SDX Energy Inc. announces its second quarter and half year to June 30, 2018 financial and operating results

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 ("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.

LONDON, Aug. 28, 2018 /CNW/ - SDX Energy Inc. (TSXV, AIM: SDX), the North Africa focused oil and gas company, is pleased to announce its financial and operating results for the three and six months ended June 30, 2018.  All dollar values are expressed in United States dollars net to the Company unless otherwise stated.

Highlights – three and six months ended June 30, 2018

Corporate and Financial

• SDX's key financial metrics for the three and six months ended June 30, 2018 and 2017 are as follows:

• The above financial metrics for the three and six months ended June 30, 2018 and 2017 reflect the impact of the acquisition of the Egyptian and Moroccan businesses of Circle Oil plc (the "Circle Acquisition") from January 27, 2017 for consideration of US$28.1 million.
  
  
• The main components of SDX's comprehensive income of US$1.0 million for the six months ended June 30, 2018 are:
• US$19.3 million netback/gross profit for the period;
• US$5.3 million of E&E write down predominantly relating to two sub-commercial exploration wells in Morocco and one sub-commercial exploration well in Egypt;
• US$6.2 million of DD&A;
• US$2.8 million of G&A; and
• US$3.1 million of Corporate Income Tax expense.
  

• Netback for the six months to June 30, 2018 was US$19.3 million, up from US$13.0 million for the six months to June 30, 2017.  The increase in netback was due to;
• The Circle Acquisition completing on January 27, 2017, therefore H1 2017 results only included five months of 'Circle' activity whereas the H2 2018 results included six months; and
• H1 2018 also benefited from improved oil prices impacting SDX's Egyptian producing assets and higher realised gas pricing in Morocco due to a contract price increase and favourable currency movement.
  

• Cash position of US$25.2 million as at June 30, 2018 was US$0.6 million lower than the US$25.8 million at December 31, 2017 and US$2.4 million lower than the US$27.6 million reported at June 30, 2017.  However the Company's strong Netback, improving Receivables position and US$10 million equity placing in September 2017 have enabled it to invest approximately US$45 million of capital expenditure in the 12 months to June 30, 2018. This expenditure included 14 wells in Egypt and 9 wells in Morocco, which did not materially reduce SDX's cash balance over this period.
  
   
• The Company further improved its available liquidity when it announced on July 18, 2018 that it had secured a three year, US$10 million Credit Facility (the "Facility") with the European Bank for Reconstruction and Development.  This Facility, which also has an additional US$10 million accordion feature, will be used for drilling costs and customer connections in Morocco.  Interest on drawings from the Facility will be charged at US$ Libor plus 4.0% for drawings up to US$5 million and US$ Libor plus 4.5% on all drawings if drawings are greater than US$5 million.
  
   
• US$24.7 million of capital expenditure has been invested into the business during the six months ended June 30, 2018.  The main elements of this were;
• US$11.2 million in Morocco, US$10.4 million of which relates to the now completed nine well drilling programme and customer connection projects and US$0.8 million of which relates to the mobilisation cost for the upcoming 240km² 3D seismic programme in Gharb Centre;
• US$5.7 million on the South Disouq drilling programme, which includes the costs for the Ibn Yunus-1X and SD-4X discovery wells, the costs of the sub-commercial Kelvin-1X well and the site preparation cost for the SD-3X discovery well which reached total depth ("TD") in July;
• US$6.3 million in North West Gemsa for the costs of the AASE-25, AASE-27 infill wells and the commencement of the Al-Ola 4 well, all of which were discoveries;
• US$0.8 million in Meseda for the costs of the Rabul-4 and MSD-16 discovery wells and the ongoing electric submersible pump ("ESP") replacement programme;
• US$0.3 million in South Ramadan relating to pre-spud costs of the SRM-3 well; and
• US$0.4 million relating to new office equipment in Cairo and additional technical software.

Operational Highlights

• The Company's entitlement share of production from its operations for the six months ended June 30, 2018 was 3,234 BOE/D and is analysed as follows;
  
   
• North West Gemsa 1,941 BOE/D
• Meseda  633 BBL/D
• Morocco  660 BOE/D

• As a result of the ongoing development drilling and workover programme in North West Gemsa and the commencement of production from the successful Rabul-4, Rabul-5 and MSD-16 wells in Meseda production has increased with actual entitlement production on August 23, for Egypt and August 14 for Morocco (last day before the Eid Holiday maintenance shutdown) amounting to 4,444 BOE/D (Gross – 11,257 BOE/D) analysed as follows;
  
   
• North West Gemsa 2,777 BOE/D (Gross -  5,553 BOE/D)
• Meseda  917 BBL/D (Gross – 4,704 BOE/D)
• Morocco  750 BOE/D (Gross – 1,000 BOE/D)

Egypt

• In North West Gemsa (SDX 50% working interest and non-operator), a seven well workover programme is underway and two new infill wells, AASE-25 and AASE-27, were successfully completed.  A third well, Al Ola-4, was spud towards the end of the period.  AASE-25 was targeting an un-swept area of the field in the Rahmi sand and encountered 32 feet of net light crude oil bearing pay in this section.  The well was subsequently completed as a producer and flowed on test at 549 BOE/D of light crude oil with 1% water cut prior to being connected to the local infrastructure and placed on production.  AASE-27 was also targeting an un-swept area of the field in the Rahmi and encountered 13.5 feet of net light crude oil bearing pay.  The well was completed as a producer and flowed on test at 537 BOE/D of light crude oil with a 5% water cut.  This well is currently being connected to the infrastructure prior to being placed on production.  Al Ola-4, was drilled as a replacement well in the Rahmi after the original well failed due to a mechanical problem.  Al Ola-4 was spud during the period but completed post-period.  The well encountered 14 feet of net light crude oil bearing Rahmi section and, on test, flowed 1,011 BOE/D of dry light crude oil with 0% water cut and was subsequently completed as a producer. The results of these wells and the ongoing workover programme are expected to allow the field production rate for the year to average approximately 4,400 BOE/D of light crude oil (SDX net: 2,200 BOE/D) which means that the gross field 2018 production rate guidance provided by the Company in January is unchanged.
  
  
• In Meseda (SDX 50% working interest and non-operator), an ESP replacement programme is underway and three wells have been successfully completed; Rabul-5, Rabul-4 during the period, and MSD-16 post period end.  Rabul-5 encountered 151 feet of net heavy crude oil pay, with an average porosity of 18% across the Yusr and Bakr formations.  Rabul-4 encountered 43 feet of net heavy crude oil pay also across the Yusr and Bakr, with an average porosity of 16%.  Both wells were completed as producers and placed on production.  MSD-16 was drilled as a crestal infill producer in a newly available area of the field 100 meters from the concession boundary after an agreement was reached with the offset operator to reduce the boundary stand-off limits.  The well encountered 176 feet of net heavy crude oil pay in the ASL reservoir section with an average porosity of 22%. The well was completed as a producer in the ASL using an ESP pump to provide artificial lift and is currently producing approximately 1,200 BBL/D of heavy crude oil.  Post-period end, a second lease line development well, MSD-15, was spud, and subsequently reached TD.  The MSD-15 well encountered 226 feet of net of heavy crude oil pay in the ASL section and is currently being completed as a producer in this section.  Upon production start-up, it is expected to flow at similar rates to the MSD-16, again using an ESP to provide artificial lift.  Production at MSD-15 is anticipated to start up between late August and early September 2018.  The results of these wells and the ongoing workover programme are expected to allow the field production rate for the year to average approximately 3,800 BBL/D of heavy crude oil (SDX net: 732 BBL/D) which means that the gross field 2018 production rate guidance provided by the Company in January is unchanged.
  
  
• In South Disouq (SDX 55% working interest and operator), the Company announced on April 12, 2018 that a gas discovery had been made at its Ibn Yunus-1X exploration well.  The well was drilled to a TD of 9,068 feet and encountered 101 feet of net conventional natural gas pay in the Abu Madi horizon, with average porosity in the pay section of 28.5%.  The well came in on prognosis but with a reservoir section that was of better quality and thicker than pre-drill expectations.  On May 18, 2018 the well successfully flow tested conventional natural gas at a stabilised rate of 39.3 MMSCF/D on a 32/64" choke.  This flow rate exceeded initial expectations and was limited by the surface facilities in place.  The well was subsequently completed in the Kafr El Sheik section and then suspended until it can be connected to the surface facilities that are being developed at the SD-1X location.

The Kelvin-1X exploration well was spud on May 8, 2018 and drilled to a total depth of 8,075 feet, encountering 606 net feet of high quality reservoir interval in the Abu‐Madi formation with an average porosity of 21%.  However, the sands had low gas saturation and were not deemed to be commercial.  The well was subsequently plugged and abandoned.

The SD-4X appraisal well was spud on June 4, 2018 and drilled to a total depth of 7,806 feet and encountered 89 feet of net conventional natural gas pay in the Abu Madi horizon, with an average porosity in the pay section of 24%.  The well came in on prognosis with a reservoir section of similar quality but thicker than the original SD-1X discovery well. The well was completed in the Abu Madi section and tested at a maximum rate of 30.4 MMSCF/D during an eight hour clean up period.  The well was then shut in for eight hours, during which time no pressure decline was observed. Following this the well was flowed at varying choke sizes for two successive 12-hour periods at average rates of 5.4 MMSCF/D, 8.6 MMSCF/D respectively and then one extended flow period of 24-hours at an average rate of 10.5 MMSCF/D.  The well was then suspended until it can be connected to the surface facilities that are being developed at the SD-1X location.

Post-period end, the SD-3X appraisal well was spud on July 5, 2018, drilled to a total depth of 7,842 feet and encountered 32.6 feet of net conventional natural gas pay in the Abu Madi and Kafr el Sheik horizons, with an average porosity in the pay sections of 21.7%. The well was completed as a producer in the Abu Madi horizon and tested post period end at flow rate of 16.6MM SCF/D of conventional natural gas. In order to optimise the potential recovery from the SD-3X well, the Abu Madi horizon will be completed and produced initially before re-entering the well to complete and produce the Kafr el Sheik horizon.  The well will be connected to the infrastructure located adjacent to the original SD-1X discovery. 

Given the above, and assuming all necessary regulatory approvals are obtained at South Disouq, first gas is targeted by the end of 2018, at an initial gross plateau production rate of conventional natural gas at between 50-60 MMSCF/D from the Ibn Yunus discovery and the three development wells in the SD-1X discovery structure.  

• At South Ramadan (SDX 12.75% working interest and non-operator), the SRM-3 appraisal well was spud on June 14, 2018. The well is targeting undrained light oil volumes up-dip of one of the previous producing wells in the field. The well is anticipated to take up to 90 days to drill and complete.   The SRM-3 well is the last remaining commitment well on the South Ramadan concession and based upon the results of this well the Company will decide how best to optimise its position in the licence.

Morocco

• The Company's Moroccan acreage consists of three concessions; Sebou, Lalla Mimouna and Gharb Centre, all of which are located in the Gharb Basin in northern Morocco (SDX 75% working interest and operator).  Sebou and Lalla Mimouna were obtained as part of the Circle Acquisition and Gharb Centre was acquired directly from the Moroccan State on June 1, 2017.
  
  
• In September 2017, the Company commenced a nine well drilling programme covering six appraisal/development wells in Sebou, one appraisal/development well in Gharb Centre and two exploration wells in Lalla Mimouna.
  
  
• The results of the well programme to date are as follows with the Company achieving seven successful wells from the nine that have been drilled, a 78% success rate;

• During Q1 2018, the results of the ELQ-1, ONZ-7, KSS-2 and SAH-2 wells were announced.  ONZ-7 and SAH-2 were successfully tested in the quarter and have been tied to existing infrastructure as producers.  The ELQ-1 and KSS-2 wells were plugged and abandoned.
  
  
  On April 20, 2018 and May 7, 2018, respectively, the Company announced the successes of the LNB-1 and LMS-1 exploration wells in the Lalla Mimouna concession.
  
  
  
• The primary target of the LNB-1 well was in the Lafkerena sequence, where 300 meters of gas bearing horizons were encountered in a significantly over-pressured section. This section could not be logged using conventional methods due to hole conditions, however, the gas shows in this section contained heavier hydrocarbon components throughout, which is indicative of a thermogenic hydrocarbon source rock and indicates that a new petroleum system has been encountered in this area. Based on the mud log shows, reservoir quality information from the formation cuttings, analogue fields (outside the Gharb basin), and the size of the feature as currently mapped, a preliminary un-risked mid-case recoverable gas volume of 10.2 BCF of conventional natural gas and 55 thousand barrels of condensate has been estimated by management. This is significantly larger than the traps typically encountered in Sebou and would exceed the size required to justify development and connection to the existing infrastructure in the Sebou area. Additionally in the secondary target, the Upper Dlalha, 2.6 meters of net conventional natural gas pay sands were encountered with average porosity in the pay section of 33%. This pay section is similar to the Guebbas targets, from which SDX successfully produces on the Sebou permit. The LNB-1 well has been completed as a conventional gas producer in the Upper Dlalha with the deeper Lafkerena section being suspended until the appropriate equipment can be mobilized, to test and produce from this over-pressured section. The timetable to test this section has not been finalized and will be the subject of a future update.
  
  
• The primary target of the LMS-1 well was in the H-9 sequence, which is a Miocene aged shallow marine deposit that had not been previously tested in the area.  The well encountered 16.4 meters of net conventional gas pay sands which had an average porosity of 32% in an over-pressured section. Similar to the LNB-1 well, heavier gas shows were encountered indicating the presence of a deeper thermogenic source rock charging the structure. In addition, the cuttings showed evidence of fluorescence indicating the potential presence of liquid hydrocarbons within the section encountered. The well was completed as a conventional natural gas producer in the H-9 interval. Upon test the well flowed at sub-commercial rates which the Company believes are temporary and due to damage created by the fluids used to control the elevated pressures encountered in the well whilst drilling. The damage is thought to result from the formation clays reacting to certain components used to increase the mud weight in the drilling fluid. The reservoir section, beyond this zone of damage, is thought to be of excellent quality based upon the well log response and is not expected to have been damaged by the drilling fluids. Once the fluid interaction study is complete, a stimulation programme will be designed and implemented and the well test will be repeated.
  
  
• As a result of the success seen in the LNB-1 and LMS-1 wells, a two year extension to the LM Nord permit was submitted and granted post-period end. This extends the permit validity from July 2018 to July 2020.
  
  
• The Company continued its land permitting and other associated activities necessary to conduct its 240 km² 3D seismic acquisition in the Gharb Centre permit. The acquisition started up post-period end during the first week of August and is anticipated to be completed early in Q3 2018.
  
  
• Gross production in H1 2018 of approximately 5.3 MMSCF/D of conventional natural gas (660 BOE/D net to SDX) is expected to increase in H2 2018 when gas sales to the recently contracted customers, Peugeot, Setexam and Extralait, will commence. These contracts are expected to add incremental production of approximately 1.33 MMSCF/D of conventional natural gas during H2 2018.
  
  
• The achievement of the Company's guidance for the year-end 2018 production rate of 8-10 MMSCF/D of conventional natural gas from its Morocco operations is dependent upon the number of new customer connections made and the subsequent commencement/increase of manufacturing activity at these new customers. The Company will provide a further update towards achieving its stated guidance when its Q3 2018 results are issued in November.

Outlook:

Egypt

• North West Gemsa (50% Working Interest and non-operator)
  
   
• Targeting FY 2018 gross production of approximately 4,400 BOE/D of light crude oil, in line with Company guidance provided at start of year.
• Workover programme to continue in H2 2018, however no further drilling is planned.
• SDX's share of North West Gemsa FY 2018 capex is expected to be US$7.9million with approximately US$1.6 million of this to be incurred in H2 2018.

• Meseda (50% Working Interest and non-operator)
  
   
• Targeting FY 2018 gross production of 3,800 BBL/D of heavy crude oil, approximately 700 BBL/D higher than 2017's level, and in line with Company guidance provided at start of year.
• Workover programme to continue in H2 2018 however no further drilling planned.
• SDX's share of Meseda FY 2018 capex is expected to be US$1.4million with approximately US$0.6 million of this to be incurred in H2 2018.

• South Disouq (55% Working Interest and operator)
  
   
• Complete construction of SD-1X processing facility, well tie-ins and 10 kilometer pipeline connecting the processing facilities to the main export line.
• Given the above, and assuming all necessary approvals are obtained, first gas is targeted before the end of 2018, at an initial gross plateau production rate of approximately 50-60 MMSCF/D of conventional natural gas. The gas price is still under negotiation.
• SDX's share of South Disouq FY 2018 capex is expected to be approximately US$22million with approximately US$16 million to be incurred in H2 2018 for the SD-3X and SD-4X well completions and testing, the processing facility, well tie-ins and 10 kilometer pipeline to the main export line.

• South Ramadan (12.75% Working Interest and non-operator)
  
   
• The SRM-3 well is the last remaining commitment well on the South Ramadan concession and based upon the results of this well the Company will decide how best to optimise its position in the licence.
• Gross South Ramadan capex FY 2018 is expected to be approximately US$23.5 million (SDX net: US$3.0 million).  All of this capex is still to be incurred in H2 2018.

Morocco (75% Working Interest and operator)

• Given the recent drilling success, 2018 gross production is targeted to increase in line with new customer tie-ins.  Depending on the timing of new customer tie-ins and the subsequent commencement/increase of  manufacturing activity at these new customers, SDX is still targeting gross production of 8-10 MMSCF/D of conventional natural gas by the end of 2018.
  
  
• SDX's nine well Moroccan drilling programme completed on May 7, 2018 with the LMS-1 discovery.  The Company will now commence planning for the mobilisation of equipment for a further drilling campaign in 2019 during which the LNB-1 and LMS-1 wells in Lalla Mimouna will be re-tested.
  
  
• The Company will acquire 240km² of 3D seismic in its Gharb Centre concession at an estimated cost of US$6.5 million.

Corporate

• Continue to minimise costs and crystallise synergies from the Circle Oil Acquisition; and
  
  
• 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 through new licencing rounds and acquisitions.

Paul Welch, President  & CEO of SDX Energy, commented: 

"The first half of 2018 was a busy period for SDX and one which saw the Company significantly increase its net revenue and overall production year on year.

We also made significant operational progress across our portfolio with discoveries from 20 of the 23 wells drilled in the recent Moroccan and Egyptian drilling campaigns, representing a success rate of 87%.

In Egypt, at Meseda, we enjoyed success at our Rabul-5, Rabul-4, MSD-16 and MSD-15 (post-period end) appraisal wells.  This was matched in North West Gemsa with successful wells at AASE-25, AASE-27 and Al-Ola-4 (post-period end), and at South Disouq, with discoveries at our Ibn Yunus-1X, SD-4X and SD-3X wells (post-period end).  Due to this drilling success, the Company is able to reconfirm its FY 2018 gross production guidance for North West Gemsa and Meseda at 4,400 BOE/D and 3,800 BBL/D respectively. We also remain on target to commence production at South Disouq at gross 50-60 MMSCF/D by the end of the year. 

In Morocco, the Company completed its nine well drilling programme with seven gas discoveries, a 78% success rate throughout the campaign. The last two exploration wells appear to be very significant successes and upon completion of testing it is hoped that they will have opened up new producing areas for the Company. The Company has signed Gas Sales Agreements with three new customers: Peugeot, Setexam and Extralait, and is still targeting gross production of 8-10 MMSCF/D of conventional natural gas by the end of 2018.

Throughout the period, we remained focused on strict capital discipline and continued to monitor opportunities that would enable us to increase our asset base in North Africa. As at June 30, 2018, we are well funded for our remaining work commitments with US$25.2 million of cash and an undrawn Credit Facility of US$10.0 million and we continue to target doubling our production by the end of 2018."

KEY FINANCIAL & OPERATING HIGHLIGHTS

Unaudited interim consolidated financial statements with Management's Discussion and Analysis for Q2 2018 are now available on the Company's website at www.sdxenergy.com and on SEDAR at www.sedar.com.

About SDX

SDX is an international oil and gas exploration, production and development company, headquartered in London, England, UK, with a principal focus on North Africa. In Egypt, SDX has a working interest in two producing assets (50% North West Gemsa & 50% Meseda) located onshore in the Eastern Desert, adjacent to the Gulf of Suez. In Morocco, SDX has a 75% working interest in the Sebou concession situated in the Rharb Basin. These producing assets are characterised by exceptionally low operating costs making them particularly resilient in a low oil price environment. SDX's portfolio also includes high impact exploration opportunities in both Egypt and Morocco.

For further information, please see the website of the Company at www.sdxenergy.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 Paul Welch, Chief Executive Officer of SDX. Mr. Welch, who has over 30 years of experience, is the qualified person as defined in the London Stock Exchange's Guidance Note for Mining and Oil and Gas companies. Mr. Welch holds a BS and MS in Petroleum Engineering from the Colorado School of Mines in Golden, CO. USA and an MBA in Finance from SMU in Dallas, TX USA and is a member of the Society of Petroleum Engineers (SPE).

Neither the TSX Venture Exchange nor its Regulation Services Provider (as such term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

Glossary

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 use of proceeds from the Facility; the timing of first gas at South Disouq; the Company's plans, production targets, volume targets, drilling, production start-up dates, seismic work and the timing and costs thereof; capital expenditures; operational expenditures; and the Company's 2018 outlook and corporate strategy, 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 labor and services.

All timing given in this announcement, unless stated otherwise is indicative and while the Company endeavors 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; 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 reference SDX's Management's Discussion & Analysis for the three and six months ended June 30, 2018, which can be found on SDX's SEDAR profile at www.sedar.com, for a description of additional risks and uncertainties associated with SDX's business, including its exploration activities.

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. See Netback reconciliation to operating income/(loss) in note 20 to the Interim Consolidated Financial Statements.

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 of the financial statements 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.  See EBITDAX reconciliation to operating income/(loss) in note 20 to the Interim Consolidated Financial Statements.

Oil and Gas Advisory

Certain disclosure in this news release constitute "anticipated results" for the purposes of National Instrument 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 and pay thickness attributable to the resources of the Company. Such estimates have been prepared by management of the Company 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.

In addition to the uncertainties listed above, due to the level of information available, there is still uncertainty associated with the volume estimates prepared by management for the LNB-1 discovery in Morocco.  Some of the risks and uncertainties are outlined below:

• Petrophysical parameters and quality estimates of the reservoir section.
• Fluid composition, especially heavy end hydrocarbons and the potential presence of associated liquids.
• Accurate estimation of reservoir conditions (pressure and temperature), currently unknown but roughly estimated based on mud weight range while drilling of 1.6-1.65 Specific Gravity.
• Reservoir drive mechanism.
• Potential well deliverability and long-term sustainability.
• The thickness and quality of the reservoir section away from the well penetration location.

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

SOURCE SDX Energy Inc.

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