Exhibit 15.2

Gaffney, Cline & Associates, Inc.

5555 San Felipe St., Suite 550

Houston, TX 77056

Telephone: +1 713 850 9955

www.gaffney-cline.com

March 1, 2019

Mr. Carlos Colo

Auditor de Reservas

YPF S.A.

Macacha Guemes 515

C1106BKK Buenos Aires

Argentina

carlos.colo@ypf.com

Dear Mr. Carlos Colo,

Proved Hydrocarbon Reserves Statement

for YPF S.A. for Certain Argentine Properties

as of December 31, 2018

This Proved reserves statement has been prepared by Gaffney, Cline & Associates (GCA) and issued on March 1, 2019 at the request of YPF S.A. (YPF or “the Client”), in respect of certain assets in Argentina where YPF has a participating interest. YPF’s participating interest in each asset is shown in Appendix V. This report is intended for inclusion in YPF’s filings (20-F, F-3) with the United States Securities and Exchange Commission.

GCA has conducted an independent audit examination as of December 31, 2018, of the hydrocarbon liquid and natural gas proved reserves of 36 units. On the basis of technical and other information made available to GCA concerning these property units, GCA hereby provides the reserves statement in the following table:

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Statement of Remaining Hydrocarbon Volumes

YPF S.A. Certain Properties in Argentina

as of December 31, 2018

	Gross (100%) Field Volumes				YPF Net Reserves
Reserves	Liquids (MMm3)		Gas (Bm3)		Liquids (MMm3)		Gas (Bm3)
Proved
Developed Producing		21.2		17.3		15.8		14.6
Developed Non Producing		0.6		3.0		0.3		1.6
Undeveloped		38.7		6.6		21.2		4.4
Total Proved		60.5		27.0		37.3		20.7

Notes:

1. Gross (100%) Field Volumes represents 100% working interest.

2. YPF Net Reserves represent YPF’s working interest volumes and therefore include volumes related to royalties payable to the relevant Argentine provinces. According to YPF’s accounting procedures, royalties are accounted for as a cost of production and are not deducted in determining reserves.

3. Hydrocarbon liquid volumes represent crude oil, condensate, gasoline and NGL estimated to be recovered during field separation and plant processing and are reported in millions of stock tank cubic meters (MMm³).

4. Natural gas volumes represent expected gas sales plus produced gas used for consumption and are reported in billion (10⁹) standard cubic meters (Bm³) at standard condition of 15 degrees Celsius and 1 atmosphere. The total YPF Net Proved reserves gas volume estimate of 20.7 Bm³ includes 2.0 Bm³ used for fuel.

5. Totals may not exactly equal the sum of the individual entries because of rounding.

This report relates specifically and solely to the subject matter as defined in the scope of work in the Proposal for Services and is conditional upon the assumptions described herein. The report must be considered in its entirety and must only be used for the purpose for which it was intended.

Gas reserves sales volumes are based on firm and existing gas contracts, or on the reasonable expectation of a contract or on the reasonable expectation that any such existing gas sales contracts will be renewed on similar terms in the future.

Appendices II and III provide the Gross (100%) Field and YPF Net Reserves for each basin, respectively.

YPF has advised GCA that the YPF reserves estimated in this report constitute approximately 33.8% percent of YPF’s Proved reserves and that the Proved Undeveloped Reserves estimated in this report constitute approximately 45% percent of all of YPF’s Proved Undeveloped Reserves as of December 31, 2018. These proportions are on a barrel oil equivalent (BOE) basis. GCA is not in a position to verify these statements because it was not requested to review YPF’s other oil and gas assets. Our study was completed on February 5, 2019.

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Reserves Assessment

GCA’s audit of the YPF reserves estimates was based on decline curve analysis to extrapolate the production of existing wells or prepare type curves to estimate future production from the locations proposed by YPF. Geological information, material balance, fluid laboratory tests and other pertinent information was used to assess the reserves estimates and the classification and categorization of the volumes to be recovered based on the proposed development plan.

This audit examination was based on reserves estimates and other information provided by YPF to GCA from September 2018 to February 2019 and included such tests, procedures and adjustments as were considered necessary under the circumstances to prepare the report. All questions that arose during the course of the audit process were resolved to our satisfaction.

The economic tests for the December 31, 2018 Proved Reserves volumes were based on realized crude oil, condensate, NGL and average gas sales prices as shown in the Appendix IV, as advised by YPF. YPF is subject to extensive regulations relating to the oil and gas industry in Argentina, which include specific natural gas market regulations.

Information on net proved reserves as of December 31, 2018 was calculated in accordance with the SEC regulations¹ and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, as amended. Accordingly, oil prices used to determine volumes and reserves were calculated each month, for crude oils of different quality produced by YPF. Consequently, for calculation of volumes and reserves as of December 31, 2018 YPF considered the realized price for crude oil in the domestic market taking into account the unweighted average price for each month within the twelve-month period ended December 31, 2018. There were no published benchmark crude oil prices during 2018 in Argentina that relate to YPF’s oil production from which first-day-of-month prices could be obtained. Additionally, YPF considered that the current export fees will not be in place after December 31, 2020 based on the amendments of the legislation promulgated during 2018. Therefore, two set of prices resulted, one for 2019-2020 which includes export fees, and the other for 2021 and thereafter as indicated in Appendix III. Additionally, since there are no benchmark market natural gas prices available in Argentina, YPF used average realized gas prices during the year to derive its reserves estimates. GCA reviewed and accepted the methodology and prices used by YPF in estimating the reserves in Argentina.

Future capital costs were derived from development program forecasts prepared by YPF for the fields. Recent historical operating expense data were utilized as the basis for operating cost projections. GCA has found that YPF has projected sufficient capital investments and operating expenses to produce economically the projected volumes.

It is GCA’s opinion that the estimates of total remaining recoverable hydrocarbon liquid and gas volumes at December 31, 2018, are, in the aggregate, reasonable and the reserves categorization is appropriate and consistent with the definitions for reserves set out in 17-CFR Part 210 Rule 4-10(a) of Regulation S-X of the United States Securities and Exchange Commission (as set out in Appendix VII). GCA concludes that the methodologies employed by YPF in the derivation of the volume estimates are appropriate and that the quality of the data relied upon, the depth and thoroughness of the estimation process are adequate.

¹  Modernization of Oil and Gas Reporting, Release Nos 33-8995; 34-59192, 17 CFR Part 210, Rule 4-10

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Basis of Opinion

This document reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client, 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 Client, and has accepted the accuracy and completeness of this data. GCA has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.

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

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

The accuracy of any resources 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, resources 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.

GCA’s review and audit involved reviewing pertinent facts, interpretations and assumptions made by YPF in preparing estimates of reserves. GCA performed procedures necessary to enable it to render an opinion on the appropriateness of the methodologies employed, adequacy and quality of the data relied on, depth and thoroughness of the reserves and resources estimation process, classification and categorization of reserves and resources appropriate to the relevant definitions used, and reasonableness of the estimates.

Definition of Reserves

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

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

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

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

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

Qualifications

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

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

Staff members who prepared this report hold appropriate professional and educational qualifications and have the necessary levels of experience and expertise to perform the work. The technical qualification of the person primarily responsible for the preparation of the reserves estimates presented in this report are given in Appendix I.

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Notice

This report is intended for inclusion in its entirety in YPF’s filings (20-F, F-3) with the United States Securities and Exchange Commission (SEC) in accordance with the disclosure requirements set forth in the SEC regulations. YPF S.A. will obtain GCA’s prior written approval for any other use of any results, statements or opinions expressed to YPF S.A. in this report, which are attributed to GCA.

Yours sincerely,

Gaffney, Cline & Associates

        /s/ Daniel Amitrano        

Project Manager

Daniel Amitrano, Principal Advisor

        /s/ Rawdon Seager        

Reviewed by

Rawdon Seager, Technical Director

Appendices

Appendix I Statement of Qualifications

Appendix II Gross (100%) Field Volumes per Basin

Appendix III YPF Net Reserves per Basin

Appendix IV Hydrocarbon Prices

Appendix V YPF’s Participating Interest in Each Area

Appendix VI SEC Reserves Definitions

Appendix VII Glossary

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Appendix I

Statement of Qualifications

D. A. Amitrano

D. A. Amitrano is one of GCA’s Principal Advisors and was the person primarily responsible for the preparation of the audit. Mr. Amitrano has over 29 years of diversified international industry experience mainly in reservoir engineering, geology, reserves estimates, project development, including classification and reporting of reserves and resources. He is a member of the Society of Petroleum Engineers (SPE) and holds a BS degree in Civil Engineering and a Master’s Degree in Field Exploitation from Buenos Aires University, Argentina.

Appendix II

Gross (100%) Field Volumes per Basin

Statement of Gross 100% Field Volumes per Basin

YPF S.A. Certain Properties in Argentina

as of December 31, 2018

Liquid Hydrocarbon Volumes

	Proved
	Developed				Undeveloped		Total
	Producing		Non
			Producing
Basin	Mm3		Mm3		Mm3		Mm3
Cuyana		986		27		137		1,150
Golfo San Jorge		4,440		—		2,564		7,005
Neuquina		15,793		608		35,960		52,360
Total		21,219		636		38,661		60,515

Notes:

1. Hydrocarbon liquid volumes represent crude oil, condensate, gasoline and NGL estimated to be recovered during field separation and plant processing and are reported in thousands of cubic meters.

2. Totals may not exactly equal the sum of the individual entries because of rounding.

Natural Gas

	Proved
	Developed				Undeveloped		Total
	Producing		Non
			Producing
Basin	MMm3		MMm3		MMm3		MMm3
Cuyana		62		0		0		62
Golfo San Jorge		469		—		116		584
Neuquina		16,800		3,039		6,473		26,311
Total		17,330		3,039		6,588		26,957

Notes:

1. Natural gas volumes represent expected gas sales plus produced gas used for consumption and are reported in millions of cubic meters at standard conditions of 15 degrees Celsius and 1 atmosphere.

2. Totals may not exactly equal the sum of the individual entries because of rounding.

Appendix III

YPF Net Reserves per Basin

Statement of Reserves Net to YPF per Basin

Certain Properties in Argentina

as of December 31, 2018

Liquid Hydrocarbon Volumes

	Proved
	Developed				Undeveloped		Total
	Producing		Non
			Producing
Basin	Mm3		Mm3		Mm3		Mm3
Cuyana		973		22		137		1,132
Golfo San Jorge		4,381		—		2,564		6,945
Neuquina		10,478		312		18,462		29,252
Total		15,832		334		21,163		37,329

Notes:

1. YPF Net Reserves represent YPF’s working interest volumes and therefore include volumes related to royalties payable to the relevant Argentine provinces, which, according to reporting in YPF’s 20-F filings with the SEC, are treated as financial obligations.

2. Hydrocarbon liquid volumes represent crude oil, condensate, gasoline and NGL estimated to be recovered during field separation and plant processing and are reported in thousands of cubic meters.

3. Totals may not exactly equal the sum of the individual entries because of rounding.

Statement of YPF Net Reserves per Basin

Certain Properties in Argentina

as of December 31, 2018

Natural Gas

	Proved
	Developed				Undeveloped		Total
	Producing		Non
			Producing
Basin	MMm3		MMm3		MMm3		MMm3
Cuyana		62		0		0		62
Golfo San Jorge		458		—		116		573
Neuquina		14,095		1,602		4,325		20,022
Total		14,614		1,602		4,441		20,657

Notes:

1. YPF Net Reserves represent YPF’s working interest volumes and therefore include volumes related to royalties payable to the relevant Argentine provinces, which according to reporting in YPF’s 20-F filings with the SEC, are treated as financial obligations.

2. Natural gas volumes represent expected gas sales plus produced gas used for consumption and are reported in millions of cubic meters at standard conditions of 15 degrees Celsius and 1 atmosphere.

3. Totals may not exactly equal the sum of the individual entries because of rounding.

Appendix IV

Hydrocarbon Prices

Hydrocarbon Prices

	Crude Oil Condensate Gasoline
Area	From 2019 to 2020 (US$/Bbl)		From 2021 and thereafter (US$/Bbl)		NGL (US$/Bbl)		Natural Gas US$/Mcf
Bajada de Añelo		65.40		70.78		—		3.85
Bajo del Piche		65.40		70.78		—		4.26
Bajo del Toro		65.40		70.78		—		—
Bandurria Sur		65.40		70.78		—		4.17
Cañadón Amarillo		63.01		68.39		21.03		4.04
Cañadón Perdido		63.34		69.57		—		—
Cañadón Vasco		63.84		70.07		—		—
Ceferino		60.23		65.34		—		—
Cerro Hamaca		65.40		70.78		—		—
Cerro Piedra-Cerro Guadal Norte		63.84		70.07		—		4.54
El Cordón		63.84		70.07		—		4.70
El Destino		63.84		70.07		—		4.59
El Medanito		65.40		70.78		—		4.77
El Orejano		65.40		70.78		21.03		3.85
El Trébol		63.34		69.57		—		—
Escalante		63.34		69.57		—		—
La Amarga Chica		65.40		70.78		21.03		3.85
Llancanelo		57.45		62.56		—		—
Loma Alta Sur		57.45		62.56		—		—
Loma Campana		65.40		70.78		21.03		3.85
Loma de la Mina		57.45		62.56		—		—
Loma La Lata Central		63.82		69.20		21.03		3.86
Loma La Lata Norte		65.40		70.78		21.03		3.86
Los Cavaos		57.45		62.56		—		4.95
Octógono		63.82		69.20		21.03		3.90
Pampa Palauco		57.45		62.56		—		—
Pico Truncado		63.84		70.07		—		4.59
Piedras Negras - Señal Lomita		65.40		70.78		—		3.45
Puesto Molina		63.01		68.39		—		—
Puesto Molina Norte		—		—		—		—
Punta Barda		65.40		70.78		—		—
Puntilla de Huincán		—		—		—		4.26
Rincón del Mangrullo		63.82		69.20		21.03		3.85
Río Tunuyán		60.23		65.34		—		4.39
Señal Cerro Bayo		65.40		70.78		—		—
Zampal Oeste		—		—		—		—

Appendix V

YPF’s Participating Interest in Each Area

YPF’s Participating Interest in each Area

AREA	WI
Bajada de Añelo		50	%
Bajo del Piche		100	%
Bajo del Toro		50	%
Bandurria Sur		51	%
Cañadón Amarillo		100	%
Cañadón Perdido		50	%
Cañadón Vasco		100	%
Ceferino		100	%
Cerro Hamaca		100	%
Cerro Piedra-Cerro Guadal Norte		100	%
El Cordón		100	%
El Destino		100	%
El Medanito		100	%
El Orejano		50	%
El Trébol		100	%
Escalante		100	%
La Amarga Chica		50	%
Llancanelo		100	%
Loma Alta Sur		100	%
Loma Campana		50	%
Loma de la Mina		100	%
Loma La Lata Central		100	%
Loma La Lata Norte (Sierras Blancas)		100	%
Loma La Lata Norte (Quintuco - Vaca Muerta)		50	%
Los Cavaos		100	%
Octógono		100	%
Pampa Palauco		100	%
Pico Truncado		100	%
Piedras Negras - Señal Lomita		100	%
Puesto Molina		100	%
Puesto Molina Norte		100	%
Punta Barda		100	%
Puntilla de Huincán		100	%
Rincón del Mangrullo (Vaca Muerta)		100	%
Rincón del Mangrullo (Mulichinco)		50	%
Río Tunuyán		70	%
Señal Cerro Bayo		100	%
Zampal Oeste		90	%

Appendix VI

SEC Reserves Definitions

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].

(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.

(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.

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.

(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

(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. 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.

Appendix VII

Glossary

Glossary – Standard Oil Industry Terms and Abbreviations

%	Percentage
1H05	First half (6 months) of 2005 (example)
2Q06	Second quarter (3 months) of 2006 (example)
2D	Two dimensional
3D	Three dimensional
4D	Four dimensional
1P	Proved Reserves
2P	Proved plus Probable Reserves
3P	Proved plus Probable plus Possible Reserves
ABEX	Abandonment Expenditure
ACQ	Annual Contract Quantity
oAPI	Degrees API (American Petroleum Institute)
AAPG	American Association of Petroleum Geologists
AVO	Amplitude versus Offset
A$	Australian Dollars
B	Billion (109)
Bbl	Barrels
/Bbl	per barrel
BBbl	Billion Barrels
BHA	Bottom Hole Assembly
BHC	Bottom Hole Compensated
Bscf or Bcf	Billion standard cubic feet
Bscfd or Bcfd	Billion standard cubic feet per day
Bm3	Billion cubic metres
bcpd	Barrels of condensate per day
BHP	Bottom Hole Pressure
blpd	Barrels of liquid per day
bpd	Barrels per day
boe	Barrels of oil equivalent @ xxx mcf/Bbl
boepd	Barrels of oil equivalent per day @ xxx mcf/Bbl
BOP	Blow Out Preventer
bopd	Barrels oil per day
bwpd	Barrels of water per day
BS&W	Bottom sediment and water
BTU	British Thermal Units
bwpd	Barrels water per day
CBM	Coal Bed Methane
CO2	Carbon Dioxide
CAPEX	Capital Expenditure
CCGT	Combined Cycle Gas Turbine
cm	centimetres
CMM	Coal Mine Methane
CNG	Compressed Natural Gas
Cp	Centipoise (a measure of viscosity)

CSG	Coal Seam Gas
CT	Corporation Tax
D1BM	Design 1 Build Many
DCQ	Daily Contract Quantity
Deg C	Degrees Celsius
Deg F	Degrees Fahrenheit
DHI	Direct Hydrocarbon Indicator
DLIS	Digital Log Interchange Standard
DST	Drill Stem Test
DWT	Dead-weight ton
E&A	Exploration & Appraisal
E&P	Exploration and Production
EBIT	Earnings before Interest and Tax
EBITDA	Earnings before interest, tax, depreciation and amortisation
ECS	Elemental Capture Spectroscopy
EI	Entitlement Interest
EIA	Environmental Impact Assessment
ELT	Economic Limit Test
EMV	Expected Monetary Value
EOR	Enhanced Oil Recovery
EUR	Estimated Ultimate Recovery
FDP	Field Development Plan
FEED	Front End Engineering and Design
FPSO	Floating Production Storage and Offloading
FSO	Floating Storage and Offloading
FWL	Free Water Level
ft	Foot/feet
Fx	Foreign Exchange Rate
g	gram
g/cc	grams per cubic centimetre
gal	gallon
gal/d	gallons per day
G&A	General and Administrative costs
GBP	Pounds Sterling
GCoS	Geological Chance of Success
GDT	Gas Down to
GIIP	Gas Initially In Place
GJ	Gigajoules (one billion Joules)
GOC	Gas Oil Contact
GOR	Gas Oil Ratio
GRV	Gross Rock Volumes
GTL	Gas to Liquids
GWC	Gas water contact
HDT	Hydrocarbons Down to
HSE	Health, Safety and Environment
HSFO	High Sulphur Fuel Oil

Glossary – Standard Oil Industry Terms and Abbreviations

HUT	Hydrocarbons up to
H2S	Hydrogen Sulphide
IOR	Improved Oil Recovery
IPP	Independent Power Producer
IRR	Internal Rate of Return
J	Joule (Metric measurement of energy) I kilojoule = 0.9478 BTU)
k	Permeability
KB	Kelly Bushing
KJ	Kilojoules (one Thousand Joules)
kl	Kilolitres
km	Kilometres
km2	Square kilometres
kPa	Thousands of Pascals (measurement of pressure)
KW	Kilowatt
KWh	Kilowatt hour
LAS	Log ASCII Standard
LKG	Lowest Known Gas
LKH	Lowest Known Hydrocarbons
LKO	Lowest Known Oil
LNG	Liquefied Natural Gas
LoF	Life of Field
LPG	Liquefied Petroleum Gas
LTI	Lost Time Injury
LWD	Logging while drilling
m	Metres
M	Thousand
m3	Cubic metres
Mcf or Mscf	Thousand standard cubic feet
MCM	Management Committee Meeting
MMcf or MMscf	Million standard cubic feet
m3/d	Cubic metres per day
mD	Measure of Permeability in millidarcies
MD	Measured Depth
MDT	Modular Dynamic Tester
Mean	Arithmetic average of a set of numbers
Median	Middle value in a set of values
MFT	Multi Formation Tester
mg/l	milligrams per litre
MJ	Megajoules (One Million Joules)
Mm3	Thousand Cubic metres
Mm3/d	Thousand Cubic metres per day
MM	Million
MMm3	Million Cubic metres
MMm3/d	Million Cubic metres per day

MMBbl	Millions of barrels
MMBTU	Millions of British Thermal Units
Mode	Value that exists most frequently in a set of values = most likely
Mscfd	Thousand standard cubic feet per day
MMscfd	Million standard cubic feet per day
MW	Megawatt
MWD	Measuring While Drilling
MWh	Megawatt hour
mya	Million years ago
NGL	Natural Gas Liquids
N2	Nitrogen
NTG	Net/Gross Ratio
NPV	Net Present Value
OBM	Oil Based Mud
OCM	Operating Committee Meeting
ODT	Oil-Down-To
OGIP	Original Gas in Place
OIIP	Oil Initially In Place
OOIP	Original Oil in Place
OPEX	Operating Expenditure
OWC	Oil Water Contact
p.a.	Per annum
Pa	Pascals (metric measurement of pressure)
P&A	Plugged and Abandoned
PDP	Proved Developed Producing
Phie	effective porosity
PI	Productivity Index
PIIP	Petroleum Initially In Place
PJ	Petajoules (1015 Joules)
PSDM	Post Stack Depth Migration
psi	Pounds per square inch
psia	Pounds per square inch absolute
psig	Pounds per square inch gauge
PUD	Proved Undeveloped
PVT	Pressure, Volume and Temperature
P10	10% Probability
P50	50% Probability
P90	90% Probability
RF	Recovery factor
RFT	Repeat Formation Tester
RT	Rotary Table
R/P	Reserve to Production
Rw	Resistivity of water
SCAL	Special core analysis
cf or scf	Standard Cubic Feet
cfd or scfd	Standard Cubic Feet per day
scf/ton	Standard cubic foot per ton

Glossary – Standard Oil Industry Terms and Abbreviations

SL	Straight line (for depreciation)
so	Oil Saturation
SPM	Single Point Mooring
SPE	Society of Petroleum Engineers
SPEE	Society of Petroleum Evaluation Engineers
SPS	Subsea Production System
SS	Subsea
stb	Stock tank barrel
STOIIP	Stock tank oil initially in place
Swi	irreducible water saturation
sw	Water Saturation
T	Tonnes
TD	Total Depth
Te	Tonnes equivalent
THP	Tubing Head Pressure
TJ	Terajoules (1012 Joules)
Tscf or Tcf	Trillion standard cubic feet

TCM	Technical Committee Meeting
TOC	Total Organic Carbon
TOP	Take or Pay
Tpd	Tonnes per day
TVD	True Vertical Depth
TVDss	True Vertical Depth Subsea
UFR	Umbilical Flow Lines and Risers
USGS	United States Geological Survey
US$	United States dollar
VLCC	Very Large Crude Carrier
Vsh	shale volume
VSP	Vertical Seismic Profiling
WC	Water Cut
WI	Working Interest
WPC	World Petroleum Council
WTI	West Texas Intermediate
wt%	Weight percent