Statement of Hydrocarbon Reserves South Disouq Concession as … · Reference Post-Tax NPVs have been attributed to the Proved, the Proved plus Probable and the Proved plus Probable

RTA/kab/EL-19-217500/0997 1 SDX Energy

Registered in England, number 1122740, at the above address

Gaffney, Cline & Associates Limited Bentley Hall, Blacknest Alton, Hampshire GU34 4PU, UK Telephone: +44 (0)1420 525366 Fax: +44 (0) 1420 525367 www.gaffney-cline.com

RTA/kab/EL-19-217500/0997 6th January 2020

Dr. Rob Cook VP Subsurface SDX Energy 38 Welbeck Street, London, W1G 8DP

[email protected]

Dear Rob,

Statement of Hydrocarbon Reserves South Disouq Concession as at 30th September 2019

At the request of SDX Energy (SDX), Gaffney, Cline & Associates (GCA) has performed an independent technical and economic audit of the Reserves in the South Disouq Concession in Egypt, in which SDX holds a 55% interest, as at an Effective Date of 30th September 2019.

This statement relates specifically and solely to the subject matter as defined in GCA’s scope of work and is conditional upon the assumptions described herein. The statement must be considered in its entirety and must only be used for the purpose for which it was intended.

Reserves Statement

GCA has conducted an independent audit, as of 30th September 2019, of the natural gas and condensate Reserves in the South Disouq and Ibn Yunus fields located onshore within the South Disouq Concession in the central Nile Delta. The audit was based on reserves and other information provided by SDX to GCA through November and December 2019, 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.

In the preparation of this letter, GCA has used definitions contained within the Canadian Oil and Gas Evaluation Handbook (COGEH) and National Instrument (NI) 51-101 Standards of Disclosure for Oil and Gas Activities as well as the Petroleum Resources Management System (PRMS) published by the Society of Petroleum Engineers (SPE), the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE), the Society of Exploration Geophysicists (SEG), the Society of Petrophysicists and Well Log Analysts (SPWLA), and the European Association of Geoscientists and Engineers (EAGE) in June 2018, referred to as the SPE PRMS (see Appendices I and II).

http://www.gaffney-cline.com/

mailto:[email protected]

SDX Energy 2 RTA/kab/EL-19-217500/0997

On the basis of technical and other information made available to GCA, GCA hereby provides the gross field and net entitlement reserve statement given in Table 1. Natural gas volumes represent expected gas sales and are reported in billion (109) standard cubic feet (Bscf) at standard conditions of 14.7 psia and 60°F. Condensate volumes are reported in millions of stock tank barrels (MMBbl).

Table 1: Statement of Reserves, South Disouq as at 30th September 2019

(a) Gas

South Disouq

Gross Field Gas Reserves

SDX Net Entitlement

Gas Reserves

(Bscf) (Bscf)

Proved Developed 39.15 11.37

Proved Undeveloped 7.20 2.79

Total Proved 46.36 14.16

Probable 39.16 14.17

Proved plus Probable 85.52 28.33

Possible 54.48 20.97

Proved plus Probable plus Possible

140.00 49.30

(b) Condensate

South Disouq

Gross Field Condensate

Reserves

SDX Net Entitlement Condensate

Reserves

(MMBbl) (MMBbl)




Probable 0.33 0.12


Possible 0.71 0.28


1.30 0.48

Notes:

1. Gross Field Reserves are 100% of the volumes estimated to be commercially recoverable from the fields.

2. Net Entitlement Reserves are SDX’s net economic entitlement under the terms of the PSC.

3. Entitlements include volume equivalent of value of income tax paid by EGAS on behalf of SDX.

4. Reserves are the same whether COGEH/NI 51-101 or SPE PRMS definitions are used.

Economic Assessment

A gas sales price of US$2.65/MMBTU and GCA’s 4Q 2019 Brent Crude Oil price scenario (see Table 2) were used for the economic analysis, i.e. for the economic limit test and the calculation of net entitlement volumes. Based on information provided by SDX, the condensate is assumed to sell at 90% of Brent price.


Table 2: GCA 4Q 2019 Brent Price Scenario

Year Brent Price (US$/Bbl)

4Q 2019 60.02

2020 56.90

2021 61.50

2022 66.75

2023 70.00

2024+ +2% per annum

Future capital and operating cost estimates for the Reserves cases were provided by SDX. GCA reviewed these and made minor adjustments where required in GCA’s opinion. Operating cost estimates included G&A but excluded SDX’s Cairo office overheads. Except where otherwise fixed by contract, costs were escalated at 2% p.a. from 2021 onwards.

Reference Post-Tax NPVs have been attributed to the Proved, the Proved plus Probable and the Proved plus Probable plus Possible Reserves cases, at discount rates of 7.5, 10 and 12.5%. All NPVs are discounted to 1st October 2019.

Table 3: NPV (US$ MM) of Future Cash Flow from Reserves, Net to SDX, South Disouq Fields, as at 30th September 2019

US$ MM Discount Rates

0% 5% 10% 15% 20%

Proved Developed 16.4 15.3 14.4 13.5 12.8

Proved Undeveloped 5.6 5.1 4.6 4.2 3.8

Total Proved 22.0 20.4 19.0 17.7 16.6

Probable 30.0 25.9 22.6 19.9 17.7

Proved plus Probable 52.0 46.3 41.6 37.6 34.2

Possible 39.1 30.6 24.2 19.5 15.9


91.1 76.9 65.9 57.1 50.1

It should be clearly noted that the Net Present Values (NPVs) contained herein do not represent a GCA opinion as to the market value of the subject property, nor any interest therein. In assessing a likely market value, it would be necessary to take into account a number of additional factors including: reserves risk (i.e. that Proved and/or Probable and/or Possible Reserves may not be realized within the anticipated timeframe for their exploitation); perceptions of economic and sovereign risk; potential upside; other benefits, encumbrances or charges that may pertain to a particular interest; and the competitive state of the market at the time. GCA has explicitly not taken such factors into account in deriving the reference NPVs presented herein.


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 and/or obtained from other sources (e.g., public domain), 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/or obtained from other sources (e.g., public domain), and has accepted the accuracy and completeness of this data. GCA has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.

The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.

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.

Oil and condensate volumes are reported in millions (106) of barrels at stock tank conditions (MMstb). Natural gas volumes have been quoted in billions (109) of standard cubic feet (Bscf) and are volumes of sales gas, after an allocation has been made for fuel and process shrinkage losses. Standard conditions are defined as 14.7 psia and 60°F.

GCA’s review and audit involved reviewing pertinent facts, interpretations and assumptions made by SDX or others in preparing estimates of reserves and resources. 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

Under the PRMS, Reserves are those quantities of petroleum that are anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must satisfy four criteria: discovered, recoverable, commercial and remaining (as of the evaluation’s effective date) based on the development project(s) applied.

Under COGEH, Reserves are estimated quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed.

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) prior to any net present value (NPV) analysis.

Reserves net to SDX are quoted as Net Entitlement volumes, reflecting the terms of the applicable Production Sharing Contract (PSC).

GCA has not undertaken a site visit as part of this work. As such, GCA is not in a position to comment on the operations or facilities in place, their appropriateness and condition and 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).


Notice

This document has been prepared for SDX. It may not be distributed or made available in whole or in part in any other form without the prior knowledge and written consent of GCA. No person or company other than those for whom it is intended may directly or indirectly rely upon its contents. GCA is acting in an advisory capacity only and, to the fullest extent permitted by law, disclaims all liability for actions or losses derived from any actual or purported reliance on this document (or any other statements or opinions of GCA) by the Client or by any other person or entity.

*****

It has been a pleasure preparing this Statement of Hydrocarbon Reserves for SDX Energy. Please contact the undersigned if you have any questions.

Yours sincerely,

Gaffney, Cline & Associates

Project Manager

Dr. Rand Al-Obaidy Mustafa, Senior Petroleum Engineer

Reviewed by

Dr. John W. Barker, Technical Director – Reservoir Engineering

Appendices

Appendix I COGEH Definitions of Reserves and Resources Appendix II SPE PRMS Definitions of Reserves and Resources

SDX Energy 6th January 2020

Appendix I COGEH Definitions of Reserves and Resources


Canadian Oil and Gas Evaluations Handbook (COGEH) Definition of Reserves and Resources1

August 2018 The Calgary Chapter of the Society of Petroleum Evaluation Engineers (SPEE) and industry professionals have updated the 3-volume COGEH handbooks into a single digital reference document for National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. References in the extract are to other sections of the updated COGEH.

1.3.2 TERMINOLOGY: RESOURCES AND RESERVES

Petroleum is defined as a naturally occurring mixture consisting predominantly of hydrocarbons in the gaseous, liquid, or solid phase. The term “Resources” encompasses all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including discovered and undiscovered (recoverable and unrecoverable) plus quantities already produced. Accordingly, the term “total Resource” is equivalent to Petroleum Initially-In-Place (PIIP) and it is recommended the term “PIIP” be used rather than “total Resources” to avoid any confusion that may result from the mixed historical usage of the term “Resource” to mean only the recoverable portion of PIIP.

The term Recoverable Resources is sometimes used to denote a sum of Reserves, Contingent Resources, and Prospective Resources (see Section 5.7.2.5 – Aggregating Across Resource Classes for cautions on using this term and this practice).

1.3.3 PROJECTS AND SCENARIOS

The concepts of projects and scenarios are fundamental to COGEH.

A project is:

A defined activity or set of activities for the discovery or recovery of oil or gas and related by -products.

A project provides the basis for the assessment and classification of Resources.

A scenario is:

A specific exploration or development plan for the execution of a project, with sufficient details (planned or assumed) to facilitate an estimate of potential volumes and the preparation of capital, production and operating cost forecasts to enable cash flow analysis.

The level of detail of a scenario will depend on the information available. Early in the life of a project, scenarios can vary widely with respect to recovery mechanism, facility capacities, construction methods, and development timing, etc.

Projects and scenarios are described in detail in Section 1.5 – Projects.

1.3.4 LEVELS OF EVALUATION AND REPORTING

There are three important levels at which estimates are made and recorded for Resource management and reporting.

Resource (or Reserve) Entity: The discrete part of an oil and gas asset for which a Resource estimate is prepared. For example, a Reserve entity may be an individual well zone, a group of well zones, or a pool. A Prospective Resource entity might be a play.

Property Resource Class (or Reserve): In COGEH, “property” is a term used to describe a grouping of oil and gas Reserve entities in a common geographic area (e.g., a field). Properties are defined primarily for asset management purposes to facilitate functions such as production and financial accounting and land, contract, and records management. Property Reserve will typically, but not always, consist of the estimates for multiple Reserve entities.

1 These definitions are extracted from Section 1.3 of the Canadian Oil and Gas Evaluation Handbook (COGEH) and are not intended to be an exact replica.


Reported Resources (or Reserve): The sum of all individual Resource estimates to be contained in a report. There are specific requirements for reported Reserve estimates for all Reserve entities in all properties presented in a Qualified Reserves Evaluator’s (QRE) report (see Section 1.3.8.3 - Levels of Certainty for Reported Reserves). Reported Reserves commonly refers to the corporate total Reserves a company owns.

The evaluation process begins with estimating Resource at the entity level, following which the entity level estimates are aggregated to provide the total for properties, company, reporting or other enterprise.

See Section 5.7 - Aggregation of Resource estimates for a discussion of the aggregation process.

1.3.5 THE PETROLEUM RESOURCE MANAGEMENT SYSTEM AND RESOURCE DEFINITIONS

COGEH uses the SPE-PRMS classification (see Figure 1-1), for which:

CLASS forms the vertical axis of the PRMS diagram and represents the COC. It describes the relative maturity of exploration and development projects. Assignment to a Class depends on the extent to which various conditions are satisfied.

CATEGORY forms the horizontal axis of the PRMS framework and provides a measure of the uncertainty in estimates of a Resource CLASS.

Figure 1-1 SPE-PRMS Resources Classification System

The following definitions relate to the subdivisions in the Resources classification framework of Figure 1-1 and use the primary nomenclature and concepts contained in the 2018 SPE-PRMS.

Total Petroleum Initially-In-Place (PIIP) is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations and is potentially producible. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered (equivalent to “total Resources”).


Discovered PIIP (equivalent to discovered Resources) is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The Discovered PIIP includes production, Reserves, and Contingent Resources; the remainder is unrecoverable.

Production is the cumulative quantity of petroleum that has been recovered at a given date.

Although the volume of all fluid produced from a reservoir and measured at the wellhead is essential for reservoir engineering analyses, the production referred to in the PRMS classification is the volume of specific product types that is delivered to and measured at a specific reference point (a reference, sales or transfer point) that excludes any volumes that are not delivered at that point.

Reserves are estimated remaining quantities of commercially recoverable oil, natural gas, and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data, the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Reserves are further categorized according to the level of certainty associated with the estimates and may be sub-classified based on development and production status. Refer to the full definitions of Reserves in Section 1.3.8 – Definitions of Reserves.

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development (TUD) but are not currently considered to be commercially recoverable due to one or more contingencies. Contingent Resources are further categorized according to the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. See Section 1.4.7.2.2 – Contingent Resources.

Contingencies may include economic, environmental, social and political factors, regulatory matters, a lack of markets, and a prolonged timetable for development. Contingent Resources have a Chance of Development that is less than certain.

Undiscovered PIIP (equivalent to undiscovered Resources) is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The potentially recoverable portion of Undiscovered PIIP is referred to as “Prospective Resources,” the remainder as “unrecoverable.”

Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by applying future development projects. Prospective Resources have both an associated Chance of Discovery and a Chance of Development. Prospective Resources are further categorized according to the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity. See Section 1.4.7.2.3 – Prospective Resources.

Unrecoverable is that portion of Discovered or Undiscovered PIIP quantities that is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

Resources may be unrecoverable because:

There is no known technically viable recovery process for any portion of a Resource.

Of other contingencies, including, but not limited, to lack of market access, regulatory approval, or social or environmental objections.

The sum of Reserves, Contingent Resources, and Prospective Resources is described as “Recoverable Resources” but has significant potential to be misunderstood. It is valuable for activities such as regional studies, but without an explanation and a full understanding of what it represents, it is inadequate for investment decisions. When a report includes an estimate of Recoverable Resources, it must specify:

Which Resource classes are included: Reserves, Contingent Resource and/or Prospective Resource, and the relative proportions.

Whether it is risked or un-risked with respect to Chance of Discovery and Chance of


Development (e.g., Chance of Commerciality).

The uncertainty Category for which the summation has been carried out. This should always include the sum of the Best estimates. The arithmetic summation of Low and, especially High estimates has significant potential to be misleading and is not recommended.

Regulatory agencies may forbid the disclosure of the sums of Reserves, risked or un-risked Contingent and Prospective Resource Classes because they can be misleading.

1.3.6 PROJECT MATURITY SUB-CLASSES

Project Maturity Sub-Classes (See Figure 1-2) describe the stage of an exploration or development project and correspond to the Chance of Commerciality (COC) of the project. The boundaries between the maturity sub-classes represent “decision gates” that reflect the actions (business decisions) required to move the project up the maturity “ladder” towards commercial production. The Project Maturity Sub-Classes are those of the SPE-PRMS with further guidance in Section 2.1.3.5 of the Petroleum Resources Management System, Revised, June 2018 and can be obtained through the following link: PRMS Revised, June 2018.

The use of Project Maturity Sub-Classes is relevant for all Resource Classes and is a recommended best practice. A report of a project maturity sub-class may be accompanied by an estimate of the probability of progressing to the next level of maturity.

Project Maturity Sub-Classes for Reserves are: On Production, Approved for Development and Justified for Development and describe those actions that progress identified Reserves associated with a defined project through final approvals to implementation and initiation of production and product sales.

Project Maturity Sub-Classes for Contingent Resources are: Development Pending, Development on Hold, Development Unclarified and Development Not Viable and are consistent with the 2018 PRMS.Guidance on Project Maturity Sub-Classes for Contingent Resources is provided in Section 1.4.7.2.2.9 – Project Maturity Sub-Classes for Contingent Resources.

Figure 1-2 Sub-classes based on project maturity

https://www.spe.org/en/industry/petroleum-resources-management-system-2018/


Project Maturity Sub-Classes for Prospective Resources are: Play, Lead, Prospect (refer to Section 1.4.7.2.3.2 - Project Maturity Sub-Classes for Prospective Resources for detailed guidance). These classes describe a progression in each of which, potential accumulations are evaluated according to their Chance of Discovery and, assuming a discovery, the estimated quantities that would be recoverable under appropriate development projects.

1.3.7 CLASSIFICATION OF RECOVERABLE RESOURCES

For petroleum quantities associated with simple conventional reservoirs, the divisions between the Resource Classes defined in Section 1.3.5 – The Petroleum Resource Management System and Resource Definitions may be clear, and the basic definitions alone may suffice for differentiation between classes. For example, the drilling and testing of a well in a simple structural accumulation may be sufficient to allow classification of the entire estimated recoverable quantity as Contingent Resources or Reserves. However, as the industry has trended toward the exploitation of more complex and costly petroleum sources, the divisions between Resource Classes have become less distinct, and accumulations may have several classes of Resources simultaneously. For example, in extensive “basin-centered” low-permeability gas plays, the division between all classes of remaining recoverable quantities, (e.g., Reserves, Contingent Resources, and Prospective Resources), may be highly interpretive. Consequently, additional guidance is necessary to promote consistency in classifying Resources. The following provides some clarification of the key criteria that delineate Resources.

1.3.7.1 DISCOVERY STATUS

As shown in Figure 1-2, the Total PIIP is first sub-classified based on the discovery status of a petroleum accumulation. Discovered PIIP, production, Reserves, and Contingent Resources are associated with known accumulations. Recognition as a known accumulation requires the accumulation be penetrated by a well and have evidence of the existence of petroleum. The concepts of discovery and known accumulation are discussed in detail in Section 1.4.7.1.2 – Discovered Petroleum Initially-In-Place.

1.3.7.2 COMMERCIAL STATUS

Commercial status differentiates Reserves from Contingent Resources. The criteria that should be considered in determining commerciality includes:

The project is economically viable;

There is a market for the forecast sales quantities of production required to justify development;

The necessary production, transportation facilities and access to infrastructure are available or can be made available;

The regulatory, environmental, societal and political conditions will allow for the actual implementation of the recovery project being evaluated; and

All required internal and external approvals are forthcoming. Evidence of this may include items such as signed contracts, budget approvals, and approvals for expenditures, etc.

Section 1.4.7.2.1 – Reserves provides additional details relating to the foregoing aspects of commerciality relating to classification as Reserves versus Contingent Resources.

1.3.7.3 COMMERCIAL RISK

Estimates of recoverable quantities are stated in terms of a product type delivered to a reference point (typically a custody transfer or sales point) derived from a development program, assuming commercial development. It must be recognized that Reserves, Contingent Resources, and Prospective Resources involve different risks associated with achieving commerciality. The likelihood that a project will achieve commerciality is referred to as the COC. The COC varies in different classes of Recoverable Resources as follows:

Reserves: To be classified as Reserves, estimated recoverable quantities must be associated with a project(s) that is in a known accumulation with a COC that is effectively 100 percent.

Contingent Resources: Have been discovered and are recoverable using established technology or potentially recoverable with TUD. But not all technically feasible development plans will be commercial. The commercial viability of a development project is dependent on the forecast of fiscal and other conditions over the life of the project. For Contingent Resources,


the risk component relating to the likelihood that an accumulation will be commercially developed is referred to as the Chance of Development. For Contingent Resources the COC is equal to the Chance of Development.

Prospective Resources: A Prospective Resource is an estimate of what may be recovered if a discovery is made and developed, but not all exploration projects will result in discoveries and not all discoveries will be developed. The chance that an exploration project will result in the discovery of petroleum is referred to as the Chance of Discovery. Thus, for an undiscovered accumulation the COC is the product of two risk components; the Chance of Discovery and the Chance of Development.

1.3.7.4 ECONOMIC STATUS

Demonstration of economic viability is a prerequisite for classification as a Reserve.

In examining the economic viability of Contingent Resources, the same fiscal conditions should be applied as in the estimation of Reserves, (e.g., specified economic conditions), which are generally accepted as being reasonable. By definition, Reserves are commercially (and hence economically) recoverable, but a Contingent Resources that has satisfied other relevant contingencies may or may not be economically viable and can be sub-classified by economic status:

Economic Contingent Resources are those Contingent Resources that are currently economically recoverable.

Sub-economic Contingent Resources are those Contingent Resources that are not currently economically recoverable.

The designation of a Contingent Resource as sub-economic implies there is a reasonable chance it could become economic within the foreseeable future. If this is not the case, the classification must be development not viable or unrecoverable Discovered PIIP.

Where evaluations are incomplete, such that it is premature to identify the economic viability of a project, it is acceptable to note that project economic status is undetermined (e.g., “Contingent Resource – economic status undetermined”) and in which case the Project Maturity Sub-Class would be Development Unclarified.

Classification as a Prospective Resource implies an expectation of economic viability but the assessment of this is likely to be less rigorous than for Reserves or Contingent Resource.

1.3.7.5 UNCERTAINTY CATEGORIES

Estimates of Resources always involve uncertainty, and the degree of uncertainty can vary widely between accumulations/projects and over the life of a project. Consequently, estimates of Resources should generally be quoted according to the level of confidence associated with the estimates. An understanding of statistical concepts and terminology is essential to understanding the confidence associated with Resource definitions and categories. These concepts, which apply to all Resources, are outlined in Section 1.6 – Risk and Uncertainty in Resource Evaluation and Classification.

The range of uncertainty of estimated recoverable volumes may be represented by either deterministic scenarios or by a probability distribution. Resources should be provided as Low, Best, and High estimates as follows:

Low Estimate: This is considered to be a conservative estimate of the quantity that will be recovered. It is likely the actual remaining quantities recovered will exceed the Low Estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90)2 the quantities actually recovered will equal or exceed the Low Estimate.

Best Estimate: This is considered to be the Best Estimate of the quantity that will be recovered. It is equally likely the actual remaining quantities recovered will be greater or less than the Best

2 Notation such as P90 indicates that there is a 90% probability of obtaining greater production, similarly for P50

and P10.


Estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50)3 that the quantities actually recovered will equal or exceed the Best Estimate.

High Estimate: This is considered to be an optimistic estimate of the quantity that will be recovered. It is unlikely the actual remaining quantities recovered will exceed the High Estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) the quantities actually recovered will equal or exceed the High Estimate.

1.3.8 DEFINITIONS OF RESERVES

The following Reserves definitions and guidelines are designed to assist evaluators in making Reserves estimates on a reasonably consistent basis and assist users of evaluation reports in understanding what such reports contain and, if necessary, in judging whether evaluators have followed generally accepted standards. The guidelines outline:

general criteria for classifying Reserves,

procedures and methods for estimating Reserves,

confidence levels of individual entity and aggregate Reserves estimates,

verification and testing of Reserves estimates.

The following definitions apply to both estimates of individual Reserves entities and the aggregate of Reserves for multiple entities.

1.3.8.1 RESERVES CATEGORIES

Reserves are categorized according to the probability that at least a specific volume will be produced.

In a broad sense, Reserves categories reflect the following expectations regarding the associated estimates:

Reserves Category Confidence Characterization

Proved (1P) Low Estimate, Conservative

Proved + Probable (2P) Best Estimate

Proved + Probable + Possible (3P) High Estimate, Optimistic

1.3.8.1.1 PROVED RESERVES

Proved Reserves are those Reserves that can be estimated with a high degree of certainty to be recoverable. It is likely the actual remaining quantities recovered will exceed the estimated Proved Reserves.

1.3.8.1.2 PROBABLE RESERVES

Probable Reserves are those additional Reserves that are less certain to be recovered than Proved Reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved + Probable Reserves.

1.3.8.1.3 POSSIBLE RESERVES

Possible Reserves are those additional Reserves that are less certain to be recovered than Probable Reserves. It is unlikely the actual remaining quantities recovered will exceed the sum of the estimated Proved + Probable + Possible Reserves.

Stand-alone Possible Reserves may be assigned to a property for which no Proved or Probable Reserves volumes have been assigned but would be rare. Circumstances for doing so could include any one or more of the following:

3 P50 is a statistical median and may differ from a mean. In early stage discoveries, unconventional Resources, or

frontier areas, there may be a significant difference between P50 and mean estimates.


Project economics are such that no Proved or Probable Reserves can be assigned, but on a Proved + Probable + Possible Reserves basis, the project is economically viable, and a development decision has been made (e.g., adding compression, expanding facilities, offshore development of a structure delineated mainly with seismic with only limited well control).

Only minor expenditure is required to develop the Possible Reserves and development is likely to proceed in the near future (e.g., behind-pipe zones in a well, which have Proved or Probable Reserves in another interval).

Possible Reserves may be assigned to an accumulation that is being evaluated if Proved or Probable Reserves have been assigned to an adjacent part of the same accumulation that is not part of the evaluation for which a report is being prepared.

In all these situations, there should be an intention to develop the stand-alone Possible Reserves within a reasonable time. A report should contain an explanation of the reason for the assignment of stand-alone Possible Reserves.

1.3.8.2 DEVELOPMENT AND PRODUCTION STATUS

1.3.8.2.1 DEVELOPED RESERVES

Developed Reserves are those Reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling and completing a well) to put the Reserves on production. The developed category may be sub-divided into Producing and Non-Producing.

Developed Producing Reserves are those Reserves that are expected to be recovered from completion intervals open at the time of the estimate. These Reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

Developed Non-Producing Reserves are those Reserves that either have not been on production or have previously been on production but are shut-in and the date of resumption of production is unknown.

1.3.8.2.2 UNDEVELOPED RESERVES

Undeveloped Reserves are those Reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling and completing a well) is required to render them capable of production. They must fully meet the requirements of the Reserves category (Proved, Probable, Possible) to which they are assigned and expected to be developed within a limited time (see Section 1.4.7.2.1.8 - Timing of Production and Development).

In multi-well pools, it may be appropriate to allocate total pool Reserves between the Developed and Undeveloped Sub-classes or to sub-divide the Developed Reserves for the pool between Developed Producing and Developed Non-Producing. This allocation should be based on the estimator’s assessment as to the Reserves that will be recovered from specific wells, facilities, and completion intervals in the pool and their respective development and production status.

1.3.8.3 LEVELS OF CERTAINTY FOR REPORTED RESERVES

The qualitative certainty levels contained in the definitions are applicable to “individual Reserves entities”, which refers to the lowest level that Reserves calculations are performed, and to “Reported Reserves”, which refers to the highest-level sum (aggregated quantity) of individual entity estimates for which Reserves estimates are presented. Reported Reserves should target the following levels of certainty under a specific set of economic conditions.

At least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated Proved Reserves.

At least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved + Probable Reserves.

At least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved + Probable + Possible Reserves.


A quantitative measure of the certainty levels pertaining to estimates prepared for the various Reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, most Reserves estimates are prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods. Additional clarification of certainty levels associated with Reserves estimates and the effect of aggregation is provided in Section 5.7.1.6 The Portfolio Effect.


Appendix II SPE PRMS Definitions of Reserves and Resources


Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists, Society of Petroleum Evaluation Engineers,

Society of Exploration Geophysicists, Society of Petrophysicists and Well Log Analysts, and European Association of Geoscientists & Engineers

Petroleum Resources Management System

Definitions and Guidelines (4)

(Revised June 2018)

Table 1—Recoverable Resources Classes and Sub-Classes

Class/Sub-Class Definition Guidelines

Reserves Reserves are those quantities

of petroleum anticipated to be

commercially recoverable by

application of development

projects to known

accumulations from a given

date forward under defined

conditions.

Reserves must satisfy four criteria: discovered, recoverable,

commercial, and remaining based on the development

project(s) applied. 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 the development and production

status.

To be included in the Reserves class, a project must be

sufficiently defined to establish its commercial viability (see

Section 2.1.2, Determination of Commerciality). This includes

the requirement that there is evidence of firm intention to

proceed with development within a reasonable time-frame.

A reasonable time-frame for the initiation of development

depends on the specific circumstances and varies according

to the scope of the project. While five years is recommended

as a benchmark, a longer time-frame could be applied where,

for example, development of an economic project is deferred

at the option of the producer for, among other things, market-

related reasons or to meet contractual or strategic objectives.

In all cases, the justification for classification as Reserves

should be clearly documented.

To be included in the Reserves class, there must be a

high confidence in the commercial maturity and economic

producibility of the reservoir as supported by actual

production or formation tests. In certain cases, Reserves

may be assigned on the basis of well logs and/or core

analysis that indicate that the subject reservoir is

hydrocarbon-bearing and is analogous to reservoirs in

the same area that are producing or have demonstrated

the ability to produce on formation tests.

4 These Definitions and Guidelines are extracted from the full Petroleum Resources Management System (revised June 2018)

document.


On Production The development project is

currently producing or capable

of producing and selling

petroleum to market.

The key criterion is that the project is receiving income from

sales, rather than that the approved development project is

necessarily complete. Includes Developed Producing Reserves.

The project decision gate is the decision to initiate or continue

economic production from the project.


Approved for

Development All necessary approvals have

been obtained, capital funds

have been committed, and

implementation of the

development project is ready

to begin or is under way.

At this point, it must be certain that the development

project is going ahead. The project must not be subject to

any contingencies, such as outstanding regulatory

approvals or sales contracts. Forecast capital

expenditures should be included in the reporting entity’s

current or following year’s approved budget.

The project decision gate is the decision to start investing

capital in the construction of production facilities and/or

drilling development wells.

Justified for

Development Implementation of the

development project is justified

on the basis of reasonable

forecast commercial conditions

at the time of reporting, and

there are reasonable

expectations that all necessary

approvals/contracts will be

obtained.

To move to this level of project maturity, and hence have

Reserves associated with it, the development project must be

commercially viable at the time of reporting (see Section

2.1.2, Determination of Commerciality) and the specific

circumstances of the project. All participating entities have

agreed and there is evidence of a committed project (firm

intention to proceed with development within a reasonable

time-frame}) There must be no known contingencies that

could preclude the development from proceeding (see

Reserves class).

The project decision gate is the decision by the reporting entity

and its partners, if any, that the project has reached a level of

technical and commercial maturity sufficient to justify

proceeding with development at that point in time.

Contingent

Resources Those quantities of petroleum

estimated, as of a given date,

to be potentially recoverable

from known accumulations by

application of development

projects, but which are not

currently considered to be

commercially recoverable

owing to one or more

contingencies.

Contingent Resources may include, for example, projects for

which there are currently no viable markets, where

commercial recovery is dependent on technology under

development, where evaluation of the accumulation is

insufficient to clearly assess commerciality, where the

development plan is not yet approved, or where regulatory or

social acceptance issues may exist.

Contingent Resources 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 the economic status.


Development

Pending

A discovered accumulation

where project activities are

ongoing to justify commercial

development in the

foreseeable future.

The project is seen to have reasonable potential for eventual

commercial development, to the extent that further data

acquisition (e.g., drilling, seismic data) and/or evaluations are

currently ongoing with a view to confirming that the project is

commercially viable and providing the basis for selection of an

appropriate development plan. The critical contingencies have

been identified and are reasonably expected to be resolved

within a reasonable time-frame. Note that disappointing

appraisal/evaluation results could lead to a reclassification of

the project to On Hold or Not Viable status.

The project decision gate is the decision to undertake

further data acquisition and/or studies designed to move

the project to a level of technical and commercial maturity

at which a decision can be made to proceed with

development and production.


Development

on Hold A discovered accumulation where

project activities are on hold and/or

where justification as a commercial

development may be subject to

significant delay.

The project is seen to have potential for commercial

development. Development may be subject to a significant

time delay. Note that a change in circumstances, such

that there is no longer a probable chance that a critical

contingency can be removed in the foreseeable future,

could lead to a reclassification of the project to Not Viable

status.

The project decision gate is the decision to either proceed

with additional evaluation designed to clarify the potential for

eventual commercial development or to temporarily suspend

or delay further activities pending resolution of external

contingencies.

Development

Unclarified A discovered accumulation

where project activities are

under evaluation and where

justification as a commercial

development is unknown based

on available information.

The project is seen to have potential for eventual

commercial development, but further appraisal/evaluation

activities are ongoing to clarify the potential for eventual

commercial development.

This sub-class requires active appraisal or evaluation

and should not be maintained without a plan for future

evaluation. The sub-class should reflect the actions required

to move a project toward commercial maturity and economic

production.

Development

Not Viable A discovered accumulation for

which there are no current plans

to develop or to acquire additional

data at the time because of limited

production potential.

The project is not seen to have potential for eventual

commercial development at the time of reporting, but the

theoretically recoverable quantities are recorded so that the

potential opportunity will be recognized in the event of a

major change in technology or commercial conditions.

The project decision gate is the decision not to undertake

further data acquisition or studies on the project for the

foreseeable future.


Prospective

Resources Those quantities of petroleum that

are estimated, as of a given date,

to be potentially recoverable from

undiscovered accumulations.

Potential accumulations are evaluated according to the

chance of geologic discovery and, assuming a discovery,

the estimated quantities that would be recoverable under

defined development projects. It is recognized that the

development programs will be of significantly less detail and

depend more heavily on analog developments in the earlier

phases of exploration.

Prospect A project associated with a

potential accumulation that

is sufficiently well defined to

represent a viable drilling

target.

Project activities are focused on assessing the chance of

geologic discovery and, assuming discovery, the range

of potential recoverable quantities under a commercial

development program.

Lead A project associated with a

potential accumulation that is

currently poorly defined and

requires more data acquisition

and/or evaluation to be classified

as a Prospect.

Project activities are focused on acquiring additional data

and/or undertaking further evaluation designed to confirm

whether or not the Lead can be matured into a Prospect.

Such evaluation includes the assessment of the chance of

geologic discovery and, assuming discovery, the range of

potential recovery under feasible development scenarios.

Play A project associated with a

prospective trend of potential

prospects, but that requires more

data acquisition and/or evaluation

to define specific Leads or

Prospects.

Project activities are focused on acquiring additional data

and/or undertaking further evaluation designed to define

specific Leads or Prospects for more detailed analysis of

their chance of geologic discovery and, assuming discovery,

the range of potential recovery under hypothetical

development scenarios.


Table 2—Reserves Status Definitions and Guidelines

Status Definition Guidelines

Developed

Reserves Expected quantities to be

recovered from existing wells

and facilities.

Reserves are considered developed only after the necessary

equipment has been installed, or when the costs to do so are

relatively minor compared to the cost of a well. Where required

facilities become unavailable, it may be necessary to reclassify

Developed Reserves as Undeveloped. Developed Reserves

may be further sub-classified as Producing or Non-producing.

Developed

Producing

Reserves

Expected quantities to be

recovered from completion

intervals that are open and

producing at the effective date

of the estimate.

Improved recovery Reserves are considered producing only

after the improved recovery project is in operation.

Developed

Non-Producing

Reserves

Shut-in and behind-pipe

Reserves.

Shut-in Reserves are expected to be recovered from (1)

completion intervals that are open at the time of the estimate

but which have not yet started producing, (2) wells which

were shut-in for market conditions or pipeline connections, or

(3) wells not capable of production for mechanical reasons.

Behind-pipe Reserves are expected to be recovered from

zones in existing wells that will require additional completion

work or future re-completion before start of production with

minor cost to access these reserves.

In all cases, production can be initiated or restored with

relatively low expenditure compared to the cost of drilling a

new well.

Undeveloped

Reserves Quantities expected to be

recovered through future

significant investments.

Undeveloped Reserves are to be produced (1) from new

wells on undrilled acreage in known accumulations, (2) from

deepening existing wells to a different (but known) reservoir,

(3) from infill wells that will increase recovery, or (4) where a

relatively large expenditure (e.g., when compared to the cost of

drilling a new well) is required to (a) recomplete an existing well

or (b) install production or transportation facilities for primary or

improved recovery projects.


Table 3—Reserves Category Definitions and Guidelines

Category Definition Guidelines

Proved Reserves Those quantities of petroleum

that, by analysis of geoscience

and engineering data, can be

estimated with reasonable

certainty to be commercially

recoverable from a given date

forward from known reservoirs

and under defined economic

conditions, operating methods,

and government regulations.

If deterministic methods are used, the term “reasonable

certainty” is intended to express a high degree of confidence

that the quantities will be recovered. If probabilistic methods are

used, there should be at least a 90% probability (P90) that the

quantities actually recovered will equal or exceed the estimate.

The area of the reservoir considered as Proved includes (1)

the area delineated by drilling and defined by fluid contacts,

if any, and (2) adjacent undrilled portions of the reservoir

that can reasonably be judged as continuous with it and

commercially productive on the basis of available

geoscience and engineering data.

In the absence of data on fluid contacts, Proved quantities

in a reservoir are limited by the LKH as seen in a well

penetration unless otherwise indicated by definitive

geoscience, engineering, or performance data. Such

definitive information may include pressure gradient

analysis and seismic indicators. Seismic data alone may

not be sufficient to define fluid contacts for Proved.

Reserves in undeveloped locations may be classified as Proved

provided that:

A. The locations are in undrilled areas of the reservoir

that can be judged with reasonable certainty to be

commercially mature and economically productive.

B. Interpretations of available geoscience and engineering

data indicate with reasonable certainty that the

objective formation is laterally continuous with drilled

Proved locations.

For Proved Reserves, the recovery efficiency applied to these

reservoirs should be defined based on a range of possibilities

supported by analogs and sound engineering judgment

considering the characteristics of the Proved area and the

applied development program.

Probable

Reserves Those additional Reserves that

analysis of geoscience and

engineering data indicates are

less likely to be recovered than

Proved Reserves but more

certain to be recovered than

Possible Reserves.

It is equally likely that actual remaining quantities recovered will

be greater than or less than the sum of the estimated Proved

plus Probable Reserves (2P). In this context, when probabilistic

methods are used, there should be at least a 50% probability

that the actual quantities recovered will equal or exceed the 2P

estimate.

Probable Reserves may be assigned to areas of a reservoir

adjacent to Proved where data control or interpretations of

available data are less certain. The interpreted reservoir

continuity may not meet the reasonable certainty criteria.

Probable estimates also include incremental recoveries

associated with project recovery efficiencies beyond that

assumed for Proved.


Category Definition Guidelines

Possible

Reserves Those additional reserves that

analysis of geoscience and

engineering data indicates are

less likely to be recoverable

than Probable Reserves.

The total quantities ultimately recovered from the project have

a low probability to exceed the sum of Proved plus Probable

plus Possible (3P), which is equivalent to the high-estimate

scenario. When probabilistic methods are used, there should

be at least a 10% probability (P10) that the actual quantities

recovered will equal or exceed the 3P estimate.

Possible Reserves may be assigned to areas of a reservoir

adjacent to Probable where data control and interpretations

of available data are progressively less certain. Frequently,

this may be in areas where geoscience and engineering data

are unable to clearly define the area and vertical reservoir

limits of economic production from the reservoir by a defined,

commercially mature project.

Possible estimates also include incremental quantities

associated with project recovery efficiencies beyond that

assumed for Probable.


Probable

and Possible

Reserves

See above for separate criteria

for Probable Reserves and

Possible Reserves.

The 2P and 3P estimates may be based on reasonable

alternative technical interpretations within the reservoir and/

or subject project that are clearly documented, including

comparisons to results in successful similar projects.

In conventional accumulations, Probable and/or 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 minor faulting or other geological discontinuities and have

not been penetrated by a wellbore but are interpreted to be in

communication with the known (Proved) reservoir. Probable or

Possible Reserves may be assigned to areas that are

structurally higher than the Proved area. Possible (and in some

cases, Probable) Reserves may be assigned to areas that are

structurally lower than the adjacent Proved or 2P area.

Caution should be exercised in assigning Reserves to adjacent

reservoirs isolated by major, potentially sealing faults until this

reservoir is penetrated and evaluated as commercially mature

and economically productive. Justification for assigning

Reserves in such cases should be clearly documented.

Reserves should not be assigned to areas that are clearly

separated from a known accumulation by non-productive

reservoir (i.e., absence of reservoir, structurally low reservoir, or

negative test results); such areas may contain Prospective

Resources.

In conventional accumulations, where drilling has defined

a highest known oil elevation and there exists the potential

for an associated gas cap, Proved Reserves of oil should

only be assigned in the structurally higher portions of the

reservoir if there is reasonable certainty that such portions

are initially above bubble point pressure based on

documented engineering analyses. Reservoir portions that

do not meet this certainty may be assigned as Probable

and Possible oil and/or gas based on reservoir fluid

properties and pressure gradient interpretations.


Figure 1.1—RESOURCES CLASSIFICATION FRAMEWORK

Range of Uncertainty

DIS

CO

VE

RE

D P

IIP

CO

MM

ER

CIA

LS

UB

-CO

MM

ER

CIA

L

PRODUCTION

UNRECOVERABLE

CONTINGENT RESOURCES

RESERVES

PROSPECTIVE RESOURCES

Incre

asin

g C

han

ce o

f C

om

merc

iality

Not to scale

TO

TA

L P

ET

RO

LE

UM

INIT

IALL

Y-I

N-P

LA

CE

(P

IIP

)

UN

DIS

CO

VER

ED

PII

P

UNRECOVERABLE

1P 2P 3P

P1

Proved

P2

Probable

P3

Possible

HighBest EstimateLow

1C 2C 3C

C1 C2 C3

1U 2U 3U

P50 P10P90


Figure 2.1—SUB-CLASSES BASED ON PROJECT MATURITY

Range of Uncertainty

TO

TA

L P

ET

RO

LE

UM

INIT

IAL

LY

-IN

-PL

AC

E (P

IIP)

DIS

CO

VE

RE

D P

IIP

UN

DIS

CO

VER

ED

PII

P

CO

MM

ER

CIA

LS

UB

-CO

MM

ER

CIA

L

PRODUCTION

UNRECOVERABLE

CONTINGENT

RESOURCES

RESERVES

PROSPECTIVE

RESOURCES

Incre

asin

g C

han

ce

of

Co

mm

erc

iality

On Production

Approved for

Development

Justified for

Development

Development Pending

Development On Hold

Development Unclarified

Prospect

Play

Not to scale

Project Maturity

Sub-classes

Development Not Viable

Lead

UNRECOVERABLE

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© 2020 Gaffney, Cline & Associates. All rights reserved. Terms and conditions of use: by accepting this document, the recipient agrees that the document together with all information included therein is the confidential and proprietary property of

Gaffney, Cline & Associates and includes valuable trade secrets and/or proprietary information of Gaffney, Cline & Associates (collectively "information"). Gaffney, Cline & Associates retains all rights under copyright laws and trade secret laws of the

United States of America and other countries. The recipient further agrees that the document may not be distributed, transmitted, copied or reproduced in whole or in part by any means, electronic, mechanical, or otherwise, without the express prior

written consent of Gaffney, Cline & Associates, and may not be used directly or indirectly in any way detrimental to Gaffney, Cline & Associates’ interest.

South Disouq Concession Reserves Audit As at 30th September 2019

Prepared for SDX Energy

January 2019

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Confidentiality and Disclaimer Statement

This document is confidential and has been prepared for the exclusive

use of the Client or parties named herein. It may not be distributed or

made available, in whole or in part, to any other company or person

without the prior knowledge and written consent of GCA. No person or

company other than those for whom it is intended may directly or

indirectly rely upon its contents. GCA is acting in an advisory capacity

only and, to the fullest extent permitted by law, disclaims all liability for

actions or losses derived from any actual or purported reliance on this

document (or any other statements or opinions of GCA) by the Client or

by any other person or entity.

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Report Approvals

This report was approved by the following Gaffney, Cline & Associates personnel:

Project Manager: Dr. Rand A. Mustafa – Senior Petroleum Engineer

Project Reviewer: Dr. John Barker – Technical Director

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Reserves Summary

▪ On the basis of technical and other information made available to GCA, GCA

hereby provides the following statement of Proved, Proved plus Probable and

Proved plus Probable plus Possible gas and condensate Reserves for the

South Disouq Concession (South Disouq and Ibn Yunus fields).

Notes:

1. Gross Field Reserves are 100% of the volumes estimated to be commercially recoverable from the fields.

2. Net Entitlement Reserves are SDX’s net economic entitlement under the terms of the PSC.

3. Entitlements include volume equivalent of value of income tax paid by EGAS on behalf of SDX.

4. Reserves are the same whether COGEH/NI 51-101 or SPE PRMS definitions are used.

Statement of Gas Reserves,

South Disouq

as at 30th September 2019

Statement of Condensate Reserves,

South Disouq


South Disouq

Gross Field Gas

Reserves

SDX Net

Entitlement Gas

Reserves

(Bscf) (Bscf)




Probable 39.16 14.17


Possible 54.48 20.97

Proved plus Probable

plus Possible140.00 49.30

South Disouq

Gross Field

Condensate

Reserves

SDX Net

Entitlement

Condensate

Reserves

(MMBbl) (MMBbl)




Probable 0.33 0.12


Possible 0.71 0.28

Proved plus Probable

plus Possible1.30 0.48

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NPV Summary

▪ All NPVs discounted to 1st October 2019

▪ NPVs evaluated assuming US$2.65/MMBTU gas sales price and GCA’s 4Q

2019 Brent crude oil price scenario, with a 10% discount for condensate

▪ It should be clearly noted that the Net Present Values (NPVs) contained herein do not represent a GCA opinion as to

the market value of the subject property, nor any interest therein. In assessing a likely market value, it would be

necessary to take into account a number of additional factors including: reserves risk (i.e. that Proved and/or Probable

and/or Possible Reserves may not be realized within the anticipated timeframe for their exploitation); perceptions of

economic and sovereign risk; potential upside; other benefits, encumbrances or charges that may pertain to a particular

interest; and the competitive state of the market at the time. GCA has explicitly not taken such factors into account in

deriving the reference NPVs presented herein.

NPV (US$ MM) of Future Cash Flow from Reserves, Net to SDX, South Disouq Fields


US$ MMDiscount Rates

0% 5% 10% 15% 20%

Proved Developed 16.4 15.3 14.4 13.5 12.8

Proved Undeveloped 5.6 5.1 4.6 4.2 3.8

Total Proved 22.0 20.4 19.0 17.7 16.6

Probable 30.0 25.9 22.6 19.9 17.7

Proved plus Probable 52.0 46.3 41.6 37.6 34.2

Possible 39.1 30.6 24.2 19.5 15.9

Proved plus Probable plus

Possible91.1 76.9 65.9 57.1 50.1

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Introduction

▪ The South Disouq block is located in the central Nile Delta region onshore

Egypt. SDX acquired the South Disouq concession in 2013 and farmed-out

45% to IPR Energy in 2014. SDX currently holds 55% and continues to be the

block operator.

▪ Two fields have been discovered within the Concession, South Disouq field

(2017) and Ibn Yunus (2018)

Drilling History:

▪ SD-1X 2017: Abu Madi gas discovery

▪ Ibn Yunus-1X 2018: Kafr El Sheikh gas discovery

▪ Kelvin-1X 2018: Dry Abu Madi stratigraphic trap

▪ SD-3X 2018: Abu Madi appraisal+ Kafr El Sheikh

gas discovery

▪ SD-4X 2018: Abu Madi appraisal

Source: SDX

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South Disouq Field

G&G Review and GIIP Estimates

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Seismic Line and Type Well Log

Source: SDX

▪ The seismic data across South Disouq is of reasonable quality allowing

confident interpretation of the Base Kafr El Sheikh Reservoir.

▪ The Abu Madi Reservoirs are not directly interpreted from seismic but are

stacked down from the Base Kafr El Sheikh, using the available well tops.

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Source: SDX and modified by GCA

KES

AMI

AMII

AMIII

Geoseismic Section – Highlighting The 4 Key Reservoirs Across South Disouq

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Workflow Summary

▪ GCA calculated GRV using Petrel’s map based volumetric tool and matched

the GRVs presented by SDX within less than 10%.

▪ GCA checked SDX’s petrophysical interpretation and calculated average

reservoir parameters across each of the reservoir zones, using the latest well

tops.

▪ The GRV’s and petrophysical parameters were input into a Monte Carlo

Simulation (Crystal Ball), with an appropriate range of uncertainty applied to

low and high case input parameters.

▪ GCA’s GIIP estimates for each reservoir are summarised in the following

slides.

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South Disouq – Kafr El Sheikh (KES)

Volumetric Inputs

Name P90 P50 P10 Shape

GRV MMft3 306 420 547 Lognormal

FVF 180 187 194 Normal

Name Min ML Max Shape

NTG 0.49 0.61 0.73 Beta

Phi 0.13 0.16 0.19 Beta

SH 0.46 0.57 0.69 Beta

GIIP Bscf

P90 P50 P10

2.99 4.19 5.87

Low Case GRV GDT in SD-3X

High Case Total Structure

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South Disouq – Abu Madi I (AMI)

Volumetric Area SD-3X

Volumetric Area SD-1X

GOC -6,868 ft TVDss

Probabilistic Input Parameters – Crystal Ball

Volumetric Inputs





NTG 0.34 0.42 0.50 Beta

Phi 0.18 0.23 0.27 Beta

SH 0.43 0.54 0.65 Beta

GIIP Bscf

P90 P50 P10

4.80 6.55 8.90

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South Disouq – AMII

GOC -6,890 ft TVDss

Probabilistic Input Parameters – Crystal Ball

Volumetric Inputs





NTG 0.53 0.67 0.80 Beta

Phi 0.19 0.24 0.29 Beta

SH 0.47 0.59 0.71 Beta

GIIP Bscf

P90 P50 P10

9.18 12.03 15.67

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South Disouq – AMIII

GOC -7,102 ft TVDss Volumetric Inputs


GRV MMft3 2,186 2,732 3,278 Lognormal



NTG 0.50 0.62 0.75 Beta

Phi 0.17 0.21 0.25 Beta

SH 0.47 0.59 0.71 Beta

GIIP Bscf

P90 P50 P10

29.08 38.00 49.51

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Ibn Yunus Field

G&G Review and GIIP Estimates

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Geophysical Review

▪ GCA has reviewed the geophysical

interpretation of SDX

▪ Top and Base reservoir are picked at

zero crossings, which are tied to well.

GCA suggests this is not necessarily

the best geophysical solution, but

errors/uncertainties are likely small

▪ There is strong seismic attribute

definition of the “core area” from both

far stack and gradient volumes

▪ For the “outer area”, horizon definition

is much more tentative and there is

uncertainty in sandstone pinchout, and

possible fault, definition

▪ GCA recommends that the “outer area”

only be considered in the High Case

and restricted to areas where there is

seismic attribute support.

Top Reservoir (SDX)

Base Reservoir (SDX)

Top Reservoir (SDX)

Base Reservoir (SDX)

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Minimum amplitude Far

Geophysical Attributes and Definition of Volume Cases

Low Case

Best Case

High Case

Low Case

Best Case

High Case

Average negative trough Far

▪ Final definition of pool areas for volumetric calculation

▪ Low and Best Cases are essentially as defined by SDX

▪ High Case has been redefined by GCA

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Ibn Yunus-1: Basal Kafr El Sheikh Reservoir

▪ GCA has reviewed the petrophysical interpretation and can confirm the

analysis of SDX

WATER GRADIENT

(2 KES)

Pay

Summary

Top Bottom Gross Net N/G Av Phi Av Sw Av Vcl Phi*H PhiSo*H

TVDss TVDss ft ft v/v v/v v/v ft ft

Basal KES Sand 6537.14 6645.91 108.77 100.8 0.9247 0.285 0.217 0.012 28.76 22.5

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GIIP Calculation

GIIP (Bscf)

Low Best High

39.0 66.8 112.0

GRV (MMft3) NTG Porosity Shc GEF ( = 1/FVF)

Low Best High Low Best High Low Best High Low Best High Low Best High

1,108 1,993 4,394 0.75 0.93 0.95 0.25 0.29 0.30 0.70 0.78 0.85 180 183 186

• GRV are derived from GCA interpretation of SDX geophysical attributes

• NTG is derived from a volume weighted average of those estimated by SDX for the “core” and “outer” areas

• All other parameters are as defined by SDX

• In the Monte Carlo Analysis, a negative correlation of -0.75 between NTG and GRV is introduced to allow for the apparent better reservoir quality interpreted for the “core area”

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Production Profiles

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Recovery Factors

▪ First step was to establish a range of Recovery Factors (RF) for the 5 reservoirs under evaluation

▪ The range of RFs established are shown in table below with some reasoning behind each choice

▪ In general, as this is a new development with only a few weeks production data, the range of RF

has to be fairly wide

▪ The maximum RF possible is driven by lowest expected manifold pressure, 650 psig, and the

hydrostatic head of gas at that pressure, leading to an absolute lowest possible abandonment

pressure;

– 77% for South Disouq

– 75% for Ibn Yunus

Recovery Factors Low Best High Comment

South Disouq KES 65% 70% 77% Possible basal water

South Disouq AM I 65% 75% 77% Possible edge aquifer in thin reservoir unit

South Disouq AM II 30% 40% 50%Small gas column with large basal water

column, high Kv/Kh

South Disouq AM III 55% 70% 77%Basal water confirmed from logs, but low

Kv/Kh may hold back water

Ibn Yunus 60% 70% 75%Edge aquifer & possibly low connectivity

from PTA

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Technically Recoverable Resources (TRR)

▪ From the range of RFs established, three deterministic TRR values were

derived by applying each RF to the corresponding Low, Best and High GIIP

estimates.

▪ Tables for GIIP and TRR are shown below:

TRR (Bscf) Low Best High

South Disouq KES 1.9 2.9 4.5

South Disouq AM I 3.1 4.9 6.9

South Disouq AM II 2.8 4.8 7.8

South Disouq AM III 16.0 26.6 38.1

Ibn Yunus 23.4 46.8 84.0

SUM 47.2 86.0 141.3

GIIP (Bscf) Low Best High

South Disouq KES 3.0 4.2 5.9

South Disouq AM I 4.8 6.6 8.9

South Disouq AM II 9.2 12.0 15.7

South Disouq AM III 29.1 38.0 49.5

Ibn Yunus 39.0 66.8 112.0

SUM 85.1 127.6 192.0

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Production Forecasting

▪ A single GAP model was provided by SDX containing well models and reservoir models

for South Disouq and Ibn Yunus

▪ From this single model, GCA created three versions to generate 1P, 2P and 3P

production forecasts

▪ The GIIP values for each of the 5 reservoirs in each of the three cases were updated

with GCA’s estimates.

▪ The production profile from each reservoir for each case is constrained by the TRR

established earlier.

▪ The Down Time level proposed by SDX is 5%, this is reasonable for Best and High

cases, but for the Low case a more pessimistic 15% was used, given there is no track

record yet.

▪ Manifold pressure at start up is 1,200 psig. With compression scheduled for installation

by 2021, the manifold pressure is reduced to 650 psig.

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CGR

▪ Initial CGR levels for the two main fields were provided by SDX.

▪ Given that these reservoirs are gas condensate reservoirs, the CGR will

fall over time.

▪ Given the small values involved, a simple approach was taken to replicate

a declining CGR – GCA assumed the initial CGR is maintained for ~50% of the production profile to reflect being

above the dew point

– For the remaining 50% of the profile, the CGR is stepped down until it reaches a value of 3

stb/MMscf for Ibn Yunus and 1 stb/MMscf/d for South Disouq.

Initial CGR

(stb/MMscf)

South

DisouqIbn Yunus

Low 3 9

Best 4 12

High 5 15

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Gas Production Profiles and Cumulative Recovery

Note: profiles shown are prior to any economic cut-off being applied

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Capex and Opex

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Future Activities Plan

Year Low Best High

2020Install compression ready for 1/1/2021

Install compression ready for 1/1/2021

Install compression ready for 1/1/2021

2021

Drill IY-2 Drill IY-2

Recomplete 1X from AM-3 to AM-2


2022


Drill IY-2


2023

Recomplete 3X from AM-1 to KES



2024






2025


2026


Recomplete 3X from KES to AM-1

2027

2028

2029

2030

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Capex and Opex Forecasts

Main Capex Assumptions:

▪ Well Cost = US$1.5 MM

▪ Re-completion Cost = US$0.1 MM

▪ Flow lines and Compression = US$4.5 MM

Low Best High

Capex Opex Capex Opex Capex Opex

US$ MM US$ MM US$ MM US$ MM US$ MM US$ MM

2019 Q4 3.1 1.1 3.1 1.1 3.1 1.1

2020 4.5 5.9 4.5 5.9 4.5 5.9

2021 1.7 5.5 1.5 5.5 0 5.6

2022 0.2 5.1 0.0 5.2 1.5 5.3

2023 0.1 4.7 0.2 4.9 0 5.1

2024 0.2 4.6 0.3 4.8

2025 0.1 4.3 0 4.6

2026 0.2 4.3

2027 4.3

2028 4.3

2029 4.3

9.6 22.3 9.6 31.6 9.6 49.7

Note: Operating cost estimates included G&A but excluded SDX’s Cairo office overheads.

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Economics and Reserves

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Fiscal Assumptions

▪ SDX has a 55% Working Interest in the South Disouq Concession License

▪ Assumes license expiry at end of 2037

– All profiles are limited by the economic limit as none reach the license end date

▪ GCA 4Q 2019 Brent Scenario applied:

– Based on information provided by SDX, the condensate is assumed to sell at 90% of Brent price

▪ Base on the GSA a flat US$2.65/MMBTU price applied

– Assumed to equate to US$2.85/Mscf

▪ Cost Recovery Cap of 25%

– Capex recoverable over 5 years

▪ Gas profit share based on production rate

– Never exceeds the first tranche of 32.5%

▪ Liquids profit share based on production & crude price

– Equates to 35% for this analysis except for 2020, where it equates to 37.4%

▪ Income tax of 40.55% - paid by EGAS on behalf of Contractor Group

– The volume equivalent of the value of the tax paid by the NOC on behalf of SDX has been included in the Reserve Entitlements

▪ 2% cost inflation included in the model

▪ Based on information from the client, historic costs contribute US$55.5 MM of recoverable costs at the effective date of this analysis

YearBrent Price (US$/Bbl)

4Q 2019 60.02

2020 56.90

2021 61.50

2022 66.75

2023 70.00

2024+ +2% per annum

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Basis of Opinion

This document must be considered in its entirety. It reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as

applicable, the data and information provided by the Client and/or obtained from other sources e.g. public domain, 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 outcomes will conform to the outcomes presented herein. GCA has not independently verified any information provided by or at the direction of

the Client and/or obtained from other sources e.g. public domain, and has accepted the accuracy and completeness of these data. GCA has no reason to believe that

any material facts have been withheld from it, 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 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.

This assessment has been conducted within the context of 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,

and any necessary licenses and consents including planning permission, financial interest relationships or encumbrances thereon for any part of the appraised

properties.

GCA has not undertaken a site visit and inspection. As such, GCA is not in a position to comment on the operations or facilities in place, their appropriateness and

condition and 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.

In carrying out 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 UEGL. Furthermore, the management and employees of GCA

have no interest in any of the assets evaluated or related with the analysis carried out 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.

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Reserves and Resources

In the preparation of this letter, GCA has used definitions contained within the Canadian Oil and Gas Evaluation Handbook (COGEH) and National Instrument (NI) 51-

101 Standards of Disclosure for Oil and Gas Activities as well as the Petroleum Resources Management System published by the Society of Petroleum Engineers

(SPE), the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE), the

Society of Exploration Geophysicists (SEG), the Society of Petrophysicists and Well Log Analysts (SPWLA), and the European Association of Geoscientists and

Engineers (EAGE) in June 2018, referred to as the SPE PRMS.

Under PRMS, Reserves are those quantities of petroleum that are anticipated to be commercially recoverable by application of development projects to known

accumulations from a given date forward under defined conditions. Reserves must satisfy four criteria: discovered, recoverable, commercial and remaining (as of the

evaluation’s effective date) based on the development project(s) applied.

Under COGEH, Reserves are estimated quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given

date, based on (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions,

which are generally accepted as being reasonable and shall be disclosed.

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) prior to any net present value (NPV) analysis.

Reserves net to SDX are quoted as Net Entitlement volumes, reflecting the terms of the applicable Production Sharing Contract (PSC).

There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses

and cash flows. Oil and gas reserve engineering and resource assessment must be recognized as a subjective process of estimating subsurface accumulations of oil

and gas that cannot be measured in an exact way. Estimates of oil and gas reserves or resources prepared by other parties may differ, perhaps materially, from those

contained within this report. The accuracy of any reserve estimate is a function of the quality of the available data and of engineering and geological interpretation.

Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material. Accordingly,

reserve 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.

Oil and condensate volumes appearing in this report have been quoted at stock tank conditions. Typically these volumes have been referred to in million barrel

increments (MMstb). Natural gas volumes have been quoted in billions of standard cubic feet (Bscf) and are volumes of sales gas, after an allocation has been made

for fuel and process shrinkage losses. Standard conditions are defined as 14.696 psia and 60o Fahrenheit.

GCA prepared an independent assessment of the reserves based on data and interpretations provided by the Client. It is GCA’s opinion that the estimates of total

remaining recoverable hydrocarbon liquid and gas volumes are, in the aggregate, reasonable and the reserves and resources classification and categorization is

appropriate and consistent with the definitions and guidelines for reserves and resources.

Documents

Statement of Hydrocarbon Reserves South Disouq Concession as … · Reference Post-Tax NPVs have been attributed to the Proved, the Proved plus Probable and the Proved plus Probable