H1 2021 FINANCIAL AND OPERATING RESULTS

RNS Number : 2418J

SDX Energy PLC

20 August 2021

 

THE INFORMATION CONTAINED WITHIN THIS ANNOUNCEMENT IS DEEMED BY SDX TO CONSTITUTE INSIDE INFORMATION AS STIPULATED UNDER THE MARKET ABUSE REGULATION (EU) NO. 596/2014 AS IT FORMS PART OF UK LAW BY VIRTUE OF THE EUROPEAN UNION (WITHDRAWAL) ACT 2018 ("MAR"). ON THE PUBLICATION OF THIS ANNOUNCEMENT VIA A REGULATORY INFORMATION SERVICE ("RIS"), THIS INSIDE INFORMATION IS NOW CONSIDERED TO BE IN THE PUBLIC DOMAIN.

20 August 2021

SDX ENERGY PLC ("SDX", the "Company" or the "Group")

ANNOUNCES ITS FINANCIAL AND OPERATING RESULTS FOR THE THREE AND SIX MONTHS ENDED 30 JUNE 2021

SDX Energy Plc (AIM: SDX), the MENA-focused oil and gas company, is pleased to announce its unaudited financial and operating results for the three and six months ended 30 June 2021. All monetary values are expressed in United States dollars net to the Company unless otherwise stated.

Mark Reid, CEO of SDX, commented:

"I am very pleased to report first half 2021 results that show strong growth in revenue, netback, EBITDAX and operating cash flows versus the same period in 2020, as well as ending the period with a strong liquidity position. The producing assets in Egypt and Morocco are performing well and we remain above our mid-point guidance for the year. Our drilling activities have yielded three successful wells in Morocco, all of which are now onstream and contributing to cash flow, and one at South Disouq, which is due to start up shortly. As previously announced, whilst the result of the Hanut-1X well is disappointing, I remain positive about the remaining prospectivity in the area which has not been materially impacted."

Three and six months to 30 June 2021 Operations Highlights

· H1 2021 entitlement production of 5,931 boe/d was 3% higher than 2021 mid point market guidance of 5,770 boe/d and 4% lower than H1 2020 mainly due to natural decline, well workovers and expected sand and water production in two of the five wells at South Disouq.

· Capex guidance for Morocco for the 12 months ended 31 December 2021 has been increased by US$1.5 million as wells planned for the second phase of 2021 drilling are deeper than those included in the original guidance. Capex of US$15.8 million was within guidance for South Disouq and West Gharib. This results in group 2021 capex guidance being revised to US$26.5 - 28.0 million (previous guidance US$25.0 - 26.5 million).

· The Company's operated assets recorded a carbon intensity of 2.7kg CO₂e/boe in H1 2021 which is one of the lowest rates in the industry. Scope 1 greenhouse gas emissions at operated assets were 4,405 tons of CO₂e. Scope 3 greenhouse gas emissions in Morocco were 75,500 tons of CO₂e, which is approximately 38,500 tons of CO₂e less than using alternative heavy fuel oil.

· In South Disouq, the IY-2X step-out development well, the first of a two-well campaign, was spud in late June 2021. The well was drilled to a measured depth of 8,025 feet, encountering 40.5 feet net-pay of high-quality gas-bearing sands, with an average porosity of 23.4%, near the base of the Kafr El Sheikh ("KES") formation. The top of the KES sand was encountered at a measured depth of 6,768 feet. Following well te sting, the well is expected to be brought on production during the last week in August with a view to maximising recovery from the Ibn Yunus Field and helping to maintain current gross production levels of c.45MMscfe/d at the South Disouq Central Processing Facility (the "CPF").  

· Post-period end, the second well, the Hanut-1X ("HA-1X") exploration well, spudded on 4 August and reached the target depth of 6,000ft on 17 August.  The primary target for HA-1X was the Basal Kafr El Sheikh sand at approximately 5,200ft. The well however found that the Basal Kafr El Sheikh sand had been eroded at this location.  Whilst drilling to target depth, good quality sands were found at the Qawasim level, however they were not charged with gas. SDX considers the result of the HA-1X well to have limited impact on the remaining c.90-100bcf of prospectivity in the SDX acreage at South Disouq.

· Following the IY-2X and HA-1X well results, during H2 2021 the Company will evaluate the current and future prospectivity of the South Disouq concession to assess whether there is evidence that the carrying value of the asset should be impaired.

· In West Gharib, following the ten-year concession extension granted earlier in 2021, preparations continued for a campaign of three to four development wells, the first of which is expected to spud in early Q4.

· The first phase of the Morocco drilling campaign, which consisted of three appraisal/development wells in SDX's operated Gharb Basin acreage in Morocco (SDX: 75% working interest), was successfully completed in June 2021.

· The OYF-3, KSR-17 and KSR-18 wells were all commercial successes, with OYF-3 and KSR-17 already connected as at 30 June 2021 and producing into the Company's infrastructure. KSR-18 has been tested and was connected at the end of July 2021. Management estimates that 1.5-1.6bcf of gross resources have been added by these wells, which is in line with pre-drill P50 estimates. Preparations are underway for the drilling of up to two additional wells in Morocco later in the year.

· As previously announced, during the first half of the year, the Company received the COVID-19 delayed laboratory analysis of the cuttings and sidewall cores from the LMS-2 well. This information confirmed that LMS-2 had successfully encountered the targeted thermogenic gas source that exists in the Top Nappe horizon but that the reservoir in the Lalla Mimouna Nord concession has low permeability and the well is unlikely to flow conventionally. As such, the Company will not risk US$0.5 million testing this well, nor will it commit to further investment in the Lalla Mimouna Nord concession post the end of the concession date in July 2021 as a result of the limited likelihood of it being commercially developed. Accordingly, the Company has recognised a US$10.3 million non-cash impairment charge in Q2 ahead of relinquishment of the concession, of which US$2.8 million relates to LMS-2.

Six months to 30 June 2021 Financial Highlights

The table below reflects the unaudited results of the Company for the three and six months ended 30 June 2021 and 2020. The North West Gemsa and South Ramadan concessions, which were sold in Q3 and Q4 2020 respectively, are classified as discontinued operations (as required by IFRS). All revenues, costs and taxation from these assets have been consolidated into a single line item "(loss)/profit from discontinued operations" in both periods reported. Per unit metrics do not include North West Gemsa or South Ramadan.

	Three months ended 30 June		Six months ended 30 June
US$ million, except per unit amounts	2021	2020	2021	2020
Net revenues	13.7	9.2	27.1	21.9
Netback(1)	11.4	7.3	22.1	17.6
Net realised average oil service fees - US$/barrel	54.61	20.94	51.10	30.18
Net realised average Morocco gas price - US$/Mcf	11.49	10.40	11.40	10.35
Net realised South Disouq gas price - US$/Mcf (2)	2.83	2.85	2.85	2.85
Netback - US$/boe	20.81	13.79	20.61	15.65
EBITDAX(1)(3)	10.1	6.3	19.9	15.7
Exploration & evaluation expense ("E&E") (4)	(10.6)	(0.3)	(10.9)	(5.1)
Depletion, depreciation, and amortisation ("DD&A")	(7.5)	(5.2)	(14.9)	(12.0)
Total comprehensive loss	(10.7)	(0.8)	(10.1)	(4.0)
(Loss)/Profit from discontinued operations	-	(0.4)	-	0.7
Capital expenditure	11.9	3.8	15.8	19.4
Net cash generated from operating activities(5)	8.8	5.5	14.9	10.4
Cash and cash equivalents	9.1	9.3	9.1	9.3

⁽¹⁾  Refer to the "Non-IFRS Measures" section of this release below for details of Netback and EBITDAX.

⁽²⁾  South Disouq gas is sold to the Egyptian State at a fixed price of US$2.65 MMbtu, which equates to approximately US$2.85/Mcf. During the three months ended 30 June 2021, a small quantity of off-specification gas was produced, which reduced the realised price for this period to US$2.83/Mcf.

⁽³⁾  EBITDAX for six months ended 30 June 2021 and 2020 includes US$2.6 million and US$2.7 million respectively of non-cash revenue relating to the grossing up of Egyptian corporate tax on the South Disouq PSC which is paid by the Egyptian State on behalf of the Company (respectively US$1.4 million and US$1.3 million for the three months ended 30 June 2021 and 2020).

⁽⁴⁾  For the six months ended 30 June 2021, US$10.3 million of non-cash Exploration & Evaluation ("E&E") impairment is included within this line item (US$4.5 million for the six months ended 30 June 2020).

⁽⁵⁾  Excludes discontinued operations.

· Netback of US$22.1 million, 26% higher than the same period in 2020 of US$17.6 million, was primarily driven by strong demand in Morocco, which during H1 2020 was impacted by temporary COVID-19 shutdowns at three customers. West Gharib netback increased due to higher service fee realisations, which outweighed the impact of lower production due to natural decline. These factors were partly offset by a lower netback at South Disouq as a result of lower production due to natural decline and well management activity, including workovers.

· EBITDAX of US$19.9 million was 27% higher than the same period in 2020 of US$15.7 million due to the netback factors described above.

· Depletion, depreciation and amortisation ("DD&A") charge of US$14.9 million was higher than the US$12.0 million for the same period in 2020 due to higher production and lower 2P reserves in Morocco, partly offset by lower production at West Gharib.

· The Company recognised a US$10.3 million non-cash E&E impairment in H1 2021 following the decision to not commit to further investment in the Lalla Mimouna Nord concession in Morocco post the end of the concession date in July 2021. In H1 2020 US$4.5 million was written off following the drilling of two sub-commercial wells, SD-6X in South Disouq and SAH-5 in Morocco.

· Operating cash flow (before capex, excluding discontinued operations) of US$14.9 million, was 43% higher than the same period in 2020, US$10.4 million, primarily due to the netback drivers discussed above. 

· Capex of US$15.8 million, reflects:

o  US$8.9 million (incl. US$0.5 million decommissioning provisions) on three wells in Morocco;

o  US$2.0 million for well workovers in Morocco;

o  US$3.7 million for the completion of the SD-12X tie in at South Disouq, well drilling preparations for IY-2X and HA-1X, the SD-4X well workover, and other capex projects at South Disouq;

o  US$1.2 million for workovers and development drilling preparations in West Gharib;

· Liquidity: Closing cash as at 30 June 2021 was US$9.1 million. The Company has satisfied the conditions precedent on the five-year EBRD credit facility, which remains undrawn and has US$10.0 million availability.

· Together with cash generated from operations, the Company is fully funded for all planned activities in 2021 - 2022.

COVID-19 update

· The Company has had no COVID-19 business interruptions since Q2 2020 when three customers in Morocco resumed taking gas following a short period of mandatory shutdown. Egyptian production has remained unaffected by COVID-19. The Company continues to follow applicable government guidance in each of its territories.

H1 2021 Performance vs 2021 Guidance

Production

· H1 2021 entitlement production of 5,931 boe/d is 3% higher than midpoint guidance of 5,770 boe/d and 4% lower than H1 2020. An analysis of H1 2021 production by asset vs guidance is as follows:

Gross production			SDX entitlement production (boe/d)
Asset	Guidance - 12 months ended 31 December 2021	Actual - 6 months ended 30 June 2021	Guidance - 12 months ended 31 December 2021	Actual - 6 months ended 30 June 2021	Actual - 6 months ended 30 June 2020
Core assets
South Disouq - WI 55% & 100%	44 - 46 MMscfe/d	45.2 MMscfe/d	4,300 - 4,500	4,422	4,825
West Gharib - WI 50%	2,350 - 2,650 bbl/d	2,707 bbl/d	446 - 505	516	647
Morocco - WI 75%	7.0 - 7.3 MMscf/d	7.9 MMscf/d	874 - 915	993	707
Total			5,620 - 5,920	5,931	6,179
Discontinued operations
NW Gemsa - WI 50%	N/A	N/A	N/A	N/A	769
South Ramadan - WI 12.75%	N/A	N/A	N/A	N/A	32
Total (incl. disc. ops.)			5,620 - 5,920	5,931	6,980

o  South Disouq : During the first half of 2021, the existing wells continued to exhibit natural decline and expected sand and water production from two of the five wells, albeit this was partly offset by contribution from the SD-12X well which was brought online in December 2020. The SD-1X and SD-4X wells were successfully worked over during the period and were put back on production at improved gas production rates and with reduced sand and water production. Production for the six months was above midpoint guidance, with production for the remainder of the year expected to remain close to this as the impact of the planned 2-3% Central Processing Facility ("CPF") downtime in H2 should broadly be offset by contribution from the IY-2X well which is expected to be tied in during the last week in August.

o  West Gharib:   The existing wellstock at the asset continued to produce steadily, albeit exhibiting natural decline as expected. Preparations are advanced for a development drilling campaign of four wells plus one water injector well which will commence in Q4 and allow the Company to benefit from low-risk production growth into a higher commodity price environment. Production will trend towards midpoint guidance until such time as the new wells are drilled and brought online.

o  Morocco:   H1 2021 saw stronger demand from all customers and this is the reason that the Company is currently exceeding guidance.  In addition, H1 2021 reflects additional consumption from an existing customer's second factory which came online in December 2020. Production guidance is 8-12% higher than 2020 production and reflects a sustained return to normal levels of consumption across the customer base, following COVID shutdowns which impacted 2020 production. 

o  COVID-19: The 2021 production guidance presented assumes no significant production curtailments due to COVID-19. Should there be COVID-19 related disruptions, then production guidance may be revised.

Capex

· Capex for the six months to 30 June 2021 is shown below and is compared to the revised guidance figure of US$26.5-28.0 million (previous guidance US$25.0-26.5 million) which predominantly relates to one exploration and one development well in South Disouq together with workovers and the installation of an inlet compressor. Five new wells and workovers are planned in Morocco and four new wells and facilities upgrades will be undertaken at West Gharib. 

Asset	Guidance - 12 months ended 31 December 2021	Actual - 6 months ended 30 June 2021
South Disouq - WI 55% & 100%	US$7.0 - 7.5 million	US$3.7 million (1)
West Gharib - WI 50%	US$2.5 - 3.0 million	US$1.2 million
Morocco - WI 75%	US$17.0 - 17.5 million	US$10.9 million (2)
Total	US$26.5 - 28.0 million	US$15.8 million

⁽¹⁾  Includes US$0.6 million of expenditure that was pre-paid as a project milestone in 2020 but has now been reclassified to capex

⁽²⁾  Includes US$0.5 million of non-cash decommissioning provisions

o  South Disouq : The development well, Ibn Yunus-2X, spud in late June 2021 and reached TD in July 2021 encountering 40.5 ft of net gas sand pay. During the last week in August, the Company expects that the IY-2X well will be tied in via a short flowline to the Ibn Yunus-1X location where an existing flowline connects to the South Disouq CPF. The gross cost of the tie-in was c.US$0.55 million. The Hanut-1X exploration well, which was completed during Q3 2021, did not encounter gas-bearing sands and will be plugged and abandoned. An inlet compressor will be installed at the CPF site to maximise recovery from the fields, and several well workovers are also planned. In H1 2021, US$3.7 million of capex was invested for the compressor project (US$1.5 million), the IY-2X development well (US$0.6 million), the completion of the SD-12X tie in (US$0.4 million), planning for the HA-1X exploration well (US$0.2 million), the workovers of SD-4X and SD-1X (US$0.2 million) and other CPF projects. 

o  West Gharib: Four infill development wells and one water injection well will be drilled, and additional facilities to support this project will be installed. In H1 2021, US$1.2 million of capex was spent on a number of well workovers and development drilling preparations.

o  Morocco: Capex guidance for Morocco for the 12 months ended 31 December 2021 has been increased by US$1.5 million as the wells planned for the second phase of the 2021 campaign in H2 are deeper than those included in the original guidance. In H1 2021, US$10.9 million of capex was spent on three development wells (US$8.9 million which includes US$0.5 million of decommissioning provisions) and a well workover campaign (US$2.0 million). A further two development wells will be drilled in the next campaign in Q3/Q4 2021.

· The actual and anticipated timings of planned key capex activities are outlined below:

Asset	Activity	2021 Timing
South Disouq	SD-4X workover	Q1(1)
	SD-1X workover	Q2(1)
	Compressor fabrication & installation	Q2-Q3(2)
	Ibn Yunus-2X development well (incl. tie in)	Q2-Q3
	Hanut-1X exploration well	Q3(2)
	SD-3X workover	Q4
Morocco	Well workovers	Q1 (1) & Q4
	Drilling campaign- first three wells	Q2 (1)
	Drilling campaign- remaining two wells	Q3-Q4
West Gharib	Four development wells	Q3-Q4
	Water injection well and facilities upgrades	Q3-Q4

(1)  Activity completed

(2)  Completed post period end

2021 Drilling and Operations Update

Morocco drilling campaign update (SDX 75% working interest)

· The first phase of the Morocco drilling campaign consisted of three appraisal/development wells in SDX's operated Gharb Basin acreage in Morocco (SDX: 75% working interest).

· The first well, OYF-3, which spud on 30 April 2021, reached its TD at 1,183 metres MD on 11 May 2021. The main Guebbas reservoir target was thicker than expected and encountered a 5.2 metre net gas sand. The well also encountered a 1.7 metre net gas sand in a secondary zone that OYF-3 will also produce from.

· The second well, KSR-17, was spud on 13 May 2021 and reached its TD at 1,848 metres MD on 27 May 2021. In the main Hoot reservoir, the well encountered a 5.3 metre net gas sand which was slightly thinner than expected, but with very good reservoir properties.

· Both OYF-3 and KSR-17 have been tested, connected, and producing into our infrastructure before the end of the reporting period. Post-drill P50 reserves are estimated at a combined gross 0.81bcf recoverable which is in line with predrill estimates.

· Finally, the third well of the campaign, KSR-18, was spud on 30 May 2021 and reached its TD of 1,905 metres MD on 14 June 2021. Both prognosed targets were successfully encountered, with the shallower Mid Guebbas target comprising a 3.8 metre net gas sand and the main Hoot target encountering a 13.9 metre net gas sand. As expected, the main Hoot had been slightly depleted by production from a nearby well, however the well is still expected to contribute incremental volumes and deliverability from this extensive compartment. Further to these zones, a third 5.5 metre net gas sand was encountered at the Base Guebbas and will contribute to production in the future when the Hoot has been depleted.  Subsequent to the reporting period, KSR-18 has been tested and put on production.

· The second phase of the Moroccan drilling campaign is expected to commence in September/October 2021.

· The above developments will allow the Company to continue to supply gas to our customers in line with our contractual commitments and continue to support lower CO₂ emissions at our customers.

South Disouq Egypt exploration drilling campaign update (SDX 55%/100% working interest)

· Following the success of SD-12X and further review of the 3D seismic, management has now identified c.233bcf of mean unrisked recoverable volumes, which are close to our existing infrastructure, located in horizons that are either productive in South Disouq or in adjacent blocks and which have now been high-graded to drill-ready prospects.

· The Company received final Ministerial and Parliamentary approval of the two-year extension to the South Disouq exploration area. The campaign kicked off with the drilling of the IY-2X development well in the Ibn Yunus field to accelerate production and cash flows. The well will be tied in during the last week in August and the Company's expectations are that the IY-2X well can maximise recovery from the Ibn Yunus Field and help maintain current gross production levels of c.45MMscfe/d at the South Disouq Central Processing Facility. The IY-2X well was tied in via a short flowline to the Ibn Yunus-1X location where an existing flowline connects to the South Disouq Central Processing Facility. The gross cost of this tie-in was US$0.55 million. 

· Post-period end, the second well, the HA-1X exploration well, spudded on 4 August and reached the target depth of 6,000ft on 17 August.  The primary target for HA-1X was the Basal Kafr El Sheikh sand at approximately 5,200ft. The well however found that the Basal Kafr El Sheikh sand had been eroded at this location.  Whilst drilling to target depth, good quality sands were found at the Qawasim level, however they were not charged with gas. SDX considers the result of the HA-1X well to have limited impact on the remaining c.90-100bcf of prospectivity in the SDX acreage at South Disouq.

· Management's estimate of the mean prospective resources and chance of success of the prospects identified in the South Disouq area are shown below.

Prospect Name	Working Interest %	Interval	Concession Detail	Comment	Unrisked Mean (bcf)	Chance of Success (%)
Mohsen	55-100(1)	KES	Proposed 2 Yr(2) exploration extension	Single Target	27	46
El Deeb	55-100(1)	Qawasim	Proposed 2 Yr(2) exploration extension	Single Target	22	29
Ibn Newton/Newton	55-100(1)	KES/Abu Madi	Proposed 2 Yr(2) exploration extension	Dual Target	16	40-45
Shikabala prospects (two wells)	100	KES/ Qawasim	Up to 25 Yr Development Lease to 31 August 2045	Single Target & Dual Target	16	25-40
Warda	55	KES	Up to 25 Yr Development Lease to 2 January 2044	Single Target	14	40
Total					95

^{(1)  Working interest % dependent on Partner's decision to participate in the extension. The Company's partner has confirmed its participation in the Hanut-1X well.}

^{(2)  Two-year extension period commences on date of Parliamentary approval}

· Following the IY-2X and HA-1X well results, during H2 2021 the Company will evaluate the current and future prospectivity of the South Disouq concession to assess whether there is evidence that the carrying value of the asset should be impaired.

West Gharib Egypt development drilling campaign update (SDX 50% working interest)

· In March 2021, SDX obtained approval for a ten-year extension to the West Gharib Production Services Agreement increasing audited working interest 2P reserves in this core oil asset as at 31 December 2020, by 60% year on year, or 119% taking account of 2020 production, to 3.52 million barrels.

· Following this agreement, SDX and its partner commenced planning for a four well development drilling campaign plus one water injector well that is expected to start in Q4 2021, and is part of a wider three-year plan to arrest production decline in the asset and return production levels to c.3,000 bbl/d, taking advantage of low-risk production growth and the improved oil pricing environment.  

Six months to 30 June 2021 Financial Update

· Netback was US$22.1 million, 26% higher than the Netback of US$17.6 million for the six months to 30 June 2020, driven by:

o  Net revenue increase of US$5.2 million due to:

o  US$1.2 million higher revenue at West Gharib as lower production (2021: 516 bbl/d, 2020: 647 bbl/d) was more than offset by higher realised service fees (2021: US$51.10/bbl, 2020: US$30.18/bbl);

o  US$4.4 million higher revenue in Morocco due to increased production following strong demand rebound following COVID-19 shutdowns in early 2020 and an additional factory being supplied (2021: 993 boe/d, 2020: 707 boe/d). Revenue was further boosted by higher prices due to the strengthening of the Moroccan dirham and the additional factory taking gas at a higher price than the contractual average; offset by

o  US$0.4 million lower South Disouq revenue due to lower production (2021: 4,422 boe/d, 2020: 4,825 boe/d) as a result of natural decline at several wells and downtime for workover activity, partly offset by new production from the SD-12X well and a higher realised price for condensate.

o  Operating costs increased by US$0.7 million from the prior period due to increased well management costs at South Disouq and a greater number of wells producing in Morocco, partly offset by lower costs at West Gharib due to cost savings and lower workover activities. 

· EBITDAX was US$19.9 million, US$4.2 million (27%) higher than EBITDAX of US$15.7 million for the six months to 30 June 2020, for the reasons described in the netback section above.

· The main components of SDX's comprehensive loss of US$10.1 million for the six months ended 30 June 2021 are:

o  US$22.1 million Netback explained above;

o  US$10.9 million of E&E expense which   relates to the US$10.3 million non-cash impairment of the Lalla Mimouna Nord concession in Morocco and ongoing new venture activity (predominantly internal management time);

o  US$14.9 million of DD&A expense which reflects lower West Gharib production offset by increased production in Morocco;

o  US$2.3 million of ongoing G&A expense; and

o  US$3.7 million of corporation tax predominantly for South Disouq.

Operating cash flow (before capex, excluding discontinued operations)

· Operating cash flow (before capex, excluding discontinued operations) of US$14.9 million, 43% higher than the same period in 2020 of US$10.4 million primarily due to the netback drivers discussed above, as well as less cash spent on inventory. 

H1 2021 ESG metrics

· The Company's operated assets recorded a carbon intensity of 2.7kg CO₂e/boe in H1 2021, which is one of the lowest rates in the industry. This was higher than the 1.7 kg CO_2e/boe reported for the twelve months ended 31 December 2020 as the booster compressor at South Disouq was online throughout H1 2021, but only from Q2 2020, and in January 2021 a second production compressor was commissioned in Morocco. Combined production from the two assets was also marginally lower in H1 2021 compared to H1 2020.

· Scope 1 greenhouse gas emissions at operated assets were 4,405 tons of CO₂e. Scope 3 greenhouse gas emissions in Morocco were 75,500 tons of CO₂e, which is approximately 38,500 tons of CO₂e less than using alternative heavy fuel oil.

· There was one Lost Time Injury recorded in Morocco in July 2021. A contractor sustained a minor injury in a road traffic accident but after a short period of observation was able to return to work.

· No produced water was discharged into the environment in Morocco (100% contained and evaporated) or at South Disouq (100% recycled) during H1 2021.

· There were no hydrocarbon spills at operated assets during H1 2021.

· During the first half of 2021, the Company was delighted to support two hospitals close to the South Disouq operation by donating 13 monitors and BPAP ventilators to assist both in alleviating the current COVID-19 crisis and equipping the teams there for the longer-term health of our local communities. In Morocco, the Company is working on several initiatives to be launched later in 2021 as soon as this can be done safely.

· The Company continues to adopt high standards of Governance through its adherence to the QCA Code on Corporate Governance.

Outlook

· Management believes that the Company is well-placed to weather the current macroeconomic uncertainties and continues to screen a number of business development opportunities.

· Cash generation is expected to continue strongly through 2021 and beyond as approximately 85% of the Company's cash flows are expected to be generated from fixed-price gas businesses.

· Whilst acknowledging the volatility of the commodities market, the current strong oil price and outlook means that the Group also plans to capitalise on its recent production service agreement extension at West Gharib by investing in a 12-well development drilling programme over the next three years, including four wells in 2021.

· Anticipated 2021 and 2022 work programmes are fully funded.

· The Company continues to assess the optimum use of capital in the interests of all stakeholders, whether that be investment into new projects or returning cash to shareholders. At present the Company is focussed on continued investment of its portfolio and considers this the most appropriate use of the Company's capital. This will be assessed on an ongoing basis.

 

KEY FINANCIAL & OPERATING HIGHLIGHTS 

	Prior Quarter	Three months ended 30 June(3)		Six months ended 30 June
$000s except per unit amounts		2021 (unaudited)	2020 (unaudited)	2021 (unaudited)	2020 (unaudited)
FINANCIAL
Net revenues	13,383	13,725	9,163	27,108	21,856
Operating costs	(2,616)	(2,363)	(1,844)	(4,979)	(4,258)
Netback(1)	10,767	11,362	7,319	22,129	17,598
EBITDAX (1)	9,811	10,103	6,307	19,914	15,686
Total comprehensive profit/(loss)	613	(10,699)	(801)	(10,086)	(3,945)
Net profit/(loss) per share - basic	$0.003	$(0.052)	$(0.004)	$(0.049)	$(0.019)
Cash, end of period	9,734	9,108	9,275	9,108	9,275
Capital expenditures	3,964	11,875	3,842	15,839	19,375
Total assets	123,788	114,645	129,246	114,645	129,246
Shareholders' equity	97,079	86,430	94,390	86,430	94,390
Common shares outstanding (000's)	205,378	205,378	204,723	205,378	204,723
OPERATIONAL
West Gharib production service fee (bbl/d)	543	490	628	516	647
South Disouq gas sales (boe/d)	4,094	4,313	4,401	4,204	4,557
Morocco gas sales (boe/d)	1,023	964	551	993	707
Other products sales (boe/d)	202	235	253	218	268
Total sales volumes (boe/d) (2)	5,682	6,002	5,833	5,931	6,179
Realised West Gharib service fee (US$/bbl)	$47.90	$54.61	$20.94	$51.10	$30.18
Realised South Disouq gas price (US$/Mcf)	$2.85	$2.83	$2.85	$2.85	$2.85
Realised Morocco gas price (US$/Mcf)	$11.32	$11.49	$10.40	$11.40	$10.35
Royalties ($/boe) (2)	$4.82	$5.02	$4.91	$4.93	$5.01
Operating costs ($/boe) (2)	$4.96	$4.33	$3.47	$4.64	$3.79
Netback ($/boe)(1)(2)	$20.41	$20.81	$13.79	$20.61	$15.65

(1)  Refer to the "Non-IFRS Measures" section of this release below for details of Netback and EBITDAX.

(2)  Excludes discontinued operations

(3)  The Q2 2021 and Q2 2020 information in respect of the three months ended 30 June 2021 and 30 June 2020 respectively included in the Condensed Financial Statements has not been reviewed by PricewaterhouseCoopers LLP (the Company's auditors).

 

Consolidated Balance Sheet (unaudited)
(US$'000s)					As at 30 June 2021	As at 31 December 2020
Assets
Cash and cash equivalents					9,108	10,056
Trade and other receivables					18,967	18,608
Inventory					7,643	8,414
Current assets					35,718	37,078
Investments					4,013	3,790
Property, plant and equipment					56,375	57,880
Exploration and evaluation assets					16,873	24,455
Right-of-use assets					1,666	1,400
Non-current assets					78,927	87,525
Total assets					114,645	124,603
Liabilities
Trade and other payables					18,230	20,120
Decommissioning liability					-	327
Current income taxes					1,187	241
Lease liability					501	461
Current liabilities					19,918	21,149
Decommissioning liability					6,822	5,862
Deferred income taxes					290	290
Lease liability					1,185	960
Non-current liabilities					8,297	7,112
Total liabilities					28,215	28,261
Equity
Share capital					2,601	2,601
Share premium					130	130
Share-based payment reserve					7,443	7,269
Accumulated other comprehensive loss					(917)	(917)
Merger reserve					37,034	37,034
Retained earnings					40,139	50,225
Total equity					86,430	96,342
Equity and liabilities					114,645	124,603

 

Consolidated Statement of Comprehensive Income (unaudited)
						Unreviewed (1) Three months ended 30 June				Six months ended 30 June
(US$'000s)						2021		2020		2021	2020
Revenue, net of royalties						13,725		9,163		27,108	21,856
Direct operating expense						(2,363)		(1,844)		(4,979)	(4,258)
Gross profit						11,362		7,319		22,129	17,598
Exploration and evaluation expense						(10,612)		(303)		(10,880)	(5,099)
Depletion, depreciation and amortisation						(7,521)		(5,225)		(14,945)	(11,973)
Share-based compensation						(50)		(68)		(174)	(313)
Share of profit from joint venture						108		137		223	384
General and administrative expenses
- Ongoing general and administrative expenses						(1,317)		(1,013)		(2,264)	(1,915)
- Transaction costs						-		(68)		-	(68)
Operating (loss)/income						(8,030)		779		(5,911)	(1,386)
Finance costs						(153)		(134)		(334)	(276)
Foreign exchange (loss)/gain						(70)		30		(162)	(301)
(Loss)/income before income taxes						(8,253)		675		(6,407)	(1,963)
Current income tax expense						(2,446)		(1,085)		(3,679)	(2,728)
(Loss)/profit from discontinued operations						-		(391)		-	737
Loss and total comprehensive loss for the period						(10,699)		(801)		(10,086)	(3,954)
Net loss per share
Basic						$(0.052)		$(0.004)		$(0.049)	$(0.019)
Diluted						$(0.052)		$(0.004)		$(0.049)	$(0.019)

(1)  The Q2 2021 and Q2 2020 information in respect of the three months ended 30 June 2021 and 30 June 2020 respectively included in the Condensed Financial Statements has not been reviewed by PricewaterhouseCoopers LLP (The Company's auditors).

 

Consolidated Statement of Changes in Equity (unaudited)
					Six months ended 30 June
(US$'000s)					2021	2020
Share capital
Balance, beginning of period					2,601	2,593
Balance, end of period					2,601	2,593
Share premium
Balance, beginning of period					130	-
Balance, end of period					130	-
Share-based payment reserve
Balance, beginning of period					7,269	7,038
Share-based compensation for the period					174	313
Balance, end of period					7,443	7,351
Accumulated other comprehensive loss
Balance, beginning of period					(917)	(917)
Balance, end of period					(917)	(917)
Merger reserve
Balance, beginning of period					37,034	37,034
Balance, end of period					37,034	37,034
Retained earnings
Balance, beginning of period					50,225	52,283
Total comprehensive loss					(10,086)	(3,954)
Balance, end of period					40,139	48,329
Total equity					86,430	94,390

 

Consolidated Statement of Cash Flows (unaudited)
	Unreviewed (1) Three months ended 30 June		Six months ended 30 June
(US$'000s)	2021	2020	2021		2020
Cash flows generated from/(used in) operating activities
(Loss)/income before income taxes	(8,253)	675	(6,407)		(1,963)
Adjustments for:
Depletion, depreciation and amortisation	7,521	5,225	14,945		11,973
Exploration and evaluation expense	10,313	-	10,313		4,527
Finance expense	153	134	334		276
Share-based compensation charge	50	68	174		313
Foreign exchange loss/(gain)	(137)	173	(74)		457
Tax paid by state	(1,338)	(1,240)	(2,566)		(2,678)
Share of profit from joint venture	(108)	(137)	(223)		(384)
Operating cash flow before working capital movements	8,201	4,898	16,496		12,521
Decrease/(increase) in trade and other receivables	1,603	2,739	(273)		892
(Decrease)/increase in trade and other payables	(1,057)	(763)	(763)		(498)
Decrease/(increase) of inventory	73	(361)	(512)		(1,422)
Cash generated from operating activities	8,820	6,513	14,948		11,493
Income taxes paid	-	(1,062)	-		(1,135)
Net cash generated from operating activities	8,820	5,451	14,948		10,358
Cash generated from discontinued operations	-	2,970	-		4,140
Cash flows generated from/(used in) investing activities:
Property, plant and equipment expenditures	(7,409)	(139)	(10,094)		(5,625)
Exploration and evaluation expenditures	(1,907)	(8,466)	(5,282)		(11,593)
Advance proceeds from NW Gemsa sale	-	1,000	-		1,000
Dividends received	-	-	-		774
Net cash used in investing activities	(9,316)	(7,605)	(15,376)		(15,444)
Cash flows generated from/(used in) financing activities:
Payments of lease liabilities	(229)	(150)	(503)		(308)
Finance costs paid	(40)	(26)	(95)		(70)
Net cash used in financing activities	(269)	(176)	(598)		(378)
(Decrease)/increase in cash and cash equivalents	(765)	640	(1,026)		(1,324)
Effect of foreign exchange on cash and cash equivalents	139	(172)	78		(455)
Cash and cash equivalents, beginning of period	9,734	8,807	10,056		11,054
Cash and cash equivalents, end of period	9,108	9,275	9,108		9,275

(1)  The Q2 2021 and Q2 2020 information in respect of the three months ended 30 June 2021 and 30 June 2020 respectively included in the Condensed Financial Statements has not been reviewed by PricewaterhouseCoopers LLP (The Company's auditors).

About SDX

SDX is an international oil and gas exploration, production and development company, headquartered in London, United Kingdom, with a principal focus on MENA. In Egypt, SDX has a working interest in two producing assets: a 55% operated interest in the South Disouq and Ibn Yunus gas fields and a 100% operated interest in the Ibn Yunus North gas field, all in the Nile Delta and a 50% non-operated interest in the West Gharib concession, which is located onshore in the Eastern Desert, adjacent to the Gulf of Suez. In Morocco, SDX has a 75% working interest in five development/production concessions, all situated in the Gharb Basin. The producing assets in Morocco are characterised by attractive gas prices and exceptionally low operating costs. SDX has a strong weighting of fixed price gas assets in its portfolio with low operating costs and attractive margins throughout, providing resilience in a low commodity price environment. SDX's portfolio also includes high impact exploration opportunities in both Egypt and Morocco.

For further information, please see the Company's website at www.sdxenergygroup.com or the Company's filed documents at www.sedar.com. 

Competent Persons Statement

In accordance with the guidelines of the AIM Market of the London Stock Exchange, the technical information contained in the announcement has been reviewed and approved by Rob Cook, VP Subsurface of SDX. Dr. Cook has over 25 years of oil and gas industry experience and is the qualified person as defined in the London Stock Exchange's Guidance Note for Mining and Oil and Gas companies. Dr. Cook holds a BSc in Geochemistry and a PhD in Sedimentology from the University of Reading, UK. He is a Chartered Geologist with the Geological Society of London (Geol Soc) and a Certified Professional Geologist (CPG-11983) with the American Institute of Professional Geologists (AIPG).

For further information:

SDX Energy Plc Mark Reid Chief Executive Officer Tel: [phone]
Stifel Nicolaus Europe Limited (Nominated Adviser and Joint Broker) Callum Stewart Jason Grossman Ashton Clanfield Tel: [phone]
Peel Hunt LLP (Joint Broker) Richard Crichton David McKeown Tel: [phone]
Camarco (PR) Billy Clegg/Owen Roberts/Violet Wilson Tel: [phone]

Glossary

"bbl"	stock tank barrel
"bbl/d"	barrels of oil per day
"bcf"	billion cubic feet
"boe/d"	barrels of oil equivalent per day
"CO2e/boe"	carbon dioxide equivalent per barrels of oil equivalent
"Mcf"	thousands of cubic feet
"MD"	measured depth
"MMscf/d"	million standard cubic feet per day
"MMscfe/d"	million standard cubic feet equivalent per day
"P50"	means that there is at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate.
"TD"	total depth
"2P Reserves"	proved plus probable reserves

 

Forward-looking information

Certain statements contained in this press release may constitute "forward-looking information" as such term is used in applicable Canadian securities laws. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or are not statements of historical fact should be viewed as forward-looking information. In particular, statements regarding the Company's 2021 production and capex guidance, liquidity and sources of cash flows in 2021, the impact of COVID-19 on customer consumption, and future drilling developments and results should all be regarded as forward-looking information.  

The forward-looking information contained in this document is based on certain assumptions, and although management considers these assumptions to be reasonable based on information currently available to them, undue reliance should not be placed on the forward-looking information because SDX can give no assurances that they may prove to be correct. This includes, but is not limited to, assumptions related to, among other things, commodity prices and interest and foreign exchange rates; planned synergies, capital efficiencies and cost-savings; applicable tax laws; future production rates; receipt of necessary permits; the sufficiency of budgeted capital expenditures in carrying out planned activities, and the availability and cost of labour and services.

All timing given in this announcement, unless stated otherwise, is indicative, and while the Company endeavours to provide accurate timing to the market, it cautions that, due to the nature of its operations and reliance on third parties, this is subject to change, often at little or no notice. If there is a delay or change to any of the timings indicated in this announcement, the Company shall update the market without delay.

Forward-looking information is subject to certain risks and uncertainties (both general and specific) that could cause actual events or outcomes to differ materially from those anticipated or implied by such forward-looking statements. Such risks and other factors include, but are not limited to, political, social, and other risks inherent in daily operations for the Company, risks associated with the industries in which the Company operates, such as: operational risks; delays or changes in plans with respect to growth projects or capital expenditures; costs and expenses; health, safety and environmental risks; commodity price, interest rate and exchange rate fluctuations; environmental risks; competition; permitting risks; the ability to access sufficient capital from internal and external sources; and changes in legislation, including but not limited to tax laws and environmental regulations. Readers are cautioned that the foregoing list of risk factors is not exhaustive and are advised to refer to the Principal Risks & Uncertainties section of SDX's Annual Report for the year ended 31 December 2020, which can be found on the Company's website at https://www.sdxenergygroup.com/ and on SDX's SEDAR profile at www.sedar.com, for a description of additional risks and uncertainties associated with SDX's business.

The forward-looking information contained in this press release is as of the date hereof and SDX does not undertake any obligation to update publicly or to revise any of the included forward‐looking information, except as required by applicable law. The forward‐looking information contained herein is expressly qualified by this cautionary statement.

Non-IFRS Measures

This news release contains the terms "Netback," and "EBITDAX" which are not recognized measures under IFRS and may not be comparable to similar measures presented by other issuers. The Company uses these measures to help evaluate its performance.

Netback is a non-IFRS measure that represents sales net of all operating expenses and government royalties. Management believes that Netback is a useful supplemental measure to analyze 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 as it demonstrates the Company's profitability relative to current commodity prices. Netback may not be comparable to similar measures used by other companies.

EBITDAX is a non-IFRS measure that represents earnings before interest, tax, depreciation, amortization, exploration expense and impairment. EBITDAX is calculated by taking operating income/(loss) and adjusted for the add-back of depreciation and amortization, exploration expense and impairment of property, plant, and equipment (if applicable).  EBITDAX is presented in order for the users to understand the cash profitability of the Company, which excludes the impact of costs attributable to exploration activity, which tend to be one-off in nature, and the non-cash costs relating to depreciation, amortization and impairments. EBITDAX may not be comparable to similar measures used by other companies. 

Oil and Gas Advisory

Certain disclosures in this news release constitute "anticipated results" for the purposes of National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") of the Canadian Securities Administrators because the disclosure in question may, in the opinion of a reasonable person, indicate the potential value or quantities of resources in respect of the Company's resources or a portion of its resources. Without limitation, the anticipated results disclosed in this news release include estimates of volume, flow rate, production rates, porosity, and pay thickness attributable to the resources of the Company. Such estimates have been prepared by Company management and have not been prepared or reviewed by an independent qualified reserves evaluator or auditor. Anticipated results are subject to certain risks and uncertainties, including those described above and various geological, technical, operational, engineering, commercial, and technical risks. In addition, the geotechnical analysis and engineering to be conducted in respect of such resources is not complete. Such risks and uncertainties may cause the anticipated results disclosed herein to be inaccurate. Actual results may vary, perhaps materially.

Use of the term "boe" or the term "MMscf" may be misleading, particularly if used in isolation. A "boe" conversion ratio of 6 Mcf: 1 bbl and a "Mcf" conversion ratio of 1 bbl: 6 Mcf are based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Reserve and Resource Data

The reserve and resource estimates disclosed or referenced herein have been prepared by Dr. Rob Cook, a qualified reserves evaluator, in accordance with the SPE's Canadian Oil and Gas Evaluation Handbook and in accordance with NI 51-101. The reserves and resources disclosed herein have an effective date of 31 December 2020.

Prospective resources are those quantities of gas, estimated as of the given date, to be potentially recoverable from undiscovered accumulations through future development projects. As prospective resources, there is no certainty that any portion of the resources will be discovered. The chance that an exploration project will result in a discovery is referred to as the "chance of discovery" as defined by the management of the Company.

There is no certainty that it will be commercially viable to produce any portion of the resources discussed herein; though any discovery that is commercially viable would be tied back to the Company's pipeline in Morocco and then connected to customers' facilities within 9 to 12 months of discovery. Based upon the economic analysis undertaken on any discovery, management has attributed an associated chance of development of 100%.

There are uncertainties associated with the volume estimates of the prospective resources disclosed herein, due to the level of information available on prospective resources, but ranges are defined based on data from the Company's nearby existing analogous wells. Some of the risks and uncertainties are outlined below:

· Petrophysical parameters of the sand/reservoir;

· Fluid composition, especially heavy end hydrocarbons;

· Accurate estimation of reservoir conditions (pressure and temperature);

· Reservoir drive mechanism;

· Potential well deliverability; and

· The thickness and lateral extent of the reservoir section, currently based on 3D seismic data.

 

END

 

 

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