Exhibit 15.3

Gaffney,

Cline &

Associates

THIRD PARTY REPORT

RESERVES ESTIMATION AND EVALUATION OF

THE HALFAYA OIL FIELD, EASTERN IRAQ

AS OF 31^st DECEMBER, 2012

Prepared for

PETROCHINA COMPANY LIMITED IRAQ BRANCH

MARCH, 2013

CONFIDENTIAL

This document contains proprietary and confidential information which may not, without the express written permission of Gaffney, Cline & Associates, be released to any third party in any form, copied in any way or reproduced, nor utilized for any purpose except that for which it is intended, and must be returned upon request.

www.gaffney-cline.com

PetroChina Copy No. 1 C2116.00

Gaffney,

Cline &

Associates

	Page No.
INTRODUCTION		1
METHODOLOGY		2
1.      RESULTS SUMMARY		3
1.1 Net Reserves		3
1.2 Gross Volumes		4
1.3 Net Present Values		4
2.      BASIS OF OPINION		5
APPENDIX
I.       Sec Reserves Definitions
II.     Glossary
III.    Technical Qualifications

Gaffney,

Cline &

Associates

Gaffney, Cline & Associates, Inc.

1300 Post Oak Blvd.

Suite 1000

Houston, TX 77056, USA

Telephone: +1 713 850 9955

www.gaffney-cline.com

SAS/RJHS/dh/C2116.00/0115 14^th March, 2013

PetroChina Company Limited. – Iraq Branch

c/o PetroChina Halfaya FZ-LLC

Dubai Internet City

Building No.10, 4^th Floor

P.O. Box 500486 Dubai, UAE

Dear Gentlemen,

THIRD PARTY REPORT

RESERVES ESTIMATION AND EVALUATION OF

THE HALFAYA OIL FIELD, EASTERN IRAQ

AS OF 31^st DECEMBER, 2012

INTRODUCTION

At the request of PetroChina Company Limited Iraq Branch (PetroChina), Gaffney, Cline & Associates (GCA) has prepared an independent estimate of the proved reserves and financial data attributable to certain participating interests owned by PetroChina as at 31^st December, 2012. 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 14^th January, 2009 in the Federal Register, including all references to Regulation S-X and Regulation S-K (SEC regulations). GCA’s independent study, completed on 13^th March, 2013 and summarized herein, was prepared for public disclosure by PetroChina 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 Appendix I.

The subject property, the Halfaya Oil Field (Halfaya), is located in eastern Iraq, 35 km southeast of Amara City. PetroChina has signed a 20-year Development and Production Service Contract (DPSC) with the Missan Oil Company of The Iraqi Ministry of Oil (MOC) for the exploration, appraisal, development and production of the Halfaya Contract Area. PetroChina is the Operator of and holds a 37.5% participating interest in the project.

The proved oil reserves and financial data reported herein were estimated on the basis of SEC Rules. GCA has classified as proved reserves those hydrocarbon volumes that would be economically recoverable as a result of implementing the Supplementary Plan to the Preliminary Development Plan (SPDP), which was approved in December, 2011 and which meet the SEC definition for proved reserves. For purposes of this evaluation, only the first five years of SPDP development activities have been included for Proved Reserves consideration.

In line with the foregoing, the statement of proved reserves, presented herein, is based on a program that is expected to be superseded by the development activities proposed under the final Field Development Plan (FDP)

1

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

to be submitted and approved during 2013. As such, the volumes actually recovered under the FDP may be significantly greater than those presented. However, should the FDP not be approved, it is possible that the PetroChina would be seen as in default of the contract and there could be an early termination and a consequential reduction in reserves.

METHODOLOGY

In carrying out the review, GCA relied upon information and data provided through PetroChina, which comprised: basic engineering data; geoscience information and engineering interpretations associated with such data; other technical reports; costs and commercial data; financial data and other information pertaining to the fiscal and contractual terms applicable to DPSC; and, development plans. The available data and interpretations were reviewed for reasonableness and the latter adjusted where appropriate.

The study was based on an independent resource evaluation, using PetroChina’s interpretations of the existing data as the starting point for the estimation. The results presented in this report are based upon information and data made available to GCA on or before 31^st December, 2012 and included such tests, procedures and adjustments as were considered necessary. All questions that arose during the course of the evaluation process were resolved to GCA’s satisfaction. 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, 2012.

Economic models were constructed based on terms of the DPSC as provided by PetroChina, in order to calculate PetroChina’s Net Entitlement volumes, which are made up of PetroChina’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, 2012 were based on a prior twelve-month first-day-of-the-month un-weighted average reference price for UK North Sea Brent crude of U.S.$111.21/barrel, corrected for location and quality to an average wellhead price for Halfaya crude of U.S.$106.61/barrel. No price escalation, or cost inflation, has been included in the evaluation.

Under the terms of the DPSC, 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”, until a planned gas processing facility is commissioned in 2017. Thus, the contractor has no entitlement to any Gas Reserves prior to 2017. Gas sales have been included in this assessment starting in 2017 and, as per the DPSC; the Deemed Gas Price was set at 25% of the Deemed Oil Price.

Future capital costs were derived from development plans prepared by PetroChina for the field. Recent historical operating expense data were utilized as the basis for operating cost projections. GCA has found that PetroChina has projected sufficient capital investments and operating expenses over the next 5-year period to produce economically the projected volumes recoverable from the development activities planned under the SPDP.

NPV computations were also undertaken and derived using cost and production profiles input to the economic model established for the relevant petroleum contract. These NPVs represent future net revenue, after taxes, attributable to the interests of PetroChina, discounted over the economic life of the project at a specified discount rate to a present value as of 31st December, 2012.

GCA attests that the methodologies employed in the derivation of the reserves estimates are appropriate and that the depth and thoroughness of the reserves estimation process are adequate, given the nature and amount of

2

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of producing maturity of the property.

It is GCA’s opinion that the estimates of oil and gas reserve volumes as of 31^st December, 2012, presented in this document are, in aggregate, reasonable and were prepared in accordance with the Final Rule of Modernization of Oil and Gas Reporting (17 CFR Parts 210, 211, 229 and 249) published by the US Securities and Exchange Commission (“SEC”) on 14^th January, 2009 on Federal Register/ Vol. 74, No. 9 (see web version: http://www.sec.gov/rules/final/2010/33-8995fr.pdf). The definitions are applicable to the Proved reserve categories and sub-classifications.

A glossary of abbreviations and key industry standard terms, some or all of which may be used in this report, is attached as Appendix II.

1. RESULTS SUMMARY

1.1 Net Reserves

PetroChina’s net reserve volumes are derived by converting calculated net revenues accruing to PetroChina under the terms of the relevant petroleum contract into equivalent barrels of oil utilising the average 2012 oil pricing explained above. The PetroChina net revenue interest volumes reported in this document represent those amounts that are determined to be attributable to PetroChina’s net economic interest after the deduction of amounts attributable to third parties (government and other working interest partners).

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 and prices which are un-escalated 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, 2012).

ESTIMATED NET RESERVES AND FINANCIAL DATA

HALFAYA OIL FIELD 5-YEAR DEVELOPMENT

AS AT 31^ST DECEMBER, 2012

	Proved Developed		Proved Undeveloped		Total Proved
Net Reserves
Oil/Condensate – MBbl		1,948		44,035		45,983
Gas – MMscf		0		5,326		5,326
Income Data (MM$)
Future Gross Revenue		208		4,712		4,920
Deductions		27		4,496		4,523
Future Net Income (FNI)		180		216		397
Discounted FNI @ 10%		171		169		340

Liquid hydrocarbon volumes are expressed in thousands of standard (42 gallon) barrels (MBbl) and gas volumes are expressed in millions of standard cubic feet (MMscf). In this report, the revenues, deductions and income data are expressed in thousands of US dollars (M$).

3

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

The future gross revenue represents PetroChina’s net entitlement share of Service Fees (Petroleum Cost Recovery plus Remuneration Fees) due under the Development and Production Service Contract (DPSC). Deductions represent PetroChina’s 50% share of project Capital Expenditure, Operating Expenditure and contractual Supplementary Costs, plus mandated Training Fees. PetroChina’s 50% share of costs reflects its share of the State partner ‘carry’ (37.5% participating share grossed-up from total project less State partner’s 25% share). Future Net Income represents PetroChina’s Future Gross Revenue less costs incurred, and on a pre-tax basis, under the terms of the DPSC.

1.2 Gross Volumes

Gross production volumes are presented for reference information only. They represent a 100% working interest 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

HALFAYA OIL FIELD 5-YEAR DEVELOPMENT

AS OF 31^st DECEMBER, 2012

	Proved Developed		Proved Undeveloped		Total Proved
Gross Reserves
Oil/Condensate – MBbl		48,715		676,401		725,116
Gas – MMscf		0		132,559		132,559

1.3 Net Present Values

The NPVs as of 31^st December, 2012 of estimated cash flows discounted at 10%, after taxes, attributable to PetroChina’s working interest in Halfaya Oil Field (excluding any balance sheet adjustments or financing costs), are summarised below.

NET PRESENT VALUES ATTRIBUTABLE TO PETROCHINA

HALFAYA OIL FIELD 5-YEAR DEVELOPMENT

AS OF 31^st DECEMBER, 2012

DISCOUNT RATE 10%

Proved Developed (U.S.$ MM)	Proved Undeveloped (U.S.$ MM)	Total Proved (U.S.$ MM)
161	107	268
Notes: Mid-year discounted cash flow.

The NPVs were calculated on the basis of SEC guidelines under which the economic cut-offs were applied using un-escalated 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, 2012), except in instances where alternate prices are prescribed by contract.

4

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

2. BASIS OF OPINION

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. Brian Rhodes, Mr. Stephen A. Sakowski, Mr. Rawdon Seager, Mr. William Lau, Mr. Joshua Oletu, Mr. Chao Li, Mr. Olumide Bola Akinsanmi, Mr. Frederick Weltge. All hold degrees in geoscience, petroleum engineering or related discipline. A summary of technical qualifications for these individuals is attached as Appendix III.

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 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.

The opinions expressed herein represent GCA’s informed judgment based upon accepted standards of professional investigation in its evaluation of the issues, the data that has been made available and the company’s professional experience in the consideration of these matters but subject to the generally accepted uncertainties associated with the interpretation of geoscience and engineering data, but should not be considered a guarantee or prediction of results. Any evaluation may be subject to significant variation over time as new information becomes available or perceptions of market conditions change.

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 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. GCA is not aware of any potential changes in regulations applicable to this field that could affect the ability of PetroChina to produce the estimated reserves.

It must be clearly understood that any assessment of resources volumes, particularly involving continuing field development, will be subject to significant variations over short periods of time as new information becomes available and perceptions change. Not only are such estimates of Reserves based on that information which is currently available, but such estimates are also subject to uncertainties inherent in the application of judgmental factors in interpreting such information. Those quantities that might actually be recovered may differ significantly from the estimates presented herein.

It should be clearly noted that the Future Net Income (FNI) and Net Present Values (NPVs) of future revenue potential of a petroleum property, such as those discussed in this letter, do not represent a GCA opinion as to the market value of that 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 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 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 FNI presented herein.

The estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks; therefore, the proved reserves included in this report

5

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

are estimates only and should not be construed as being exact quantities. Also, 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.

In carrying out this study, GCA is not aware that any conflict of interest has existed. GCA is an independent energy consultancy specializing in petroleum reservoir evaluation and economic analysis. The firm’s management and employees have no direct or indirect interest holding in PetroChina. GCA’s remuneration was not in any way contingent on the contents of this report. In the preparation of this report, GCA has maintained, and continues to maintain, a strict consultant-client relationship with PetroChina. The management and employees of GCA have been, and continue to be, independent of PetroChina in the services they provide to the company including the provision of the opinions expressed in this report. Furthermore, the management and employees of GCA have no interest in any assets or share capital of PetroChina or in the promotion of PetroChina.

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 PetroChina.

This report has been prepared for PetroChina and should not be used for purposes other than those for which it is intended. This report should not be reproduced, either in whole or part, without the written permission of GCA. PetroChina/PetroChina 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 PetroChina, 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.

GCA hereby consents to the references to its name and its third party report as well as the filing of its third party report as an exhibit to PetroChina’s annual report on Form 20-F for the fiscal year ended 31^st December, 2012.

Yours faithfully,

GAFFNEY, CLINE & ASSOCIATES

Stephen A. Sakowski

Regional QA Director – Asia Pacific

Attachments:

I. SEC Reserves Definitions

II. Glossary of Abbreviations

III. Technical Qualifications

6

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

APPENDIX I

SEC RESERVES DEFINITIONS

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

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:

(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.

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].

AI.1

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

(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.

AI.2

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

(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.

AI.3

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

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.

AI.4

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

(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.

(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

AI.5

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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

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

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

AI.6

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

(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.

(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.

AI.7

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

APPENDIX II

GLOSSARY

SAS/RJHS/dh/C2116.00/0115 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
°API	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

AII.1

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

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
EI	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
PI	Productivity Index	TVDss	True Vertical Depth Subsea

AII.2

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

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	WI	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

AII.3

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

APPENDIX III

TECHNICAL QUALIFICATIONS

SAS/RJHS/dh/C2116.00/0115 PetroChina (Third Party Report) Gaffney, Cline & Associates

TECHNICAL QUALIFICATIONS

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. Brian Rhodes, Mr. Stephen A. Sakowski, Mr. Rawdon Seager, Mr. William Lau, Mr. Joshua Oletu, Mr. Chao Li, Mr. Olumide Bola Akinsanmi, Mr. Frederick Weltge. All hold degrees in geoscience, petroleum engineering or related discipline.

Mr. Rhodes holds a B.Sc (Hons) Geology, is a member of the Energy Institute, the Petroleum Exploration Society of Great Britain, the Society of Petroleum Engineers and the European Association of Geoscientists and Engineers, and has more than 38 years industry experience.

Mr. Sakowski holds a M.Eng. Mechanical Engineering and a Master’s Certificate Project Management, is a member of the Society of Petroleum Engineers and the Association of Professional Engineers, Geologists and Geophysicists of Alberta, and has more than 35 years international experience in the oil and gas industry and has managed numerous field studies, reserve assessments, and asset evaluations.

Mr. Seager holds a BSc. (Hons) in Physics and a MSc. (Distinction) in Petroleum Reservoir Engineering, is a member of Society of Petroleum Engineers (Chairman of SPE Oil and Gas Reserves Committee), Society of Petroleum Evaluation Engineers and American Association of Petroleum Geologists, is a member of the Energy Institute, UK, Chartered Petroleum Engineer, UK and European Engineer, registered with FEANI. He has over 40 years of experience in the international oil and gas arena and has managed numerous field studies, reserve assessments, and asset evaluations. He has made presentations within the industry relating to reserves estimating and reporting issues and has given expert testimony during arbitration hearings.

Mr. Lau holds a BSc (Special Honors) in Geology and an MBA, is a member of the Society of Petroleum Engineers, a Certified Professional Geologist of the American Association of Petroleum Geologists and a Registered Professional Geologist in the state of Texas, and has more than 40 years global experience in Petroleum Geology.

Mr. Oletu holds a BSc in Mechanical Engineering and an MBA, is a member of the Society of Petroleum Engineers, the Society of Professional Well Log Analysts, and has over 20 years global experience in petrophysical evaluation of conventional (clastics, carbonates, fresh water, heavy oil) and unconventional (tight gas, ‘shale’ gas/oil, Coal bed methane) reservoirs.

Mr. Li holds a BSc in Applied Mathematics and an MSc in Petroleum Engineering, is a member of the Society of Petroleum Engineers. He has 20 years of broad reservoir analysis experience including log analysis, fluid substitution, AVO, and seismic inversion; building 3D geologic models; predicting pore and fracture pressures; and well performance analysis.

Mr. Akinsanmi holds a BSc in Electrical/Electronics Engineering and an MSc in Petroleum Engineering, is a member of the Society of Petroleum Engineers and the Society of Petrophysicists and Well Log Analysts, and has 20 years experience in exploration and production operations, reservoir characterization and project integration.

Mr. Weltge holds a BA in Economics with minor in Finance, is a member of Society of the Association of International Petroleum Negotiators, and specializes in economic modelling, contract creation and interpretation, statistical analysis, and financial analysis.

AIII.1