South Disouq Concession Reserves Audit As at 30 September 2019€¦ · zero crossings, which are tied to well. GCA suggests this is not necessarily the best geophysical solution,

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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)

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 Possible140.00 49.30

South Disouq

Gross Field

Condensate

Reserves

SDX Net

Entitlement

Condensate

Reserves

(MMBbl) (MMBbl)

Proved Developed 0.20 0.06

Proved Undeveloped 0.06 0.02

Total Proved 0.26 0.08

Probable 0.33 0.12

Proved plus Probable 0.59 0.21

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

South Disouq Concession Reserves Audit As at 30 September 2019€¦ · zero crossings, which are tied to well. GCA suggests this is not necessarily the best geophysical solution,