Exhibit 15.2

Gaffney,

Cline &

Associates

THIRD PARTY REPORT

RESERVES ESTIMATION AND EVALUATION OF

CHAD AND ALGERIA ASSETS

AS OF 31^st DECEMBER, 2013

Prepared for

PETROCHINA COMPANY LIMITED

FEBRUARY, 2014

www.gaffney-cline.com

PetroChina Copy No. 1 PS-13-2115 & PS-13-2116

Gaffney,

Cline &

Associates

		Page No.
INTRODUCTION			1
METHODOLOGY			2
1.	RESULTS SUMMARY		3
	1.1    Net Reserves		3
	1.2    Gross Volumes		3
	1.3    Net Present Values		4
	1.4    Sensitivity Analysis		4
2.	QUALIFICATIONS		5
3.	BASIS OF OPINION		5
APPENDICES
I.	SEC Reserve Definitions
II.	Glossary

Gaffney,

Cline &

Associates

Gaffney, Cline & Associates

(Consultants) Pte. Ltd.

80 Anson Road

#31-01C Fuji Xerox Towers

Singapore 079907

Telephone: +65 6225 6951

www.gaffney-cline.com

DSR/jbi/L0062/2014/PS-13-2115 & PS-13-2116 26^th February,  2014

PetroChina Company Limited

9 Dongzhimen North Street, Dongcheng District

Beijing 100007

China

Dear Gentlemen,

THIRD PARTY REPORT

RESERVES ESTIMATION AND VALUATION OF

CHAD AND ALGERIA ASSETS

AS OF 31^st DECEMBER, 2013

INTRODUCTION

Gaffney, Cline & Associates (“GCA”) was requested by China National Oil and Gas Exploration and Development Corporation International Holding Ltd. (“CNODCI”), to conduct reserves estimation and evaluation (as of 31^st December, 2013) of selected petroleum assets in Algeria, Chad, and Venezuela, in which CNODCI has current interests.

The SEC Executive and SEC Technical Reports documenting this work were submitted to CNODCI in January and February, 2014, respectively. These reports are required for CNODCI internal management reporting purposes and are limited to Proved Reserves only. The report references are as follows:

Asset	SEC Executive Report	SEC Technical Report
Algeria and Venezuela	DSR/jbi/L0015/2014/PS-13-2115 dated 29th January, 2014	DSR/jbi/L0043/2014/PS-13-2115 dated 14th February, 2014
Chad	DSR/jbi/L0025/2014/PS-13-2116 dated 29th January, 2014	DSR/jbi/L0049/2014/PS-13-2116 dated 14th February, 2014

Recently, CNODCI requested GCA to prepare a Third Party Report intended to be submitted to PetroChina Company Limited (“PetroChina”). This report is to summarize the results of reserves estimation and evaluation as of 31^st December, 2013 as mentioned above of only selected petroleum assets. The selected petroleum assets, as determined by CNODCI, are in Chad and Algeria.

UEN: 198701453N

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METHODOLOGY

In carrying out the review, GCA relied upon information and data provided by CNODCI, which comprised: basic engineering data; geoscience information and engineering interpretations associated with such data; other technical reports; costs and commercial data; and development plans. The available data and interpretations were reviewed for reasonableness and the latter adjusted where appropriate.

The results presented in this report are based upon information and data made available to GCA on or before 19^th December, 2013. The Reserve Estimates, forward production estimates and Net Present Value (NPV) computations as presented herein are based upon these data and represent GCA’s opinion as of 31^st December, 2013.

Economic models were constructed based on terms of the applicable petroleum contracts as provided by CNODCI, in order to calculate CNODCI’s net revenue interest Proved reserves. As of 31^st December, 2013, all Proved SEC¹ reserves were allocated up to the end of the license contract period only.

As per SEC guidelines (Appendix I), the oil prices which were used in the evaluation are the un-weighted 12-month arithmetic averages of the first-day-of-the month price for each month within the 12-month period (January to December, 2013) prior to the end of reporting period, unless prescribed by contract. Those prices were held constant throughout the evaluation period except where alternate prices are prescribed by contract. The report also summarises the sensitivity results in which oil prices were escalated throughout the evaluation period except as prescribed by contract. The historical 12-month oil prices were supplied by CNODCI.

Future capital costs were derived from development program forecasts prepared by CNODCI for each production unit and corresponding recent historical unit cost data. The recent historical cost data for each relevant production unit were utilised to determine current operating cost conditions. These costs were not escalated throughout the evaluation period in the Base Case; however the future capital and operating costs were escalated in the sensitivity analysis.

CNODCI’s net reserve volumes are derived by converting calculated net revenues accruing to CNODCI under the terms of the relevant petroleum contract into equivalent barrels of oil utilising the average 2013 oil pricing explained above. The CNODCI net revenue interest volumes reported in this document represent those amounts that are determined to be attributable to CNODCI’s net economic interest after the deduction of amounts attributable to third parties (government and other working interest partners).

Net Present Value (NPV) computations were also undertaken and derived using cost and production profiles input to the various economic models established for the selected assets in Algeria and Venezuela. These NPVs represent future net revenue, after taxes, attributable to the interests of CNODCI, discounted over the economic life of the project at a specified discount rate to a present value as of 31^st December, 2013. NPV results are also presented for the sensitivity analysis using the escalated oil prices and capital and operating costs. Unless otherwise stated, no opening tax positions were considered.

A glossary of abbreviations and key industry standard terms, some but not all of which have been used in this report, is attached as Appendix II.

¹  US Securities and Exchange Commission

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1. RESULTS SUMMARY

1.1 Net Reserves

The following tables present the net entitlement Proved Developed, Proved Undeveloped and Total Proved oil reserves attributable to CNODCI’s working interests (WI) estimated in accordance with SEC guidelines.

As required under SEC guidelines, these estimates were prepared under the prevailing fiscal terms and exclude any government share. The economic cut offs were applied using costs which are unescalated throughout the period of calculation and constant prices, except where alternate prices are prescribed by contract. The oil prices used for these computations were the un-weighted 12-month arithmetic average of the first-day-of-the month price for each month within the 12-month period (January to December, 2013).

NET ENTITLEMENT PROVED OIL RESERVES

AS OF 31^st DECEMBER, 2013

Country	Proved Developed (Mstb)		Proved Undeveloped (Mstb)		Total Proved (Mstb)
Algeria – Adrar		5,451		—		5,451
Chad – Permit H		50,836		64,596		115,432
TOTAL CNODCI		56,287		64,596		120,883

Notes:

1. The net entitlement in Adrar is attributable to CNODCI’s 49% net interest.

2. CNODCI holds 100% WI in Permit H. Royalty in Permit H is paid in kind; therefore, it is deducted from the Gross Reserves volumes.

3. Both assets produce oil only. Gas has been discovered in some structures in Permit H, but there is no market as yet.

4. Totals may not add exactly due to rounding errors.

1.2 Gross Volumes

Gross production volumes are presented for reference information only. They represent a 100% total in commercially recoverable volumes, i.e. after economic cutoffs have been applied. Gross volumes include volumes attributable to third parties, government and other working interest partners.

GROSS PROVED OIL RESERVES

AS OF 31^st DECEMBER, 2013

Country	Proved Developed (Mstb)		Proved Undeveloped (Mstb)		Total Proved (Mstb)
Algeria – Adrar		11,132		—		11,132
Chad – Permit H		58,098		73,824		131,922
TOTAL CNODCI		69,231		73,824		143,055

Note: Totals may not add exactly due to rounding errors.

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1.3 Net Present Values

The NPVs as of 31^st December, 2013 of estimated cash flows discounted at 10%, after taxes, attributable to CNODCI’s working interest in the projects identified above (excluding any balance sheet adjustments or financing costs), are summarised below.

NET PRESENT VALUES ATTRIBUTABLE TO CNODCI

AS OF 31^st DECEMBER, 2013

DISCOUNT RATE 10%

Country	Proved Developed (US$ MM)		Proved Undeveloped (US$ MM)		Total Proved (US$ MM)
Algeria – Adrar		64		—		64
Chad – Permit H		1,387		867		2,255
TOTAL CNODCI		1,451		867		2,319

Notes:

1. NPVs in Adrar and Permit H represent CNODCI’s 49% and 100% WI, respectively.

2. No opening tax positions or un-recovered balances are available for Adrar.

3. The average Adrar net-back price received in year 2013 per Contract is US$21.14/Bbl.

4. Permit H domestic crude price per Contract is US$65.20/Bbl. The average exported crude price is US$88.64/Bbl.

5. Loss carried forward in Permit H based on the CNODCI information as of 31^st December, 2013 is US$285.95 MM.

6. Mid-year discounted cash flow.

The NPVs were calculated on the basis of SEC guidelines under which the economic cut-offs were applied using unescalated costs and constant prices. The crude oil prices used for these computations were the un-weighted 12-month arithmetic average of the first-day-of-the month price for each month within the 12-month period (January to December, 2013) except in instances where alternate prices are prescribed by contract.

1.4 Sensitivity Analysis

Sensitivity analysis has been carried out on the oil prices. In the sensitivity analysis, a future crude oil price scenario was adopted and oil prices were also escalated throughout the evaluation period, except where prescribed by contract. In addition to the escalated oil prices, CAPEX and OPEX were also escalated. The sensitivity results are summarised in the following table.

NET PRESENT VALUES ATTRIBUTABLE TO CNODCI

SENSITIVITY RESULTS

AS OF 31^st DECEMBER, 2013

DISCOUNT RATE 10%

Country	Proved Developed (US$ MM)		Proved Undeveloped (US$ MM)		Total Proved (US$ MM)
Algeria – Adrar		66		—		66
Chad – Permit H		1,338		684		2,022
TOTAL CNODCI		1,404		684		2,088

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Notes:

1. NPVs in Adrar and Permit H represent CNODCI’s 49% and 100% WI, respectively.

2. No opening tax positions or un-recovered balances are available for Adrar.

3. Loss carried forward in Permit H based on the CNODCI information as of 31^st December, 2013 is US$285.95 MM.

4. Mid-year discounted cash flow.

2. QUALIFICATIONS

This report has been compiled under the supervision of Mr. Stephen A. Sakowski and Ms. Dewi S. Redjeki. Mr. Stephen A. Sakowski is a Technical Director and Ms. Dewi S. Redjeki is a Senior Advisor. Both of them are based in Singapore.

Mr. Sakowski has over 35 years’ experience in the petroleum industry and has managed numerous reserves audits. Mr. Sakowski has a Master’s Degree in Mechanical Engineering from McGill University, Montreal, Canada in year 1975 and a Master’s Certificate in Project Management from Texas A&M University, USA. He is a member of Society of Petroleum Engineers (SPE), Association of Professional Engineers and Geoscientists of Alberta (APEGA), and Project Management Institute (PMI).

Ms. Redjeki has over 20 years’ experience in the petroleum industry and has managed numerous reserves audits. Ms. Redjeki holds a B.Sc equivalent degree in Metallurgical Engineering from University of Indonesia, Depok, Indonesia in year 1992 and an MBA degree from IPMI Business School (affiliated to Monash University, Australia) in Jakarta, Indonesia in year 2000. She is a member of the Indonesian Petroleum Association (IATMI & IPA), South East Asia Petroleum Exploration Society (SEAPEX) and Society of Petroleum Engineers (SPE).

3. BASIS OF OPINION

This document must be considered in its entirety. It reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the CNODCI, and/or obtained from other sources e.g. public domain, 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 the CNODCI, and has accepted the accuracy and completeness of these data. GCA has no reason to believe that any material facts have been withheld from it, 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 engineering and geoscience 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.

This assessment has been conducted within the context of 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

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attest to property title or rights, conditions of these rights including environmental and abandonment obligations, and any necessary licenses and consents including planning permission, financial interest relationships or encumbrances thereon for any part of the appraised properties.

In carrying out 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 CNODCI. Furthermore, the management and employees of GCA have no interest in any of the assets evaluated or related with the analysis carried out as part of this report.

Staff members who prepared this report are professionally-qualified with appropriate educational qualifications and levels of experience and expertise to perform the scope of work set out in the Proposal for Services.

GCA has not undertaken a site visit and inspection because it is not included in the scope of work and its related budget. As such, GCA is not in a position to comment on the operations or facilities in place, their appropriateness and condition and 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.

It should be clearly noted that the Net Present Values (NPVs) contained herein do not represent a GCA opinion as to the market value of the subject property, nor any interest in it.

In assessing a likely market value, it would be necessary to take into account a number of additional factors including: reserves risk (i.e. that Proved and/or Probable and/or Possible Reserves may not be realized within the anticipated timeframe for their exploitation); perceptions of economic and sovereign risk; potential upside, such as in this case exploitation of reserves beyond the Proved and the Probable level; other benefits, encumbrances or charges that may pertain to a particular interest; and the competitive state of the market at the time. GCA has explicitly not taken such factors into account in deriving the reference NPVs presented herein.

In the preparation of this report GCA has used Part 210 Rule 4-10(a) of Regulation S-X of the United States Securities and Exchange Commission (Appendix I).

There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas reserve engineering and resource assessment 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 reserves or resources prepared by other parties may differ, perhaps materially, from those contained within this report. The accuracy of any reserve 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, reserve 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 appearing in this report have been quoted at stock tank conditions. Typically these volumes have been referred to in million barrel increments (MMstb). Natural gas volumes have been quoted in billions of standard cubic feet (Bscf) and are volumes of sales gas, after an allocation has been made for fuel and process shrinkage losses. Standard conditions are defined as 14.696 psia and 60° Fahrenheit.

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

It is GCA’s opinion that the estimates of Proved Developed and Total Proved of oil and gas volumes at 31^st December, 2013, are, in the aggregate, reasonable and the reserves classification and categorization is appropriate and consistent with the definitions and guidelines for reserves.

Reserves are those quantities of petroleum that are anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial and remaining (as of the evaluation date) based on the development project(s) applied. 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 Reserve volumes quoted herein have been determined within the context of an economic limit test (pre-tax and exclusive of accumulated depreciation amounts) assessment prior to any NPV analysis.

Yours faithfully,

GAFFNEY, CLINE & ASSOCIATES (CONSULTANTS) PTE LTD

Dewi Sri Redjeki

Senior Advisor

Project Manager

Stephen Sakowski

Technical Director

Project Reviewer

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APPENDIX I

SEC RESERVE DEFINITIONS

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U.S. SECURITIES AND EXCHANGE COMMISSION (SEC)

MODERNIZATION OF OIL AND GAS REPORTING²

Oil and Gas Reserves Definitions and Reporting

(a) Definitions

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

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

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

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

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

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

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

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

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

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

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

²  Extracted from 17 CFR Parts 210, 211, 229, and 249 [Release Nos. 33-8995: 34-59192: FR-78; File No. S7-15-08] RIN 3235-AK00].

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

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

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

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

(iv) Provide improved recovery systems.

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

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

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

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

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in pail as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

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

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

(iii) Dry hole contributions and bottom hole contributions.

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(iv) Costs of drilling and equipping exploratory wells.

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

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

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

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

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

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

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

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

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

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

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

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

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

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to 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.

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

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

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

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

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

(D) Production of geothermal steam.

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

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

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

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

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

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

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of 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.

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

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

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

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

(20) Production costs.

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

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

(B) Repairs and maintenance.

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

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

(E) Severance taxes.

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

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

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

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

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

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(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.

(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.

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Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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

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

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

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

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

(i) Reserves on undrilled acreage shall be limited to those directly offsetting 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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APPENDIX II

GLOSSARY

DSR/jbi/L0062/2014/PS-13-2115 & PS-13-2116 PetroChina (Third Party Report) Gaffney, Cline & Associates

List of Standard Oil Industry Terms and Abbreviations

ABEX	Abandonment Expenditure	g/cc	grams per cubic centimetre
ACQ	Annual Contract Quantity	Gal	gallon
oAPI	Degrees API (American Petroleum Institute)	gal/d	gallons per day
AAPG	American Association of Petroleum Geologists	G&A	General and Administrative costs
AVO	Amplitude versus Offset	GBP	Pounds Sterling
A$	Australian Dollars	GDT	Gas Down to
B	Billion (109)	GIIP	Gas initially in place
Bbl	Barrels	GJ	Gigajoules (one billion Joules)
/Bbl	per barrel	GOR	Gas Oil Ratio
BBbl	Billion Barrels	GTL	Gas to Liquids
BHA	Bottom Hole Assembly	GWC	Gas water contact
BHC	Bottom Hole Compensated	HDT	Hydrocarbons Down to
Bscf or Bcf	Billion standard cubic feet	HSE	Health, Safety and Environment
Bscfd or Bcfd	Billion standard cubic feet per day	HSFO	High Sulphur Fuel Oil
Bm3	Billion cubic metres	HUT	Hydrocarbons up to
Bcpd	Barrels of condensate per day	H2S	Hydrogen Sulphide
BHP	Bottom Hole Pressure	IOR	Improved Oil Recovery
Blpd	Barrels of liquid per day	IPP	Independent Power Producer
Bpd	Barrels per day	IRR	Internal Rate of Return
Boe	Barrels of oil equivalent @xxx mcf/Bbl	J	Joule (Metric measurement of energy) 1 kilojoule = 0.9478 BTU)
boepd	Barrels of oil equivalent per day @ xxx mcf/Bbl	k	Permeability
BOP	Blow Out Preventer	KB	Kelly Bushing
Bopd	Barrels oil per day	KJ	Kilojoules (one Thousand Joules)
Bwpd	Barrels of water per day	kl	Kilolitres
BS&W	Bottom sediment and water	km	Kilometres
BTU	British Thermal Units	km2	Square kilometres
Bwpd	Barrels water per day	kPa	Thousands of Pascals (measurement of pressure)
CBM	Coal Bed Methane	KW	Kilowatt
CO2	Carbon Dioxide	KWh	Kilowatt hour
CAPEX	Capital Expenditure	LKG	Lowest Known Gas
CCGT	Combined Cycle Gas Turbine	LKH	Lowest Known Hydrocarbons
cm	centimetres	LKO	Lowest Known Oil
CMM	Coal Mine Methane	LNG	Liquefied Natural Gas
CNG	Compressed Natural Gas	LoF	Life of Field
Cp	Centipoise (a measure of viscosity)	LPG	Liquefied Petroleum Gas
CSG	Coal Seam Gas	LTI	Lost Time Injury
CT	Corporation Tax	LWD	Logging while drilling
DCQ	Daily Contract Quantity	m	Metres
Deg C	Degrees Celsius	M	Thousand
Deg F	Degrees Fahrenheit	m3	Cubic metres

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DHI	Direct Hydrocarbon Indicator	Mcf or Mscf	Thousand standard cubic feet
DST	Drill Stem Test	MCM	Management Committee Meeting
DWT	Dead-weight ton	MMcf or MMscf	Million standard cubic feet
E&A	Exploration & Appraisal	m3d	Cubic metres per day
E&P	Exploration and Production	mD	Measure of Permeability in millidarcies
EBIT	Earnings before Interest and Tax	MD	Measured Depth
EBITDA	Earnings before interest, tax, depreciation and amortisation	MDT	Modular Dynamic Tester
El	Entitlement Interest	Mean	Arithmetic average of a set of numbers
EIA	Environmental Impact Assessment	Median	Middle value in a set of values
EMV	Expected Monetary Value	MFT	Multi Formation Tester
EOR	Enhanced Oil Recovery	mg/l	milligrams per litre
EUR	Estimated Ultimate Recovery	MJ	Megajoules (One Million Joules)
FEED	Front End Engineering and Design	Mm3	Thousand Cubic metres
FPSO	Floating Production, Storage and Offloading	Mm3d	Thousand Cubic metres per day
FSO	Floating Storage and Offloading	MM	Million
Ft	Foot/feet	MMBbl	Millions of barrels
Fx	Foreign Exchange Rate	MMBTU	Millions of British Thermal Units
G	gram	Mode	Value that exists most frequently in a set of values = most likely
Mscfd	Thousand standard cubic feet per day	scf/ton	Standard cubic foot per ton
MMscfd	Million standard cubic feet per day	SL	Straight line (for depreciation)
MW	Megawatt	So	Oil Saturation
MWD	Measuring While Drilling	SPE	Society of Petroleum Engineers
MWh	Megawatt hour	SPEE	Society of Petroleum Evaluation Engineers
mya	Million years ago	Ss	Subsea
NGL	Natural Gas Liquids	Stb	Stock tank barrel
N2	Nitrogen	STOIIP	Stock tank oil initially in place
NPV	Net Present Value	Sw	Water Saturation
OBM	Oil Based Mud	T	Tonnes
OCM	Operating Committee Meeting	TD	Total Depth
ODT	Oil down to	Te	Tonnes equivalent
OPEX	Operating Expenditure	THP	Tubing Head Pressure
OWC	Oil Water Contact	TJ	Terajoules (1012 Joules)
p.a.	Per annum	Tscf or Tcf	Trillion standard cubic feet
Pa	Pascals (metric measurement of pressure)	TCM	Technical Committee Meeting
p.a.	Per annum	TOC	Total Organic Carbon
Pa	Pascals (metric measurement of pressure)	TOP	Take or Pay
P&A	Plugged and Abandoned	Tpd	Tonnes per day
PDP	Proved Developed Producing	TVD	True Vertical Depth

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PI	Productivity Index	TVDss	True Vertical Depth Subsea
PJ	Petajoules (1015 Joules)	USGS	United States Geological Survey
PSDM	Post Stack Depth Migration	US$	United States Dollar
Psi	Pounds per square inch	VSP	Vertical Seismic Profiling
Psia	Pounds per square inch absolute	WC	Water Cut
Psig	Pounds per square inch gauge	Wl	Working Interest
PUD	Proved Undeveloped	WPC	World Petroleum Council
PVT	Pressure volume temperature	WTI	West Texas Intermediate
P10	10% Probability	wt%	Weight percent
P50	50% Probability	1H05	First half (6 months) of 2005 (example of date)
P90	90% Probability	2Q06	Second quarter (3 months) of 2006 (example of date)
Rf	Recovery factor	2D	Two dimensional
RFT	Repeat Formation Tester	3D	Three dimensional
RT	Rotary Table	4D	Four dimensional
Rw	Resistivity of water	1P	Proved Reserves
SCAL	Special core analysis	2P	Proved plus Probable Reserves
cf or scf	Standard Cubic Feet	3P	Proved plus Probable plus Possible Reserves
cfd or scfd	Standard Cubic Feet per day	%	Percentage

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