EX-99.15AIII 11 t1700553_ex15aiii.htm EXHIBIT 15.A(III)
​
EXHIBIT 15.a(iii)​
Gaffney, Cline & Associates Limited Bentley Hall, Blacknest Alton, Hampshire GU34 4PU, UK Telephone: +44 (0)1420 525366Fax: +44 (0) 1420 525367 www.gaffney-cline.com JKB/kab/EL-16-211000/0841 9th March, 2017 Mr. Pietro Consonni Vice President Reserves Eni S.p.A.Via Emilia 1 20097 San Donato Milanese Milano, Italy Dear Mr Consonni, Proved Reserves Statement (SEC Rules) Certain Properties in Asiaas of 31st December, 2016 This proved reserves audit has been conducted by Gaffney, Cline & Associates (GCA) at the request of Eni S.p.A. (Eni or “the Client”), in certain properties located in Asia. This third party report, completed on February 14, is intended for inclusion in Eni’s filings to the U.S. Securities and Exchange Commission (SEC).This statement relates specifically and solely to the subject matter as set out herein and is conditional upon the specified assumptions. The report must be considered in its entirety and must only be used for the purpose for which it was intended.On the basis of technical and other information made available to GCA concerning these properties, GCA has conducted an independent audit examination, as of 31st December, 2016, of the proved crude oil and natural gas reserves as prepared by Eni in certain properties in Asia, based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal register.Reserves included herein are expressed as net reserves as represented by Eni.Eni has advised GCA that the net proved reserves of the properties that GCA reviewed represent 0.4 percent of Eni’s total net proved reserves as of December 31, 2016, on an oil- equivalent basis. GCA is not in a position to verify this statement as it was not requested to review Eni’s other oil and gas assets. Reserves AssessmentThis audit examination was based on reserves estimates and other information provided by Eni to GCA through 31st December, 2016, and included such tests, procedures and adjustments as were considered necessary. All questions that arose during the audit process were resolved to GCA’s satisfaction. For the purposes of this assessment, Eni provided GCA with a set of data and presentation material that included production, reservoir studies and aJKB/kab/EL-16-211000/0841 1 Eni S.p.A. Registered in England, number 1122740, at the above address
E-51

​
selection of static and dynamic models. GCA audited the data provided for consistency and reasonableness. GCA also had discussions and meetings with Eni technical and commercial personnel. As part of the audit GCA developed independent production forecasts, employing decline curve analysis, material balance and type well methods, in addition to auditing and reviewing Eni’s static, dynamic and material balance models, to ensure consistency with the volumetric and other methods performed by Eni. The properties are all mature producing fields and it is GCA’s opinion that performance-based methods are appropriate for the purposes of estimating remaining recoverable volumes and reserves. GCA has also performed an economic limit test to establish the economic limit and commerciality of the properties in aggregate. Up to the economic limit, the GCA estimates of proved reserves for the reviewed properties are, in aggregate, reasonable and within 7 percent of Eni’s estimates, when compared on the basis of net equivalent barrels. The economic tests for the 31st December, 2016 net proved reserves were based on a flat oil price of US$35.38 per barrel, based on an unweighted average of the first day of the month realized prices over the preceding 12 months, as per SEC rules. Future capital costs were derived from development plans prepared by Eni for the fields. Recent historical operating expense data were used as the basis for operating cost projections. GCA has reviewed Eni’s estimates of capital and operating costs and considers them to be reasonable. Excluding abandonment costs, GCA has found that Eni has projected sufficient capital investments and operating expenses to economically produce the projected volumes. It is GCA’s opinion that the estimates of net proved reserves as of 31st December, 2016, are, in the aggregate, reasonable and the reserves categorization is appropriate and consistent with the definitions for reserves in Part 210 Rule 4-10(a) of Regulation S-X of the US Securities and Exchange Commission (see Appendix I). GCA concludes that the methodologies employed by Eni in the derivation of the proved reserves estimates are appropriate, and that the quality of the data relied upon and the depth and thoroughness of the reserves estimation process are adequate. 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, engineering and production 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 Eni S.p.A. 2March, 2017
E-52

​
selection of static and dynamic models. GCA audited the data provided for consistency and reasonableness. GCA also had discussions and meetings with Eni technical and commercial personnel. As part of the audit GCA developed independent production forecasts, employing decline curve analysis, material balance and type well methods, in addition to auditing and reviewing Eni’s static, dynamic and material balance models, to ensure consistency with the volumetric and other methods performed by Eni. The properties are all mature producing fields and it is GCA’s opinion that performance-based methods are appropriate for the purposes of estimating remaining recoverable volumes and reserves. GCA has also performed an economic limit test to establish the economic limit and commerciality of the properties in aggregate. Up to the economic limit, the GCA estimates of proved reserves for the reviewed properties are, in aggregate, reasonable and within 7 percent of Eni’s estimates, when compared on the basis of net equivalent barrels. The economic tests for the 31st December, 2016 net proved reserves were based on a flat oil price of US$35.38 per barrel, based on an unweighted average of the first day of the month realized prices over the preceding 12 months, as per SEC rules. Future capital costs were derived from development plans prepared by Eni for the fields. Recent historical operating expense data were used as the basis for operating cost projections. GCA has reviewed Eni’s estimates of capital and operating costs and considers them to be reasonable. Excluding abandonment costs, GCA has found that Eni has projected sufficient capital investments and operating expenses to economically produce the projected volumes. It is GCA’s opinion that the estimates of net proved reserves as of 31st December, 2016, are, in the aggregate, reasonable and the reserves categorization is appropriate and consistent with the definitions for reserves in Part 210 Rule 4-10(a) of Regulation S-X of the US Securities and Exchange Commission (see Appendix I). GCA concludes that the methodologies employed by Eni in the derivation of the proved reserves estimates are appropriate, and that the quality of the data relied upon and the depth and thoroughness of the reserves estimation process are adequate. 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, engineering and production 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 Eni S.p.A. 2March, 2017
E-53

​
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 Eni. 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. The qualifications of the technical person primarily responsible for overseeing this audit are provided in Appendix II. 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. Notice This report was prepared for public disclosure in its entirety in conjunction with filings to the SEC by Eni S.p.A. Yours sincerely, Gaffney, Cline & Associates Project Manager Jeremy Berry, Global Business Development Manager Reviewed by Dr. John W Barker, Technical Director Appendices Appendix I SEC Reserves Definitions Appendix II Technical Qualifications of Person Responsible for Audit Eni S.p.A. March, 2017 4
E-54

​
Appendix I SEC Reserves Definitions Eni S.p.A. March, 2017
E-55

​
U.S. SECURITIES AND EXCHANGE COMMISSION (SEC) MODERNIZATION OF OIL AND GAS REPORTING1 Oil and Gas Reserves Definitions and Reporting (a) Definitions (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties. (2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) Same environment of deposition; (iii) Similar geological structure; and (iv) Same drive mechanism. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi- solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons. (4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 1 Extracted from 17 CFR Parts 210, 211, 229, and 249 [Release Nos. 33-8995; 34-59192; FR-78; File No. S7- 15-08] RIN 3235-AK00].
E-56

​
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. (iv) Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. (10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section. (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in pail as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs. (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. (iii) Dry hole contributions and bottom hole contributions. (iv) Costs of drilling and equipping exploratory wells. (v) Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
E-57

​
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir. (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: (1) Lifting the oil and gas to the surface; and (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as: a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered. (ii) Oil and gas producing activities do not include: (A) Transporting, refining, or marketing oil and gas; (B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or (D) Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be
E-58

​
recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. (18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter
E-59

​
(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) Pro ved area. The part of a property to which proved reserves have been specifically attributed. (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the
E-60

​
proved classification when:(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and(B) The project has been approved for development by all necessary parties and entities, including governmental entities.(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.(23) Proved properties. Properties with proved reserves.(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
E-61

​
(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.
E-62

​
Appendix II Technical Qualifications of Person Responsible for Audit
E-63

​
Statement of Qualification Dr. John W. Barker Dr. John Barker is a Technical Director with Gaffney, Cline & Associates (GCA) in the UK and was responsible for overseeing the preparation of the audit. Dr. Barker has over 30 years of international industry experience as a reservoir engineer, both in major oil companies and in consulting. He has worked on conventional oil, gas and gas condensate fields of all types in many different parts of the world, including naturally fractured reservoirs and enhanced oil recovery projects, and also on some tight gas and heavy oil fields. He is an acknowledged expert in all aspects of reservoir simulation and has extensive experience in estimation, auditing and reporting of reserves and resources. Dr. Barker is a former Executive Editor of the SPE Reservoir Engineering journal, and has authored 34 technical publications, of which 20 have appeared in peer reviewed journals. He holds an M.A. in Mathematics from the University of Cambridge and a Ph.D. in Applied Mathematics from the California Institute of Technology. He is a member of the Society of Petroleum Engineers and of the Society of Petroleum Evaluation Engineers.
E-64