EX-99.1 8 d361809dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

 

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Gaffney, Cline & Associates, Inc.

5555 San Felipe St., Suite 550

Houston, TX 77056

Telephone: +1 713 850 9955

www.gaffney-cline.com

March 9, 2017

Mr. Javier Sanagua

Auditor de Reservas

YPF S.A.

Macacha Guemes 515

C1106BKK Buenos Aires

Argentina

javier.sanagua@ypf.com

Dear Mr. Javier Sanagua,

Proved Hydrocarbon Reserves Statement

for YPF S.A. for Certain Argentine Properties

as of December 31, 2016

This Proved reserves statement has been prepared by Gaffney, Cline & Associates (GCA) and issued on March 9, 2017 at the request of YPF S.A. (YPF), operator of certain assets in Argentina. YPF’s participating interest in each asset are shown in Appendix V.

GCA has conducted an independent audit examination as of December 31, 2016, of the hydrocarbon liquid and natural gas proved reserves of 47 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:

Statement of Remaining Hydrocarbon Volumes

YPF S.A. Certain Properties in Argentina

as of December 31, 2016

 

Reserves

    Gross (100%)
Field Volumes		      YPF Net Reserves  
   Liquids
(MMm3)		      Gas
(Bm3)		      Liquids
(MMm3)		      Gas
(Bm3)		  

Proved

            

Developed Producing

      27.9        34.5        26.1        20.5  

Developed Non Producing

      0.2        0.0        0.2        0.0  

Undeveloped

      12.7        11.3        12.6        7.0  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total Proved

      40.9        45.9        38.9        27.5  
  

 

 

     

 

 

     

 

 

     

 

 

  

 

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Notes:

 

  1. Gross Field (100%) 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, which according to domestic treatment in Argentina and reporting in YPF’s 20-F filings with the SEC, are treated as financial obligations.

 

  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 27.5 Bm3 includes 7.9 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. This report is intended for inclusion in YPF’s filings (20-F, F-3) with the United States Securities and Exchange Commission.

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 Field (100%) and YPF Net Reserves for each basin.

YPF has advised GCA that the YPF reserves estimated in this report constitute approximately 37.5% percent of YPF’s Proved reserves and that the Proved Undeveloped Reserves estimated in this report constitute approximately 41.4% percent of all YPF’s Proved Undeveloped Reserves as of December 31, 2016. 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 January 31, 2017.

Reserves Assessment

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 reserves estimates and other information provided by YPF to GCA from September to December 2016 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, 2016 Proved Reserve 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.

 

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Information on net proved reserves as of December 31, 2016 was calculated in accordance with the SEC rules and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932, as amended. Accordingly oil prices used to determine volumes and reserves were calculated each month, for crude oils of different quality produced by the Company. Consequently, for calculation of volumes and reserves as of December 31, 2016 the Company considered the realized for crude oil in the domestic market (which are higher than those that had prevailed in the international market) taking into account the unweighted average price for each month within the twelve-month period ended December 31, 2016. There are no benchmark crude oil prices in Argentina that relate to YPF’s oil production from which first-day-of-month prices could be obtained. Additionally, since there are no benchmark market natural gas prices available in Argentina, the Company used average realized gas prices during the year to determine its reserves. GCA audited 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, 2016, 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 is adequate.

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

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.

 

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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 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, 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.

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.

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 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).

 

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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

 

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Project Manager

Daniel Amitrano, Principal Advisor
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Reviewed by

Rawdon Seager, Technical Director

Appendices

Appendix I: Statement of Qualifications

Appendix II: Statement of Gross Field (100%) 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

 

  

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Statement of Qualifications

D. A. Amitrano

D. A. Amitrano is one of GCA’s Principal Advisors and was the primary responsible for preparation of the audit. Mr. Amitrano has over 27 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 Civil Engineering and Field Exploitation – Production Career and Reservoir Engineering Course from Buenos Aires University, Argentina.

 

  

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Appendix II

Gross Field (100%) Volumes per Basin

 

  

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Statement of 100% Gross Field Volumes per Basin

YPF S.A. Certain Properties in Argentina

as of December 31, 2016

Liquid Hydrocarbon Volumes

 

     Proved  

Basin

    Developed      Undeveloped
Mm3		      Total
Mm3		  
     Producing
Mm3		      Non
Producing
Mm3		        

Cuyana

      2,411        35        336        2,783  

Golfo San Jorge

      19,862        —          10,493        30,355  

Neuquina

      4,125        194        1,866        6,185  

Noroeste

      1,521        —          32        1,553  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total

      27,919        229        12,727        40,876  
  

 

 

     

 

 

     

 

 

     

 

 

  

Notes:

 

  1. Hydrocarbon liquid volumes represent crude oil, condensate, gasoline and NGL estimated to be recovered during field separation and plant processing.

 

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

Natural Gas

 

     Proved  

Area

    Developed      Undeveloped
MMm3		      Total
MMm3		  
     Producing
MMm3		      Non
Producing
MMm3		        

Cuyana

      27        0        3        30  

Golfo San Jorge

      4,277        —          1,371        5,648  

Neuquina

      17,498        7        9,789        27,294  

Noroeste

      12,703        —          184        12,886  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total

      34,504        8        11,347        45,859  
  

 

 

     

 

 

     

 

 

     

 

 

  

Notes:

 

  1. Natural gas volumes represent expected gas sales plus produced gas used for consumption.

 

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

 

  

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Appendix III

YPF Net Reserves per Basin

 

  

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Statement of Reserves Net to YPF per Basin

Certain Properties in Argentina

as of December 31, 2016

Liquid Hydrocarbon Volumes

 

     Proved  

Basin

    Developed      Undeveloped
Mm3		      Total
Mm3		  
     Producing
Mm3		      Non
Producing
Mm3		        

Cuyana

      2,411        35        336        2,783  

Golfo San Jorge

      19,331        —          10,391        29,722  

Neuquina

      3,758        194        1,855        5,807  

Noroeste

      552        —          17        569  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total

      26,052        229        12,599        38,881  
  

 

 

     

 

 

     

 

 

     

 

 

  

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 historical treatment and 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.

 

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

 

  

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Statement of YPF Net Reserves per Basin

Certain Properties in Argentina

as of December 31, 2016

Natural Gas

 

     Proved  

Area

    Developed      Undeveloped
MMm3		      Total
MMm3		  
     Producing
MMm3		      Non
Producing
MMm3		        

Cuyana

      27        0        3        30  

Golfo San Jorge

      4,267        —          1,371        5,638  

Neuquina

      11,664        7        5,572        17,243  

Noroeste

      4,519        —          97        4,616  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total

      20,477        8        7,043        27,528  
  

 

 

     

 

 

     

 

 

     

 

 

  

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 historical treatment and 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.

 

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

 

  

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Appendix IV

Hydrocarbon Prices

 

  

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Hydrocarbon Prices

 

Area

    Crude Oil
Condensate
Gasoline
(US$/Bbl)		      Natural
Gas
US$/Mcf		      NGL
(US$/Bbl)		  

Acambuco

      62.97        4.98        —    

Aguaragüe

      62.97        4.80        —    

Ramos (PPE and YYE)

      62.97        4.80        —    

San Antonio Sur

      62.97        4.78        —    

Lindero Atravesado

      65.13        8.11        —    

Manantiales Behr Norte

      53.58        5.40        —    

Manantiales Behr Sur

      53.58        5.40        —    

Restinga Alí

      53.58        —          —    

Río Mayo

      53.58        —          —    

Zona Central—Bella Vista Este

      53.58        —          —    

Sarmiento No Operada

      53.58        —          —    

Barrancas

      54.68        6.23        21.56  

Cajón de los Caballos

      —          —          —    

Cerro Fortunoso

      51.38        —          —    

El Manzano

      51.38        —          —    

Estructura Cruz de Piedra-Lunlunta

      54.68        6.23        —    

L.Carrizal

      54.68        6.23        —    

LV-Cañada Dura

      —          —          —    

Llancanelo R

      —          —          —    

Mesa Verde

      54.68        —          —    

Ugarteche

      54.68        —          —    

Altiplanicie del Payún

      —          —          —    

Cerro Liupuca

      64.00        —          —    

Cerro Negro

      64.00        —          —    

Aguada de la Arena

      65.13        7.35        —    

La Ribera Bloque I

      —          —          —    

La Ribera Bloque II

      —          —          —    

Las Tacanas

      —          —          —    

Pampa de las Yeguas Bloque I

      65.13        7.49        21.56  

Aguada Toledo—Sierra Barrosa

      65.13        5.39        21.56  

Río Neuquén

      64.55        8.26        —    

Barranca de los Loros

      65.55        —          —    

Don Ruiz

      65.13        —          —    

Las Manadas

      65.55        —          —    

Loma Amarilla

      65.55        —          —    

Loma del Molle

      —          —          —    

Los Caldenes

      65.55        2.68        —    

Volcán Auca Mahuida

      65.55        —          —    

Barranca Baya

      55.08        5.23        —    

Seco León

      55.08        5.44        —    

Barranca Yankowsky

      —          —          —    

Cañadón Yatel

      55.08        5.23        —    

Lomas del Cuy

      55.08        5.23        —    

Los Monos

      55.08        —          —    

Los Perales

      55.08        5.23        —    

Ojo de Agua

      —          —          —    

 

  

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Appendix V

YPF’s Participating Interest in Each Area

 

  

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YPF’s Participant Interest in each Area

 

Area

    WI (%)  

MANANTIALES BEHR

      100 % 

RESTINGA ALI

      100 % 

RIO MAYO

      100 % 

SARMIENTO

      100 % 

ZONA CENTRAL-BELLA V.ESTE

      50 % 

ACAMBUCO

      23 % 

AGUARAGUE

      53 % 

LINDERO ATRAVESADO

      38 % 

RAMOS (PLUSPETROL ENERGY)

      23 % 

RAMOS YPF (YPF + ASTRA)

      28 % 

SAN ANTONIO SUR

      53 % 

BARRANCAS

      100 % 

CERRO FORTUNOSO

      100 % 

EST.CRUZ PIEDRA-LUNLUNTA

      100 % 

EL MANZANO 100%

      100 % 

EL MANZANO 60%

      60 % 

L.CARRIZAL

      100 % 

MESA VERDE

      100 % 

UGARTECHE

      100 % 

CERRO LIUPUCA

      100 % 

CERRO NEGRO

      100 % 

AGUADA DE LA ARENA

      80 % 

PAMPA DE LAS YEGUAS BLOQUE I

      50 % 

AGUADA TOLEDO-SIERRA BARROSA

      100 % 

RÍO NEUQUÉN

      33 % 

BARRANCA DE LOS LOROS

      100 % 

DON RUIZ

      100 % 

LOMA AMARILLA

      100 % 

LOS CALDENES

      100 % 

LAS MANADAS

      100 % 

VOLCAN AUCA MAHUIDA

      100 % 

BARRANCA BAYA

      100 % 

CAÑADON YATEL

      100 % 

LOMAS DEL CUY

      100 % 

LOS MONOS

      100 % 

LOS PERALES

      100 % 

SECO LEON

      100 % 

CAJON DE LOS CABALLOS

      60 % 

LV-CAÑADA DURA

      70 % 

LLANCANELO R

      100 % 

ALTIPLANICIE DEL PAYUN

      100 % 

CERRO PARTIDO*

      0 % 

LA RIBERA BLOQUE I

      100 % 

LA RIBERA BLOQUE II

      100 % 

LAS TACANAS

      50 % 

MATA MORA*

      0 % 

LOMA DEL MOLLE

      50 % 

BARRANCA YANKOWSKY

      98 % 

CERRO AVISPA*

      0 % 

Notes:

The YPF’s interest participation in the mentioned areas below, were transferred during 2016 to the following companies:

 

  1. Working Interest in Palmar Largo was transferred to HIGH LUCK GROUP LTD SUC ARG

 

  2. The YPF’s participation in Corralera, Cerro Partido, Mata Mora and Cerro Avispa areas were transferred to GAS Y PETROLEO DEL NEUQUEN S.A.

 

  

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Appendix VI

SEC Reserves Definitions

 

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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.

(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:

 

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].

 

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  (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.

 

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(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;

 

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

 

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

 

  (D) Production of geothermal steam.

 

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

 

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

 

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

 

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

 

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

 

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

 

  (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18)    Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 

  (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

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

 

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

 

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

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

 

(20) Production costs.

 

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

 

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

 

  (B) Repairs and maintenance.

 

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

 

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

 

  (E) Severance taxes.

 

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

 

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

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

 

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  (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.

 

 

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(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.

 

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Appendix VII

Glossary

 

26

Glossary – Standard Oil Industry Terms and Abbreviations    LOGO

 

%    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

 

 

27

Glossary – Standard Oil Industry Terms and Abbreviations    LOGO

 

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

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

 

 

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Glossary – Standard Oil Industry Terms and Abbreviations    LOGO

 

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

 

 

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Glossary – Standard Oil Industry Terms and Abbreviations    LOGO

 

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

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

 

 

30