laying the foundations for production growth

SDX Energy Plc 2019 Q2 Interim Report

Laying the foundations for production growth

3 / SDX Energy Plc / 2019 Q2 Interim Report

Our Highlights

Second Quarter 2019

Contents 06 Key Financial & Operating Highlights 08 Review of Operations 16 Management’s Discussion & Analysis 38 Financial Statements 42 Notes to the Financial Statements IBC Corporate Information

Mark Reid, CFO and Interim CEO of SDX, commented:

“The Company continues to make good progress toward achieving its three medium-term strategic objectives of securing first gas at South Disouq in Q4 2019, executing an efficient and successful 12-well drilling campaign in Morocco in 2019/20, and continuing with our potential exploration drilling campaign in South Disouq in 2020. Production and capex from our operations remains within our guided ranges and we look forward to updating the market on the results of our drilling activities in Meseda and Morocco in the coming months. Our cashflow generation, liquidity position, and balance sheet remain strong and continue to provide us with the necessary funding to complete all of these medium-term strategic objectives. Achieving first gas at South Disouq in Q4 will be transformative for the Company, as we will benefit from our 55% share of the expected production plateau of 50 MMscfe/d from Q1 2020.”

SDX Energy Plc / 2019 Q2 Interim Report / 01

Our Highlights

Second Quarter 2019

Operations • H1 2019 production of 3,539 boe/d, net to SDX, an increase of 9% from H1 2018 due to successful drilling

in Meseda and increased gas sales in Morocco. Q2 2019 production of 3,366 boe/d (net) was 9% lower than Q1 2019, primarily the result of an increased water cut in North West Gemsa.

Egypt • Construction of the South Disouq central processing facility (“CPF”), pipeline, and well tie-ins continued

in H1 2019 with first gas expected in Q4 2019. The CPF has cleared customs in Alexandria and is en route to site at South Disouq, thus achieving the second of the three key project milestones. The final milestone of first gas in Q4 2019 remains on track, subject to the successful installation and hook-up of the CPF, which is scheduled to begin later in August, with the Company aiming for a gross plateau production rate of c.50 MMscfe/d by Q1 2020.

• Discussions continue with our partner relating to the potential exploration drilling programme in South

Disouq. A further update will be provided when agreement on the drilling programme is reached. • In Meseda, following successful drilling of the Rabul-7 development well, a further development well,

MSD-19, was spud in early August, and the Company will announce the result of this well in due course. The Company maintains its existing gross production guidance of 4,000-4,200 bbl/d.

• In North West Gemsa, 2019 gross production guidance is maintained at 3,000-3,200 boe/d, with well

workovers slowing the rate of natural field decline. Morocco • Planning for the drilling of 12 wells in Morocco is at an advanced stage, with the campaign targeted to begin

in Q4 2019 and complete in H1 2020. All long lead items have been ordered and all key contracts finalised. The programme will be targeting 15bcf of gross unrisked prospective resources.

• Morocco gas customers added in late 2018/early 2019 continue to stabilise consumption rates, underpinning

2019 sales guidance of an annual average gross rate of 6.0-6.5 MMscf/d. • The drilling campaign in Morocco will target sufficient reserves to satisfy existing customers’ forecast

demands and test new play opening areas of prospectivity across the portfolio. Financial • H1 2019 net revenues of US$25 million are 4% higher than in H1 2018, with higher production compensating

for lower net realised average oil/service fees of US$57/boe, compared to US$62/boe in H1 2018. • H1 2019 netback of US$18 million was lower than the US$19 million achieved in H1 2018, mainly because

of increased workover opex activity in H1 2019 and a greater allocation of costs to opex in H1 2019. These costs were allocated to capex/drilling campaigns in Morocco and NW Gemsa in H1 2018.

• Operating cash flow before capex in H1 2019 remained robust at US$13 million (H1 2018: US$20 million

(which was higher as a result of the unwinding of a larger Egyptian Petroleum Company (“EGPC”) debtor in the period)), supporting US$19 million of capex invested in the period (H1 2018: US$22 million). Of this US$19 million, US$12 million related to the South Disouq CPF, pipeline and well tie-ins and 3D seismic, US$3 million for customer connections and 3D seismic in Morocco, US$3 million for workovers in Meseda and North West Gemsa and US$1 million for drilling and completion costs at South Ramadan.

• The Company’s drilling and development activities set out above are fully funded from expected future cash

flows and its existing sources of liquidity. • Cash at 30 June 2019 was US$11 million, with the US$10 million EBRD facility remaining undrawn.

Summary

3,539boe/d 9% increase in H1 2019 production compared to H1 2018

12 well drilling campaign planned for Morocco in Q4 2019/Q1 2020

2 of 3 South Disouq project milestones completed, as factory acceptance tests have been passed and the CPF has cleared customs in Egypt

South Disouq first gas targeted Q4 2019, reaching a gross plateau production rate of c.50 MMscfe/d by Q1 2020

Highlights


Our Highlights

Second Quarter 2019

SDX’s key financial metrics for the three and six months ended 30 June 2019 and 2018 are: Three months Six months ended ended 30 June 30 June US$ million, except per unit amounts 2019 2018 2019 2018 Net revenues 12.7 13.5 25.4 24.4 Netback(1) 9.1 10.3 18.5 19.3 Net realised average oil/service fees-US$/barrel 60.62 64.23 57.44 61.97 Net realised average Morocco gas price-US$/mcf 10.31 10.51 10.28 10.27 Netback-US$/boe 29.84 33.00 28.80 32.91 EBITDAX(1) (2) 7.3 8.6 15.1 16.2 Exploration & evaluation expense (“E&E”) (0.4) (2.1) (0.6) (5.3) Depletion, depreciation and amortisation (“DD&A”) (6.0) (3.7) (11.9) (6.2) Total comprehensive(loss)/income (0.5) 0.6 (0.4) 1.0 Net cash generated from operating activities 5.8 9.4 12.8 20.3 Cash and cash equivalents 11.2 25.2 11.2 25.2 (1) Refer to the “Non-IFRS Measures” section of this release below for details of Netback and EBITDAX.

(2) EBITDAX for each period presented includes non-cash revenue relating to the grossing up of Egyptian Corporate Tax on the North West Gemsa

PSC, which is paid by the Egyptian State on behalf of the Company (Q2 2019: US$0.9 million, Q2 2018: US$1.2 million, H1 2019: US$1.9 million,

H1 2018: US$2.2 million)

• The main components of SDX’s comprehensive loss of US$(0.4) million for the six months ended

30 June 2019 are: - US$18.5 million netback; - US$11.9 million of DD&A; - US$3.3 million of G&A; and - US$1.1 million of transaction costs covering the re-domicile of the Company from Canada to the UK,

the Company’s capital reduction to improve our ability to pay dividends, and other business development activities.

• Netback for the six months ended 30 June 2019 was US$18.5 million, down from US$19.3 million for the

six months to 30 June 2018. This decrease has mainly been driven by a 7% reduction in H1 2019 realised average oil prices in Egypt to US$57.44/bbl from US$61.97/bbl in H1 2018, higher opex resulting from increased workover activity in H1 2019, and a greater allocation of costs to opex in the period. These costs were allocated to capex/drilling campaigns in Morocco and NW Gemsa in H1 2018. These factors were partly offset by increased production at Meseda and in Morocco.

• The cash position of US$11.2 million as at 30 June 2019 is broadly unchanged from the US$11.4 million

as at 31 March 2019 and US$6.1 million lower than the US$17.3 million as at 31 December 2018. • The main components of this H1 2019 cash movement are: operating cash flows of US$14.1 million,

which includes a US$3.0 million improvement in working capital predominantly due to the continued reduction in Egyptian receivables, an Egyptian corporation tax payment of US$1.3 and the US$19.3 million capital investment programme discussed below. The Company’s three-year, US$10.0 million credit facility established in July 2018 with the EBRD remains undrawn.

Corporate & Financial

US$12.8m Net cash generated from operating activities during H1 2019

US$11.2m Cash balance as at 30 June 2019

US$10.0m Undrawn facility with EBRD

Cash flows and existing sources of liquidity fully fund 2019/20 development and drilling programmes


Our Highlights

Second Quarter 2019

• US$19.3 million of capital expenditure has been invested into the business during the six months ended 30 June 2019. This is comprised of:

- US$12.4 million for the South Disouq development, comprising US$9.8 million for the CPF, pipeline and well tie-ins, and US$2.6 million for the 170km2 3D seismic programme;

- US$1.9 million in North West Gemsa for the ongoing well workover programme; - US$1.1 million in Meseda for the ongoing electrical submersible pump (“ESP”) and sucker

rod pump replacement programmes; - US$1.4 million in South Ramadan for the SRM-3 well and development project, the results

of which are currently being assessed; and - US$2.5 million in Morocco, comprising US$2.1 million for customer connections, facilities and

studies, and US$0.4 million relating to the 240km2 3D seismic programme in Gharb Centre. • Trade and other receivables have reduced to US$21.8 million as at 30 June 2019, down from US$24.3 million

as at 31 December 2018. This reduction is predominantly a result of the continued recovery of trade receivables which were due from the Egyptian State and offset against costs owing to Egyptian State contractors used on the South Disouq development project.

• Post period end, the Company has collected a further US$5.7 million of trade receivables of which

US$3.9 million was collected from EGPC and US$1.8 million was collected from third-party gas customers in Morocco. Out of the US$3.9 million from EGPC, US$0.4 million was offset against South Disouq drilling and development costs and amounts owing to joint venture partners.

Corporate & Financial (continued)

US$19.3m Capital expenditure during H1 2019

170km2 3D seismic acquisition programme in South Disouq completely safely and successfully during H1 2019, with interpretation ongoing

Highlights


Our Highlights

Second Quarter 2019

• The Company’s entitlement share of production from its operations for the six months ended 30 June 2019 was 3,539 boe/d (gross – 9,250 boe/d) split as follows:

- North West Gemsa 1,972 boe/d (gross – 3,944 boe/d) - Meseda 822 bbl/d (gross – 4,313 bbl/d) - Morocco 745 boe/d (gross – 993 boe/d) Egypt • In South Disouq (SDX 55% working interest and operator), the Company was awarded a 25-year development

lease on 1 July 2019 covering the Ibn Yunus development area, which together with the 25-year South Disouq development lease granted on 2 January 2019 comprises the South Disouq development project. Gas sales agreements have been signed for both development leases, with pricing of US$2.85/Mcf.

• Development of the South Disouq CPF, pipeline and well tie-ins continued during H1 2019, with the 12” export

line to the Egyptian national grid now 100% completed and tested, alongside three of the four 6” flowlines from the discovery wells to the CPF. The CPF and the compressor both passed factory acceptance tests and the CPF has cleared Customs in Alexandria and is en route to site at South Disouq. The installation and hook-up of the CPF is scheduled to commence later in August and production is expected to start up in Q4 2019. After a ramp up phase, an initial gross plateau production rate of c.50 MMscfe/d of conventional natural gas is being targeted.

• Interpretation of South Disouq’s 170km2 3D seismic survey that was completed in February 2019 continues,

alongside the re-processing of 300km2 3D seismic data acquired in 2016. During H2 2019, the Company will review the final results of the composite 3D interpretation, undertake partner discussions on a potential drilling campaign, and complete an assessment of drilling risk and capital allocation. Upon conclusion of these activities, a decision will be made on a future drilling campaign.

• In Meseda (SDX 50% working interest and joint operator), the Company completed the Rabul-7 development well,

which is contributing c.400 bbl/d gross to production, and participated in the workover of five wells during Q2 2019 across the Rabul (Rabul-2, Rabul-2R) and Meseda (MSD-8, MSD-11 and FADL N-1) fields. The two Rabul wells were recompleted in additional producing horizons, the MSD-8 well had an ESP replacement, and the MSD-11 and FADL N-1 wells had sucker rod pump replacements. These workovers were part of a wider programme, following on from the four wells worked over in Q1 2019. During Q1 2019, the MSD-4 well was converted to a water injector, with the planned Rabul water injection well deferred pending the results of a subsurface study. The above activities were all part of the 2019 budgeted capital expenditure programme supporting the 2019 annual production guidance of 4,000-4,200 bbl/d.

• In the remainder of 2019, the partners will complete the drilling of a further development well, MSD-19, which spud

in early August. The Company will announce the result of this well in due course. • In North West Gemsa (SDX 50% working interest and non-operator), five workovers were carried out in Q2 2019.

The AASE-25, AASE-18 and AASE-5 wells had ESPs installed, the AASE-6 well had its completion string replaced and the Geyad-1 was re-entered to replace the ESP and the results of this operation are currently being reviewed. One well was worked over in Q1 2019.

• At South Ramadan (SDX 12.75% working interest and non-operator), the SRM-3 appraisal well was spud on

14 June 2018 and reached a target depth of 15,635 feet. The operator reported encountering 75 feet of net conventional oil pay in the Matulla section (primary target), 20 feet of net conventional oil pay in the Brown Limestone formation, and a further 15 feet of net conventional oil pay in the Sudr section. The well was completed and operations continue on the flowline upgrade/replacement so that the well can be flow-tested. Based on the results of the flow-test, the Company will decide how best to optimise its position in the licence.

Morocco • The Company’s Moroccan acreage (SDX 75% working interest and operator) consists of five concessions, all of which

are located in the Gharb Basin in northern Morocco: Sebou, Lalla Mimouna Nord, Gharb Centre, Lalla Mimouna Sud, and Moulay Bouchta Ouest, with the latter two secured by the Company during H1 2019.

• In 2018, the Company began selling natural gas to the following new customers: Peugeot, Extralait, and GPC Kenitra.

During H1 2019, natural gas sales began to three additional customers: Setexam, Citic Dicastal and Omnium Plastic. • The six new customers have been increasing their consumption rates during H1 2019, with several expected to reach

stabilised rates during the second half of the year. H1 2019 gross production was 6.0MMscf/d, a 15% increase from the 2018 rate of 5.2MMscf/d.

• The Moulay Bouchta Ouest exploration concession has been awarded to SDX for a period of eight years, with a

commitment to reprocess 150km of 2D seismic data, acquire 100km2 of new 3D seismic, and drill one exploration well within the first three and a half-year period.

• The Lalla Mimouna Sud exploration concession has been re-awarded to SDX for a period of eight years, with

a commitment to acquire 50km2 of 3D seismic and drill one exploration well within the first three-year period. • None of these commitments are expected to require funding in the next 12 months.

Operational Highlights

South Disouq 12” export flowline and three of four 6” well flowlines 100% complete and tested

6.0MMscf/d (gross) H1 2019 increase in Morocco production to 6.0 MMscf/d (gross) from 2018 annual gross production rate of 5.2 MMscf/d (gross)

Planning commenced for 12 well Morocco drilling campaign in Q4 2019/Q1 2020

3 Additional natural gas customers in Morocco connected and flowing during H1 2019


Our Highlights

Second Quarter 2019

The Company’s H1 2019 production, FY19 production guidance, and FY19 Capex guidance are shown below: Gross production Capex (net to SDX) Six months ended Asset 30 June 2019 FY19 Guidance FY19 Guidance NW Gemsa-WI 50% 3,944 boe/d 3,000-3,200 boe/d US$2.0 million Meseda – WI 50% 4,313 bbl/d 4,000-4,200 bbl/d US$2.7 million South Disouq – WI 55% N/A First gas by Q4’19. US$19.5 million c.50 MMscfe/d plateau by Q1’20 Morocco – WI 75% 6.0 MMscf/d* 6.0-6.5 MMscf/d 2019 US$12.0 million annual average rate * Reflects stabilised consumption from four out of eight customers. The remaining four customers consumed

low volumes of gas in H1 2019 and are expected to increase consumption in H2 2019. • Capex guidance is unchanged and comprises: - North West Gemsa: US$4.0 million (US$2.0 million net to SDX) consisting of up to 10 well workovers

and infrastructure maintenance. - Meseda: US$5.4 million (US$2.7 million net to SDX) for two development wells, ESP replacements

and facilities upgrades. - South Disouq: US$35.5 million (US$19.5 million net to SDX). Of the Company’s share, approximately

US$17.0 million relates to South Disouq development activities and US$2.5 million relates to long lead items and drilling preparations for two potential exploration wells in 2020. To date in 2019, the Company has offset US$13.9 million of its accounts receivable due from the EGPC against costs incurred with Egyptian State contractors on the South Disouq development. The Company expects to use future accounts receivable offsets amounting to US$3.2 million to fund its remaining US$4.0 million share of capex to first gas.

- Morocco: US$14.0 million (US$12.0 million net to SDX). Out of this US$12.0 million, US$3.4 million relates to long lead items for the 12 wells and US$6.0 million relates to the drilling costs for up to four wells expected to be drilled by the end of 2019. The remaining US$2.6 million relates to the Company’s share of facilities and field maintenance capex.

Corporate • SDX remains fully funded for all existing and planned activities. • Corporate reorganisation completed in May 2019, with re-domiciliation from Canada to the UK, and delisting

from TSX-V. • Completed capital reduction exercise in June 2019 to improve the ability to pay dividends in the future when

the Company deems it prudent to do so. • As part of the Company’s strategy, it continues to review and explore opportunities to expand the asset base

in the North Africa region, including new licencing rounds and acquisitions.

2019 Production and Capex guidance

FY19 production and capex guidance unchanged

Highlights


Our Highlights

Key financial & operating highlights

Three months ended 30 June Six months ended 30 June US$’000s Prior quarter 2019 2018 2019 2018 Financial Gross revenues 16,690 16,491 18,123 33,181 32,887 Royalties (4,009) (3,759) (4,651) (7,768) (8,455) Net revenues 12,681 12,732 13,472 25,413 24,432 Operating costs (3,374) (3,589) (3,168) (6,963) (5,162) Netback(1) 9,307 9,143 10,304 18,450 19,270 EBITDAX(1) 7,808 7,307 8,585 15,116 16,208 Total comprehensive income/(loss) 132 (489) 640 (354) 971 Net income/(loss) per share-basic 0.001 (0.002) 0.003 (0.002) 0.005 Cash, end of period 11,354 11,195 25,234 11,195 25,234 Working capital (excluding cash) 10,069 6,409 11,121 6,409 11,121 Capital expenditures 13,041 8,777 14,742 21,818 24,690 Total assets 137,630 140,122 143,419 140,122 143,419 Shareholders’ equity 116,491 115,346 116,246 115,346 116,246 Common shares outstanding (000’s) 204,723 204,723 204,493 204,723 204,493 Operational NW Gemsa oil sales (bbl/d) 1,586 1,326 1,665 1,455 1,586 Block-H Meseda production service fee (bbl/d) 826 818 706 822 633 Morocco gas sales (boe/d) 761 729 656 745 660 Other products sales (boe/d) 542 493 403 517 355 Total sales volumes (boe/d) 3,715 3,366 3,430 3,539 3,234

Realised oil price (US$/bbl) 58.22 64.98 68.41 61,32 65.77 Realised service fee (US$/bbl) 47.58 53.56 54.37 50.57 52.45 Realised oil sales price and service fees ($/bbl) 54.58 60.62 64.23 57.44 61.97 Realised Morocco gas price (US$/mcf) 10.26 10.31 10.51 10.28 10.27 Royalties ($/boe) 11.99 12.27 14.90 12.12 14.44 Operating costs ($/boe) 10.09 11.72 10.15 10.87 8.82 Netback ($/boe)(1) 27.84 29.84 33.00 28.80 32.91 (1) Refer to the “Non-IFRS Measures” section of this release below and the Company’s MD&A for the three and six months ended 30 June 2019 and 2018 for details of netback and EBITDAX.

Glossary “bbl” stock tank barrel “boepd” & “boe/d” barrels of oil equivalent per day “bopd” & “bbl/d” barrels of oil per day “mcf” thousands of cubic feet “MMscf/d” million standard cubic feet per day “MMscfe/d” million standard cubic feet equivalent per day

South Disouq Ibn Yunus, SD-4X and SD-3X discoveries in 2018. First gas targeted Q4 2019. Plateau of c.50 MMscfe/d by Q1 2020

9,250boe/d Production Combined Egyptian and Moroccan daily average gross production for the six months ended 30 June 2019

24.6MMboe (gross)

13.1MMboe (net) Reserves Asset reserves-NW Gemsa, Meseda, South Disouq and Morocco as at 31 December 2018


Our Expertise

Onshore

Review

of Operations


Where We Operate

Egypt

SDX Energy is actively involved in exploration and development activities in Egypt’s Eastern Desert, Nile Delta, and Gulf of Suez basins.

The Eastern Desert and Gulf of Suez areas account for the bulk of Egypt’s historical oil production. These two areas are geologically related and expertise acquired in one translates across to the other. The Nile Delta area offers exciting exploration opportunities in a prolific and proven hydrocarbon system with multiple productive horizons.

South Disouq55% working interest

Block-H Meseda50% working interest

North West Gemsa50% working interest

South Ramadan12.75% working interest

Cairo

AlexandriaPort Said

Suez

EGYPT

Gulf of Suez

Gul

f of

Aqa

ba

Red Sea

200 KM

Nile

959km2 Combined concession area

4 Concessions


Where We Operate

Morocco

The Company’s Moroccan acreage consists of five concessions, all of which are located in the Gharb Basin in northern Morocco.

Review

of Operations

In April 2017, the Sebou Onshore permit was renewed for eight years over a larger area and renamed Sebou Central. In June 2017 the Gharb Centre Exploration permit was acquired directly from the State, and in February 2019 the Moulay Bouchta concession was awarded and Lalla Mimouna Sud concession re-awarded by the State.

4,239km2 Combined concession area

5 Concessions 75% working interest in each


Review of Operations

Egypt

The concession is 83km2 in area and includes three fields: Geyad, Al Amir SE, and Al Ola (the southern extension of Al Amir SE). All the fields are covered by development leases. PetroAmir, a joint operating company between the partners and Ganoub El Wadi (a subsidiary of the Egyptian General Petroleum Corporation), operates the fields. SDX Energy’s interest in the concession is 50%, with Zenhua Oil, the operator, holding the remaining 50%. The Al Amir SE and Geyad fields produce light oil (40-42o API oil; sold at Brent less 10%) from two reservoir intervals, the Miocene-aged Shagar and Rahmi sandstones of the Kareem formation.

Q2 2019 Activity The second quarter of 2019 saw the workover of the AASE-6 well (completion string replacement), AASE-18 and -25 (installation of an ESP) and Geyad-6 wells (installation of a jet pump), and a major workover of the Geyad-1ST well. Ultimately, Geyad-1ST could not be worked over and options are being reviewed. The workover of AASE-5 had just started at the end of the quarter but has subsequently had an ESP installed. The average gross production from NW Gemsa for Q2 2019 stood at 3,638 boe/d (1,819 boe/d net to SDX). Now that the field is fully developed, gross capex in 2019 is expected to be approximately US$4.0 million (US$2.0 million net to SDX) consisting of up to 10 workovers and infrastructure maintenance, but no additional wells.

North West Gemsa Eastern Desert Overview The North West Gemsa concession is located in the Eastern Desert, 300km southeast of Cairo.

EasternDesert

Gulf of Suez

North West Gemsa

10KM

EasternDesert

GEYAD

AL AMIR

AL OLA

For more information please visit our website: www.sdxenergy.com

83km2

Concession area



Egypt

Block-H Meseda is 22km2 in area and is currently producing from the Meseda and Rabul fields, both of which are included in the Meseda-H development lease. The concession is covered by a production service agreement, which allows for lower cost operations than the traditional joint venture structure. SDX Energy has a 50% working interest in the operation, with Dublin International Petroleum, the operator, holding the remaining 50% working interest. The Meseda field produces 18o API oil from the high-quality Miocene-aged Asl sands of the Rudeis formation. The Rabul field produces 16o API oil from the Miocene-aged Yusr and Bakr sands, which are also part of the Rudeis formation.

Q2 2019 Activity During Q2 2019, the Company participated in the drilling of the Rabul-7 well, reaching TD on 3 June, finding oil in the Yusr and Bakr sands with a total net pay of 115ft. The well was completed as a producer and came on-line with initial rates of 415 bbl/d and, after optimisation of the ESP, well rates of 700 bbl/d (gross) have been achieved. Workovers of five wells were carried out during Q2 in the Meseda and Rabul Fields: MSD-11 and N.FADL-1X had new sucker rod pumps, MSD-8 had an ESP installed, Rabul-2R was recompleted and had an ESP installed, and Rabul-2 was recompleted to the Yusr from the Bakr. In the remainder of 2019, the partners plan to drill the MSD-19 well (which was spudded in August 2019) and the Company will announce the results of the well in due course. Throughout Q2, the combined Meseda and Rabul average gross production stood at approximately 4,292 boe/d (818 boe/d net to SDX).

Block-H Meseda Eastern Desert Overview Block-H is located in the Eastern Desert, 230km southeast of Cairo.

5KM

Eastern Desert

West Gharib

HOSHIA

MESEDA

FADI

H

K

M

Meseda

South Hania

Trans GlobeTrans Globe

Trans Globe

Trans Globe

Trans Globe

Trans Globe

Trans Globe

open

open

open

open

openFor more information please visit our website: www.sdxenergy.com

Review

of Operations

22km2

Concession area



Egypt

The South Disouq concession is on trend with several other prolific gas fields in the Abu Madi Formation. SDX Energy holds a 55% interest and operates the concession. Its partner, IPR, holds the remaining 45% interest. Development leases have been granted for the Messinian-aged Abu Madi Formation South Disouq gas field and the Pliocene-aged Kafr El Sheikh Formation Ibn Yunus gas field.

Q2 2019 Activity Final processed 3D seismic data from the 170km2 survey that was completed in February 2019 was received in Q2 and interpretation of the data is underway alongside the re-processing of the 300km2 3D seismic data acquired in 2016. During H2 2019, the Company reviewed the final results of the composite 3D interpretation, undertook partner discussions on a potential drilling campaign, and completed an assessment of drilling risk and capital allocation. When these activities are concluded, a decision will be made regarding a future drilling campaign. Development of the South Disouq CPF, pipeline, and well tie-ins continued during Q2 2019, with the 12” export line to the Egyptian national grid now 100% completed and tested, alongside three of the four 6” flowlines from the discovery wells to the CPF. The CPF and the compressor both passed factory acceptance tests and the CPF has now arrived on site at South Disouq. The installation and hook-up of the CPF is scheduled to begin later in August and production is expected to start up in Q4 2019. After a ramp-up phase, an initial gross plateau production rate of conventional natural gas of c.50 MMscfe/d is being targeted

South Disouq Nile Delta Overview South Disouq is a 828km2 concession located 65km north of Cairo in the Nile Delta region.

WesternDesert

Mediterranean Sea

Cairo

South Disouq

Alexandria

Nile

EGYPT

Red Sea


828km2

Concession area



Egypt

SDX Energy holds a 12.75% working interest in the concession, with Pico holding 37.25% and GPC holding the remaining 50%. The concession is considered prospective for the Lower Cretaceous-aged Nubia sandstone and there has been historical production from the Eocene-aged Thebes and Upper Cretaceous-aged Matulla formations.

Q2 2019 Activity The SRM-3 appraisal well was spud on 14 June 2018, targeting undrained light oil volumes up-dip of one of the previous producing wells in the field. The SRM-3 well was the last remaining commitment well on the South Ramadan concession. As a result of the severe losses incurred, the well was side-tracked in early Q4 2018 and reached a target depth of 15,635 feet on 13 January 2019. The operator reported encountering 75 feet of net conventional oil pay in the Matulla section (primary target), 20 feet of net conventional oil pay in the Brown Limestone formation and a further 15 feet of net conventional oil pay in the Sudr section. The well was completed over the Thebes, Brown Limestone, and Sudr Formations. During Q2, the offshore pipeline work was finished and the line hydrotested on 19 June, holding 450psi for four hours. Work on the onshore pipeline is in the planning phase and work on the platform rehabilitation will follow so that the well can be flow-tested. Based on the results of the flow test, the Company will decide how best to optimise its position in the licence.

South Ramadan Gulf of Suez Overview The 26km2 South Ramadan development concession is located in the offshore Gulf of Suez, between the prolific Ramadan and Morgan fields.

South Ramadan

EasternDesert

Gulf of Suez

RAMADAN MARINE

SOUTH

JULY

RAMADAN


Review

of Operations

26km2

Concession area



Morocco

The Company’s Moroccan acreage (SDX 75% working interest and operator) consists of five concessions, all of which are in the Gharb Basin in northern Morocco: Sebou, Gharb Centre, Lalla Mimouna Nord, Lalla Mimouna Sud, and Moulay Bouchta Ouest. The Sebou Central concession is a 220km2 exploration permit with several exploitation concessions contained within it. The exploitation concessions granted under the Sebou Onshore Petroleum Agreement are: • Gueddari Sud, expiry 18 January 2020 • Sidi Al Harati SW, expiry 20 September 2023 • Ksiri Central, expiry 18 January 2025 • Sidi Al Harati W, expiry 17 October 2024 The Lalla Mimouna area comprises the Lalla Mimouna Nord and Lalla Mimouna Sud permits for a total land area of 2,211km2. SDX has completed the work programme requirements of the final extension of the Lalla Mimouna Petroleum Agreement and applied for and was granted an extension of two years to the Lalla Mimouna Nord permit (1,371km2). The two-year extension is being used to evaluate and commercialise the discoveries in the area. This extension did not include any additional work commitments. The Lalla Mimouna Sud permit lapsed in July 2018 and was re-applied for in a separate request. On 7 February 2019, the Company was re-awarded the Lalla Mimouna Sud permit (857km2) for a period of eight years, with a commitment to drill one exploration well and acquire 50km2 of 3D seismic within the first two-and-a-half-year period, formally starting on 14 March 2019. The 3D

seismic commitment was met as part of the 2018 Gharb Centre 3D seismic acquisition programme described below. The permit for the Gharb Centre concession was acquired on 1 June 2017 for a period of eight years. Covering an area of over 1,362km2, it has a work programme commitment to acquire 200km2 of 3D seismic, which was acquired in Q3 2018, and to drill two exploration wells within the first four-year period, the first of which was drilled in Q1 2018. Finally, the Company announced the award of the Moulay Bouchta Ouest concessions from the Government of Morocco on 7 February 2019. This exploration concession has been awarded to SDX for a period of eight years for a commitment to reprocess 150 kilometres of 2D seismic data, acquire 100km2 of new 3D seismic, and drill one exploration well within the first three-and-a-half-year period that formally started on 14 March 2019. Q2 2019 Activity In 2018, the Company began selling natural gas to the following new customers: Peugeot, Extralait, and GPC Kenitra. During H1 2019, natural gas sales began to three additional customers, Setexam, Citic Dicastal and Omnium Plastic. The six new customers increased their consumption rates during Q2 2019, with several expected to reach stabilised rates during the second half of the year. Gross production for Q2 2019 was 5.8MMscf/d, reduced by lower customer demand during the Eid holiday when planned maintenance at customer sites took place.

In order to extend the life of some of the larger wells beyond their natural flow limits, two compressors were purchased in Q2 2019 and will be installed later in Q3 2019 at the KSR substation and at the CGD-13 well. As part of ongoing field management, a workover of the KSR-10 well is planned for Q3 2019, together with well interventions at SAH-W1, CGD-13, and KSR-11 to access additional volumes of gas. Planning for the drilling of 12 wells in Morocco is at an advanced stage, with the campaign targeted to begin in Q4 2019 and complete in H1 2020. All long lead items are ordered, and all key contracts finalised. The surface locations for the majority of the new wells have been agreed, with the remainder being scouted in Q3. Planning for future connections and pipeline routes has started and has partly guided the drilling locations. The programme will target 15bcf of gross unrisked prospective resources. The 2019 total gross capex is expected to be approximately US$14.0 million, with SDX’s share being approximately US$12.0 million. Out of this US$12.0 million, US$3.4 million relates to long lead items for the 12 wells and US$6.0m relates to the drilling costs for up to four wells that are expected to be drilled by the end of 2019. The remaining US$2.6 million relates to the Company’s share of facilities and field maintenance capex.

Gharb Basin concessions Overview The Company’s Moroccan acreage consists of five concessions all of which are located in the Gharb Basin in northern Morocco.



Our Focus

North Africa

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ent’s Discussion &

Analysis



24.6MMboe (gross)



Management’s Discussion & Analysis For the three and six months ended 30 June 2019 (prepared in US$)

Basis of presentation The following Management’s Discussion and Analysis (“MD&A”), dated 22 August 2019, is a review of the results of operations and the liquidity and capital resources of SDX Energy Plc (the “Company” or “SDX”), for the three and six months ended 30 June 2019. This MD&A should be read in conjunction with the accompanying unaudited Interim Condensed Consolidated Financial Statements (“Interim Consolidated Financial Statements”) for the three and six months ended 30 June 2019 and the audited Consolidated Financial Statements for the year ended 31 December 2018. The Interim Consolidated Financial Statements for the three and six months ended 30 June 2019 have been prepared in accordance with IAS 34 Interim Financial Reporting. The Interim Consolidated Financial Statements do not include all the information and disclosures required in annual financial statements. The Company’s production and reserves are reported in barrels of oil equivalent (“boe”). Boe may be misleading, particularly if used in isolation. A boe conversion ratio for natural gas of 6 Mcf (6,000 cubic feet): 1 boe has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, using a 6:1 conversion ratio may be misleading as an indication of value. Certain information contained in this report is forward-looking and based upon assumptions and anticipated results that are subject to risks, uncertainties and other factors. Should one or more of these uncertainties materialise, or should the underlying assumptions prove incorrect, actual results may vary materially from those expected. See “Forward-looking statements”, below. All financial references in this MD&A are in thousands of United States dollars unless otherwise noted. Additional information on the Company can be found on Companies House at www.beta.companieshouse.gov.uk. Forward-looking statements Certain statements included or incorporated by reference in this MD&A constitute forward-looking statements or forward-looking information under applicable securities legislation. Such forward-looking statements or information are for the purpose of providing information about Management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward-looking statements or information typically contain statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements or information in this MD&A include, but are not limited to, statements or information with respect to: business strategy and objectives; development plans; exploration plans; acquisition and disposition plans and the timing thereof; reserve quantities and the discounted present value of future net cash flows from such reserves; future production levels; capital expenditures; net revenue; operating and other costs; royalty rates and taxes. Forward-looking statements or information are based on a number of factors and assumptions that have been used to develop such statements and information but may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions that may be identified in this MD&A, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost-efficient manner; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the countries in which the Company operates; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions that may have been used. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. The risks and uncertainties that may cause actual results to differ materially from the forward-looking statements or information include, among other things: the ability of Management to execute its business plan; general economic and business conditions; the risk of war or instability affecting countries or states in which the Company operates; the risks of the oil and natural gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas; market demand; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; risks and uncertainties involving geology of oil and natural gas deposits; the uncertainty of reserves estimates and reserves life; the ability of the Company to add production and reserves through acquisition, development and exploration activities; the Company’s ability to enter into or renew production sharing concession; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to production (including decline rates), costs and expenses; fluctuations in oil and natural gas prices, foreign currency exchange, and interest rates; risks inherent in the Company’s marketing operations, including credit risk; uncertainty in amounts and timing of oil revenue payments; health, safety and environmental risks; risks associated with existing and potential future law suits and regulatory actions against the Company; uncertainties as to the availability and cost of financing; and financial risks affecting the value of the Company’s investments. Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties.



Use of estimates The preparation of Interim Consolidated Financial Statements in conformity with IFRS requires management to make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, particularly the recoverability of accounts receivable. Estimates and assumptions also affect the recording of liabilities and contingent liabilities at the date of the Interim Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Due to various factors affecting future costs and operations, actual results could differ from management’s best estimates. Non-IFRS measures The MD&A contains the terms “netback” and “EBITDAX”, which are not recognised measures under IFRS. The Company uses these measures to help evaluate its performance. Netback Netback is a non-IFRS measure that represents sales net of all operating expenses and government royalties. Management believes netback to be a useful supplemental measure to analyse operating performance and provide an indication of the results generated by the Company’s principal business activities prior to the consideration of other income and expenses. Management considers netback an important measure because it demonstrates the Company’s profitability relative to current commodity prices. Netback may not be comparable to similar measures other companies use. See Netback reconciliation to operating income/(loss) in note 21 to the Interim Consolidated Financial Statements. EBITDAX EBITDAX is a non-IFRS measure that represents earnings before interest, tax, depreciation, amortisation, exploration expense, and impairment, which is operating income/(loss) adjusted for the add-back of depreciation and amortisation, exploration expense, and impairment of property, plant and equipment (if applicable). EBITDAX is presented so that users of the financial statements can understand the cash profitability of the Company, excluding the impact of costs attributable to exploration activity, which tend to be one-off in nature, and the non-cash costs relating to depreciation, amortisation, and impairments. EBITDAX may not be comparable to similar measures other companies use. See EBITDAX reconciliation to operating income/(loss) in note 21 to the Interim Consolidated Financial Statements.

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Analysis



SDX’s business strategy and work program SDX’s business SDX is engaged in the exploration, development, and production of oil and gas. Current activities are concentrated in Egypt and Morocco, where the Company has interests in nine concessions with short and long-term potential. The Company’s strategy is to develop the potential of its existing concessions while seeking growth opportunities within its North Africa region of focus. The Company intends to create shareholder value by enhancing the value of its assets and through significant growth in production volumes, cash flow, and earnings. Strategy The Company’s strategy is to create value through organic and inorganic low-cost production growth and low-cost, high-impact exploration success. The Company is underpinned by a portfolio of low-cost, onshore producing assets combined with onshore exploration prospects in Egypt and Morocco. SDX intends to increase production and cash flow generation organically through an active work programme consisting of workover, exploration, and development wells in its existing portfolio in Egypt and Morocco, combined with high impact exploration drilling in both countries. In pursuing this strategy, SDX also intends to leverage its balance sheet, its early mover advantage and its regional network to grow through the acquisition of undervalued and/or underperforming producing assets located principally in onshore North Africa, while maintaining a strict financial discipline to ensure efficient use of funds. The Company currently holds working interests (“WI”) in three development/producing concessions and one exploration concession in Egypt, and one development/producing concession and four exploration concessions in Morocco. These are: • Egypt (development/producing)-The NW Gemsa Concession (“NW Gemsa”)-(50% WI); • Egypt (development/producing)-The Block-H Meseda production service agreement (“Meseda”)-(50% WI); • Egypt (development)-The South Ramadan Concession (“South Ramadan”)-(12.75% WI); • Egypt (exploration)-The South Disouq Concession (“South Disouq”)-(55% WI); • Morocco (development/producing)-The Sebou Concession (“Sebou”)-(75% WI); • Morocco (exploration)-The Lalla Mimouna Nord Concession (“Lalla Mimouna Nord”)-(75% WI); • Morocco (exploration)-The Lalla Mimouna Sud Concession (“Lalla Mimouna Sud”)-(75% WI); • Morocco (exploration)-The Moulay Bouchta Ouest Concession (“Moulay Bouchta”)-(75% WI) and • Morocco (exploration)-The Gharb Centre Concession (“Gharb Centre”)-(75% WI). 2019 Work program The Company’s capital expenditure programme for 2019 is expected to be approximately US$36.2 million. In Morocco, the Company is planning for a 12-well campaign, with drilling set to begin in Q4 2019 and complete during H1 2020. During this campaign, the LNB-1 and LMS-1 wells in Lalla Mimouna, originally drilled in 2018, will be re-tested, with the remainder of the programme’s targets coming from the recently acquired Gharb Centre 3D seismic and the Sebou area. SDX’s share of 2019 total capex is expected to be approximately US$12.0 million. Out of this US$12.0 million, US$3.4 million relates to long lead items for the 12 wells and US$6.0 million relates to the drilling costs for up to four wells that are expected to be drilled by the end of 2019. The remaining US$2.6 million relates to the Company’s share of facilities and field maintenance capex. The Company is targeting annual average gross production of 6.0-6.5 MMscf/d of conventional natural gas for 2019. In South Disouq the Company is investing approximately US$19.5 million, US$17.0 million of which is for its share of the South Disouq development activities and US$2.5 million is for long lead items and drilling preparations for two exploration wells in 2020. During 2019, SDX will complete construction of the Central Processing Facility, the 10km export pipeline and the tie-ins for the four existing production wells. First gas is targeted for Q4 2019, at a gross plateau production rate of 50 MMscf/d by Q1 2020, with the conventional natural gas being sold to the state at a price of US$2.85/Mcf. Prospect inventory for future drilling has increased with the interpretation of the recently acquired 170km² of 3D seismic in the southern section of the concession and, subject to partner approval, the Company is proposing to drill two further exploration wells in 2020 prior to the concession expiry on 20 March 2020. In Meseda, c.US$1.6 million will be contributed to cover the Company’s share of the cost of drilling one Rabul well and one Meseda well. The operator also plans to replace up to five electrical submersible pumps (“ESPs”) in the wider Meseda area, drill two water injection wells, upgrade water handling capabilities at the field facilities and undertake additional workovers required (SDX share US$1.1 million). The Company has 2019 gross production guidance of 4,000-4,200 barrels of oil per day (bbl/d). In North West Gemsa, the Company will be investing c.US$2.0 million for its share of a 10-well workover programme, as the field is now fully developed and no additional wells are required. Given field decline, the Company expects 2019 gross production of 3,000-3,200 boe/d. In South Ramadan, the SRM-3 well was completed and operations continue on the flowline upgrade/replacement in order for the well to be flow-tested. Based on the results of the flow-test, the Company will decide on how best to optimise its position in the licence.



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Analysis

Operational and financial highlights In accordance with industry practice, production volumes and revenues are reported on a Company interest basis, before the deduction of royalties.

Three months ended 30 June Six months ended 30 June US$’000s Prior quarter(1) 2019 2018 2019 2018 NW Gemsa oil sales revenue 8,312 7,838 10,366 16,150 18,885 Royalties (3,568) (3,364) (4,449) (6,932) (8,105) Net oil revenue 4,744 4,474 5,917 9,218 10,780

Block-H Meseda production service fee revenues 3,536 3,989 3,495 7,525 6,008

Morocco gas sales revenue 4,213 4,105 3,767 8,318 7,364 Royalties (186) (170) - (356) - Net Morocco gas sales revenue 4,027 3,935 3,767 7,962 7,364

Net other products revenue 374 334 293 708 280

Total net revenue 12,681 12,732 13,472 25,413 24,432

Direct operating expense (3,374) (3,589) (3,168) (6,963) (5,162)

Netback: NW Gemsa oil(2) 2,945 2,324 3,964 5,270 7,938 Netback: Block-H Meseda 2,426 3,088 2,566 5,513 4,270 Netback: Morocco gas 3,562 3,397 3,481 6,959 6,782 Netback: Other products(2) 374 334 293 708 280 Netback (pre-tax) 9,307 9,143 10,304 18,450 19,270

EBITDAX 7,808 7,307 8,585 15,116 16,208

NW Gemsa oil sales (bbl/d) 1,586 1,326 1,665 1,455 1,586 Block-H Meseda production service fee (bbl/d) 826 818 706 822 633 Morocco gas sales (boe/d) 761 729 656 745 660 Other products sales (boe/d) 542 493 403 517 355 Total sales volumes (boe/d) 3,715 3,366 3,430 3,539 3,234

NW Gemsa oil sales volumes (bbls) 142,768 120,624 151,520 263,392 287,150 Block-H Meseda production service fee volumes (bbls) 74,315 74,475 64,286 148,790 114,543 Morocco gas sales volumes (boe) 68,458 66,358 59,740 134,816 119,519 Other products sales volumes (boe) 48,791 44,875 36,681 93,666 64,327 Total sales volumes (boe) 334,332 306,332 312,227 640,664 585,539

Brent oil price (US$/bbl) $63.02 $68.95 $74.53 $65.99 $70.65 West Gharib oil price ($US/bbl) $56.03 $63.16 $63.99 $59.60 $61.37

Realised NW Gemsa oil price (US$/bbl) $58.22 $64.98 $68.41 $61.32 $65.77 Realised Block-H Meseda service fee (US$/bbl) $47.58 $53.56 $54.37 $50.57 $52.45 Realised oil sales price and service fees (US$/bbl) $54.58 $60.62 $64.23 $57.44 $61.97

Realised Morocco gas price (US$/mcf) $10.26 $10.31 $10.51 $10.28 $10.27

Total royalties (US$/boe) $11.99 $12.27 $14.90 $12.12 $14.44 Operating costs (US$/boe) $10.09 $11.72 $10.15 $10.87 $8.82 Netback (US$/boe) $27.84 $29.84 $33.00 $28.80 $32.91

Capital expenditures 13,041 8,777 14,742 21,818 24,690

(1) Three months ended 31 March 2019

(2) When calculating netback for NW Gemsa oil and other products (NW Gemsa natural gas and NGLs), all NW Gemsa operating costs are allocated to oil, as natural gas and NGLs are associated products with assumed

nil incremental operating costs.



Operational and financial highlights (continued) Oil sales and production service fee revenues

Three months ended 30 June Six months ended 30 June US$’000s Prior quarter 2019 2018 2019 2018 Oil sales revenue 8,312 7,838 10,366 16,150 18,885 Production service fee revenues 3,536 3,989 3,495 7,525 6,008 Total oil sales and production service fees revenue 11,848 11,827 13,861 23,675 24,893 Oil sales revenue (relates to NW Gemsa only) Oil sales volumes Total oil sales volumes for the three and six months ended 30 June 2019 averaged 1,326 bbl/d and 1,455 bbl/d against 1,665 bbl/d and 1,586 bbl/d for the comparative periods of the prior year. Total sales volumes decreased by 23,758 barrels, 8%, to 263,392 barrels in the six months ended 30 June 2019 compared to 287,150 barrels in the comparative period of 2018. This decrease was due to water breakthrough in one well and water cut increase in several wells, partly offset by three new wells coming into production in Q3 2018: AASE-25, AASE-27 and Al Ola-4. Total sales volumes decreased by 22,144 barrels, 16%, in the three months ended 30 June 2019, compared to the previous quarter because of water cut increase due to field decline. Oil sales pricing The Company is exposed to the volatility of commodity price markets for all its oil sales and service fee volumes and changes in the foreign exchange rate between the Egyptian pound and the US dollar for capital and operational expenditure. The Operational and Financial Highlights table in this MD&A outlines the changes in various benchmark commodity prices and the economic parameters that affect the prices received for the Company’s oil sales and service fee volumes. During the six months ended 30 June 2019, the Brent price ranged from a low of US$53.23 per barrel on 3 January 2019 to a high of US$74.94 per barrel on 25 April 2019. The Company does not currently hedge any of its production. For the three and six months ended 30 June 2019, the Company’s oil sales achieved an average realised price per barrel of oil of US$64.98 and US$61.32 respectively, compared to the average Brent Oil price (“Brent”) for the periods of US$68.95 and US$65.99 respectively; a discount of US$3.97, 6%, and US$4.67, 7%, per barrel respectively. The Company receives a discount to Brent because of the quality of the oil produced. A further deduction is reflected in the realised price as a result of marketing fees. For the three and six months ended 30 June 2018, the Company achieved an average realised price of US$68.41 and US$65.77.

Three months ended 30 June Six months ended 30 June Prior quarter 2019 2018 2019 2018

Oil sales revenue ($’000s) 8,312 7,838 10,366 16,150 18,885 Realised price per bbl ($/bbl) 58.22 64.98 68.41 61.32 65.77 Oil sales revenue variance from prior year For the six months ended 30 June 2019 (compared to the six months ended 30 June 2018), oil sales revenue decreased by US$2.7 million as a result of a decrease in sales price of US$1.2 million, 6% and a decrease in sales volume of US$1.6 million, 8%, owing to water breakthrough and natural field decline. The decrease was compensated for with three new wells that were put into production after Q2 2018. US$’000s Six months ended 30 June 2018 18,885 Price variance (1,172) Production variance (1,563) Six months ended 30 June 2019 16,150 Oil sales revenue variance from prior quarter For the three months ended 30 June 2019 (compared to the three months ended 31 March 2019), oil sales revenue decreased as a result of a decrease in sales volume of US$1.3 million, 16%, owing to a number of operational factors, including one well ceasing to flow in late Q1 2019 mainly related to increased water cut. This decrease was partly offset by an increase in sales pricing of US$0.8 million, 10%. US$’000s Three months ended 31 March 2019 8,312 Price variance 815 Production variance (1,289) Three months ended 30 June 2019 7,838



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Analysis

Operational and financial highlights (continued) Production service fees (relates to Meseda only) Production service fee volumes The Company records service fee revenue relating to the oil production that is delivered to the State Oil Company (“GPC”) from the Meseda area of Block H. The Company is entitled to a service fee of between 19.0% and 19.25% of the delivered volumes and has a 50% working/paying interest. The service fee revenue is based on the current market price of West Gharib crude oil, adjusted for a quality differential. Total production service fee volumes for the six months ended 30 June 2019, increased by 34,247 barrels, 30%, to 148,790 barrels, compared to the six months ended 30 June 2018. The increase was the result of the MSD-16 and MSD-15 discoveries being put on production in Q3 2018 and greater production from Rabul discoveries. Together they compensated for a reduction in production resulting from increased water cut in four wells. Barrels produced per day during Q2 2019 remained stable at 818bbl/d, compared to 826bbl/d during Q1 2019, due to water cut increase, which offset strong production from well workovers during 2019. Production service fee pricing For the three and six months ended 30 June 2019, the Company received an average service fee per barrel of oil of US$53.56 and US$50.57 respectively, compared to the average West Gharib prices for the periods of US$63.16 and US$59.60, a discount of US$9.60 (15%) per barrel and a discount of US$9.03 (15%) per barrel. The Company receives a discount to West Gharib because of the quality of the oil produced. For the three and six months ended 30 June 2018, the Company received an average service fee of US$54.37 and US$52.45 per barrel of oil respectively.

Three months ended 30 June Six months ended 30 June Prior quarter 2019 2018 2019 2018

Production service fee revenues ($’000s) 3,536 3,989 3,495 7,525 6,008 Realised service fee per bbl ($/bbl) 47.58 53.56 54.37 50.57 52.45 Production service fee variance from prior year For the six months ended 30 June 2019 (compared to the six months ended 30 June 2018), the increase in production service fee revenue of US$1.5 million, 25%, to US$7.5 million was due to increased production of US$1.8 million, 30%, mainly owing to new wells on production from Q3 2018 (MSD-16 and MSD-15), which were partially offset by a decrease in realised sales price of US$0.3 million, 5%. US$’000s Six months ended 30 June 2018 6,008 Price variance (279) Production variance 1,796 Six months ended 30 June 2019 7,525 Production service fee variance from prior quarter For the three months ended 30 June 2019 (compared to the three months ended 31 March 2019), the increase in production service fee revenue of US$0.5 million, 14%, was due to an increase in the realised sales price, with stable production owing to well workover results compensating for increased water cut. US$’000s Three months ended 31 March 2019 3,536 Price variance 445 Production variance 8 Three months ended 30 June 2019 3,989 Morocco gas sales revenue

Three months ended 30 June Six months ended 30 June US$’000s Prior quarter 2019 2018 2019 2018 Morocco-Sebou 4,213 4,105 3,767 8,318 7,364 Realised price per mcf ($/mcf) 10.26 10.31 10.51 10.28 10.27 The Company currently sells natural gas to eight industrial customers in Kenitra, northern Morocco.



Operational and financial highlights (continued) Morocco gas sales variance from prior year For the six months ended 30 June 2019 (compared to the six months ended 30 June 2018), the increase in Morocco gas sales revenue of US$0.9 million, 12%, is due to an increase in sales volumes driven by new customer connections at the end of 2018. US$’000s Six months ended 30 June 2018 7,364 Price variance 11 Production variance 943 Six months ended 30 June 2019 8,318 Morocco gas sales variance from prior quarter For the three months ended 30 June 2019 (compared to the three months ended 31 March 2019), the decrease in Morocco gas sales revenue of US$0.1 million, 2%, is due to reduced production resulting from lower customer demand during the Eid holiday when planned maintenance at customer sites took place. US$’000s Three months ended 31 March 2019 4,213 Price variance 21 Production variance (129) Three months ended 30 June 2019 4,105 Royalties Royalties fluctuate in Egypt from quarter to quarter because of changes in production and the impact of commodity prices on the amount of cost oil allocated to the contractors. In turn, there is an impact on the amount of profit oil from which royalties are calculated. Royalties for crude oil sales per boe by concession are as follows:

Three months ended 30 June Six months ended 30 June US$’000s Prior quarter 2019 2018 2019 2018 NW Gemsa 3,568 3,364 4,449 6,932 8,105 Total royalties (US$/bbls) by concession 24.99 27.89 29.36 26.32 28.23 The concession agreements allow for the recovery of operating and capital costs through a cost oil allocation. This allocation has an impact on the government share of production, as highlighted below (as at 30 June 2019 and 30 June 2018):

SDX’s Cost oil to Capital cost Operating cost Excess oil to Profit oil to Concession WI(1) Contractors(2) recovered(2) recovered(2) Contractor(3) Contractor(4) NW Gemsa (up to 10,000 bbl/d Gross) 50% 30% 5 years Immediate Nil 16.1% NW Gemsa (10,000 bbl/d to 25,000 bbl/d Gross) 50% 30% 5 years Immediate Nil 15.4% NW Gemsa-Gas and LPG 50% 30% 5 years Immediate Nil 18.2% (1) WI denotes the Company’s working interest.

(2) Cost oil is the amount of oil revenue that is attributable to SDX and its joint venture partners (the “Contractor”) subject to the limitation of the cost recovery pool. Oil revenue up to a specified percentage is available

for recovery by the Contractor for costs incurred in exploring and developing the concession. Operating costs and capital costs are added to a cost recovery pool (the “Cost Pool”). Capital costs for exploration and

development expenditures are amortised into the Cost Pool over a specified number of years, with operating costs added to the Cost Pool as they are incurred.

(3) If the costs in the Cost Pool are less than the cost oil attributable to the Contractor, the shortfall, which is referred to as excess cost oil (“Excess Oil”), reverts 100 percent to the state in NW Gemsa.

(4) Profit oil is the amount of oil revenue that is attributable to the Contractor.

For the purposes of the operating and financial highlights disclosure in the MD&A, royalties per boe for the Company are calculated by dividing total royalties by total production for all assets. In Morocco, sales-based royalties become payable when certain inception-to-date production thresholds are reached, according to the terms of each exploitation concession. During Q3 2018, natural gas production from the Ksiri exploitation concession exceeded such a threshold, resulting in the recognition of royalties amounting to 5% of revenue from this concession from that point forward. Royalty payments are made directly to the Government of Morocco biannually.



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Operational and financial highlights (continued) Direct operating costs The direct operating costs per concession were:

Three months ended 30 June Six months ended 30 June US$’000s Prior quarter 2019 2018 2019 2018 NW Gemsa 1,799 2,150 1,953 3,949 2,842 Block-H Meseda 1,110 901 929 2,011 1,738 Morocco-Sebou 465 538 286 1,003 582 Total direct operating expense 3,374 3,589 3,168 6,963 5,162 The direct operating costs per boe per concession were:

Three months ended 30 June Six months ended 30 June US$/boe Prior quarter 2019 2018 2019 2018 NW Gemsa 9.39 12.99 10.38 11.06 8.09 Block-H Meseda 14.94 12.10 14.45 13.52 15.17 Morocco-Sebou 6.79 8.11 4.79 7.44 4.87 Total direct operating costs per boe 10.09 11.72 10.15 10.87 8.82 Direct operating costs for the three and six months ended 30 June 2019 were US$3.6 million and US$7.0 million respectively, compared to US$3.2 million and US$5.2 million respectively for the comparative period of the prior year. Prior quarter direct operating costs are US$0.2 million lower at US$3.4 million. NW Gemsa NW Gemsa direct operating costs for the six months to 30 June 2019 were US$3.9 million, US$1.1 million higher than the comparative period of the prior year. The variance is the result of higher allocated operational employee costs to direct operating expenses in H1 2019. In H1 2018, these costs were allocated to capital expenditure due to drilling activity taking place over this period. There was also increased workover activity in H1 2019 and a slight increase to bonuses paid to field staff. The quarter-on-quarter increase in the NW Gemsa direct operating costs per US$/boe to US$12.99/boe from US$9.39/boe is due to higher workover related costs and lower production in Q2 2019. Block-H Meseda Direct operating costs for the six months to 30 June 2019 for Block H-Meseda were US$0.3 million higher than the comparative period of the prior year owing to the 30% increase in production. For the three months to 30 June 2019, direct operating costs were US$0.2 million lower than the prior quarter due to higher workover costs in Q1 2019. The US$/bbl cost decreased to US13.52/bbl in the six months ended 30 June 2019, compared to US$15.17/bbl in the comparative period last year due to the rate of production increasing at a higher rate than the cost base due to fixed and variable nature of Meseda’s cost base. Morocco-Sebou Direct operating costs for the six months to 30 June 2019 for Morocco were US$0.4 million higher than the comparative period of the prior year. The variance is the result of higher allocated operational employee costs to direct operating expenses in H1 2019. In H1 2018, these costs were allocated to capital expenditure due to drilling activity taking place over this period. The increase is also because of a true up made relating to 2018 costs reflected in Q1 2019, as the result of late billings received from the Company’s partner, and to higher production in 2019. Direct operating costs were US$0.5 million for the three months to 30 June 2019 and 31 March 2019.



Operational and financial highlights (continued) Exploration and evaluation expense For the six months ended 30 June 2019, exploration and evaluation expenses stood at US$0.6 million compared to US$5.3 million in the comparative period. The variance is due to the write-off of non-commercial wells drilled in Morocco (ELQ-1 and KSS-2: US$3.2 million) and South Disouq (Kelvin-1X: $1.6 million) in 2018.

Depletion, depreciation and amortisation For the six months ended 30 June 2019, depletion, depreciation and amortisation (“DD&A”) amounted to US$11.9 million, compared to US$6.2 million in the comparative period.

Three months ended 30 June Six months ended 30 June US$’000s Prior quarter 2019 2018 2019 2018 Depletion, depreciation and amortisation 5,898 6,047 3,657 11,945 6,190 Per boe 17.64 19.74 11.71 18.64 10.57 The DD&A per concession was:

Three months ended 30 June Six months ended 30 June US$’000s Prior quarter 2019 2018 2019 2018 NW Gemsa 2,179 1,882 1,763 4,061 2,629 Block-H Meseda 624 626 354 1,250 631 Morocco-Sebou 2,804 3,245 1,398 6,049 2,760 Right of use assets 171 174 - 345 - Other 120 120 142 240 170 Total DD&A 5,898 6,047 3,657 11,945 6,190 The DD&A movement by concession is primarily the result of the following: • The increase of $1.5 million in DD&A for NW Gemsa for the six months ended 30 June 2019 compared to the same period of the prior year,

is the result of a higher depreciable asset base due to wells drilled in 2018 and a reserves downgrade in 2018. The decrease of $0.3 million compared to the prior quarter is due to lower production.

• The DD&A for Block-H Meseda was $1.3 million for the six months ended 30 June 2019, compared to $0.6 million for the comparative period

of the prior year. The variance is due to a higher depreciable asset base resulting from wells drilled in 2018 and higher production. • The DD&A for Morocco increased by $3.2 million for the six months ended 30 June 2019, compared to the comparative period of the prior

year owing to a higher depreciable asset base due to wells drilled in 2018, customer connections and facilities upgrades in 2018 and 2019, and higher production.

• The DD&A for right of use assets was $0.3 million and related to recognition of leases under IFRS 16. Please refer to note 23 in the

Interim Consolidated Financial Statements.



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Operational and financial highlights (continued) General and administrative expenses

Three months ended 30 June Six months ended 30 June US$’000s Prior quarter 2019 2018 2019 2018 Wages and employee costs 1,902 2,419 1,914 4,321 3,797 Consultants-inc. PR/IR 175 160 164 335 292 Legal fees 152 119 59 271 153 Audit, tax and accounting services 104 236 339 340 471 Public company fees 158 148 169 306 364 Travel 11 86 64 97 147 Office expenses 118 88 295 206 573 IT expenses 129 154 67 283 223 Service recharges (1,539) (1,327) (1,551) (2,866) (3,255) Ongoing general and administrative expenses 1,210 2,083 1,520 3,293 2,765 Transaction costs 338 766 - 1,104 - Total net G&A 1,548 2,849 1,520 4,397 2,765 Ongoing general and administrative (“G&A”) costs for the six months ended 30 June 2019 were US$3.3 million compared to US$2.8 million for the comparative period of the prior year, primarily due to higher wages and employee costs in Q2 2019 relating to London staff severance costs for two employees and a reduction in the service recharges in the six months to 2019. Higher service recharges were incurred in the six months to 30 June 2018 due to two drilling campaigns in 2018, in Morocco and in South Disouq. These higher recharges were partly offset by lower office expenses, which were reduced because of the change to the accounting standard for leases under IFRS16. Transaction costs in 2019 related to the re-domicile of the Group from Canada to the UK, the Group’s capital reduction and previous business development initiatives. Current taxes Pursuant to the terms of the Company’s concession agreements for NW Gemsa, the 40.4% corporate tax liability of the joint venture partners is paid by the Government of Egypt-controlled corporations (“Corporations”) out of the profit oil attributable to the Corporations, and not by the Company. For accounting purposes, the corporate taxes paid by the Corporations are “grossed up” in the financial statements and included in net oil revenues and income tax expense, thereby having a net neutral impact on net income. The Company has a “cash” corporate tax liability in relation to its production service agreement for Block-H Meseda because the Company’s Egyptian subsidiary, SDX Energy Egypt (Meseda) Ltd, which is party to this concession, is subject to corporate tax. The Company’s Moroccan operations benefit from a 10-year corporation tax holiday from first production and no taxation is due on Moroccan profits as at 30 June 2019.

Three months ended 30 June Six months ended 30 June US$’000s Prior quarter 2019 2018 2019 2018 NW Gemsa 980 921 1,192 1,901 2,167 Block-H Meseda 433 325 547 758 886 Morocco-Sebou - - - - - Other - - - - 14 Total current taxes 1,413 1,246 1,739 2,659 3,067 Current taxes for the six months ended 30 June 2019 were US$2.7 million compared to US$3.1 million for the comparative period of the previous year. The variance is due to an overprovision previously recognised for 2018 Block-H Meseda corporation tax versus the final tax return submitted in Q2 2019.



Operational and financial highlights (continued) Net earnings As per the Interim Consolidated Financial Statements, for the six months ended 30 June 2019 the Company recorded a Total Comprehensive Loss of US$0.4 million, compared to a Total Comprehensive Income of US$1.0 million for the six months ended 30 June 2018, a reduction of US$1.4 million. The main components of this difference are:

US$ millions Comment Net revenues 1.0 Increase in net revenues in 2019 as a result of increased production in Morocco and

Block-H Meseda offset by the impact of lower oil prices comparative to 2018. Direct operating expense (1.8) Increase in direct operating expense in 2019 due to higher production at Block-H

Meseda, more wells on production and workover activity at NW Gemsa. General and administrative expenses (0.5) Ongoing general and administrative expenses have increased mainly due to staff - Ongoing severance in London and higher legal fees in Morocco. General and administrative expenses (1.1) Higher transaction costs relate to a number of business development initiatives, - Transaction costs including the discontinued acquisition of a package of assets in Egypt from BP and

the re-domicile of the Group from Canada to the UK Exploration and evaluation expense 4.7 Lower exploration and evaluation expenditure due to write off of non-commercial

wells in 2018, ELQ-1 and KSS-2 in Morocco and Kelvin-1X in South Disouq. Depletion, depreciation and amortisation (5.7) DD&A charge is higher by US$0.2 million due to the IFRS 16 transition.

The remaining variance is because of a higher depreciable asset base due to wells drilled in 2018, a reserves downgrade in 2018 and higher levels of production in Morocco and Block-H Meseda.

Share-based compensation 1.0 The variance relates to the reversal of LTIP charges for two departing employees in London.

Foreign exchange gain 0.4 Current income tax expense 0.4 Other 0.2 Total variance (1.4) Capital expenditures The following table shows the capital expenditure for the Company and agrees with notes 8 and 9 to the Interim Consolidated Financial Statements for the period ended 30 June 2019, which include discussion therein.

Three months ended 30 June Six months ended 30 June US$’000s Prior quarter 2019 2018 2019 2018 Property, plant and equipment expenditures (“PP&E”) 1,359 3,153 6,597 4,512 10,051 Exploration and evaluation expenditures (“E&E”) 11,660 5,586 7,923 17,246 14,193 Office furniture and fixtures 22 38 222 60 446 Total capital expenditures 13,041 8,777 14,742 21,818 24,690 Decommissioning liability

Carrying amount 30 June 31 December

US$’000s 2019 2018 Decommissioning liability, beginning of period 5,167 4,542 Changes in estimate - 575 Payments for decommissioning - (23) Accretion 38 73 Decommissioning liability, end of period 5,205 5,167 Of which: Current 1,125 1,125 Non-current 4,080 4,042 For a discussion of the Company’s decommissioning liability, see note 13 to the Interim Consolidated Financial Statements for the six months ended 30 June 2019.

Liquidity and capital resources Share capital The Company’s authorised share capital consists of an unlimited number of common shares and an unlimited number of preferred shares, issuable in one or more series. The common shares of SDX trade on the AIM market of the London Stock Exchange under the symbol SDX.

Three months Six months ended ended 30 June 30 June

Trading statistics Prior quarter 2019 2019 High (GBP) £0.43 £0.36 £0.43 Low (GBP) £0.35 £0.20 £0.20 Average volume 296,515 601,299 481,664 The following table summarises the outstanding common shares and options as at 22 August 2019, 30 June 2019, and 31 December 2018.

22 August 30 June 31 December Outstanding as at: 2019 2019 2018 Common shares 204,723,041 204,723,041 204,723,041 Options (stock option plan) 2,008,334 2,008,334 2,115,000 Options (long-term incentive plan) 3,837,099 3,837,099 7,100,884 The following table summarises the outstanding stock option plan options as at 30 June 2019:

Outstanding options Vested options Number of Contractual Number of Contractual

Exercise price range options life options life GBP £0.21-£0.45 2,008,334 3-5 years 1,795,000 3-5 years Stock based compensation Stock option program The Company has a stock option programme that entitles officers, directors, employees, and certain consultants to purchase shares in the Company. Stock-based compensation expense is the amortisation over the vesting period of the fair value of stock options granted to employees, directors, and key consultants of the Company. The fair value of all options granted is estimated using the Black-Scholes option pricing model. Each tranche of options in an award is considered a separate award with its own vesting period and grant date fair value. Compensation cost is expensed over the vesting period with a corresponding increase in share based payment reserve. When stock options are exercised, the cash proceeds and the amount previously recorded as contributed surplus are recorded as share capital. Stock based compensation Long-Term Incentive Plan On 31 July 2017 the Company established a new Long-Term Incentive Plan (“LTIP”) and issued awards to its Executive Directors and certain other key employees. The outstanding balance for the LTIP has decreased by 3.3 million and a corresponding credit of US$0.8 million has been posted to the Interim Income Statement due to the departure of two employees. For further details, see note 15 to the Interim Consolidated Financial Statements.



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Liquidity and capital resources (continued) Capital resources As at 30 June 2019 the Company had working capital of approximately US$17.6 million. The Company expects to fund its 2019 capital programme through funds generated from operations and cash on hand. As at 30 June 2019, the Company had cash and cash equivalents of US$11.2 million, compared to US$17.3 million as at 31 December 2018. During the three and six months ended 30 June 2019, the Company had net cash outflows of US$0.2 million and US$6.2 million respectively (including the effects of foreign exchange on cash and cash equivalents). For further details, please see the sources and uses table below. As at 30 June 2019, the Company had US$19.9 million in trade and other receivables, compared to US$23.7 million as at 31 December 2018 (net of prepayments). US$7.5 million is due from a Government of Egypt-controlled corporation (“EGPC”) for oil sales, gas, and NGL sales and production service fees, all of which are expected to be received in the normal course of operations. The Company also recorded US$4.1 million related to the joint venture partner account for the South Disouq and NW Gemsa concessions. US$3.2 million is owed by a Government of Morocco-controlled corporation, Office National Hydrocarbures et des Mines (“ONHYM”) and relates to ONHYM’s share of well completion and connection costs and production costs. US$3.2 million is owing from third-party gas customers in Morocco and is expected to be collected within agreed credit terms. The other receivables of US$1.8 million consist of US$1.3 million for Goods and Services Tax (“GST”)/Value Added Tax (“VAT”) and US$0.5 million for other items. Subsequent to 30 June 2019, the Company collected US$5.7 million of trade receivables from those outstanding at 30 June 2019; US$3.9 million from EGPC and US$1.8 million from third-party gas customers in Morocco. Of the US$3.9 million collected from EGPC, US$3.5 million was in cash and US$0.4 million was offset against South Disouq drilling and development costs and amounts owing to joint venture partners. The following table outlines the Company’s working capital. Working capital is defined as current assets, less current liabilities, and includes drilling inventory materials that may not be immediately monetised.

30 June 31 December US$’000s 2019 2018 Current assets Cash and cash equivalents 11,195 17,345 Trade and other receivables 21,764 24,324 Inventory 3,741 5,236 Total current assets 36,700 46,905

Current liabilities Trade and other payables 16,018 14,418 Deferred income 491 495 Decommissioning liability 1,125 1,125 Current income taxes 938 1,458 Lease liability 524 - Total current liabilities 19,096 17,496

Working capital 17,604 29,409



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Liquidity and capital resources (continued) Capital resources (continued) The following table outlines the Company’s sources and uses of cash for the three and six months ended 30 June 2019 and 2018:

Three months ended 30 June Six months ended 30 June US$’000s 2019 2018 2019 2018 Sources Operating cash flow before working capital movements 4,780 6,763 11,099 13,072 Changes in non-cash working capital 2,362 3,709 3,006 8,351 Dividends received 639 525 639 525 Effect of foreign exchange on cash and cash equivalents 73 - 190 58 Total sources 7,854 10,997 14,934 22,006

Uses Property, plant and equipment expenditures (3,007) (7,726) (4,811) (13,203) Exploration and evaluation expenditures (3,430) (5,946) (14,494) (8,311) Payments of lease liabilities (243) - (418) - Finance costs paid (30) (8) (58) (11) Income taxes paid (1,303) (1,091) (1,303) (1,091) Effect of foreign exchange on cash and cash equivalents - (269) - - Total uses (8,013) (15,040) (21,084) (22,616)

Decrease in cash (159) (4,043) (6,150) (610) Cash and cash equivalents at beginning of period 11,354 29,277 17,345 25,844 Cash and cash equivalents at end of period 11,195 25,234 11,195 25,234 Financial instruments The Company is exposed to financial risks because of the nature of its business and the financial assets and liabilities it holds. This section outlines material financial risks, quantifies the associated exposures, and explains how these risks and the Company’s capital are managed. Market risk Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates, and interest rates, could affect the Company’s income or the value of the financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimising the return. Commodity price risk Commodity price risk is the risk that the fair value of future cash flows will fluctuate because of changes in commodity prices. Commodity prices for oil and natural gas are affected not only by the relationship between the United States dollar and other currencies, but also world economic events that have an impact on the perceived levels of supply and demand. The Company may hedge some oil and natural gas sales using various financial derivative forward sales contracts and physical sales contracts. In Egypt, the Company’s production is sold on the daily average price and in Morocco at contracted prices. The Company may give consideration in certain circumstances to the appropriateness of entering into longer term, fixed-price marketing contracts. The Company will not enter into commodity contracts other than to meet the Company’s expected sale requirements. At 30 June 2019 the Company did not have any outstanding derivatives in place.

Liquidity and capital resources (continued) Financial instruments (continued) Foreign currency risk Currency risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. The reporting and functional currency of the Company is United States dollars (“US$”). Most of the Company’s operations are in foreign jurisdictions and, as a result, the Company is exposed to foreign currency exchange rate risk on some of its activities, primarily exchange fluctuations between the Egyptian pound (“EGP”) and the US$, the Moroccan dirham (“MAD”) and the US$, and Sterling (“GBP”) and the US$. Most capital expenditures are incurred in US$, EGP, and MAD, and oil, natural gas, NGL, and service fee revenues are received in US$, EGP and MAD. The Company can use EGP and MAD to fund its Egyptian and Moroccan office general and administrative expenses and to part-pay cash requirements for both capital and operating expenditure, thereby reducing the Company’s exposure to foreign exchange risk during the period. The table below shows the Company’s exposure to foreign currencies for its financial instruments:

Total per FS(1) US$ EGP MAD GBP Other As at 30 June 2019 US$ equivalent Cash and cash equivalents 11,195 1,840 1,680 5,132 2,429 114 Trade and other receivables(2) 19,889 9,495 2,397 6,547 1,406 44 Trade and other payables (16,018) (6,868) (2,647) (3,335) (3,166) (2) Current income taxes (938) - (938) - - - Balance sheet exposure 14,128 4,467 492 8,344 669 156 (1) FS denotes Financial Statements.

(2) Excludes prepayments.

The average exchange rates during the three months ended 30 June 2019 and 2018 were: Average: 1 April 2019 to 30 June 2019 Average: 1 April 2018 to 30 June 2018

USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD Period average 16.9675 0.7782 9.6424 Period average 17.7878 0.7358 9.3380 The average exchange rates during the six months ended 30 June 2019 and 2018 were: Average: 1 January 2019 to 30 June 2019 Average: 1 January 2018 to 30 June 2018

USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD Period average 17.2525 0.7732 9.6021 Period average 17.7268 0.7273 9.2981 The exchange rates as at 30 June 2019 and 2018 were: Period end: 30 June 2019 Period end: 30 June 2018

USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD Period average 16.6500 0.7880 9.5718 Period average 17.8962 0.7600 9.5050 Trade and other payables The foreign currency risk from a trade and other payables perspective arises because the Company’s operations are conducted in Egypt and Morocco and its corporate office is in London, with G&A and other listing and regulatory costs paid in both jurisdictions. As at 30 June 2019 and 31 December 2018 the Company’s trade and other payables are as follows:


US$’000s 2019 2018 Trade payables 2,835 3,870 Accruals 6,869 3,747 Joint venture partners 4,241 5,409 Other payables 2,073 1,392 Total trade and other payables 16,018 14,418 For a discussion of the Company’s trade and other payables, see note 11 to the Interim Consolidated Financial Statements for the three and six months ended 30 June 2019.





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Liquidity and capital resources (continued) Financial instruments (continued) Credit risk Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations. It arises principally from the Company’s receivables from joint operations partners, oil and natural gas marketers, and cash held with banks. The maximum exposure to credit risk at the end of the period is as follows:


US$’000s 2019 2018 Cash and cash equivalents 11,195 17,345 Trade and other receivables(1) 19,889 23,689 Total 31,084 41,034 (1) excludes prepayments of US$1.9 million which are included in the Interim Consolidated Balance Sheet as trade and other receivables but which are not categorised as financial assets as summarised above (2018: US$0.6 million).

Trade and other receivables: All the Company’s operations as at 30 June 2019 were conducted in Egypt and Morocco. The Company’s exposure to credit risk is influenced mainly by the individual characteristics of each counterparty. The Company does not anticipate any default and expects continued payment from customers against invoiced sales. The maximum exposure to credit risk for trade and other receivables at the reporting date by type of customer was:


US$’000s 2019 2018 Government of Egypt-controlled corporations 7,490 14,846 Government of Morocco-controlled corporations 3,218 3,053 Third-party gas customers 3,223 2,715 Joint venture partners 4,137 1,761 Other(1) 1,821 1,314 Total 19,889 23,689 (1) excludes prepayments of US$1.9 million which are included in the Interim Consolidated Balance Sheet as trade and other receivables but which are not categorised as financial assets as summarised above (2018: US$0.6 million).

As at 30 June 2019 and 31 December 2018, the Company’s trade and other receivables, excluding prepayments, are aged as follows:


US$’000s 2019 2018 Current (less than 90 days) 15,918 14,805 Past due (more than 90 days) 3,971 8,884 Total 19,889 23,689 For a discussion of the Company’s trade and other receivables, see note 5a to the Interim Consolidated Financial Statements for the three and six months ended 30 June 2019.



Liquidity and capital resources (continued) Financial instruments (continued) Cash and cash equivalents: The Company limits its exposure to credit risk by only investing in liquid securities and only with highly rated counterparties. The Company’s cash and cash equivalents are currently held with established financial institutions with high credit ratings in either countries of operation or the UK. Given these credit ratings, management does not expect any counterparty to fail to meet its obligations. Capital management: The Company defines and computes its capital as follows:


US$’000s 2019 2018 Equity 115,346 116,039 Working capital(1) (17,604) (29,409) Total capital 97,742 86,630 (1) Working capital is defined as current assets less current liabilities.

The Company’s objective when managing its capital is to ensure that it has sufficient capital to maintain its ongoing operations, pursue the acquisition of interests in producing or near to production oil and gas properties, and to maintain a flexible capital structure that optimises the cost of capital at an acceptable risk. The Company manages its capital structure and adjusts it based on the funds available to the Company, to support the exploration and development of its interests in its existing properties and to pursue other opportunities. Accounting policies and estimates The Company is required to make judgments, assumptions and estimates in the application of accounting policies that could have a significant impact on its financial results. Actual results may differ from those estimates, and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. The accounting policies and estimates are reviewed annually by the Audit Committee of the board. Further information on the basis of presentation and our significant accounting policies can be found in the notes to the Consolidated Financial Statements and Annual MD&A for the year ended 31 December 2018. Accounting policies The accounting policies adopted are consistent with those of the previous financial year, except for the adoption of new standards and interpretations effective 1 January 2019. Further information on the accounting policies and estimates can be found in the notes to the Interim Consolidated Financial Statements and MD&A for the three and six months ended 30 June 2019. Future changes in accounting policies There are no updates to future changes in accounting policies in the first six months of 2019.



Business risk assessment There are a number of inherent business risks associated with oil and gas operations and development. Many of these risks are beyond the control of management. The following outlines some of the principal risks and their potential impact to the Company. Political Risk SDX operates in Egypt and Morocco, countries that have different political, economic and social systems from North America and which subject the Company to a number of risks not within the control of the Company. Exploration or development activities in such countries may require protracted negotiations with host governments, national oil companies and third parties and are frequently subject to economic and political considerations such as taxation, nationalisation, expropriation, inflation, currency fluctuations, increased regulation and approval requirements, corruption and the risk of actions by terrorist or insurgent groups, changes in laws and policies governing the operations of foreign-based companies, economic and legal sanctions and other uncertainties arising from foreign governments, any of which could adversely affect the economics of exploration or development projects. Financial Resources The Company’s cash flow from operations may not be sufficient to fund its ongoing activities and implement its business plans. From time to time the Company may enter into transactions to acquire assets or the shares of other companies. Depending on the future exploration and development plans, the Company may require additional financing, which may not be available or, if available, may not be available on favorable terms. Failure to obtain such financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate operations. If the revenues from the Company’s reserves decrease because of lower oil prices or otherwise, it will affect its ability to expend the necessary capital to replace its reserves or to maintain its production. If cash flow from operations is not sufficient to satisfy capital expenditure requirements, there can be no assurance that additional debt, equity, or asset dispositions will be available to meet these requirements or available on acceptable terms. In addition, cash flow is influenced by factors that the Company cannot control, such as commodity prices, exchange rates, interest rates and changes to existing government regulations and tax and royalty policies. Exploration, Development and Production The long-term success of SDX will depend on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. SDX mitigates these risks through the use of skilled staff, focusing exploration efforts in areas in which the Company has existing knowledge and expertise or access to such expertise, using up-to-date technology to enhance methods, and controlling costs to maximise returns. Despite these efforts, oil and natural gas exploration involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that SDX will be able to locate satisfactory properties for acquisition or participation or that the Company’s expenditures on future exploration will result in new discoveries of oil or natural gas in commercial quantities. It is difficult to accurately project the costs of implementing an exploratory drilling programme due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions such as over-pressured zones, tools lost in the hole and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion, infrastructure and operating costs. In addition, drilling hazards and/or environmental damage could greatly increase the costs of operations and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-in of wells resulting from extreme weather conditions or natural disasters, insufficient transportation capacity or other geological and mechanical conditions. As well, approved activities may be subject to limited access windows or deadlines, which may cause delays or additional costs. While diligent well supervision and effective maintenance operations can contribute to maximising production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. The nature of oil and gas operations exposes SDX to risks normally incident to the operation and development of oil and natural gas properties, including encountering unexpected formations or pressures, blow-outs, and fires, all of which could result in personal injuries, loss of life and damage to the property of the Company and others. The Company has both safety and environmental policies in place to protect its operators and employees, as well as to meet the regulatory requirements in those areas where it operates. In addition, the Company has liability insurance policies in place, in such amounts as it considers adequate. The Company will not be fully insured against all of these risks, nor are all such risks insurable.

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Business risk assessment (continued) Oil and Natural Gas Prices The price of oil and natural gas will fluctuate based on factors beyond the Company’s control. These factors include demand for oil and natural gas, market fluctuations, the ability of regional state-owned monopolies to control prices, the proximity and capacity of oil and natural gas pipelines and processing equipment and government regulations, including regulations relating to environmental protection, royalties, allowable production, pricing, importing and exporting of oil and natural gas. Fluctuations in price will have a positive or negative effect on the revenue the Company receives. Reserve Estimates There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids, reserves and cash flows to be derived from them, including many factors beyond the Company’s control. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows are based on a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary from actual results. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues prepared by different engineers, or by the same engineers at different times, may vary. The Company’s actual production, revenues and development and operating expenditures with respect to its reserves will vary from estimates and such variations could be material. Estimates of proved reserves that may be developed and produced in the future are often based on volumetric calculations and comparisons to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based on production history and production practices will result in variations in the estimated reserves and such variations could be material. The Company’s actual future net cash flows, as estimated by independent reserve engineers, will be affected by many factors including, but not limited to: actual production levels; supply and demand for oil and natural gas; curtailments or increases in consumption by oil and natural gas purchasers; changes in governmental regulation; taxation changes; the value of the Moroccan Dirham, British Pound, Egyptian Pound and US$; and the impact of inflation on costs. Actual production and cash flows will vary from the estimates contained in the applicable engineering reports. The reserve reports are based in part on the assumed success of activities the Company intends to undertake in future years. The reserves and estimated cash flows contained in the engineering reports will be reduced to the extent that such activities do not achieve the level of success assumed in the calculations. Reliance on Operators and Key Employees To the extent that SDX is not the operator of its oil and natural gas properties, it will depend on such operators for the timing of activities related to such properties and is largely unable to direct or control the activities of the operators. In addition, the success of the Company will largely depend on the performance of its management and key employees. The Company has no key-man insurance policies, and therefore there is a risk that the death or departure of any member of management or key employee could have a material adverse effect on the Company. Government Regulations SDX may be subject to various laws, regulations, regulatory actions and court decisions that can have negative effects on it. Changes in the regulatory environment imposed upon the Company could adversely affect its ability to attain its corporate objectives. The current exploration, development and production activities of the Company require certain permits and licenses from governmental agencies and such operations are, and will be, governed by laws and regulations governing exploration, development and production, labor laws, waste disposal, land use, safety, and other matters. There can be no assurance that all licenses and permits that the Company may require to carry out exploration and development of its projects will be obtainable on reasonable terms or on a timely basis, or that such laws and regulation would not have an adverse effect on any project that the Company may undertake. Environmental Factors All phases of the Company’s operations are subject to environmental regulation in Egypt and Morocco. Environmental legislation is evolving in a manner that requires stricter standards and enforcement, increased fines, and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their officers, directors and employees. Insurance The Company’s involvement in the exploration for and development of oil and natural gas properties may result in the Company or its subsidiaries, as the case may be, becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Prior to drilling, the Company or the operator will obtain insurance in accordance with industry standards to address certain of these risks. However, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not in all circumstances be insurable or, in certain circumstances, the Company or its subsidiaries, as the case may be, may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The occurrence of a significant event that the Company may not be fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Company’s financial position.



Business risk assessment (continued) Regulatory Matters The Company’s operations will be subject to a variety of federal and provincial or state laws and regulations, including income tax laws and laws and regulations relating to the protection of the environment. The Company’s operations may require licenses from various governmental authorities and there can be no assurance that the Company will be able to obtain all necessary licenses and permits that may be required to carry out planned exploration and development projects. Operating Hazards and Risks Exploration for natural resources involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. Operations in which the Company has a direct or indirect interest will be subject to all the hazards and risks normally incidental to exploration, development and production of resources, any of which could result in work stoppages, damages to persons or property and possible environmental damage. Although the Company has obtained liability insurance in an amount it considers adequate, the nature of these risks is such that liabilities might exceed policy limits, the liabilities and hazards might not be insurable, or the Company might not elect to insure itself against such liabilities due to high premium costs or other reasons, in which event the Company could incur significant costs that could have a material adverse effect upon its financial condition. Repatriation of earnings All of the Company’s production and earnings are generated in Egypt and Morocco. Currently there are no restrictions on foreign entities repatriating earnings from Egypt. However, there can be no assurance that restrictions on repatriation of earnings from Egypt will not be imposed in the future. A company can repatriate earnings from Morocco each year up to the limit of its retained earnings. Disruptions in Production Other factors affecting the production and sale of oil and gas that could result in decreases in profitability include: (i) expiration or termination of permits or licenses, or sales price redeterminations or suspension of deliveries; (ii) future litigation; (iii) the timing and amount of insurance recoveries; (iv) work stoppages or other labor difficulties; (v) changes in the market and general economic conditions, equipment replacement or repair, fires, civil unrest or other unexpected geological conditions that can have a significant impact on operating results. Foreign Investments All the Company’s oil and gas investments are located outside Canada. These investments are subject to the risks associated with foreign investment, including tax increases, royalty increases, re-negotiation of contracts, currency exchange fluctuations and political uncertainty. The jurisdictions in which the Company operates, Egypt and Morocco, have well-established fiscal regimes. As operations are primarily carried out in US dollars, the main exposure to currency exchange fluctuations is the conversion to equivalent EGP, MAD and GBP. Competition SDX operates in the highly competitive areas of oil and gas exploration, development and acquisition with a substantial number of other companies, including U.S.-based and foreign companies doing business in Egypt and Morocco. The Company faces intense competition from both major and other independent oil and gas companies in seeking oil and gas exploration licences and production licences in Egypt and Morocco; and acquiring desirable producing properties or new leases for future exploration. The Company believes it has significant in-country relationships within the business community and government authorities needed to obtain cooperation to execute projects. Disclosure Controls and Procedures As the Company is classified as a Venture Issuer under applicable Canadian securities legislation, it is required to file basic Chief Executive Officer and Chief Financial Officer Certificates, which it has done for the period ended 30 June 2019. The Company makes no assessment relating to the establishment and maintenance of disclosure controls and procedures and internal controls over financial reporting as defined under Multilateral Instrument 52-109 as at 30 June 2019.

Managem


Analysis



Summary of quarterly results Fiscal year 2019 2018 2017 Financial US$’000s Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Cash, beginning of period 11,354 17,345 18,713 25,234 29,277 25,844 30,469 27,627

Cash, end of period 11,195 11,354 17,345 18,713 25,234 29,277 25,844 30,469

Working capital 17,604 21,423 29,409 33,190 36,355 43,091 46,725 58,397

Comprehensive (loss)/income (489) 132 (4,029) 3,169 640 331 (2,621) 4,408

Net (loss)/income per share-basic (0.002) 0.001 (0.020) 0.015 0.003 0.002 (0.013) 0.022

Capital expenditure 8,777 13,041 8,316 11,017 14,742 9,948 15,328 3,423

Total assets 140,122 137,630 138,107 146,239 143,419 140,497 141,057 138,898

Shareholders’ equity 115,346 116,491 116,039 119,848 116,246 115,282 114,619 116,981

Common shares outstanding (000s) 204,723 204,723 204,723 204,706 204,493 204,493 204,493 204,459

Fiscal year 2019 2018 2017 Operational Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 NW Gemsa oil sales (bbl/d) 1,326 1,586 1,808 1,987 1,665 1,507 1,710 1,893 Block-H Meseda production service fee (bbl/d) 818 826 864 802 706 558 561 551 Morocco gas sales (boe/d) 729 761 648 615 656 664 680 611 Other products sales (boe/d) 493 542 604 485 403 307 310 384 Total boe/d 3,366 3,715 3,924 3,889 3,430 3,036 3,261 3,439

NW Gemsa oil sales volumes (bbls) 120,624 142,768 166,296 182,803 151,520 135,630 157,302 174,202 Block-H Meseda production service fee volumes (bbls) 74,475 74,315 79,530 73,761 64,286 50,257 51,599 50,674 Morocco gas sales volumes (boe) 66,358 68,458 59,573 56,602 59,740 59,779 62,543 56,219 Other products sales volumes (boe) 44,875 48,791 55,564 44,575 36,681 27,646 28,550 35,404 Total sales and service fee volumes (boe) 306,332 334,332 360,963 357,741 312,227 273,312 299,994 316,499

Brent oil price (US$/bbl) 68.95 63.02 67.75 75.18 74.53 66.86 61.52 52.07 West Gharib oil price (US$/bbl) 63.16 56.03 60.09 65.36 63.99 58.75 53.59 44.48

Realised oil price (US$/bbl) 64.98 58.22 62.77 70.76 68.41 62.81 57.77 48.28 Realised service fee (US$/bbl) 53.56 47.58 51.34 55.50 54.37 50.00 44.11 36.41 Realised oil sales price and service fees 60.62 54.58 59.07 66.38 64.23 59.34 54.39 45.61

Realised Morocco gas price (US$/mcf) 10.31 10.26 9.78 11.05 10.51 10.03 9.72 9.53

Royalties (US$/boe) 12.27 11.99 13.53 16.88 14.90 13.92 9.89 11.94

Operating costs (US$/boe) 11.72 10.09 9.40 9.45 10.15 7.30 8.42 8.44

Netback-(US$/boe) 29.84 27.84 28.94 33.62 33.00 32.80 23.54 21.48


Low cost

High margin production

Financial Statements



24.6MMboe (gross)


As at As at 30 June December 31

US$’000s Note 2019 2018 Assets Cash and cash equivalents 6 11,195 17,345 Trade and other receivables 5a 21,764 24,324 Inventory 7 3,741 5,236 Current assets 36,700 46,905

Investments 10 3,479 3,394 Property, plant and equipment 8 41,652 48,680 Exploration and evaluation assets 9 56,374 39,128 Right-of-use assets 23 1,917 - Non-current assets 103,422 91,202

Total assets 140,122 138,107

Liabilities Trade and other payables 11 16,018 14,418 Deferred income 12 491 495 Decommissioning liability 13 1,125 1,125 Current income taxes 19 938 1,458 Lease liability 23 524 - Current liabilities 19,096 17,496

Deferred income 12 - 240 Decommissioning liability 13 4,080 4,042 Deferred income taxes 19 290 290 Lease liability 23 1,310 - Non-current liabilities 5,680 4,572

Total liabilities 24,776 22,068

Equity Share-capital 14 2,593 88,899 Share-based payment reserve 6,521 6,860 Accumulated other comprehensive loss (917) (917) Merger reserve 14 37,034 - Retained earnings 70,115 21,197

Total equity 115,346 116,039

Equity and liabilities 140,122 138,107 The notes are an integral part of these Interim Consolidated Financial Statements. The financial statements on pages 38 to 56 were approved by the board of directors on 22 August 2019 and signed on its behalf by: Michael Doyle Mark Reid Chairman Interim Chief Executive Officer

and Chief Financial Officer


Interim Consolidated Balance Sheet (Unaudited)


Interim Consolidated Statement of Comprehensive Income (Unaudited)


Three months ended 30 June Six months ended 30 June US$’000s Note 2019 2018 2019 2018 Revenue, net of royalties 16 12,732 13,472 25,413 24,432 Direct operating expense 17 (3,589) (3,168) (6,963) (5,162) Gross profit 9,143 10,304 18,450 19,270 Exploration and evaluation expense 9 (380) (2,064) (615) (5,314) Depletion, depreciation and amortisation 8,23 (6,047) (3,657) (11,945) (6,190) Share-based compensation 15 658 (324) 339 (656) Share of profit from joint venture 10 355 292 724 526 Release of historic operational tax provision - 300 - 300 Inventory write-off - (490) - (490) Gain on sale of office asset - 23 - 23 General and administrative expenses - Ongoing general and administrative expenses 18 (2,083) (1,520) (3,293) (2,765) - Transaction costs 18 (766) - (1,104) - Operating income 880 2,864 2,556 4,704 Net finance expense (105) (33) (246) (54) Foreign exchange loss (18) (452) (5) (438) Loss on acquisition - - - (174) Income before income taxes 757 2,379 2,305 4,038 Current income tax expense 19 (1,246) (1,739) (2,659) (3,067) Deferred income tax expense - - - - Total current and deferred income tax expense (1,246) (1,739) (2,659) (3,067) Total comprehensive (loss)/income for the period (489) 640 (354) 971 Net (loss)/income per share Basic 20 $(0.002) $0.003 $(0.002) $0.005 Diluted 20 $(0.002) $0.003 $(0.002) $0.005 The notes are an integral part of these Interim Consolidated Financial Statements.


Interim Consolidated Statement of Changes in Equity (Unaudited)

Six months ended 30 June US$’000s Note 2019 2018 Share capital Balance, beginning of period 14 88,899 88,785 Share-for-share exchange - old 14 (88,899) - Share-for-share exchange - new 14 51,865 - Capital reduction 14 (49,272) - Balance, end of period 2,593 88,785 Share based payment reserve Balance, beginning of period 6,860 5,666 Share-based compensation for the period (339) 656 Balance, end of period 6,521 6,322 Accumulated other comprehensive loss Balance, beginning of period (917) (917) Balance, end of period (917) (917) Merger reserve Balance, beginning of period - - Share-for-share exchange 14 37,034 - Balance, end of period 37,034 - Retained earnings Balance, beginning of period 21,197 21,085 Capital reduction 14 49,272 - Total comprehensive (loss)/income for the period (354) 971 Balance, end of period 70,115 22,056 Total equity 115,346 116,246 The notes are an integral part of these Interim Consolidated Financial Statements.


Interim Consolidated Statement of Cash Flows (Unaudited)


Three months ended 30 June Six months ended 30 June US$’000s Note 2019 2018 2019 2018 Cash flows generated from/(used in) operating activities Income before income taxes 757 2,379 2,305 4,038 Adjustments for: Depletion, depreciation and amortization 8, 23 6,047 3,657 11,945 6,190 Exploration and evaluation expense 9 - 1,783 - 5,033 Finance expense 105 33 246 54 Share-based compensation 15 (658) 324 (339) 656 Loss on acquisition - - - 174 Foreign exchange loss/(gain) (73) 269 (190) (58) Gain on sale of office asset - (23) - (23) Release of historic operational tax provision - (300) - (300) Inventory write-off - 490 - 490 Amortisation of deferred income 12 (122) (365) (243) (489) Tax paid by state 19 (921) (1,192) (1,901) (2,167) Share of profit from joint venture 10 (355) (292) (724) (526) Operating cash flow before working capital movements 4,780 6,763 11,099 13,072 (Increase)/decrease in trade and other receivables 5a (112) 1,070 2,317 8,342 Increase in trade and other payables 11 2,701 2,819 1,543 778 Payments for inventory 7 (227) (180) (854) (769) Cash generated from operating activities 7,142 10,472 14,105 21,423 Income taxes paid 19 (1,303) (1,091) (1,303) (1,091) Net cash generated from operating activities 5,839 9,381 12,802 20,332 Cash flows generated from/(used in) investing activities: Property, plant and equipment expenditures 8 (3,007) (7,726) (4,811) (13,203) Exploration and evaluation expenditures 9 (3,430) (5,946) (14,494) (8,311) Dividends received 10 639 525 639 525 Net cash used in investing activities (5,798) (13,147) (18,666) (20,989) Cash flows used in financing activities: Payments of lease liabilities 23 (243) - (418) - Finance costs paid (30) (8) (58) (11) Net cash used in financing activities (273) (8) (476) (11) Decrease in cash and cash equivalents (232) (3,774) (6,340) (668) Effect of foreign exchange on cash and cash equivalents 73 (269) 190 58 Cash and cash equivalents, beginning of period 11,354 29,277 17,345 25,844 Cash and cash equivalents, end of period 11,195 25,234 11,195 25,234 The notes are an integral part of these Interim Consolidated Financial Statements.


Notes to the Interim Consolidated Financial Statements For the three and six months ended 30 June 2019 and 2018 (tabular amounts are in thousands of United States dollars except where stated)

1. Reporting entity SDX Energy Plc (“SDX” or “the Company”) is a company domiciled in the United Kingdom. The address of the Company’s registered office is 38 Welbeck Street, London, United Kingdom, W1G 8DP. The unaudited interim condensed consolidated financial statements of the Company as at and for the three and six months ended 30 June 2019 and 2018 (“Interim Consolidated Financial Statements”) comprise the Company and its wholly owned subsidiaries and include the Company’s share of joint arrangements (together the “Group”). The Company’s shares trade on the London Stock Exchange’s Alternative Investment Market (“AIM”) in the United Kingdom under the symbol “SDX”. The Company is engaged in the exploration for and development and production of oil and natural gas. The Company’s principal properties are in the Arab Republic of Egypt and the Kingdom of Morocco. On 28 May 2019, the Company obtained control of the entire issued share capital of SDX Energy Inc. via a share-for-share exchange. There were no changes in rights or proportion of control exercised as a result of this transaction. As no change in legal ownership occurred, this was a common control transaction and therefore outside the scope of IFRS3. In substance these Interim Consolidated Financial Statements reflect the continuation of the pre-existing Group headed by SDX Energy Inc., and they have been prepared applying the principals of predecessor accounting ownership. As a result, the comparatives presented in these Interim Consolidated Financial Statements are the consolidated results of SDX Energy Inc.. The prior year Consolidated Balance Sheet reflects the capital structure of SDX Energy Inc.. The current period balance sheet presents the legal change in ownership of the Group, including the share capital of SDX Energy Plc and the merger reserve arising as a result of the share-for-share exchange transaction. On 4 June 2019, the High Court of Justice Chancery Division made an order confirming the reduction of share capital of SDX Energy Plc pursuant to section 648 of the Companies Act 2006. The Interim Consolidated Statement of Changes in Equity and the additional disclosures in note 14 explain the impact of the share-for-share exchange and the reduction of share capital in more detail. 2. Basis of preparation a) Statement of compliance

These Interim Consolidated Financial Statements for the three and six months ended 30 June 2019 and 2018 have been prepared in accordance with IAS 34 “Interim Financial Reporting”, as issued by the International Accounting Standards Board (“IASB”). These interim condensed consolidated financial statements should be read in conjunction with the Consolidated Financial Statements for the year ended 31 December 2018, which have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the IASB.

These Interim Consolidated Financial Statements of SDX Energy Plc were approved by the board of directors on 22 August 2019.

b) Accounting policies

Other than as detailed in note 3, the accounting policies adopted by the Group are consistent with those of the previous financial year. The policies applied are based on IFRS that are issued and outstanding as of the date that the board of directors approved these financial statements.

c) Going concern

The Company directors have reviewed the Company’s forecasted cash flows for the next 12 months from the date of publication of these Interim Consolidated Financial Statements through until 31 December 2020. The capital expenditure and operating costs used in these forecasted cash flows are based on the Company’s board-approved 2019 SDX corporate budget, which reflects approved operating budgets for each of its joint ventures and an estimate of 2019 SDX corporate general and administrative expenses. The Company’s forecasted cash flows also reflect its best estimate of operational and corporate expenditure, including corporate general and administrative costs for the period to 31 December 2020. The directors have made enquiries into and considered the Egyptian and Moroccan business environments and future expectations regarding commodity price risk, particularly, the oil price risk given the volatility in quoted Brent and WTI crude oil prices.

The directors have considered the sensitivities and potential outcomes relating to: i) country and commodity price risks; ii) the Company’s ability to change the timing and scale of discretionary capital expenditure; iii) the Company’s ability to manage operating costs; and iv) the Company’s ability to manage general and administrative costs.

As a result, they consider that, in a low-price environment the Company has sufficient resources at its disposal to continue for the foreseeable future. The foreseeable future is defined as being not less than 12 months from the date of publication of these Interim Consolidated Financial Statements.

Given the above, these Interim Consolidated Financial Statements continue to be prepared under the going concern basis of accounting.



3. New accounting standards adopted The Company has adopted IFRS 16 Leases effective 1 January 2019. In accordance with the transition provisions in IFRS 16, the new rules have been adopted retrospectively, with the cumulative effect of initially applying the new standard recognised on 1 January 2019. Comparatives for the 2018 financial year have not been restated. See note 23 below for further details on the impact of the change in accounting policy. IFRS 16 Leases Adjustments recognised on adoption of IFRS 16 On adoption of IFRS 16, the Company recognised lease liabilities in relation to leases that had previously been classified as “operating leases” under the principles of IAS 17 Leases. These lease liabilities were measured at the present value of the remaining lease payments and discounted using entity-specific incremental borrowing rates at 1 January 2019. The incremental borrowing rate applied to each lease was determined by taking into account the risk-free rate, adjusted for factors such as the credit rating of the contracting entity and the terms and conditions of the lease. The weighted average incremental borrowing rate applied by the Company upon transition was 8%. The associated right-of-use assets for leases were measured at the amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease payments relating to that lease recognised on the balance sheet as at 31 December 2018. There were no onerous lease contracts that would have required an adjustment to the right-of-use assets at the date of initial application. The recognised right-of-use assets relate to property, motor vehicles, and software. The change in accounting policy affected the following items in the consolidated balance sheet on 1 January 2019: (i) Impact on segment disclosures and earnings per share

EBITDAX, segment assets and segment liabilities for H1 2019 all increased as a result of the change in accounting policy. (ii) Practical expedients applied

In applying IFRS 16 for the first time, the Company has used the following practical expedients permitted by the standard: • the use of a single discount rate to a portfolio of leases with reasonably similar characteristics; • the accounting for operating leases with a remaining lease term of less than 12 months as at 1 January 2019 as short-term leases; • the exclusion of initial direct costs for the measurement of the right-of-use asset at the date of initial application; and • the use of hindsight in determining the lease term where the contract contains options to extend or terminate the lease.

The Company has also elected not to apply IFRS 16 to contracts that were not identified as containing a lease under IAS 17 and IFRIC 4, “Determining whether an Arrangement contains a Lease”. (iii) The Company’s leasing activities and how these are accounted for

The Company leases various properties, motor vehicles, and software. Rental contracts are typically made for fixed periods but can have extension options. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. The lease agreements do not impose any covenants, but leased assets cannot be used as security for borrowing purposes.

Leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the Company.

Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of fixed payments (including in-substance fixed payments), less any lease incentives receivable. The lease payments are discounted using the Company’s incremental borrowing rate.

The Company recognises a right-of-use asset and a lease liability at the start of the lease. The right-of-use asset is initially measured based on the present value of lease payments, plus initial direct costs and the cost of obligations to refurbish the asset, adjusted for any lease payments made at or before the commencement date less any incentives received.

Each lease payment is allocated between the liability and finance cost. The finance cost is charged to profit or loss over the lease period to produce a constant periodic rate of interest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of the asset’s useful life and the lease term on a straight-line basis.

The Company has elected not to recognise right-of-use assets and liabilities for leases where the total lease term is less than or equal to 12 months, or for leases of low-value assets. Low-value assets comprise IT equipment and small items of office furniture. Payments associated with short-term leases and leases of low-value assets are recognised on a straight-line basis as an expense in profit or loss.


4. Determination of fair values A number of the Company’s accounting policies and disclosures require the determination of fair value; for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability. The different levels of financial instrument valuation methods have been defined as: Level 1 fair value measurements are based on unadjusted quoted market prices. Level 2 fair value measurements are based on valuation models and techniques where the significant inputs are derived from quoted indices. Level 3 fair value measurements are based on unobservable information. The carrying value of cash and cash equivalents, trade and other receivables, trade and other payables, and loans and borrowings included in the consolidated balance sheet approximate to their fair value due to the short-term nature of those instruments. The fair value of employee stock options is measured using Black-Scholes (non-market-based performance conditions) and Monte Carlo (market-based performance conditions) option pricing models. Measurement inputs include the share price on the measurement date, exercise price of the instrument, expected volatility based on the weighted average historic volatility (adjusted for changes expected due to publicly available information), the weighted average expected life of the instruments based on historical experience and general option holder behavior, expected dividends, anticipated achievement of performance conditions, and the risk-free interest rate. 5. Financial risk management Credit risk is the risk of financial loss to the Company if a customer, partner, or counterparty to a financial instrument fails to meet its contractual obligations and arises principally from the Company’s receivables from joint venture partners, oil and natural gas customers, and cash held with banks. The maximum exposure to credit risk at the end of the period is as follows:


US$’000s 2019 2018 Cash and cash equivalents 11,195 17,345 Trade and other receivables(1) 19,889 23,689 Total 31,084 41,034 (1) excludes prepayments of US$1.9 million which are included in the Interim Consolidated Balance Sheet as trade and other receivables but which are not categorised as financial assets as summarised above (2018: US$0.6 million).

a) Credit risk

Trade and other receivables

All the Company’s operations were conducted in Egypt and Morocco. The Company’s exposure to credit risk is influenced mainly by the individual characteristics of each counter party. The Company applies the IFRS 9 simplified model for measuring the expected credit losses which uses a lifetime expected loss allowance and are measured on the days past due criterion. Having reviewed past payments combined with the credit profile of its existing trade debtors in order to assess the potential for impairment, the Company has concluded that this is insignificant as there has been no history of default or disputes arising on invoiced amounts since inception and as such the credit loss percentage is assumed to be almost zero. No provision for doubtful accounts against these sales has been recorded as at 30 June 2019 and 31 December 2018.

The maximum exposure to credit risk for loans and receivables at the reporting date by type of customer was:


US$’000s 2019 2018 Government of Egypt-controlled corporations 7,490 14,846 Government of Morocco-controlled corporations 3,218 3,053 Third-party gas customers 3,223 2,715 Joint venture partners 4,137 1,761 Other(1) 1,821 1,314 Total 19,889 23,689 (1) excludes prepayments of US$1.9 million which are included in the Interim Consolidated Balance Sheet as trade and other receivables but which are not categorised as financial assets as summarised above (2018: US$0.6 million).






5. Financial risk management (continued) US$7.5 million of current receivables relates to oil, gas, and NGL sales and production service fees that are due from EGPC (2018: US$14.8 million), a Government of Egypt-controlled corporation. The Company expects to collect outstanding receivables of US$3.0 million for NW Gemsa (2018: US$10.0 million) and US$4.5 million for Block-H Meseda (2018: US$4.8 million), in the normal course of operations. The Company continues to use its accounts receivable balance to fund operations, with US$13.5 million of South Disouq development expenditure and US$1.4 million of South Ramadan drilling costs offset during the six months ended 30 June 2019.

ONHYM, a Government of Morocco-controlled corporation, owes US$3.2 million, which relates to its outstanding share of well completion and connection costs, and production costs. During Q4 2018, these receivables had been discounted at 5% with an associated finance expense of US$0.3 million recognised. No payments have been received from ONHYM during 2019, however this is due to the time required to authorise payments in the Moroccan Ministry of Finance, as opposed to this balance being disputed by ONHYM.

US$3.2 million is owing from third-party gas customers in Morocco and is expected to be collected within agreed credit terms.

Subsequent to 30 June 2019, the Company collected US$5.7 million of trade receivables from those outstanding at 30 June 2019; US$3.9 million from EGPC and US$1.8 million from third-party gas customers in Morocco. Of the US$3.9 million collected from EGPC, US$3.5 million was in cash and US$0.4 million was offset against South Disouq drilling and development costs and amounts owing to joint venture partners.

The joint venture partner current accounts represent the net of monthly cash calls paid less billings received. At 30 June 2019, US$1.8 million was receivable from the joint venture partner in the South Disouq concession (2018: US$1.8 million), representing both billed and unbilled amounts and US$2.3 million relating to an overcall from the joint venture partner in the NW Gemsa concession, which is expected to unwind as accounts payable are paid down. At 30 June 2019, the Company’s share of NW Gemsa materials inventory was US$2.6 million and accounts payable was US$(3.7) million.

The other receivables of US$1.8 million consist of US$1.1 million for Goods and Services Tax (“GST”)/Value Added Tax (“VAT”) and US$0.7 million for other items.

US$1.9 million related to prepayments predominantly associated with the South Disouq development and planned Morocco drilling campaign is recorded in the Interim Consolidated Balance Sheet.

As at 30 June 2019 and 31 December 2018, the Company’s trade and other receivables, other than prepayments, are aged as follows:


US$’000s 2019 2018 Current (less than 90 days) 15,918 14,805 Past due (more than 90 days) 3,971 8,884 Total 19,889 23,689

Current trade and other receivables are unsecured and non-interest-bearing. The balances that are past due are not considered impaired.

Current trade and other receivables past due (more than 90 days old) have decreased by US$4.9 million compared to 31 December 2018. This decrease is primarily due to using aged receivables from EGPC to fund South Disouq development costs as per the discussion above.

Cash and cash equivalents The Company limits its exposure to credit risk by investing only in liquid securities and only with highly rated counterparties. The Company’s cash and cash equivalents are currently held with established financial institutions with high credit ratings in either countries of operation or the UK. Given these credit ratings, management does not expect any counterparty to fail to meet its obligations.

5. Financial risk management (continued) b) Foreign currency risk

Currency risk is the risk that the fair value of future cash flows will fluctuate because of changes in foreign exchange rates. The reporting and functional currency of the Company is United States dollars (“US$”). Most of the Company’s operations are in foreign jurisdictions and, as a result, the Company is exposed to foreign currency exchange rate risk on some of its activities, primarily on exchange fluctuations between the Egyptian pound (“EGP”) and the US$, the Moroccan dirham (“MAD”) and the US$, and the British pound (“GBP”) and the US$. Most capital expenditures are incurred in US$, EGP and MAD, and oil, natural gas, NGL and service fee revenues are received in US$, EGP and MAD. The Company can use EGP and MAD to fund its Egyptian and Moroccan general and administrative expenses and to part-pay cash requirements for both capital and operating expenditure, thereby reducing the Company’s exposure to foreign exchange risk during the period.

The table below shows the Company’s exposure to foreign currencies for its financial instruments:

Total per FS(1) US$ EGP MAD GBP Other

As at 30 June 2019 US$ equivalent Cash and cash equivalents 11,195 1,840 1,680 5,132 2,429 114 Trade and other receivables(2) 19,889 9,495 2,397 6,547 1,406 44 Trade and other payables (16,018) (6,868) (2,647) (3,335) (3,166) (2) Current income taxes (938) - (938) - - - Balance sheet exposure 14,128 4,467 492 8,344 669 156 (1) FS denotes Financial Statements.

(2) Excludes prepayments.

The average exchange rates during the three months ended 30 June 2019 and 2018 were: Average: 1 April 2019 to 30 June 2019 Average: 1 April 2018 to 30 June 2018

USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD Period average 16.9675 0.7782 9.6424 Period average 17.7878 0.7358 9.3380 The average exchange rates during the six months ended 30 June 2019 and 2018 were: Average: 1 January 2019 to 30 June 2019 Average: 1 January 2018 to 30 June 2018

USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD Period average 17.2525 0.7732 9.6021 Period average 17.7268 0.7273 9.2981 The exchange rates as at 30 June 2019 and 2018 were: Period end: 30 June 2019 Period end: 30 June 2018

USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD Period average 16.6500 0.7880 9.5718 Period average 17.8962 0.7600 9.5050 6. Cash and cash equivalents


US$’000s 2019 2018 Cash and bank balances 9,123 15,809 Restricted cash(1) 2,072 1,536 Total cash and cash equivalents 11,195 17,345 (1) Cash collateral of US$1.6 million is held at the bank to cover bank guarantees for minimum work commitments on the Company’s Moroccan concessions. These guarantees are subject to forfeiture in certain circumstances if the

Company does not fulfil its minimum work obligations. The remaining balance of US$0.5 million relates to a vendor letter of credit.





7. Inventory During the six months ended 30 June 2019, the inventory balance decreased from US$5.2 million as at 31 December 2018 to US$3.7 million as at 30 June 2019 due to US$2.1 million of inventory consumed in the South Disouq development project, partly offset by further additions of US$0.6 million to be used later in 2019. 8. Property, plant and equipment

Oil and gas Furniture US$’000s properties and fixtures Total Cost: Balance at 31 December 2017 91,575 645 92,220 Additions 14,288 735 15,023 Balance at 31 December 2018 105,863 1,380 107,243 Additions 4,512 60 4,572 Balance at 30 June 2019 110,375 1,440 111,815 Accumulated depletion, depreciation, amortisation and impairment: Balance at 31 December 2017 (37,599) (176) (37,775) Depletion, depreciation and amortisation for the year (16,890) (378) (17,268) Impairment expense (3,520) - (3,520) Balance at 31 December 2018 (58,009) (554) (58,563) Depletion, depreciation and amortisation for the period (11,360) (240) (11,600) Balance at 30 June 2019 (69,369) (794) (70,163) NBV Property, plant and equipment as at 31 December 2018 47,854 826 48,680 NBV Property, plant and equipment as at 30 June 2019 41,006 646 41,652 During the six months ended 30 June 2019, the PP&E additions of US$4.6 million were predominantly related to new customer connections and facilities in Morocco (US$3.1 million) and well workovers in NW Gemsa (US$0.8 million) and Block-H Meseda (US$0.7 million). The difference between the US$4.6 million disclosed above and the US$4.8 million property, plant and equipment expenditure in the Interim Consolidated Statement of Cash Flows is the result of the timing of payment of capital expenditure creditors.


9. Exploration and evaluation assets US$’000s Balance at 31 December 2017 15,231 Additions 29,000 Exploration and evaluation expense (5,103) Balance at 31 December 2018 39,128 Additions 17,246 Balance at 30 June 2019 56,374 During the six months ended 30 June 2019, E&E additions totalled US$17.2 million. South Disouq additions of US$15.8 million were related to the development project (US$14.0 million) and the costs of the 3D seismic acquisition that began in Q4 2018 (US$1.8 million). US$1.2 million of costs relating to the South Ramadan SRM-3 well were incurred during the period. Additions in Morocco relate to US$0.2 million for the 2018/19 3D seismic campaign and other studies. The difference between the US$17.2 million disclosed above and the US$14.5 million exploration and evaluation expenditure in the Interim Consolidated Statement of Cash Flows is because of the timing of payment of capital expenditure creditors. 10. Investments The Company owns a 50% equity interest in Brentford Oil Tools LLC (“Brentford”), an oilfield services business incorporated in Egypt, over which it exercises joint control. Brentford owns all the assets it uses to provide its services and is legally responsible for settling its liabilities. In the current and comparative period, Brentford has provided services only to its shareholders, but it is not contractually obliged to do so. In the past, it has contracted with third parties and continues to seek future opportunities. On the balance of facts, the Company has concluded that Brentford is a joint venture under IFRS 11-“Joint Arrangements” and the Company’s interest is equity accounted for. The investment is reviewed regularly for indicators of impairment and no impairment was identified for the periods ended 30 June 2019 and 31 December 2018. The following table summarises the changes in investments for the periods ended 30 June 2019 and 31 December 2018:


US$’000s 2019 2018 Investments, beginning of period 3,394 2,724 Dividends received (639) (525) Share of operating income 724 1,195 Investments, end of period 3,479 3,394 The following table summarises the Company’s 50% interest in the assets, liabilities, revenue, and operating income of Brentford as at 30 June 2019 and 31 December 2018:

30 June 31 December US$’000s 2019 2018 Total assets 2,022 2,454 Total liabilities 15 9 Revenue 981 1,787 Net income 724 1,195 During the six-month period ended 30 June 2019 and the year ended 31 December 2018, 50% of Brentford’s revenue was earned from fees charged to the Company and 50% (2018: 50%) to the Company’s partner in the Block-H Meseda concession.






11. Trade and other payables Carrying amount 30 June 31 December

US$’000s 2019 2018 Trade payables 2,835 3,870 Accruals 6,869 3,747 Joint venture partners 4,241 5,409 Other payables 2,073 1,392 Total trade and other payables 16,018 14,418 Trade payables comprise billed services and goods. As at 30 June 2019, they consisted predominantly of creditors associated with the Moroccan facilities, royalties payable to the Moroccan government, and G&A creditors. The US$1.1 million decrease in trade payables as at 30 June 2019 is mainly due to payments made for South Disouq 3D seismic and development costs incurred in Q4 2018, offset by additional costs relating to Moroccan facilities and G&A transaction costs. Accruals include amounts for products and services received that have yet to be invoiced. US$2.2 million of the increase period on period reflects the value of work undertaken but not billed as at 30 June 2019 for the South Disouq development project and US$0.8 million for customer connection costs accrued in Morocco. Joint venture partners comprise partner current accounts of US$0.8 million for Block-H Meseda (2018: US$1.3 million) and US$3.4 million for the Morocco concessions (2018: US$3.3 million). The joint venture partner current accounts represent the net of monthly cash calls paid less billings received. Other payables of US$2.1 million comprise VAT payable of US$1.4 million (2018: US$0.7 million), an estimated liability of US$0.3 million related to the relinquishment of the Shukheir Marine concession (2018: US$0.5 million), employee costs accrued, and other sundry creditors. The difference between the increase of US$1.6 million in trade and other payables in the Interim Consolidated Balance Sheets as at 30 June 2019 and 31 December 2018 and the line item in the Interim Consolidated Statement of Cash Flows pertaining to the implied increase in trade and other payables of US$1.5 million relates to the timing differences between the receipt and payment of invoices to operational expenditure creditors. 12. Deferred income Deferred income relates to an advance receipt for gas sales from a customer in Morocco. This payment was used to fund the tie-in of the customer’s manufacturing premises to the Company’s operated gas pipeline. The amount will be credited to the Consolidated Statement of Comprehensive Income under the terms of an agreement with the customer by which the selling price of gas is discounted by 5% until the advance payment is fully recouped, which is expected to be during the first half of the year ended 31 December 2020.



13. Decommissioning liability As at 30 June 2019, the total future undiscounted cash flows relating to Moroccan assets amounted to US$5.2 million, to be incurred between 2019 and 2023, and the liability was discounted using a risk-free rate of 3.0%. Decommissioning expenditure of US$1.1 million is anticipated within the next 12 months. Following the drilling of the exploration and appraisal wells at South Disouq, the Company has a present obligation to decommission these assets under the terms of the concession agreement. The total future undiscounted cash flows amounted to US$0.6 million, to be incurred in 2025, and the liability was discounted using a risk-free rate of 8.0%. The discounted value of the cash flows above amounts to US$5.2 million as at 30 June 2019 and is shown below:


US$’000s 2019 2018 Decommissioning liability, beginning of period 5,167 4,542 Changes in estimate - 575 Payments for decommissioning - (23) Accretion 38 73 Decommissioning liability, end of period 5,205 5,167 Of which: Current 1,125 1,125 Non-current 4,080 4,042 No decommissioning liabilities are recorded for the Company’s other Egyptian assets under the terms of the respective concession agreements. 14. Share capital The share capital of the Group is represented by the share capital of the parent company, SDX Energy Plc. This company was incorporated on 20 March 2019 to act as the holding company of the Group, issuing 500,000 shares of nominal value £0.10. Prior to this, the share capital of the Group was represented by the share capital of the previous parent, SDX Energy Inc. On 4 April 2019, the Company’s 500,000 issued shares of nominal value £0.10 were consolidated into 250,000 ordinary shares at a nominal value of £0.20 per share. On 28 May 2019, the Company issued a further 204,473,041 shares to execute a share-for-share acquisition of the entire share capital of SDX Energy Inc., being in total 204,723,041 shares. There were no changes in rights or proportion of control exercised as a result of this transaction. A merger reserve of US$37.0 million was created as a result of this transaction, representing the difference between the new aggregate share capital of SDX Energy Plc before the capital reduction and the aggregate share capital of SDX Energy Inc. prior to the share-for-share exchange. On 4 June 2019, the High Court of Justice Chancery Division made an order confirming the reduction of share capital of SDX Energy Plc pursuant to section 648 of the Companies Act 2006 by cancelling the paid up capital of the Company to the extent of 19 pence on each ordinary share of £0.20 in the issued share capital of the Company (the “Capital Reduction”). As a result of the Capital Reduction, the nominal value of ordinary shares in the issued share capital of the Company is £0.01 each, with US$49.3 million transferred from share capital to retained earnings. There was no change in the number of the Company’s ordinary shares in issue. The purpose of the Capital Reduction was to restructure the issued share capital and reserves of the Company and to create distributable reserves to facilitate the payment of future dividends, when it becomes commercially prudent to do so. The Company’s retained earnings are not equal to its distributable profits.

30 June 2019 31 December 2018 Number Number of shares Stated value of shares Stated value (’000s) (US$’000s) (’000s) (US$’000s)

Balance, beginning of period 204,723 88,899 204,493 88,785 Issue of common shares (less share issue costs) - - 230 114 Creation of merger reserve - (37,034) - - Reduction of share capital - (49,272) - - Balance, end of period 204,723 2,593 204,723 88,899 Weighted average shares outstanding 204,723 204,565 The share-for-share exchange had no impact on the number of shares in issue.

15. Stock-based compensation The stock-based compensation credit of US$0.3 million recorded in the Interim Consolidated Statement of Comprehensive income represents the IFRS 2 charge. It is offset by a one-off release in 2019, which is associated with both the stock option plan and the Long-Term Incentive Plan described below. Stock option plan The Company has a stock option plan that entitles officers, directors, employees, and certain consultants to purchase shares in the Company. Stock-based compensation expense is the amortisation over the vesting period of the fair value of stock options granted to employees, directors, and key consultants of the Company. The fair value of all options granted is estimated using the Black-Scholes option pricing model. Each tranche of options in an award is considered a separate award with its own vesting period and grant date fair value. Compensation costs are expensed over the vesting period, with a corresponding increase in share based payment reserve. When stock options are exercised, the cash proceeds and the amount previously recorded as contributed surplus are recorded as share capital. During Q2 2019, 106,667 options were cancelled. In the 12 months to 31 December 2018, 400,000 options previously awarded lapsed, 106,667 options were cancelled, and 230,001 options were exercised. On 28 May 2019, as part of the share-for-share exchange transaction between SDX Energy Inc. and SDX Energy Plc, each outstanding SDX Energy Inc. share option that was not duly exercised at that date was “rolled over” and following completion of the transaction entitled the holder to acquire the same number of SDX Energy Plc shares. The exercise price of each option was converted at the GBP/CAD rate prevailing on the date of the transaction. The number and weighted average exercise price of stock options for the Company’s stock option plan is as follows:

Number Weighted average of options exercise price (’000s) (GBP£)

Outstanding 1 January 2018 2,852 0.38 Lapsed during the year (400) 0.37 Cancelled during the year (107) 0.45 Exercised during the year (230) 0.39 Outstanding 31 December 2018 2,115 0.38 Exercisable 31 December 2018 1,795 0.37 Outstanding 1 January 2019 2,115 0.38 Cancelled during the period (107) 0.45 Outstanding 30 June 2019 2,008 0.38 Exercisable 30 June 2019 1,795 0.37 The exercise price of the outstanding options under the stock option plan as at 30 June 2019 is as follows:

Outstanding options Vested options Number of Number of

Exercise price range options Contractual life options Contractual life GBP £0.21-£0.45 2,008,334 3-5 years 1,795,000 3-5 years Long-Term Incentive Plan (“LTIP”) On 31 July 2017 the Company established a new Long-Term Incentive Plan and issued awards to its Executive Directors and certain other key employees. The Company recognises the need to ensure that Executive Directors and key employees from its operational, commercial, technical, and financial divisions, who are critical to executing the Company’s strategy over the next phase of its development, are retained and incentivised to generate long-term value for shareholders. The LTIP Awards and CSOP Options granted under the Plan take the form of a base award over a number of common shares. These awards will normally vest on the third anniversary of the date of grant of the awards, subject to meeting certain strategic, operational, financial, and shareholder return performance criteria and the continued employment of the participant. The awards for the Executive Directors are subject to a further two-year holding period from the date of vesting. There are clawback provisions contained in the rules of the Plan that can be applied to awards made to all participants. The number of common shares granted to Executive Directors, over which the LTIP Awards and CSOP Options may vest, can be increased by a multiple of up to one times, depending on the level of share price growth over the three-year period from the date of grant. The potential level of increased share awards is calculated as follows: • If the share price growth in the three-year period is less than 11% pa, there will be no increase in the base award number of shares set out above; and • If the share price growth in the three-year period is between 11% pa and 20% pa, the additional number of shares that vest will increase proportionately

within this range up to a cap of a multiple of one times the base award number of shares. This cap will be triggered at share price growth of 20% pa or more.






15. Stock-based compensation (continued) Long-Term Incentive Plan (“LTIP”) (continued) The maximum number of shares that can vest for the CFO is 2,234,707. The awards made to the former CEO were cancelled on his departure in Q2 2019, with the previously recognised expense credited to the Interim Consolidated Statement of Comprehensive Income. Based on grants to 22 August 2019, the maximum potential number of common shares that can vest to the executive directors and other selected employees under the LTIP was, in aggregate, 3,837,099. All these options are outstanding as at 30 June 2019 and 22 August 2019 but none have vested. The number of ordinary shares that may be issued or reserved for issuance under the awards granted pursuant to the LTIP, together with all common shares that may be issued under options granted pursuant to the Company’s stock option plan, may not exceed 10% of the Company’s issued and outstanding common shares at the time of grant. 16. Revenue, net of royalties

Three months ended 30 June Six months ended 30 June US$’000s 2019 2018 2019 2018 NW Gemsa oil sales revenue 7,838 10,366 16,150 18,885 Royalties (3,364) (4,449) (6,932) (8,105) Net oil revenue 4,474 5,917 9,218 10,780 Block-H Meseda production service fee revenues 3,989 3,495 7,525 6,008 Morocco gas sales revenue 4,105 3,767 8,318 7,364 Royalties (170) - (356) - Net Morocco gas sales revenue 3,935 3,767 7,962 7,364 Net other products revenue 334 293 708 280 Total net revenue before tax 12,732 13,472 25,413 24,432 The oil sales revenue and royalties and net other products revenue relate to the NW Gemsa concession, which is governed by an Egyptian PSC. The royalties are those attributable to the government, taken in accordance with the fiscal terms of the PSC. The production service fees relate to Block-H Meseda, which is governed by an Egyptian PSA. The Moroccan gas sales revenue is derived from a Petroleum Agreement with the Moroccan state. Sales-based royalties become payable when certain inception-to-date production thresholds are reached, according to the terms of each exploitation concession. During Q3 2018, natural gas production from the Ksiri exploitation concession exceeded such a threshold, resulting in the recognition of royalties amounting to 5% of revenue from this concession from that point forward. Royalty payments are made directly to the Government of Morocco biannually. 17. Direct operating expense

Three months ended 30 June Six months ended 30 June US$’000s 2019 2018 2019 2018 NW Gemsa 2,150 1,953 3,949 2,842 Block-H Meseda 901 929 2,011 1,738 Morocco-Sebou 538 286 1,003 582 Total direct operating expense 3,589 3,168 6,963 5,162




18. General and administrative expenses Three months ended 30 June Six months ended 30 June

US$’000s 2019 2018 2019 2018 Wages and employee costs 2,419 1,914 4,321 3,797 Consultants-inc. PR/IR 160 164 335 292 Legal fees 119 59 271 153 Audit, tax and accounting services 236 339 340 471 Public company fees 148 169 306 364 Travel 86 64 97 147 Office expenses 88 295 206 573 IT expenses 154 67 283 223 Service recharges (1,327) (1,551) (2,866) (3,255) Ongoing general and administrative expenses 2,083 1,520 3,293 2,765 Transaction costs 766 - 1,104 - Total net G&A 2,849 1,520 4,397 2,765 19. Income tax

Three months ended 30 June Six months ended 30 June US$’000s 2019 2018 2019 2018 NW Gemsa 921 1,192 1,901 2,167 Block-H Meseda 325 547 758 886 Morocco-Sebou - - - - Other - - - 14 Total current taxes 1,246 1,739 2,659 3,067 Pursuant to the terms of the Company’s PSCs, the corporate tax liability of the joint venture partners is paid by the government-controlled corporations (“Corporations”) that participate in these PSCs. The tax is paid out of the profit oil attributable to the Corporations, and not by the Company. For accounting purposes, however, the corporate taxes the Corporations pay are treated as a benefit that the Company earns, with the amount being “grossed up” and included in net oil revenues. The income tax expense of the Company is recorded in the financial statements. The Company also has a PSA related to Block-H Meseda, with legal title residing with SDX Energy Egypt (Meseda) Limited (“SDX Meseda”), an Egyptian incorporated entity. The Company is governed by the laws and tax regulations of the Arab Republic of Egypt and pays corporate taxes on the adjusted profit of SDX Meseda. The current income tax expense in the Interim Consolidated Statement of Comprehensive Income for the three and six months ended 30 June 2019 relates to income tax on North West Gemsa’s PSC and income tax relating to the Company’s PSA in Block-H Meseda, as described above. The current income tax liability of US$0.9 million in the Interim Consolidated Balance Sheet relates to the Company’s PSA in Block-H Meseda and equates to corporate income tax for the six months ended 30 June 2019, less payments made on account. The Company’s Moroccan operations benefit from a 10-year corporation tax holiday from first production and no taxation is due on Moroccan profits as at 30 June 2019. 20. Income per share

Three months ended 30 June Six months ended 30 June US$’000s 2019 2018 2019 2018 Net (loss)/income before comprehensive income for the period (489) 640 (354) 971 Weighted average amount of shares - Basic 204,723 204,493 204,723 204,493 - Diluted 204,723 208,263 204,723 208,099 Per share amount - Basic $(0.002) $0.003 $(0.002) $0.005 - Diluted $(0.002) $0.003 $(0.002) $0.005 Basic income/(loss) per share is calculated by dividing the income attributable to shareholders of the Company by the weighted average number of ordinary shares in issue during the period. Diluted per share information is calculated by adjusting the weighted average number of ordinary shares outstanding to assume conversion of all dilutive potential ordinary shares. The Company computes the dilutive impact of common shares by assuming that the proceeds received from the pro forma exercise of in-the-money stock options or warrants are used to purchase common shares at average market prices.



21. Segmental reporting The Company’s operations are managed on a geographic basis, by country. The Company is engaged in one business of upstream oil and gas exploration and production. The Executive Directors are the Company’s chief operating decision maker within the meaning of IFRS 8.

Three months ended 30 June 2019 Three months ended 30 June 2018

US$’000s Egypt Morocco Unallocated(1) Total Egypt Morocco Unallocated(1) Total Revenue 8,797 3,935 - 12,732 9,705 3,767 - 13,472 Direct operating expense (3,051) (538) - (3,589) (2,882) (286) - (3,168) Netback (pre tax) 5,746 3,397 - 9,143 6,823 3,481 - 10,304 General and administrative expenses (135) (630) (2,084) (2,849) (19) (597) (904) (1,520) Share-based compensation - - 658 658 - - (324) (324) Share of profit from joint venture 355 - - 355 292 - - 292 Release of historic operational tax provision - - - - - 300 - 300 Inventory write-off - - - - - (490) - (490) Gain on sale of office asset - - - - 23 - - 23 EBITDAX 5,966 2,767 (1,426) 7,307 7,119 2,694 (1,228) 8,585 Exploration and evaluation expense - - (380) (380) (1,607) (342) (115) (2,064) Depletion, depreciation and amortisation (2,513) (3,330) (204) (6,047) (2,087) (1,424) (146) (3,657) Operating income/(loss) 3,453 (563) (2,010) 880 3,425 928 (1,489) 2,864 (1) Unallocated expenditure, assets and liabilities include amounts of a corporate nature and not specifically attributable to a geographical segment.

Six months ended 30 June 2019 Six months ended 30 June 2018

US$’000s Egypt Morocco Unallocated(1) Total Egypt Morocco Unallocated(1) Total Revenue 17,451 7,962 - 25,413 17,068 7,364 - 24,432 Direct operating expense (5,960) (1,003) - (6,963) (4,580) (582) - (5,162) Netback (pre tax) 11,491 6,959 - 18,450 12,488 6,782 - 19,270 General and administrative expenses (81) (1,320) (2,996) (4,397) (143) (590) (2,032) (2,765) Share-based compensation - - 339 339 - - (656) (656) Share of profit from joint venture 724 - - 724 526 - - 526 Release of historic operational tax provision - - - - - 300 - 300 Inventory write-off - - - - - (490) - (490) Gain on sale of office asset - - - - 23 - - 23 EBITDAX 12,134 5,639 (2,657) 15,116 12,894 6,002 (2,688) 16,208 Exploration and evaluation expense - - (615) (615) (1,607) (3,426) (281) (5,314) Depletion, depreciation and amortisation (5,321) (6,217) (407) (11,945) (3,207) (2,787) (196) (6,190) Operating income/(loss) 6,813 (578) (3,679) 2,556 8,080 (211) (3,165) 4,704 (1) Unallocated expenditure, assets and liabilities include amounts of a corporate nature and not specifically attributable to a geographical segment.

The segment assets and liabilities as at 30 June 2019 and 31 December 2018 are as follows:

30 June 2019 31 December 2018

US$’000s Egypt Morocco Unallocated(1) Total Egypt Morocco Unallocated(1) Total Segment assets 79,291 50,405 10,426 140,122 74,442 48,399 15,266 138,107 Segment liabilities (7,227) (12,792) (4,757) (24,776) (7,229) (11,227) (3,612) (22,068) (1) Unallocated expenditure, assets and liabilities include amounts of a corporate nature and not specifically attributable to a geographical segment.




22. Commitments and contingencies Pursuant to the concession and production service fee agreements in Egypt and Morocco, the Company is required to perform certain minimum exploration and development activities that include the drilling of exploration and development wells. These obligations have not been provided for in the Interim Consolidated Financial Statements. In Morocco, the commitments are for one exploration well in Gharb Centre, one exploration well in Lalla Mimouna Sud, and one exploration well, the acquisition of 100km2 of 3D seismic data, and the re-processing of 150km of 2D seismic data in Moulay Bouchta Ouest. The estimated cost of these commitments is US$11.1 million. In Egypt, there were no remaining commitments as at 30 June 2019. The Group operates in several countries and, accordingly, it is subject to the various tax and legal regimes in the countries in which it operates. From time to time the Group is subject to a review of its related tax filings and in connection with such reviews, disputes can arise with the taxing authorities over the interpretation or application of certain rules to the Group’s business conducted within the country involved. If the Group is unable to resolve any of these matters favourably, there may be an adverse impact on the Group’s financial performance, cash flows or results of operations. This may also be the case for any legal claims that the Group is required to defend. In the event that management’s estimate of the future resolution of these matters changes, the Group will recognise the effects of the changes in its consolidated financial statements in the period that such changes occur. There are no contingencies as at 30 June 2019. 23. Leases Note 3 explains the changes and new accounting policy introduced on 1 January 2019, resulting from the adoption of the new accounting standards IFRS 16 Leases. The Group has entered into various fixed-term leases, mainly for properties and vehicles. a) Amounts recognised in the balance sheet

The lease liability recorded on 1 January 2019 was US$2.1 million and the right-of-use assets were US$2.2 million. The right-of-use assets at 1 January 2019 by underlying class of asset comprise the following: US$’000s 1 January 2019 Properties 1,971 Motor vehicles 186 Others 45 Total right-of-use assets(1) 2,202 (1) Right-of-use assets were higher than the lease liability at the date of implementation of IFRS 16 by US$0.1 million due to adjustments made for prepayments and accrued lease payments recognised at 31 December 2018.

The lease liability at 30 June 2019 and 1 January 2019 is as follows: US$’000s 30 June 2019 1 January 2019 Current 524 587 Non-current 1,310 1,523 Total lease liabilities 1,834 2,110 Previous disclosures of operating lease commitments were limited to the non-cancellable operating lease of the office premises in London. Reconciliation of lease commitment disclosed on 31 December 2018, and lease liability recorded on 1 January 2019 is as follows: US$’000s 1 January 2019 Disclosed undiscounted future minimum lease payments under operating leases at 31 December 2018 355 Impact of discounting (81) Liabilities additionally recognised based on the initial application of IFRS 16 as of 1 January 2019 1,836 Total lease liability 2,110 There was no net impact on retained earnings upon implementation of IFRS 16 on 1 January 2019.



23. Leases (continued) a) Amounts recognised in the balance sheet (continued) The maturity analysis of the lease liability at 30 June 2019 is as follows: US$’000s 30 June 2019 Less than one year 524 Between one and two years 401 Between two and three years 268 Between three and four years 195 Between four and five years 186 After five years 260 Total lease liability 1,834 b) Amounts recognised in the statement of profit or loss The right-of-use assets at 30 June 2019 amounted to US$1.9 million and the depreciation charge amounted to US$0.3 million and is shown below by underlying class of asset:

30 June 2019 Depreciation US$’000s Carrying value charge H1 2019 Properties 1,712 282 Motor vehicles 175 48 Others 30 15 Total 1,917 345 The lease liability at 30 June 2019 was US$1.8 million. The corresponding interest expense for the six months ended 30 June 2019 amounts to US$0.1 million. The portion of the lease payments recognised as a reduction of the lease liabilities and as a cash outflow from financing activities for the six months ended 30 June 2019 amounted to US$0.4 million. The Company accounts for the expense of short-term leases of 12 months or less and underlying assets of low-value leases on a straight-line basis over the lease term. The expense for the six months ended 30 June 2019 related to these leases amounted to US$0.1 million and US$0.01 million, respectively. 24. Post balance sheet event On 1 July 2019, the Company was awarded a 25-year development lease covering the Ibn Yunus development area, which together with the 25-year South Disouq development lease granted on 2 January 2019 comprises the South Disouq development project. Gas sales agreements have been signed for both development leases, confirming pricing of US$2.85/Mcf.

Corporate information

Executive Officers Mark Reid Interim Chief Executive Officer & Chief Financial Officer Independent Directors Michael Doyle Non-Executive Chairman Timothy Linacre David Mitchell

Stock Exchange Listing London Stock Exchange AIM Symbol: SDX Registrar (United Kingdom) Link Asset Services The Registry, 34 Beckenham Road Beckenham, Kent BR3 4TU United Kingdom T: +44 (0)871 664 0300 Nominated Advisor and Joint Broker Stifel Nicolaus Europe Limited Callum Stewart/Nicholas Rhodes/ Ashton Clanfield 150 Cheapside, London, EC2V 6ET, United Kingdom Tel: +44 (0) 20 7710 7600 Joint Brokers GMP FirstEnergy Jonathan Wright 85 London Wall, London, EC2M 7AD United Kingdom T: +44 (0)20 7448 0200 Cantor Fitzgerald Europe David Porter One Churchill Place, Canary Wharf London, E14 5RB, United Kingdom T: +44 (0)20 7894 7000

Independent Engineers ERC Equipoise 6th Floor Stephenson House 2 Cherry Orchard Road Croydon, CR0 6BA Auditors PricewaterhouseCoopers LLP 431 Union Street, Aberdeen, AB11 6DA United Kingdom Public Relations Celicourt Communications Mark Antelme/Jimmy Lea 7-10 Adam House, The Strand London, WC2N 6AA, United Kingdom Telephone: +44 (0)20 7520 9261 SDX Energy Office Locations United Kingdom 38 Welbeck Street, London W1G 8DP United Kingdom T: +44 (0)20 3219 5640 F: +44 (0)20 3219 5655 Egypt Road 261, No. 10, New Maadi, Cairo, Egypt T: +20 2 2517 6528 F: +20 2 2517 6524 Morocco Forum 6, Rue Ibrahim Tadili Bureau n 7-1er Etage Souissi-Rabat, Kingdom of Morocco T: +212 537 635 656 F: +212 537 656 314

High Margin Growth www.sdxenergy.com

laying the foundations for production growth

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