributed to GCA.  Such requirement of approval shall include, but not be confined to, statements or references in documents of a public or semi-public nature such as loan agreements, prospectuses, reserve statements, websites, press releases, etc.
  As independent reserve engineers/advisors for CNOOC, GCA hereby confirms that it has granted and not withdrawn its consent to the references to GCA and to the inclusion of information contained in our report entitled “Executive Report for Reserves Estimation of the Missan Fields in Eastern Iraq as at 31stDecember, 2014” as of 28th February, 2015 prepared for CNOOC, and to the annexation of our report as an exhibit in CNOOC’s annual report on Form20-F for the fiscal year ended 31st December, 2014.
  
 Yours faithfully,
 GAFFNEY, CLINE & ASSOCIATES (CONSULTANTS) PTE LTD
 
 
 /s/Hu Yundong
 Project Manager – Dr Hu Yundong
 Senior Advisor
 
 
 /s/Stephen M. Lane
 Project Reviewer - Stephen M. Lane
 Technical Director
 
 
 Attachments:
 I.
SEC Reserves Definitions
 II.
Technical Qualifications
 
 
 
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 Attachment I
 
 SEC Reserve Definitions
 
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 U.S. SECURITIES AND EXCHANGE COMMISSION (SEC)
 MODERNIZATION OF OIL AND GAS REPORTING1
  Oil and Gas Reserves Definitions and Reporting
  (a)           Definitions
  (1)           Acquisition of properties.  Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.
  (2)           Analogous reservoir.  Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery.  When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
  (i)
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
  (ii)
Same environment of deposition;
  (iii)
Similar geological structure; and
  (iv)
Same drive mechanism.
  Instruction to paragraph (a)(2):  Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
  (3)           Bitumen.  Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.  In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
  (4)           Condensate.  Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
  (5)           Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
  (6)           Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
  
 1
Extracted from 17 CFR Parts 210, 211, 229, and 249 [Release Nos. 33-8995; 34-59192; FR-78; File No. S7-15-08] RIN 3235-AK00].
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   (i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
  (ii)
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
  (7)           Development costs.Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
  (i)
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
  (ii)
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
  (iii)
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
  (iv)
Provide improved recovery systems.
  (8)           Development project.  A development project is the means by which petroleum resources are brought to the status of economically producible.  As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
  (9)           Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
  (10)         Economically producible.  The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.  The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
  (11)         Estimated ultimate recovery (EUR).  Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
  (12)         Exploration costs.  Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic
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 test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in pail as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
  (i)
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
  (ii)
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
  (iii)
Dry hole contributions and bottom hole contributions.
  (iv)
Costs of drilling and equipping exploratory wells.
  (v)
Costs of drilling exploratory-type stratigraphic test wells.
  (13)         Exploratory well.  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
  (14)         Extension well.  An extension well is a well drilled to extend the limits of a known reservoir.
  (15)         Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
  (16)         Oil and gas producing activities.
  (i)
Oil and gas producing activities include:
  (A)
The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;
  (B)
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
  (C)
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
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    (1)
Lifting the oil and gas to the surface; and
  (2)
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
  (D)
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
  Instruction 1 to paragraph (a)(16)(i):  The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank.  If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
  a.
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
  b.
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
  Instruction 2 to paragraph (a)(16)(i):  For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
  (ii)
Oil and gas producing activities do not include:
  (A)
Transporting, refining, or marketing oil and gas;
  (B)
Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
  (C)
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
  (D)
Production of geothermal steam.
  (17)         Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
  (i)
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.  When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
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   (ii)
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain.  Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
  (iii)
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
  (iv)
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
  (v)
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir.  Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
  (vi)
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology.  Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
  (18)         Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
  (i)
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves.  When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
  (ii)
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.  Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
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   (iii)
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
  (iv)
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
  (19)         Probabilistic estimate.  The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
  (20)         Production costs.
  (i)
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities, they become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
  (A)
Costs of labor to operate the wells and related equipment and facilities.
  (B)
Repairs and maintenance.
  (C)
Materials, supplies, arid fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
  (D)
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
  (E)
Severance taxes.
  (ii)
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
  (21)         Proved area.  The part of a property to which proved reserves have been specifically attributed.
  (22)         Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
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   (i)
The area of the reservoir considered as proved includes:
  (A)
The area identified by drilling and limited by fluid contacts, if any, and
  (B)
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
  (ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
  (iii)
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
  (iv)
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
  (A)
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
  (B)
The project has been approved for development by all necessary parties and entities, including governmental entities.
  (v)
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.  The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
   (23)         Proved properties.  Properties with proved reserves.
  (24)         Reasonable certainty.  If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.  If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
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 (25)         Reliable technology.  Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
  (26)         Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
  Note to paragraph (a)(26):  Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results).  Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
  (27)         Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
  (28)         Resources.  Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations.  A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable.  Resources include both discovered and undiscovered accumulations.
  (29)         Service well.  A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
  (30)         Stratigraphic test well.  A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
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  (31)         Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
  (i)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
  (ii)
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless  the specific circumstances, justify a longer time.
  (iii)
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
  (32)         Unproved properties.  Properties with no proved reserves.
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 Attachment II
 
 Technical Qualifications
 
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 TECHNICAL QUALIFICATIONS
 
  GCA is an independent international energy advisory group of 50 years’ standing, whose expertise includes petroleum reservoir evaluation and economic analysis.
  The report is based on information compiled by professional staff members who are full time employees of GCA. Staff who participated in the compilation of this report mainly include Mr. Stephen M. Lane, Dr. Hu Yundong, Mr. Gary William Holmes, Mr. Adam K. Becis and Mr. Paul McGhee.  All hold degrees in geoscience, petroleum engineering or related discipline.
  Mr. Lane holds a BSc (Hons) in Geology, is a member of the Society of Petroleum Engineers and is a very experienced Geoscientist and Petrophysicist with over 30 years’ background in providing geological and petrophysical expertise to clients worldwide.  He has particular involvement as lead petrophysicist/geologist and Project Manager in many oil and gas reserve certifications both for project finance and for SEC reporting purposes, frequent involvement in the valuation of E&P assets for acquisition and divestment purposes and production of public documents such as Competent Person’s Reports.
  Dr. Hu holds a PhD in Petroleum Geology, is a member of the Society of Petroleum Engineers and a Registered Mineral Reserve Evaluator of the P.R. China, and has more than 30 years industry experience in China.
  Mr. Holmes holds a BSc (Hons) in Geology and Geography, is a member of Society of Petroleum Engineers, Petroleum Exploration Society of Great Britain, South East Asia Petroleum Exploration Society and London Petrophysical Society, and has 30 years international experience in Exploration and Production, with key strengths includes innovative approach to integrated formation evaluation, field studies and operations.
  Mr. Becis holds a Master of Business Administration, a BSc in Commerce and a BSc in Petroleum Engineering, is a member of the Society of Petroleum Engineers, the Southeast Asia Petroleum Exploration Society and the Australian Chamber of Commerce - Singapore. He is Reservoir Engineer with 8 years of world-wide experience.
  Mr. McGhee holds a B.Sc in Chemical Engineering, is a member of the Society of Petroleum Engineers and the Association of International Petroleum Negotiators, and has more than 25 years industry experience, with a background in the fiscal modeling and economic evaluation of numerous petroleum producing nations.




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