EX-15.2 7 d357382dex152.htm EX-15.2 EX-15.2

Exhibit 15.2

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 09, 2023

YPF Sociedad Anónima

Macacha Güemes 515

Ciudad Autónoma de Buenos Aires

Argentina

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2022, of the extent of the estimated net proved oil, condensate, natural gas liquids (NGL), gasoline, and gas reserves of certain properties in which YPF Sociedad Anónima (YPF S.A.) has represented it holds an interest. This evaluation was completed on February 9, 2023. The properties evaluated herein are located in Argentina. YPF S.A. has represented that these properties account for approximately 31.6 percent on a net equivalent barrel basis of YPF S.A.’s net proved reserves as of December 31, 2022, and approximately 27.0 percent on a net equivalent barrel basis of YPF S.A.’s net proved undeveloped reserves as of December 31, 2022. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by YPF S.A.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2022. Net reserves are defined as that portion of the gross reserves attributable to the interests held by YPF S.A. after deducting all interests held by others.

Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

The properties evaluated herein are listed in the following table:

 

Basin    Basin
Area    Area

Reservoir(s)

   

Reservoir(s)

Cuyana

   

Neuquina - (Continued)

Barrancas

   

Cerro Negro

Estructura Cruz de Piedra-Lunlunta

   

Don Ruiz

Lunlunta Carrizal

   

El Manzano

LV-Cañada Dura

   

La Ribera Bloque I

Mesa Verde

   

La Ribera Bloque II

Ugarteche

   

Las Manadas

Golfo San Jorge

   

Las Tacanas

Barranca Baya

   

Lindero Atravesado

Barranca Yankowsky

   

Llancanelo R

Cañadón Yatel

   

Loma Amarilla Sur

Lomas del Cuy

   

Loma del Molle

Los Monos

   

Los Caldenes

Los Perales

   

Pampa de las Yeguas Bloque I

Manantiales Behr

   

Río Neuquén (Neuquén Province)

Restinga Alí

   

Río Neuquén (Río Negro Province)

Seco León

   

Salinas del Huitrin

Zona Central - Bella Vista Este

   

Volcán Auca Mahuida

Neuquina

   

Noroeste

Aguada de la Arena

   

Acambuco

Aguada del Chañar

   

Macueta

Aguada Toledo - Sierra Barrosa

   

San Pedrito

Altiplanicie del Payún

   

Aguaragüe

Cajón de los Caballos

   

Ramos

Cerro Fortunoso

   

San Antonio Sur

Cerro Liupuca

   

Information used in the preparation of this report was obtained from YPF S.A. In the preparation of this report we have relied, without independent verification, upon information furnished by YPF S.A. with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.

Definition of Reserves

Petroleum reserves estimated in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

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.

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.

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 [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by YPF S.A., and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

The undeveloped reserves estimates were based on opportunities identified in the plan of development provided by YPF S.A.

YPF S.A. has represented that its senior management is committed to the development plan provided by YPF S.A. and that YPF S.A. has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas).

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production as defined under the Definition of Reserves heading of this report or the expiration of the fiscal agreement, as appropriate.

Where adequate data were available and where circumstances justified, material balance and other engineering methods were used to estimate original oil in place (OOIP) and original gas in place (OGIP) based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

Data provided by YPF S.A. from wells drilled through December 31, 2022, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through September, October, or November 2022. Estimated cumulative production, as of December 31, 2022, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 3 months.

Oil and condensate reserves estimated herein are to be recovered by normal field separation. NGL reserves estimated herein include propane and butane fractions, and gasoline reserves estimated herein consist of pentanes and heavier fractions (C5+). NGL and gasoline reserves are the result of low-temperature plant processing and were estimated in accordance with YPF S.A.’s internal reporting standards. Oil, condensate, NGL, and gasoline reserves included in this report are expressed in thousands of barrels (103bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as marketable gas, fuel gas, and sales gas. Marketable gas is defined as the total gas produced from the reservoir after reduction for shrinkage resulting from field separation; processing, including removal of the nonhydrocarbon gas to meet pipeline specifications; and flare and other losses but not from fuel usage. Fuel gas is defined as that portion of the gas consumed in field operations. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as marketable gas, fuel gas, and sales gas. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.696 pounds per square inch absolute (psia). Gas quantities included in this report are expressed in millions of cubic feet (106ft3).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.

At the request of YPF S.A., marketable gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 5,615 cubic feet of gas per 1 barrel of oil equivalent.

Primary Economic Assumptions

This report has been prepared using initial prices, expenses, and costs provided by YPF S.A. in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:

Oil, Condensate, NGL, and Gasoline Prices

YPF S.A. has represented that the oil, condensate, and gasoline prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. The volume-weighted average adjusted price attributable to the estimated proved reserves was U.S.$ 70.02 per barrel of oil, condensate, and gasoline. YPF S.A. supplied differentials by field to a Brent reference price of U.S.$ 100.19 per barrel and the prices were held constant thereafter.

YPF S.A. has represented that the NGL prices are defined by contractual agreements. The volume-weighted average adjusted price attributable to the estimated proved reserves was U.S.$ 11.40 per barrel of NGL.

Gas Prices

YPF S.A. has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. YPF S.A. has represented that the gas prices were U.S.$ 3.66 per million Btu(106 Btu) for the properties in the Cuyana Basin, U.S.$ 4.02 per 106 Btu for the properties in the Noroeste Basin, and U.S.$ 3.11 per 106 Btu for the properties in the Golfo San Jorge Basin. These prices were held constant for the producing lives of the properties.

For the properties located in the Neuquina Basin, YPF S.A. has represented that it is paid an incentive gas price that is subsidized by the Argentine government through 2028. Gas sales prices of U.S.$ 3.66 per 106 Btu for 2023, U.S.$ 3.71 per 106 Btu for 2024 through 2028, and U.S.$ 3.18 per 106 Btu for 2029 forward were used herein for the Neuquina Basin properties.

Btu factors provided by YPF S.A. were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume-weighted average adjusted price attributable to the estimated proved reserves was U.S.$ 3.81 per thousand cubic feet of gas.

Operating Expenses, Capital Costs, and Abandonment Costs

Operating expenses and capital costs, provided by YPF S.A. and based on existing economic conditions, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by YPF S.A. Estimates of operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.

In our opinion, the information relating to estimated proved reserves of oil, condensate, NGL, gasoline, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Summary of Conclusions

DeGolyer and MacNaughton has performed an independent evaluation of the extent of the estimated net proved oil, condensate, NGL, gasoline, and gas reserves of certain properties in which YPF S.A. has represented it holds an interest.

The estimated net proved reserves, as of December 31, 2022, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (103bbl), millions of cubic feet (106ft3), and thousands of barrels of oil equivalent (103boe):

 

     Estimated by DeGolyer and MacNaughton  
     Net proved reserves  
     As of December 31, 2022  
     Oil and condensate      NGL      Gasoline      Marketable gas      Oil equivalent  
     (103 bbl)      (103 bbl)      (103 bbl)      (106 ft3)      (103 boe)  

Argentina

               

Proved developed

      113,760        5,495        902        525,918        213,820  

Proved undeveloped

      65,894        8,938        433        462,749        157,678  
  

 

 

     

 

 

     

 

 

     

 

 

     

 

 

  

Total Proved

      179,654        14,433        1,335        988,667        371,498  

Notes:

1.

Marketable gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 5,615 cubic feet of gas per 1 barrel of oil equivalent.

2.

The marketable gas reserves estimated herein include fuel gas. The fuel gas portion of the marketable gas reserves estimated herein is 112,240 106ft3 of the proved developed marketable gas reserves, 26,217 106ft3 of the proved undeveloped marketable gas reserves, and 138,457 106ft3 of the total proved marketable gas reserves.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2022, estimated reserves.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in YPF S.A. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of YPF S.A. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

 

Submitted,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

 

  

/s/ Federico Dordoni

[SEAL]   

Federico Dordoni, P.E.

  

Senior Vice President

  

DeGolyer and MacNaughton

CERTIFICATE OF QUALIFICATION

I, Federico Dordoni, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

 

  1.

That I am an Executive Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to YPF S.A. dated February 9, 2023, and that I, as Executive Vice President, was responsible for the preparation of this report of third party.

 

  2.

That I attended Buenos Aires Institute of Technology (ITBA) University, and that I graduated with a degree in Petroleum Engineering in the year 2004; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 18 years of experience in oil and gas reservoir studies and reserves evaluations.

 

  

/s/ Federico Dordoni

[SEAL]   

Federico Dordoni, P.E.

  

Senior Vice President

  

DeGolyer and MacNaughton