|
Gaffney, Cline & Associates, Inc.
5555 San Felipe St., Suite 550
Houston, TX 77056
Telephone: +1 713 850 9955
www.gaffney-cline.com
March 9th, 2017 |
Mr. Horacio Turri
Director Ejecutivo Exploración y Producción
Pampa Energía S.A.
Maipú 1 - Piso 19
C1084ABA Ciudad Autónoma de Buenos Aires
República Argentina
Dear Mr. Turri,
Proved Hydrocarbon Reserves Statement
for Pampa Energía 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 9th, 2017 at the request of Pampa Energía S.A. (PAMPA), for certain assets in Argentina. PAMPA’s participating interest in each asset are shown in Appendix II.
GCA has conducted an independent audit examination as of December 31, 2016, of the hydrocarbon liquid and natural gas proved reserves of 10 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
Pampa Energía S.A. Certain Properties in Argentina
as of December 31, 2016
Reserves | PAMPA Net Reserves |
Liquids | Gas |
(MMbbl) | (Bcf) |
Proved | | |
Developed | 23.1 | 235.0 |
Undeveloped | 4.3 | 167.2 |
Total Proved | 27.4 | 402.2 |
Notes:
1. PAMPA Net Reserves represent PAMPA’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 PAMPA’s 20-F filings with the SEC, are treated as financial obligations.
SOP/sop/AB-16-2039.00 Pampa Energía S.A. | 1 |
2. Hydrocarbon liquid volumes represent crude oil, condensate, gasoline and NGL estimated to be recovered during field separation and plant processing and are reported in millions of stock tank barrels (MMbbl).
3. Natural gas volumes represent expected gas sales plus produced gas used for consumption and are reported in billion (109) standard cubic foot (Bcf) at standard condition of 15 degrees Celsius and 1 atmosphere.
4. 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 PAMPA’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.
Our study was completed on February 10th, 2017.
Reserves Assessment
GCA’s audit of the PAMPA 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 PAMPA. 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 PAMPA 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 advised by PAMPA. PAMPA is subject to extensive regulations relating to the oil and gas industry in Argentina which include specific natural gas market regulations.
Information on net proved reserves as of December 31, 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 PAMPA’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 PAMPA in estimating the reserves in Argentina.
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March 9th, 2017 | 2 |
Future capital costs were derived from development program forecasts prepared by PAMPA for the fields. Recent historical operating expense data were utilized as the basis for operating cost projections. GCA has found that PAMPA 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 in17-CFR Part 210Rule 4-10(a) of Regulation S-X of the United States Securities and Exchange Commission (as set out in Appendix III). GCA concludes that the methodologies employed by PAMPA 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.
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 Pampa Energía S.A.
GCA is not aware of any potential changes in regulations applicable to these areas that could affect the ability of PAMPA 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 ofgeoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.
There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas resources assessments must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas resources prepared by other parties may differ, perhaps materially, from those contained within this report.
The accuracy of any 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.
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March 9th, 2017 | 3 |
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 PAMPA 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).
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
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March 9th, 2017 | 4 |
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.
Pampa Energía S.A.
March 9th, 2017 | 5 |
Notice
This report is intended for inclusion in its entirety in PAMPA’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. Pampa Energía S.A. will obtain GCA's prior written approval for any other use of any results, statements or opinions expressed to Pampa Energía S.A. in this report, which are attributed to GCA.
Yours sincerely,
Gaffney, Cline & Associates
____________________________
Project Manager
Sergio Paredes, Principal Advisor
___________________________
Reviewed by
Roberto Wainhaus, Principal Advisor
Appendices
Appendix I: Statement of Qualifications
Appendix II: PAMPA’s Participating Interest in each Area
Appendix III: SEC Reserves Definitions
Appendix IV: Glossary
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March 9th, 2017 | 6 |
Appendix I
Statement of Qualifications
Pampa Energía S.A.
March 9th, 2017
Statement of Qualifications
S. O. Paredes
S. O. Paredes is a GCA Principal Advisor and was the primary responsible for the audit. Mr. Paredes has over 28 years of diversified international industry experience with international integrated producing companies, as well as in integrated operations with international service companies in Mexico, Malaysia, Venezuela, Ecuador, Peru, Colombia, Argentina, USA, Spain, Trinidad & Tobago, etc. His expertise includes the geosciences and reservoir development and its management, including the classification and reporting of reserves and resources. He holds a MS Nuclear Engineer from Instituto Balseiro, Comision Nacional de Energía Atómica / Universidad Nacional de Cuyo, Bariloche, Argentina and a Master in International Management from Daniel’s College of Business, University of Denver, CO, USA.
Pampa Energía S.A.
March 9th, 2017
Appendix II
PAMPA’s Participating Interest in Each Area
Pampa Energía S.A.
March 9th, 2017
PAMPA’s Participant Interest in each Unit
Concession / Contract | WI |
25 de Mayo - Medanito | 100% |
Agua Amarga * | 46.92% |
Bajada del Palo * | 46.92% |
El Mangrullo w/o fase I and II ** | 100.00% |
El Mangrullo fase I and II ** | 57% |
Entre Lomas (Neuquén) * | 46.92% |
Entre Lomas (Rio Negro) * | 46.92% |
Jagüel de los Machos | 100% |
Rio Neuquén (Neuquén) | 33.07% |
Rio Neuquén (Rio Negro) | 31.42% |
Sierra Chata | 45.55% |
* Total net WI results from 58.88% equity interest in Petrolera Entre Lomas (PELSA), which has a 73.15% WI in the concessions (total WI of 43.07%), plus a 3.85% of direct WI participation in the Agua Amarga, Bajada del Palo and Entre Lomas concessions.
** WI on wells drilled under fase I and Fase II contracts is 57%, WI for the rest of the wells 100%, resulting for El Mangrullo in a total effective WI for PDP of 85.48%, and a total effective WI for 1P of 86.15%
Pampa Energía S.A.
March 9th, 2017
Appendix III
SEC Reserves Definitions
U.S. SECURITIES AND EXCHANGE COMMISSION (SEC)
MODERNIZATION OF OIL AND GAS REPORTING1
Oil and Gas Reserves Definitions and Reporting
(a) Definitions
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property,
including costs of lease bonuses and options to purchase or lease properties, the portion of costsapplicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recordingfees, 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, butare typically at a more advanced stage of development than the reservoir of interest and thus mayprovide concepts to assist in the interpretation of more limited data and estimation of recovery. Whenused to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the followingcharacteristics with the reservoir of interest:
(i) Same geological formation (but not necessarily in pressure communication with thereservoir 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 morefavorable 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 temperaturein 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 thereserves 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 ofthe 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 thereserves 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
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].
costs, including depreciation and applicable operating costs of support equipment and facilitiesand other costs of development activities, are costs incurred to:
(i) Gain access to and prepare well locations for drilling, including surveying well locations forthe purpose of determining specific development drilling sites, clearing ground, draining,road building, and relocating public roads, gas lines, and power lines, to the extentnecessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type stratigraphic test wells, and servicewells, 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 gascycling 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 orfield, an incremental development in a producing field, or the integrated development of a group ofseveral 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 theoperation. The value of the products that generate revenue shall be determined at the terminal point ofoil 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 prospectingcosts) and after acquiring the property. Principal types of exploration costs, which include depreciationand applicable operating costs of support equipment and facilities and other costs of explorationactivities, are:
(i) Costs of topographical, geographical and geophysical studies, rights of access toproperties to conduct those studies, and salaries and other expenses of geologists,geophysical crews, and others conducting those studies. Collectively, these are sometimesreferred to as geological and geophysical or "G&G" costs.
(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valoremtaxes on properties, legal costs for title defense, and the maintenance of land andlease records.
(iii) Dry hole contributions and bottom hole contributions.
(iv) Costs of drilling and equipping exploratory wells.
(v) Costs of drilling exploratory-type stratigraphic test wells.
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir
in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory
well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14)Extension well.An extension well is a well drilled to extend the limits of a known reservoir.
(15)Field.An area consisting of a single reservoir or multiple reservoirs all grouped on or related tothe same individual geological structural feature and/or stratigraphic condition. There may be two or morereservoirs in a field which are separated vertically by intervening impervious strata, or laterally by localgeologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fieldsmay 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 explorationor for the purpose of removing the oil or gas from such properties;
(C) The construction, drilling, and production activities necessary to retrieve oil and gasfrom their natural reservoirs, including the acquisition, construction, installation, andmaintenance 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 toextract liquid hydrocarbons); and
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oilsands, shale, coalbeds, or other nonrenewable natural resources which are intendedto be upgraded into synthetic oil or gas, and activities undertaken with a view to suchextraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded asending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusualphysical 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 mainpipeline, 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, ifthose 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 termsaleablehydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons aredelivered.
(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 intosynthetic oil or gas by a registrant that does not have the legal right to produce or arevenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or naturalresources 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 aproject 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 todefine clearly the area and vertical limits of commercial production from the reservoir by adefined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentagerecovery of the hydrocarbons in place than the recovery quantities assumed for probablereserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within thereservoir or subject project that are clearly documented, including comparisons to results insuccessful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identifydirectly adjacent portions of a reservoir within the same accumulation that may beseparated from proved areas by faults with displacement less than formation thickness orother geological discontinuities and that have not been penetrated by a wellbore, and theregistrant believes that such adjacent portions are in communication with the known(proved) reservoir. Possible reserves may be assigned to areas that are structurally higheror lower than the proved area if these areas are in communication with the provedreservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined ahighest 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 reservoirabove 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 reasonablecertainty 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 berecovered.
(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. Whenprobabilistic methods are used, there should be at least a 50% probability that the actualquantities 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 reserveswhere data control or interpretations of available data are less certain, even if theinterpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higherthan the proved area if these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with agreater percentage recovery of the hydrocarbons in place than assumed for provedreserves.
(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 thegeoscience and engineering data) is used to generate a full range of possible outcomes and theirassociated 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 othercosts of operating and maintaining those wells and related equipment and facilities, theybecome part of the cost of oil and gas produced. Examples of production costs (sometimescalled 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 wellsand related equipment and facilities.
(D) Property taxes and insurance applicable to proved properties and wells and relatedequipment 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 extentthat the support equipment and facilities are used in oil and gas producing activities, theirdepreciation and applicable operating costs become exploration, development orproduction costs, as appropriate. Depreciation, depletion, and amortization of capitalizedacquisition, exploration, and development costs are not production costs but also becomepart of the cost of oil and gas produced along with production (lifting) costs identifiedabove.
(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 beeconomically producible—from a given date forward, from known reservoirs, and under existing economicconditions, operating methods, and government regulations—prior to the time at which contractsproviding 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 toextract the hydrocarbons must have commenced or the operator must be reasonably certain that it willcommence 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, bejudged 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 withreasonable 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 beassigned in the structurally higher portions of the reservoir only if geoscience, engineering,or performance data and reliable technology establish the higher contact with reasonablecertainty.
(iv) Reserves which can be produced economically through application of improved recoverytechniques (including, but not limited to, fluid injection) are included in the provedclassification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties nomore favorable than in the reservoir as a whole, the operation of an installed programin the reservoir or an analogous reservoir, or other evidence using reliable technologyestablishes 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-monthperiod prior to the ending date of the period covered by the report, determined as anunweighted arithmetic average of the first-day-of-the-month price for each month withinsuch 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 highdegree 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. Ahigh degree of confidence exists if the quantity is much more likely to be achieved than not, and, aschanges 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 (includingcomputational 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 analogousformation.
(26)Reserves.Reserves are estimated remaining quantities of oil and gas and related substancesanticipated to be economically producible, as of a given date, by application of development projects toknown 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 deliveringoil and gas or related substances to market, and all permits and financing required to implement theproject.Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated bymajor, potentially sealing, faults until those reservoirs are penetrated and evaluated aseconomically producible. Reserves should not be assigned to areas that are clearly separatedfrom a known accumulation by a non-productive reservoir(i.e., absence of reservoir, structurallylow 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 maybe considered to be unrecoverable. Resources include both discovered and undiscoveredaccumulations.
(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, airinjection, salt-water disposal, water supply for injection, observation, or injection for in-situcombustion.
(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 intentof being completed for hydrocarbon production. The classification also includes tests identified as coretests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests areclassified as “exploratory type” if not drilled in a known area or “development type” if drilled in a knownarea.
(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 wellswhere 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 atgreater 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 anyacreage for which an application of fluid injection or other improved recovery technique iscontemplated, unless such techniques have been proved effective by actual projects in thesame reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.
Appendix IV
Glossary
|
Gaffney, Cline & Associates, Inc.
5555 San Felipe St., Suite 550
Houston, TX 77056
Telephone: +1 713 850 9955
www.gaffney-cline.com |
% | 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 |
SOP/sop/AB-16-2039.00 Pampa Energía S.A. | 21 |
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 |
Pampa Energía S.A.
March 9th, 2017 | 22 |
DHI | Direct Hydrocarbon Indicator |
DLIS | Digital Log Interchange Standard |
DST | Drill Stem Test |
DWT | Dead-weight ton |
E&A | Exploration & Appraisal |
E&P | Exploration and Production |
EBIT | Earnings before Interest and Tax |
EBITDA | Earnings before interest, tax, depreciation and amortisation |
ECS | Elemental Capture Spectroscopy |
EI | Entitlement Interest |
EIA | Environmental Impact Assessment |
ELT | Economic Limit Test |
EMV | Expected Monetary Value |
EOR | Enhanced Oil Recovery |
EUR | Estimated Ultimate Recovery |
FDP | Field Development Plan |
FEED | Front End Engineering and Design |
FPSO | Floating Production Storage and Offloading |
FSO | Floating Storage and Offloading |
FWL | Free Water Level |
ft | Foot/feet |
Fx | Foreign Exchange Rate |
g | gram |
g/cc | grams per cubic centimetre |
gal | gallon |
gal/d | gallons per day |
G&A | General and Administrative costs |
GBP | Pounds Sterling |
Pampa Energía S.A.
March 9th, 2017 | 23 |
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 |
Pampa Energía S.A.
March 9th, 2017 | 24 |
LKG | Lowest Known Gas |
LKH | Lowest Known Hydrocarbons |
LKO | Lowest Known Oil |
LNG | Liquefied Natural Gas |
LoF | Life of Field |
LPG | Liquefied Petroleum Gas |
LTI | Lost Time Injury |
LWD | Logging while drilling |
m | Metres |
M | Thousand |
m3 | Cubic metres |
Mcf or Mscf | Thousand standard cubic feet |
MCM | Management Committee Meeting |
MMcf or MMscf | Million standard cubic feet |
m3/d | Cubic metres per day |
mD | Measure of Permeability in millidarcies |
MD | Measured Depth |
MDT | Modular Dynamic Tester |
Mean | Arithmetic average of a set of numbers |
Median | Middle value in a set of values |
MFT | Multi Formation Tester |
mg/l | milligrams per litre |
MJ | Megajoules (One Million Joules) |
Mm3 | Thousand Cubic metres |
Mm3/d | Thousand Cubic metres per day |
MM | Million |
MMm3 | Million Cubic metres |
Pampa Energía S.A.
March 9th, 2017 | 25 |
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 |
Pampa Energía S.A.
March 9th, 2017 | 26 |
PIIP | Petroleum Initially In Place |
PJ | Petajoules (1015Joules) |
PSDM | Post Stack Depth Migration |
psi | Pounds per square inch |
psia | Pounds per square inch absolute |
psig | Pounds per square inch gauge |
PUD | Proved Undeveloped |
PVT | Pressure, Volume and Temperature |
P10 | 10% Probability |
P50 | 50% Probability |
P90 | 90% Probability |
RF | Recovery factor |
RFT | Repeat Formation Tester |
RT | Rotary Table |
R/P | Reserve to Production |
Rw | Resistivity of water |
SCAL | Special core analysis |
cf or scf | Standard Cubic Feet |
cfd or scfd | Standard Cubic Feet per day |
scf/ton | Standard cubic foot per ton |
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 |
Pampa Energía S.A.
March 9th, 2017 | 27 |
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 (1012Joules) |
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 |
Pampa Energía S.A.
March 9th, 2017 | 28 |
Pampa Energía S.A.
March 9th, 2017 | 29 |
Pampa Energía S.A.
March 9th, 2017 | 30 |
Mr. Horacio Turri
Director Ejecutivo Exploración y Producción
Pampa Energía S.A.
Maipú 1 - Piso 19
C1084ABA Ciudad Autónoma de Buenos Aires
República Argentina
Dear Mr. Turri,
Proved Hydrocarbon Reserves Statement
for Petrolera Pampa 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 9th, 2017 at the request of Pampa Energía S.A. (PEPASA), for certain assets in Argentina. PEPASA’s participating interest in each asset are shown in Appendix II.
GCA has conducted an independent audit examination as of December 31, 2016, of the hydrocarbon liquid and natural gas proved reserves of 4 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
Petrolera Pampa S.A. Certain Properties in Argentina
as of December 31, 2016
Reserves | PEPASA Net Reserves |
Liquids | Gas |
(MMbbl) | (Bcf) |
Proved | | |
Developed | 0.4 | 108.5 |
Undeveloped | 0.0 | 15.5 |
Total Proved | 0.4 | 124.0 |
Notes:
5. PEPASA Net Reserves represent PEPASA’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 inPampa Energía’s 20-F filings with the SEC, are treated as financial obligations.
6. 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 barrels (MMbbl).
7. Natural gas volumes represent expected gas sales plus produced gas used for consumption and are reported in billion (109) standard cubic foot (Bcf) at standard condition of 15 degrees Celsius and 1 atmosphere.
8. Totals may not exactly equal the sum of the individual entries because of rounding.
Pampa Energía S.A.
March 9th, 2017 | 31 |
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 Pampa Energía’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.
Our study was completed on February 10th, 2017.
Reserves Assessment
GCA’s audit of the PEPASA 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 PEPASA. 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 PEPASA 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 advised by PEPASA. PEPASA is subject to extensive regulations relating to the oil and gas industry in Argentina which include specific natural gas market regulations.
Information on net proved reserves as of December 31, 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 PEPASA’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 PEPASA in estimating the reserves in Argentina.
Future capital costs were derived from development program forecasts prepared by PEPASA for the fields. Recent historical operating expense data were utilized as the basis for operating cost projections. GCA has found that PEPASA 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
Pampa Energía S.A.
March 9th, 2017 | 32 |
categorization is appropriate and consistent with the definitions for reserves set out in17-CFR Part 210Rule 4-10(a) of Regulation S-X of the United States Securities and Exchange Commission (as set out in Appendix III). GCA concludes that the methodologies employed by PEPASA 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.
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 Pampa Energía S.A.
GCA is not aware of any potential changes in regulations applicable to these areas that could affect the ability of PEPASA 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 ofgeoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.
There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas resources assessments must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas resources prepared by other parties may differ, perhaps materially, from those contained within this report.
The accuracy of any 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 PEPASA in preparing estimates of reserves. GCA performed procedures necessary to enable it to render an opinion on the appropriateness of the methodologies employed, adequacy
Pampa Energía S.A.
March 9th, 2017 | 33 |
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).
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.
Pampa Energía S.A.
March 9th, 2017 | 34 |
Notice
This report is intended for inclusion in its entirety in Pampa Energía’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. Pampa Energía S.A. will obtain GCA's prior written approval for any other use of any results, statements or opinions expressed to Pampa Energía S.A. in this report, which are attributed to GCA.
Yours sincerely,
Gaffney, Cline & Associates
____________________________
Project Manager
Sergio Paredes, Principal Advisor
___________________________
Reviewed by
Roberto Wainhaus, Principal Advisor
Appendices
Appendix I: Statement of Qualifications
Appendix II: PEPASA’s Participating Interest in each Area
Appendix III: SEC Reserves Definitions
Appendix IV: Glossary
Pampa Energía S.A.
March 9th, 2017 | 35 |
Appendix V
Statement of Qualifications
Pampa Energía S.A.
March 9th, 2017
Statement of Qualifications
S. O. Paredes
S. O. Paredes is a GCA Principal Advisor and was the primary responsible for the audit. Mr. Paredes has over 28 years of diversified international industry experience with international integrated producing companies, as well as in integrated operations with international service companies in Mexico, Malaysia, Venezuela, Ecuador, Peru, Colombia, Argentina, USA, Spain, Trinidad & Tobago, etc. His expertise includes the geosciences and reservoir development and its management, including the classification and reporting of reserves and resources. He holds a MS Nuclear Engineer from Instituto Balseiro, Comision Nacional de Energía Atómica / Universidad Nacional de Cuyo, Bariloche, Argentina and a Master in International Management from Daniel’s College of Business, University of Denver, CO, USA.
Pampa Energía S.A.
March 9th, 2017
Appendix VI
PEPASA’s Participating Interest in Each Area
Pampa Energía S.A.
March 9th, 2017
PEPASA’s Participant Interest in each Unit
Concession / Contract | WI |
Rincón del Mangrullo | 50% |
Anticlinal Campamento | 15% |
Estación Fernandez Oro | 15% |
El Mangrullo *** | 43% |
*** Working interest consist of 43% of all wells in Fase I and Fase II contracts.
Pampa Energía S.A.
March 9th, 2017
Appendix VII
SEC Reserves Definitions
U.S. SECURITIES AND EXCHANGE COMMISSION (SEC)
MODERNIZATION OF OIL AND GAS REPORTING1
Oil and Gas Reserves Definitions and Reporting
(a) Definitions
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property,
including costs of lease bonuses and options to purchase or lease properties, the portion of costsapplicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recordingfees, 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, butare typically at a more advanced stage of development than the reservoir of interest and thus mayprovide concepts to assist in the interpretation of more limited data and estimation of recovery. Whenused to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the followingcharacteristics with the reservoir of interest:
(v) Same geological formation (but not necessarily in pressure communication with thereservoir of interest);
(vi) Same environment of deposition;
(vii) Similar geological structure; and
(viii) Same drive mechanism.
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no morefavorable 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 temperaturein 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 thereserves 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:
(iii) Through existing wells with existing equipment and operating methods or in which the cost ofthe required equipment is relatively minor compared to the cost of a new well; and
(iv) Through installed extraction equipment and infrastructure operational at the time of thereserves 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
1Extracted 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].
costs, including depreciation and applicable operating costs of support equipment and facilitiesand other costs of development activities, are costs incurred to:
(v) Gain access to and prepare well locations for drilling, including surveying well locations forthe purpose of determining specific development drilling sites, clearing ground, draining,road building, and relocating public roads, gas lines, and power lines, to the extentnecessary in developing the proved reserves.
(vi) Drill and equip development wells, development-type stratigraphic test wells, and servicewells, including the costs of platforms and of well equipment such as casing, tubing,pumping equipment, and the wellhead assembly.
(vii)Acquire, construct, and install production facilities such as lease flow lines, separators,treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gascycling and processing plants, and central utility and waste disposal systems.
(viii)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 orfield, an incremental development in a producing field, or the integrated development of a group ofseveral 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 theoperation. The value of the products that generate revenue shall be determined at the terminal point ofoil 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 prospectingcosts) and after acquiring the property. Principal types of exploration costs, which include depreciationand applicable operating costs of support equipment and facilities and other costs of explorationactivities, are:
(vi) Costs of topographical, geographical and geophysical studies, rights of access toproperties to conduct those studies, and salaries and other expenses of geologists,geophysical crews, and others conducting those studies. Collectively, these are sometimesreferred to as geological and geophysical or "G&G" costs.
(vii)Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valoremtaxes on properties, legal costs for title defense, and the maintenance of land andlease records.
(viii)Dry hole contributions and bottom hole contributions.
(ix) Costs of drilling and equipping exploratory wells.
(x) 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.
(17)Extension well.An extension well is a well drilled to extend the limits of a known reservoir.
(18)Field.An area consisting of a single reservoir or multiple reservoirs all grouped on or related tothe same individual geological structural feature and/or stratigraphic condition. There may be two or morereservoirs in a field which are separated vertically by intervening impervious strata, or laterally by localgeologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fieldsmay 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.
(19)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 gasfrom their natural reservoirs, including the acquisition, construction, installation, andmaintenance of field gathering and storage systems, such as:
(3) Lifting the oil and gas to the surface; and
(4) Gathering, treating, and field processing (as in the case of processing gas toextract liquid hydrocarbons); and
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oilsands, shale, coalbeds, or other nonrenewable natural resources which are intendedto be upgraded into synthetic oil or gas, and activities undertaken with a view to suchextraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded asending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusualphysical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
c. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a mainpipeline, a common carrier, a refinery, or a marine terminal; and
d. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, ifthose 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 termsaleablehydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons aredelivered.
(ii) Oil and gas producing activities do not include:
(A) Transporting, refining, or marketing oil and gas;
(E) Processing of produced oil, gas or natural resources that can be upgraded intosynthetic oil or gas by a registrant that does not have the legal right to produce or arevenue interest in such production;
(F) Activities relating to the production of natural resources other than oil, gas, or naturalresources from which synthetic oil and gas can be extracted; or
(G) Production of geothermal steam.
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be
recovered than probable reserves.
(vii)When deterministic methods are used, the total quantities ultimately recovered from aproject 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.
(viii)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 todefine clearly the area and vertical limits of commercial production from the reservoir by adefined project.
(ix) Possible reserves also include incremental quantities associated with a greater percentagerecovery of the hydrocarbons in place than the recovery quantities assumed for probablereserves.
(x) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within thereservoir or subject project that are clearly documented, including comparisons to results insuccessful similar projects.
(xi) Possible reserves may be assigned where geoscience and engineering data identifydirectly adjacent portions of a reservoir within the same accumulation that may beseparated from proved areas by faults with displacement less than formation thickness orother geological discontinuities and that have not been penetrated by a wellbore, and theregistrant believes that such adjacent portions are in communication with the known(proved) reservoir. Possible reserves may be assigned to areas that are structurally higheror lower than the proved area if these areas are in communication with the provedreservoir.
(xii)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined ahighest 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 reservoirabove 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 reasonablecertainty 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 berecovered.
(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. Whenprobabilistic methods are used, there should be at least a 50% probability that the actualquantities recovered will equal or exceed the proved plus probable reserves estimates.
(v) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserveswhere data control or interpretations of available data are less certain, even if theinterpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higherthan the proved area if these areas are in communication with the proved reservoir.
(vi) Probable reserves estimates also include potential incremental quantities associated with agreater percentage recovery of the hydrocarbons in place than assumed for provedreserves.
(vii)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 thegeoscience and engineering data) is used to generate a full range of possible outcomes and theirassociated 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 othercosts of operating and maintaining those wells and related equipment and facilities, theybecome part of the cost of oil and gas produced. Examples of production costs (sometimescalled lifting costs) are:
(F) Costs of labor to operate the wells and related equipment and facilities.
(G) Repairs and maintenance.
(H) Materials, supplies, arid fuel consumed and supplies utilized in operating the wellsand related equipment and facilities.
(I) Property taxes and insurance applicable to proved properties and wells and relatedequipment and facilities.
(J) 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 extentthat the support equipment and facilities are used in oil and gas producing activities, theirdepreciation and applicable operating costs become exploration, development orproduction costs, as appropriate. Depreciation, depletion, and amortization of capitalizedacquisition, exploration, and development costs are not production costs but also becomepart of the cost of oil and gas produced along with production (lifting) costs identifiedabove.
(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 beeconomically producible—from a given date forward, from known reservoirs, and under existing economicconditions, operating methods, and government regulations—prior to the time at which contractsproviding 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 toextract the hydrocarbons must have commenced or the operator must be reasonably certain that it willcommence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(C) The area identified by drilling and limited by fluid contacts, if any, and
(D) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, bejudged 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 withreasonable 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 beassigned in the structurally higher portions of the reservoir only if geoscience, engineering,or performance data and reliable technology establish the higher contact with reasonablecertainty.
(iv) Reserves which can be produced economically through application of improved recoverytechniques (including, but not limited to, fluid injection) are included in the provedclassification when:
(C) Successful testing by a pilot project in an area of the reservoir with properties nomore favorable than in the reservoir as a whole, the operation of an installed programin the reservoir or an analogous reservoir, or other evidence using reliable technologyestablishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(D) 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-monthperiod prior to the ending date of the period covered by the report, determined as anunweighted arithmetic average of the first-day-of-the-month price for each month withinsuch period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
(27)Proved properties.Properties with proved reserves.
(28)Reasonable certainty.If deterministic methods are used, reasonable certainty means a highdegree 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. Ahigh degree of confidence exists if the quantity is much more likely to be achieved than not, and, aschanges 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.
(29)Reliable technology.Reliable technology is a grouping of one or more technologies (includingcomputational 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 analogousformation.
(30)Reserves.Reserves are estimated remaining quantities of oil and gas and related substancesanticipated to be economically producible, as of a given date, by application of development projects toknown 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 deliveringoil and gas or related substances to market, and all permits and financing required to implement theproject.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated bymajor, potentially sealing, faults until those reservoirs are penetrated and evaluated aseconomically producible. Reserves should not be assigned to areas that are clearly separatedfrom a known accumulation by a non-productive reservoir(i.e., absence of reservoir, structurallylow 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 maybe considered to be unrecoverable. Resources include both discovered and undiscoveredaccumulations.
(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, airinjection, salt-water disposal, water supply for injection, observation, or injection for in-situcombustion.
(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 intentof being completed for hydrocarbon production. The classification also includes tests identified as coretests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests areclassified as “exploratory type” if not drilled in a known area or “development type” if drilled in a knownarea.
(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 wellswhere a relatively major expenditure is required for recompletion.
(iv) 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 atgreater distances.
(v) 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.
(vi) Under no circumstances shall estimates for undeveloped reserves be attributable to anyacreage for which an application of fluid injection or other improved recovery technique iscontemplated, unless such techniques have been proved effective by actual projects in thesame reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.
Appendix VIII
Glossary
% | Percentage | | bpd | Barrels per day |
1H05 | First half (6 months) of 2005 (example) | | boe | Barrels of oil equivalent @ xxx mcf/Bbl |
2Q06 | Second quarter (3 months) of 2006 (example) | | boepd | Barrels of oil equivalent per day @ xxx mcf/Bbl |
2D | Two dimensional | | BOP | Blow Out Preventer |
3D | Three dimensional | | bopd | Barrels oil per day |
4D | Four dimensional | | bwpd | Barrels of water per day |
1P | Proved Reserves | | BS&W | Bottom sediment and water |
2P | Proved plus Probable Reserves | | BTU | British Thermal Units |
3P | Proved plus Probable plus Possible Reserves | | bwpd | Barrels water per day |
ABEX | Abandonment Expenditure | | CBM | Coal Bed Methane |
ACQ | Annual Contract Quantity | | CO2 | Carbon Dioxide |
oAPI | Degrees API (American Petroleum Institute) | | CAPEX | Capital Expenditure |
AAPG | American Association of Petroleum Geologists | | CCGT | Combined Cycle Gas Turbine |
AVO | Amplitude versus Offset | | cm | centimetres |
A$ | Australian Dollars | | CMM | Coal Mine Methane |
B | Billion (109) | | CNG | Compressed Natural Gas |
Bbl | Barrels | | Cp | Centipoise (a measure of viscosity) |
/Bbl | per barrel | | CSG | Coal Seam Gas |
BBbl | Billion Barrels | | CT | Corporation Tax |
BHA | Bottom Hole Assembly | | D1BM | Design 1 Build Many |
BHC | Bottom Hole Compensated | | DCQ | Daily Contract Quantity |
Bscf or Bcf | Billion standard cubic feet | | Deg C | Degrees Celsius |
Bscfd or Bcfd | Billion standard cubic feet per day | | Deg F | Degrees Fahrenheit |
Bm3 | Billion cubic metres | | DHI | Direct Hydrocarbon Indicator |
bcpd | Barrels of condensate per day | | DLIS | Digital Log Interchange Standard |
BHP | Bottom Hole Pressure | | DST | Drill Stem Test |
| blpd | Barrels of liquid per day | | DWT | Dead-weight ton |
| | | E&A | Exploration & Appraisal |
E&P | Exploration and Production | | GRV | Gross Rock Volumes |
EBIT | Earnings before Interest and Tax | | GTL | Gas to Liquids |
EBITDA | Earnings before interest, tax, depreciation and amortisation | | GWC | Gas water contact |
ECS | Elemental Capture Spectroscopy | | HDT | Hydrocarbons Down to |
EI | Entitlement Interest | | HSE | Health, Safety and Environment |
EIA | Environmental Impact Assessment | | HSFO | High Sulphur Fuel Oil |
ELT | Economic Limit Test | | HUT | Hydrocarbons up to |
EMV | Expected Monetary Value | | H2S | Hydrogen Sulphide |
EOR | Enhanced Oil Recovery | | IOR | Improved Oil Recovery |
EUR | Estimated Ultimate Recovery | | IPP | Independent Power Producer |
FDP | Field Development Plan | | IRR | Internal Rate of Return |
FEED | Front End Engineering and Design | | J | Joule (Metric measurement of energy) I kilojoule = 0.9478 BTU) |
FPSO | Floating Production Storage and Offloading | | k | Permeability |
FSO | Floating Storage and Offloading | | KB | Kelly Bushing |
FWL | Free Water Level | | KJ | Kilojoules (one Thousand Joules) |
ft | Foot/feet | | kl | Kilolitres |
Fx | Foreign Exchange Rate | | km | Kilometres |
g | gram | | km2 | Square kilometres |
g/cc | grams per cubic centimetre | | kPa | Thousands of Pascals (measurement of pressure) |
gal | gallon | | KW | Kilowatt |
gal/d | gallons per day | | KWh | Kilowatt hour |
G&A | General and Administrative costs | | LAS | Log ASCII Standard |
GBP | Pounds Sterling | | LKG | Lowest Known Gas |
GCoS | Geological Chance of Success | | LKH | Lowest Known Hydrocarbons |
GDT | Gas Down to | | LKO | Lowest Known Oil |
GIIP | Gas Initially In Place | | LNG | Liquefied Natural Gas |
GJ | Gigajoules (one billion Joules) | | LoF | Life of Field |
GOC | Gas Oil Contact | | LPG | Liquefied Petroleum Gas |
GOR | Gas Oil Ratio | | LTI | Lost Time Injury |
LWD | Logging while drilling | | MWD | Measuring While Drilling |
m | Metres | | MWh | Megawatt hour |
M | Thousand | | mya | Million years ago |
m3 | Cubic metres | | NGL | Natural Gas Liquids |
Mcf or Mscf | Thousand standard cubic feet | | N2 | Nitrogen |
MCM | Management Committee Meeting | | NTG | Net/Gross Ratio |
MMcf or MMscf | Million standard cubic feet | | NPV | Net Present Value |
m3/d | Cubic metres per day | | OBM | Oil Based Mud |
mD | Measure of Permeability in millidarcies | | OCM | Operating Committee Meeting |
MD | Measured Depth | | ODT | Oil-Down-To |
MDT | Modular Dynamic Tester | | OGIP | Original Gas in Place |
Mean | Arithmetic average of a set of numbers | | OIIP | Oil Initially In Place |
Median | Middle value in a set of values | | OOIP | Original Oil in Place |
MFT | Multi Formation Tester | | OPEX | Operating Expenditure |
mg/l | milligrams per litre | | OWC | Oil Water Contact |
MJ | Megajoules (One Million Joules) | | p.a. | Per annum |
Mm3 | Thousand Cubic metres | | Pa | Pascals (metric measurement of pressure) |
Mm3/d | Thousand Cubic metres per day | | P&A | Plugged and Abandoned |
MM | Million | | PDP | Proved Developed Producing |
MMm3 | Million Cubic metres | | Phie | effective porosity |
MMm3/d | Million Cubic metres per day | | PI | Productivity Index |
MMBbl | Millions of barrels | | PIIP | Petroleum Initially In Place |
MMBTU | Millions of British Thermal Units | | PJ | Petajoules (1015Joules) |
Mode | Value that exists most frequently in a set of values = most likely | | PSDM | Post Stack Depth Migration |
Mscfd | Thousand standard cubic feet per day | | psi | Pounds per square inch |
MMscfd | Million standard cubic feet per day | | psia | Pounds per square inch absolute |
MW | Megawatt | | psig | Pounds per square inch gauge |
| | | PUD | Proved Undeveloped |
| | | PVT | Pressure, Volume and Temperature |
P10 | 10% Probability | | TCM | Technical Committee Meeting |
P50 | 50% Probability | | TOC | Total Organic Carbon |
P90 | 90% Probability | | TOP | Take or Pay |
RF | Recovery factor | | Tpd | Tonnes per day |
RFT | Repeat Formation Tester | | TVD | True Vertical Depth |
RT | Rotary Table | | TVDss | True Vertical Depth Subsea |
R/P | Reserve to Production | | UFR | Umbilical Flow Lines and Risers |
Rw | Resistivity of water | | USGS | United States Geological Survey |
SCAL | Special core analysis | | US$ | United States dollar |
cf or scf | Standard Cubic Feet | | VLCC | Very Large Crude Carrier |
cfd or scfd | Standard Cubic Feet per day | | Vsh | shale volume |
scf/ton | Standard cubic foot per ton | | VSP | Vertical Seismic Profiling |
SL | Straight line (for depreciation) | | WC | Water Cut |
so | Oil Saturation | | WI | Working Interest |
SPM | Single Point Mooring | | WPC | World Petroleum Council |
SPE | Society of Petroleum Engineers | | WTI | West Texas Intermediate |
SPEE | Society of Petroleum Evaluation Engineers | | wt% | Weight percent |
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 (1012Joules) | | | |
Tscf or Tcf | Trillion standard cubic feet | | | |
