EX-99.1

EX-99.1 6 d526156dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

Gaffney, Cline & Associates, Inc.

1300 Post Oak Blvd., Suite 1000 Houston, TX 77056

Telephone: +1 713 850 9955 www.gaffney-cline.com


DAA/gjh/C1900.02/gcah.119.13		March 27, 2013

Mr. Javier Sanagua

Director de Reservas, YPF S.A.

Macacha Güemes 515

C1106BKK Buenos Aires

Argentina

Hydrocarbon Proved Reserve Statement for YPF S.A

Certain Operated Argentine Properties as of September 30, 2012

Dear Mr. Javier Sanagua,

This reserve statement has been prepared by Gaffney, Cline & Associates (GCA) and issued on March 27, 2013 at the request of YPF S.A. (YPF), operator of certain assets in Neuquén, Rio Negro, Mendoza, Chubut and Santa Cruz Provinces in Argentina. YPF holds 100% interest participation in these assets with the exception of those described below.


Reserves Area	Working Interest (%)
Llancanelo		51
Río Tunuyán		60
Zampal Oeste		70
Bandurria		54.54
Cañadón Perdido		50
Zona Central - Bella Vista Este		50

GCA has conducted an independent audit examination as of September 30, 2012, of the hydrocarbon liquid and natural gas proved reserves 41 units. This report is intended for inclusion in YPF’s filings (20-F, F-3) with the United States Securities and Exchange Commission.

On the basis of technical and other information made available to us concerning these property units, we hereby provide the reserve statements given in the table below.


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

Statement of Remaining Hydrocarbon Volumes

YPF S.A. Certain Operated Properties in Argentina

As of September 30, 2012

Gross (100%) Field
Volumes

YPF Net Reserves

Liquids
(MMm3)

Gas
(Bm3)

Liquids
(MMm3)

Gas
(Bm3)

Proved

Developed

12.8

2.6

11.7

2.5

Undeveloped

4.3

1.0

3.7

1.0

Total Proved

17.1

3.6

15.4

3.5

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. Natural gas volumes represent expected gas sales, and are reported in billion (10⁹) standard cubic meters (at standard conditions of 15 degrees Celsius and 1 atmosphere). The volumes have not been reduced for fuel usage in the field. Based on the interpretation that Argentine royalties are a financial obligation or substantially equivalent to a production or similar tax, royalties payable to the provinces have not been deducted from the reported volumes.

The following tables present consumption gas, as a percentage of produced gas for each area.


Area	Consumed Gas (%)
Cañadón Amarillo		100	%
Ceferino		100	%
Cerro Mollar Norte		—
Estructura Cruz de Piedra-Lunlunta		38	%
Filo Morado		—
L. Carrizal		—
La Brea		100	%
Llancanelo		—
Loma Alta Sur		100	%
Loma de la Mina		100	%
Los Cavaos		80	%
Pampa Palauco		—
Paso Bardas Norte		22	%
Puesto Molina Norte		—
Puesto Molina		—
Puntilla de Huincan		—
Río Tunuyán		—


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.


Area	Consumed Gas (%)
Ugarteche		100	%
Zampal Oeste		—
Bandurria		—
Octógono		1	%
Portezuelo Minas		—
Puesto Cortadera		—
Bajo del Piche		74	%
Cerro Hamaca		100	%
El Medanito		—
Piedras Negras - Señal Lomita		94	%
Punta Barda		100	%
Señal Cerro Bayo		100	%
Volcán Auca Mahuida		100	%
Cañadón Perdido		100	%
El Trébol		100	%
Escalante		96	%
Zona Central - Bella Vista Este		100	%
Cañadón Vasco		100	%
Cerro Piedra-Cerro Guadal Norte		56	%
El Cordón		79	%
El Destino		100	%
Pico Truncado		100	%

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

The tables below contain the reserves for each unit area. Liquid volumes are reported here in thousands of stock tank cubic meters and natural gas in million standard cubic meters (at standard conditions of 15 degrees Celsius and 1 atmosphere)


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

Note: The totals in the following tables could have rounding differences arising from hidden decimals of the individual quoted reserve values.

Statement of 100% Gross Field Volumes

YPF S.A. Certain Operated Properties in Argentina

as of September 30, 2012

Liquid Hydrocarbon Volumes


	Proved
	Developed
Area	Producing Mm³		Non Producing Mm³		Undeveloped Mm³		Total Mm³
Cañadón Amarillo		232		—		188		420
Ceferino		37		—		—		37
Cerro Mollar Norte		45		—		—		45
Estructura Cruz de Piedra-Lunlunta		946		—		38		985
Filo Morado		117		—		—		117
L. Carrizal		307		—		94		401
La Brea		—		—		—		—
Llancanelo		166		—		485		650
Loma Alta Sur		429		—		218		647
Loma de la Mina		181		—		—		181
Los Cavaos		715		—		81		796
Pampa Palauco		246		—		—		246
Paso Bardas Norte		7		—		—		7
Paso Bardas Norte		106		—		—		106
Puesto Molina Norte		2		—		23		25
Puesto Molina		—		—		—		—
Puesto Molina		—		—		—		—
Puntilla de Huincan		—		—		—		—
Río Tunuyán		232		—		—		232
Ugarteche		446		—		0		446
Zampal Oeste		—		—		—		—
Bandurria		2		—		—		2
Octógono		9		—		0		9
Portezuelo Minas		—		—		—		—
Puesto Cortadera		3		—		3		6
Bajo del Piche		68		—		—		68
Cerro Hamaca		198		—		—		198
El Medanito		579		—		336		915
Piedras Negras - Señal Lomita		—		—		—		—
Punta Barda		138		—		—		138
Señal Cerro Bayo		725		—		58		783
Volcán Auca Mahuida		674		68		441		1,184
Cañadón Perdido		334		—		160		494
El Trébol		1,093		—		191		1,284
Escalante		565		—		361		926
Zona Central - Bella Vista Este		1,536		26		547		2,109
Cañadón Vasco		163		—		115		279
Cerro Piedra-Cerro Guadal Norte		219		—		65		285
El Cordón		445		—		299		744
El Destino		583		—		200		783
Pico Truncado		1,162		—		431		1,593


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

Natural Gas Volumes


	Proved
	Developed				Undeveloped MMm³		Total MMm³
Area	Producing MMm³		Non Producing MMm³		Undeveloped MMm³		Total MMm³
Cañadón Amarillo		20		—		—		20
Ceferino		0		—		—		0
Cerro Mollar Norte		—		—		—		—
Estructura Cruz de Piedra-Lunlunta		11		—		0		11
Filo Morado		299		—		—		299
L. Carrizal		3		—		1		4
La Brea		—		—		—		—
Llancanelo		—		—		—		—
Loma Alta Sur		1		—		—		1
Loma de la Mina		22		—		—		22
Los Cavaos		260		—		—		260
Pampa Palauco		0		—		—		0
Paso Bardas Norte		360		—		0		360
Paso Bardas Norte		623		—		—		623
Puesto Molina Norte		—		—		—		—
Puesto Molina		0		—		—		0
Puesto Molina		—		—		—		—
Puntilla de Huincan		—		—		—		—
Río Tunuyán		4		—		—		4
Ugarteche		7		—		0		7
Zampal Oeste		—		—		—		—
Bandurria		—		—		—		—
Octógono		63		—		0		63
Portezuelo Minas		—		—		—		—
Puesto Cortadera		151		3		97		250
Bajo del Piche		37		—		—		37
Cerro Hamaca		17		—		—		17
El Medanito		29		—		20		49
Piedras Negras - Señal Lomita		37		—		690		727
Punta Barda		0		—		0		0
Señal Cerro Bayo		90		—		—		90
Volcán Auca Mahuida		35		4		23		62
Cañadón Perdido		14		—		—		14
El Trébol		14		—		6		20
Escalante		93		—		37		130
Zona Central - Bella Vista Este		18		—		5		23
Cañadón Vasco		30		—		15		45
Cerro Piedra-Cerro Guadal Norte		41		—		6		47
El Cordón		39		—		10		49
El Destino		63		—		26		88
Pico Truncado		176		—		73		249


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

Statement of Reserves Net to YPF

Certain Operated Properties in Argentina, as of September 30, 2012

Liquid Hydrocarbon Volumes


	Proved
	Developed				Undeveloped Mm³		Total Mm³
Area	Producing Mm³		Non Producing Mm³		Undeveloped Mm³		Total Mm³
Cañadón Amarillo		232		—		188		420
Ceferino		37		—		—		37
Cerro Mollar Norte		45		—		—		45
Estructura Cruz de Piedra-Lunlunta		946		—		38		985
Filo Morado		117		—		—		117
L. Carrizal		307		—		94		401
La Brea		—		—		—		—
Llancanelo		85		—		247		332
Loma Alta Sur		429		—		218		647
Loma de la Mina		931		13		389		1,333
Los Cavaos		715		—		81		796
Pampa Palauco		246		—		—		246
Paso Bardas Norte		7		—		—		7
Paso Bardas Norte		106		—		—		106
Puesto Molina Norte		2		—		23		25
Puesto Molina		—		—		—		—
Puesto Molina		—		—		—		—
Puntilla de Huincan		—		—		—		—
Río Tunuyán		139		—		—		139
Ugarteche		446		—		0		446
Zampal Oeste		—		—		—		—
Bandurria		1		—		—		1
Octógono		9		—		0		9
Portezuelo Minas		—		—		—		—
Puesto Cortadera		3		—		3		6
Bajo del Piche		68		—		—		68
Cerro Hamaca		198		—		—		198
El Medanito		579		—		336		915
Piedras Negras - Señal Lomita		—		—		—		—
Punta Barda		138		—		—		138
Señal Cerro Bayo		725		—		58		783
Volcán Auca Mahuida		674		68		441		1,184
Cañadón Perdido		167		—		80		247
El Trébol		1,093		—		191		1,284
Escalante		565		—		361		926
Zona Central - Bella Vista Este		768		13		273		1,054
Cañadón Vasco		163		—		115		279
Cerro Piedra-Cerro Guadal Norte		219		—		65		285
El Cordón		445		—		299		744
El Destino		583		—		200		783
Pico Truncado		1,162		—		431		1,593


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

Natural Gas Volumes


	Proved
	Developed				Undeveloped MMm³		Total MMm³
Area	Producing MMm³		Non Producing MMm³		Undeveloped MMm³		Total MMm³
Cañadón Amarillo		20		—		—		20
Ceferino		0		—		—		0
Cerro Mollar Norte		—		—		—		—
Estructura Cruz de Piedra-Lunlunta		11		—		0		11
Filo Morado		299		—		—		299
L. Carrizal		3		—		1		4
La Brea		—		—		—		—
Llancanelo		—		—		—		—
Loma Alta Sur		1		—		—		1
Loma de la Mina		39		—		17.37		57
Los Cavaos		260		—		—		260
Pampa Palauco		0		—		—		0
Paso Bardas Norte		360		—		0		360
Paso Bardas Norte		623		—		—		623
Puesto Molina Norte		—		—		—		—
Puesto Molina		0		—		—		0
Puesto Molina		—		—		—		—
Puntilla de Huincan		—		—		—		—
Río Tunuyán		2		—		—		2
Ugarteche		7		—		0		7
Zampal Oeste		—		—		—		—
Bandurria		—		—		—		—
Octógono		63		—		0		63
Portezuelo Minas		—		—		—		—
Puesto Cortadera		151		3		97		250
Bajo del Piche		37		—		—		37
Cerro Hamaca		17		—		—		17
El Medanito		29		—		20		49
Piedras Negras - Señal Lomita		37		—		690		727
Punta Barda		0		—		0		0
Señal Cerro Bayo		90		—		—		90
Volcán Auca Mahuida		35		4		23		62
Cañadón Perdido		7		—		—		7
El Trébol		14		—		6		20
Escalante		93		—		37		130
Zona Central - Bella Vista Este		9		—		2		11
Cañadón Vasco		30		—		15		45
Cerro Piedra-Cerro Guadal Norte		41		—		6		47
El Cordón		39		—		10		49
El Destino		63		—		26		88
Pico Truncado		176		—		73		249


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

It is our understanding that the proved reserves estimated in this report constitute approximately 12.7% percent of YPF’s Proved Reserves; it is also our understanding that the Proved Undeveloped Reserves estimated in this report constitute approximately 14.6% percent of all YPF’s Proved Undeveloped Reserves as of September 30, 2012. These proportions are on a barrel oil equivalent (BOE) basis. GCA is not in a position to verify this statement as it was not requested to review YPF’s other oil and gas assets. Our study was completed on January 31, 2013.

GCA’s audit of the YPF reserves estimates was based on decline curve analysis to extrapolate the production of existing wells or elaborate 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/categorization of the proposed development plan.

This audit examination was based on reserve estimates and other information provided by YPF to GCA through December 2012 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. Significant differences between GCA and YPF estimates are explained and presented in Appendix I

The economic tests for the September 30, 2012 Reserve volumes were based on realized crude oil, condensate, NGL and average gas sales prices as shown in the following table, as advised by YPF. A prior twelve-month first-day-of-the-month average price for West Texas Intermediate (WTI) crude of US$94.95/Bbl serves as the foundation for the oil, condensate and gasoline price. YPF is subject to extensive regulations relating to the oil and gas industry in Argentina which include specific natural gas market regulations as well as hydrocarbon export taxes that apply until 2017 according to Law 26,217, all of which affect the realized prices of oil and other products in the domestic market. As a result, crude oil prices used to determine reserves are set at the beginning of every month until 2012, for crude oils of different quality produced by YPF, considering the realized prices for crude oils of such quality in the domestic market, taking into account the effects of Law 26,217. Additionally, a significant portion of the Argentine gas market is regulated. Natural gas prices for the residential and power generation segments, as well as natural gas for vehicles, are regulated by the government. Natural gas prices for industrial consumers are negotiated by market participants on a private basis. As a result, there are no benchmark market natural gas prices available in Argentina. GCA audited and accepted the methodology and prices used by YPF in estimating the reserves in Argentina. In addition, YPF increments the crude oil, condensate and gasoline price in 2017 due to the scheduled expiration of the export retention tax mentioned above. Caution is advised in this regard as the export tax has been scheduled to expire several times in the recent past but extended as the deadline approached. Maintaining the current price would no doubt have an impact on the reserves estimates.


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.


	Prices Based on WTI US$ 94.95/Bbl
	Crude Oil Condensate Gasoline 2013-2016		Crude Oil Condensate Gasoline 2017+		NGL - Plant A		NGL - Plant B		Natural Gas 2013+
Area	US$/Bbl		US$/Bbl		US$/Bbl		US$/Bbl		US$/MMBTU
Cañadón Vasco		67.23		88.85		—		—		—
Cerro Piedra - Cerro Guadal Norte		67.23		88.85		—		—		2.67
El Cordón		67.23		88.85		—		—		2.91
El Destino		67.23		88.85		—		—		—
Pico Truncado		67.23		88.85		—		—		-0.06
Cañadón Perdido		66.23		87.85		—		—		—
El Trébol		66.23		87.85		—		—		—
Escalante		66.23		87.85		—		—		2.66
Zona Central - Bella Vista Este		66.23		87.85		—		—		—
Los Cavaos		64.03		85.65		—		23.32		2.68
Cerro Mollar Norte		64.03		85.65		—		—		—
La Brea		64.03		85.65		—		—		—
Llancanelo		64.03		85.65		—		—		—
Loma Alta Sur		64.03		85.65		—		—		—
Loma de la Mina		64.03		85.65		—		—		—
Pampa Palauco		64.03		85.65		—		—		—
Ceferino		67.33		88.95		—		—		—
Estructura Cruz de Piedra - Lunlunta		67.33		88.95		—		—		3.12
L. Carrizal		67.33		88.95		—		—		3.12
Río Tunuyán		67.33		88.95		—		—		3.08
Ugarteche		67.33		88.95		—		—		—
Bajo del Piche		73.31		93.95		—		—		2.78
Barranca de los Loros		73.31		93.95		—		—		—
Cerro Hamaca		73.31		93.95		—		—		—
El Medanito		73.31		93.95		—		—		2.03
Las Manadas		73.31		93.95		—		—		—
Punta Barda		73.31		93.95		—		—		—
Señal Picada Neuquén		73.31		93.95		—		—		—
Señal Picada Río Negro		73.31		93.95		—		—		—
Aguada Toledo - Sierra Barrosa		72.89		93.53		—		—		2.21
Octógono		72.89		93.53		—		—		2.43
Puesto Cortadera		72.89		93.53		—		—		2.26
Cañadón Amarillo		71.76		92.40		—		—		0.00
Cerro Negro		71.76		92.40		—		—		—
Chihuido La Salina		71.76		92.40		20.87		24.82		—
Chihuido La Salina Sur		71.76		92.40		20.87		24.82		2.23


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.


	Prices Based on WTI US$ 94.95/Bbl
	Crude Oil Condensate Gasoline 2013-2016		Crude Oil Condensate Gasoline 2017+		NGL - Plant A		NGL - Plant B		Natural Gas 2013+
Area	US$/Bbl		US$/Bbl		US$/Bbl		US$/Bbl		US$/MMBTU
Desfiladero Bayo Mendoza		71.76		92.40		—		—		—
Desfiladero Bayo Neuquén		71.76		92.40		—		—		—
El Portón Mendoza		71.76		92.40		20.87		24.82		—
El Portón Neuquen		71.76		92.40		20.87		24.82		2.23
Filo Morado		71.76		92.40		20.87		24.82		2.51
Paso Bardas Norte Mendoza		71.76		92.40		20.87		24.82		2.36
Paso Bardas Norte Neuquén		71.76		92.40		20.87		24.82		2.36
Puesto Molina Mendoza		71.76		92.40		—		—		—
Puesto Molina Neuquén		71.76		92.40		—		—		—
Puesto Molina Norte		71.76		92.40		—		—		—
Cerro Liupuca		71.76		92.40		—		—		—
Chihuido Sierra Negra		71.76		92.40		—		—		—
Piedras Negras - Señal Lomita		71.76		92.40		—		—		2.75
Puntilla Huincan		67.33		88.95		—		—		3.08
Bandurria		72.89		93.53		—		24.82		2.43
Portezuelo Minas		72.89		93.53		—		—		2.43

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 September 30, 2012, 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 II). 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 is adequate.

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

This assessment has been conducted within the context of GCA’s understanding of YPF’s petroleum property rights as represented by YPF’s management. GCA is not in a position to attest to property title, financial interest relationships or encumbrances thereon for any part of the appraised properties or interests.

There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas reserve engineering and resource assessment must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas reserves or resources prepared by other parties may differ,


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

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

For this assignment, GCA served as independent reserve auditors. The firm’s officers and employees have no direct or indirect interest holdings in the property units evaluated. GCA’s remuneration was not in any way contingent on reported reserve estimates. The qualifications of the technical person primarily responsible for overseeing this audit are included in Appendix III.

This report has been prepared at the request of YPF regarding assets it holds in Argentina and is for inclusion in YPF’s filings with the United States Securities and Exchange Commission.

YPF 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 YPF, 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.

Yours sincerely,

Gaffney, Cline & Associates

LOGO

Project Manager - Daniel Amitrano

Lead Reservoir and Petroleum Engineer

LOGO

Peer Reviewer – David K. Morgan

Technical Director


Enclosures:

Appendix I:		Statement of Qualifications
Appendix II:		SEC Reserve Definitions
Appendix III		Glossary


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

Appendix I

Statement of Qualification


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

Statement of Qualifications

D. K. Morgan

D. K. Morgan is one of GCA’s Senior Technical Mangers and was responsible for overseeing the preparation of the audit. Mr. Morgan has over 44 years of diversified international industry experience mainly in reservoir-engineering, geology, reserves estimates, project development, economics and training in the assessment, classification and reporting of reserves and resources. Over the past 5 years he has been responsible for project review and oversight for GCA’s Houston office as it pertains to exploration and production activities including the reserves audits conducted on behalf of Repsol YPF S.A. and YPF S.A. He is a member of the Society of Petroleum Engineers (SPE) and holds a petroleum engineering degree from Marietta College.


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

Appendix II

SEC Reserve Definitions


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

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].


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

(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.


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

(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:

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

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.


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

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 dearly 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.


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

(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.


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

(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.


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

(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.


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

(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.


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

Appendix III

Glossary


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.

GLOSSARY

List of Standard Oil Industry Terms and Abbreviations


ABEX		Abandonment Expenditure
ACQ		Annual Contract Quantity
°API		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 (10⁹) Barrels
BHA		Bottom Hole Assembly
BHC		Bottom Hole Compensated
Bscf or Bcf		Billion (10⁹) standard cubic feet
Bscfd or Bcfd		Billion (10⁹) standard cubic feet per day
Bm³		Billion (10⁹) 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
DCQ		Daily Contract Quantity
Deg C		Degrees Celsius
Deg F		Degrees Fahrenheit
DHI		Direct Hydrocarbon Indicator
DST		Drill Stem Test
DWT		Dead-weight ton
E&A		Exploration & Appraisal


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.


E&P		Exploration and Production
EBIT		Earnings before Interest and Tax
EBITDA		Earnings before interest, tax, depreciation and amortisation
EI		Entitlement Interest
EIA		Environmental Impact Assessment
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
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
GDT		Gas Down to
GIIP		Gas initially in place
GJ		Gigajoules (one billion Joules)
GOR		Gas Oil Ratio
GTL		Gas to Liquids
GWC		Gas water contact
HDT		Hydrocarbons Down to
HSE		Health, Safety and Environment
HSFO		High Sulphur Fuel Oil
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) 1 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


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.


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
m³d		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
Mm³d		Thousand Cubic metres per day
MM		Million
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
NPV		Net Present Value
OBM		Oil Based Mud
OCM		Operating Committee Meeting
ODT		Oil down to
OPEX		Operating Expenditure
OWC		Oil Water Contact
p.a.		Per annum


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.


Pa		Pascals (metric measurement of pressure)
P&A		Plugged and Abandoned
PDP		Proved Developed Producing
PI		Productivity Index
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 temperature
P10		10% Probability
P50		50% Probability
P90		90% Probability
Rf		Recovery factor
RFT		Repeat Formation Tester
RT		Rotary Table
R_w		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
SL		Straight line (for depreciation)
s_o		Oil Saturation
SPE		Society of Petroleum Engineers
SPEE		Society of Petroleum Evaluation Engineers
ss		Subsea
STB		Stock tank barrel
STOIIP		Stock tank oil initially in place
s_w		Water Saturation
T		Tonnes
TD		Total Depth
Te		Tonnes equivalent
THP		Tubing Head Pressure
TJ		Terajoules (10¹² Joules)
Tscf or Tcf		Trillion (10¹²) 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
USGS		United States Geological Survey
US$		United States Dollar
VSP		Vertical Seismic Profiling
WC		Water Cut


DAA/gjh/C1900.02/gcah.119.13 YPF S.A.


WI		Working Interest
WPC		World Petroleum Council
WTI		West Texas Intermediate
wt%		Weight percent
1H05		First half (6 months) of 2005 (example of date)
2Q06		Second quarter (3 months) of 2006 (example of date)
2D		Two dimensional
3D		Three dimensional
4D		Four dimensional
1P		Proved Reserves
2P		Proved plus Probable Reserves
3P		Proved plus Probable plus Possible Reserves
%		Percentage