SDX Energy — Looking ahead at 2019 work programme

SDX Energy is a North Africa-focused exploration and production company, listed on AIM and TSX Venture. Management has grown the company inorganically, through the 2017 acquisition of Circle Oil’s Moroccan assets and organically through an extensive E&A programme over the past 18 months.

We value SDX based on the NPV12.5 of the company’s producing assets and risked value of contingent and prospective resource. Recent changes in our valuation include the movement of discovered resource to core value to reflect 2017/2018 discoveries made in Egypt and Morocco, the inclusion of risked value for planned 2019 wells and a higher short-term oil price assumption. We assume realised gas prices of $2.65/mcf at South Disouq and $10.5/mcf in Morocco, with a long-term oil price of $70/bbl Brent. Our short-term oil price assumptions are based on EIA forecasts at $71.1/bbl in 2018 and $67.7/bbl in 2019. A breakdown of our RENAV is provided in Exhibit 1.

SDX maintains a strong balance sheet with net cash at 31 March 2018 at $29.3m and no debt. 2019’s well programme and immediate development plans are fully funded from cash and cash flow, and we believe SDX’s assets have the capacity to attract debt to fund inorganic growth.

SDX Energy is exposed to generic sector uncertainties, such as volatile underlying commodity prices and currency movements; however, fixed price, long-term gas contracts provide an element of certainty to cash flow forecasts. Subsurface risks relate to SDX’s ability to recover gas and oil volumes in-line with mid-case management/audited estimates. We view key risks as geopolitical, with the company’s assets concentrated in North Africa. Nevertheless, we note that Egypt is a mature hydrocarbon province and both Morocco and Egypt have relatively stable energy ministries and supportive fiscal regimes.

SDX Energy continues to grow its production and reserve base across Egypt and Morocco, and on our forecasts is well placed to achieve net production of 10kboed in 2019. Management has successfully acquired and organically added to its resources over the past two years, creating value for shareholders. Over this period, our RENAV has grown from 70.0p/share in July 2016 to 92.5p/share today. Material organic growth potential remains, which we expect to be unlocked through further drilling activity and with the prospective resource portfolio augmented by two extensive 3D seismic shoots.

Planned development and E&A activity focuses on South Disouq (Egypt) and the Rharb Basin (Morocco). Key elements of SDX’s budgeted work programme include the development of South Disouq (c $15m net); six Egypt explorations wells including the Young oil prospect (c $8.5m net); a 3D survey in South Disouq ($3.5m net); a 12-well exploration programme (c $24m payable by SDX during 2019/2020) in Morocco; Lalla Mimouna tie-in ($4.5m payable by SDX in 2019/2020); and a Gharb Centre 3D survey ($6.5m payable by SDX). SDX has more than sufficient cash and cash flow to fund this work programme and, we believe, will be generating significant excess free cash flow beyond 2018 based on current production forecasts.

SDX’s current production stands at just over 3kboed split across North West Gemsa (1.81kboed), Meseda (0.56kboed) and Morocco (0.66kboed). South Disouq should provide a step-up in group production in late 2018, and SDX remains on track to deliver a target exit rate of 8–10mmscfd (1.3–1.6kboed) in Morocco, which we believe should take group production to c 10kboed in 2019. Longer term, management has an ambition to grow output to c 30-40boed through a combination of organic investment and asset consolidation with the company’s core geographies (North Africa).

SDX Energy is led by an experienced senior leadership team and industry professionals with basin specific knowledge. Lessons learnt from prior drilling campaigns and the use of leading service companies facilitated a safe and successful 2017/2018 drilling programme and we expect in-house expertise to aid in further drilling campaigns, as well as in the identification of acquisition opportunities. CEO Paul Welch has over 25 years’ industry experience and has held positions at Shell, Hunt Oil, Pioneer Natural Resources, and most recently he was CEO of AIM-listed explorer Chariot Oil and Gas. CFO Mark Reid has over 20 years’ experience in numerous sectors, including financial services, investment banking and oil & gas. He has had significant exposure to M&A transactions and the equity and debt capital markets. Most recently, between 2009 and 2015 he was finance director at AIM-listed Aurelian and Chariot.

SDX Energy’s recent exploration and appraisal success at South Disouq provides visibility of a combined c 100bcf (mid-case) development including the SD-1X and Ibn Yunus-1X discoveries. We take a look at recent drilling success, potential regional resource upside, upcoming exploration plans and development plans for South Disouq below.

On the back of 2017 exploration success at South Disouq, SDX has taken a fast-track approach to appraising the discovery, adding additional resource through near-field exploration and engineering a modular development plan that is expected to deliver first gas in late 2018.

The initial SD-1X discovery was made in 2017 and encountered a c 750ft (230m) section of Abu Madi sands. The upper gas-bearing sands were the poorest quality seen across the section (although still averaging 20% porosity) and corresponded to the thinnest seismic reflectors. The company believed that the sands could be of better quality away from the SD-1X location and this was confirmed with the drilling of SD-4X to the east of the discovery well, which found thicker sands with an average porosity of 24%. The SD-4X appraisal well also helped prove a common gas water contact with SD-1X at two distinct reservoir levels across the four-way dip bounded structure. A second and final 2018 appraisal well, SD-3X, is due to be drilled shortly following the completion of operations at SD-4X.

In addition to appraising the original SD-1X structure, SDX also drilled two exploration wells: Kelvin-1X, to the southwest and updip of SD-1X, and Ibn Yunus-1X to the northwest. Kelvin-1X was targeting a stratigraphic trap that the company believed could be connected to SD-1X, but while thick, good quality Abu Madi sands were encountered, demonstrating their lateral continuity, they were found to be water-bearing. SDX believes that the stratigraphic trap was breached at this location and further work is being carried out in order to recognise the false positives as seen in Kelvin-1X. The potential for stratigraphic traps in the Abu Madi remains, but in addition to identifying sand, the company will now work to discriminate between gas and water.

The Ibn Yunus exploration well discovered a new play type with over 100ft of net reservoir sand in the Kafr El Sheik sand, sitting above the Abu Madi sands. The structural/stratigraphic feature demonstrated a strong acoustic impedance response easily identified on 3D seismic. Ibn Yunus-1X was tested at 39.3mmscfd gas and 12bbl/mmscf of condensate with pressure data indicating a connected volume in excess of that suggested by the gas down to (GDT). SDX’s mean recoverable volume of 52bcf for Ibn Yunus-1 is based on a modelled sand pinch-out to the northwest and gas water contact below the measured GDT; however, if the Ibn Yunus-2 development well planned for 2020/21 confirms gas pay to the northwest, we believe that estimates of mean volume have potential to increase materially (SDX estimates a P10 of c 113bcf).

The focus of SDX’s follow-on drilling campaign will be on the Ibn Yunus lookalike prospects, stratigraphic features that are identifiable as amplitude highs on 3D seismic. Mean prospective resource attributable to four drill-ready base Kafr El Sheik prospects is estimated at 70bcf unrisked. As shown in Exhibit 6, amplitude highs indicative of reservoir pay in stratigraphic traps are readily visible on 3D seismic above the Kafr El Sheik, shown as a dark black line (Exhibit 6).

In addition to the four Kafr El Sheik prospects, the company has identified another SD-1X analogue; a four-way dip closure with estimated mean recoverable volume of 17bcf. Edison’s valuation has been updated to include these five drill-ready prospects, but does not include potential incremental upside, which management estimates at over 1tcf. Further prospects are likely to be worked up as SDX acquires and processes a 170km2 3D seismic survey on acreage to the south of SD-1X that is due to commence in Q418. Current 2D data provide clear indication of an extension of the Abu Madi sand fairway to the south of SD-1X, as shown in Exhibit 7 below.

Encouragement for further oil potential can be found in the producing oil fields in the Western Desert, 100km to the west, together with oil shows in four offset wells close to South Disouq. The prolific Western Desert Bahariya and Kharita reservoir sands were encountered at the SD-1X well location; the unlogged Kharita sands showed elevated gas readings, potentially indicating a sign of thermogenic source. Vitrinite reflectance analysis suggests that the Jurassic source rock at South Disouq is present in the oil window and SDX has identified a four-way dip structure with multiple mapped reservoir intervals in order to test the basin for liquids potential. The 50mmbo mean unrisked (four reservoir intervals) Young prospect is expected to be drilled in 2019 – we include Young with a 25% geological chance of success in our valuation (risked value of 7.4p/share). The key risks to oil prospectivity at South Disouq are migration and charge.

The development of discovered resource at South Disouq is relatively straightforward given gas quality, relatively low cost wells and access to state-owned gas export infrastructure. The only downside is realisable gas prices, which are state-controlled and as per company guidance modelled at $2.65/mcf. Despite the relatively low absolute price, management estimates the threshold for commerciality for a gas development to be c 5bcf.

SDX’s planned development for SD-1X and Ibn Yunus based on a combined recoverable volume of 100bcf is expected to cost gross c $25m (excluding sunk exploration), or $0.25/mcf based on a modularised central process unit and pipeline connection to existing mid-stream gas infrastructure. Our modelled South Disouq development makes up c 9% of our core valuation at 6.9p/share.

SDX’s nine-well exploration and appraisal programme at Sebou was a success story, with an 87% discovery rate based on calibrated 3D seismic. Management is confident of a highly repeatable appraisal/development plan in order to secure further gas resource. SDX expects to reach an exit gas sales rate of over 8mmscfd in 2018, with further growth driven by the addition of new customers to the Kenitra gas pipeline network. We take a look at recent exploration success, future appraisal well locations and gas sales growth potential below.

SDX Energy’s ability to locate gas-bearing sands on calibrated 3D seismic has substantially de-risked its capacity to supply current contracted gas volumes as well as future demand growth. Anomalies mapped on 3D seismic with strong negative amplitudes have been proven to be gas-filled sands and careful mapping of prospects and locating wells close to areas of maximum amplitude has reduced the risk of locating uncommercial gas saturations/volumes. Typical Sebou discovery volumes per prospect are 0.8–1bcf; small, but at a well cost of c $2m and a realised gas price of c $10/mcf offer attractive returns. Management estimates a minimum economic volume threshold at 0.3–0.5bcf per well, depending on tie-in distance.

Prospects on the Lalla Mimouna licence to the north of Sebou offer greater materiality. The 2018 LNB-1 gas discovery discovered over 300m of biogenic and thermogenic gas intervals in a channel structure and is estimated to hold an unrisked mid-case volume of 10.2bcf and 55,000bbl of condensate. This was followed by a gas discovery at LMS-1, which discovered a smaller sand package in an over-pressured section and, as in LNB-1, heavy gas shows indicate the potential for a deeper thermogenic source. Over-pressure at both Lalla Mimouna well locations meant that well testing was compromised, with LMS-1 suffering from formation damage due to the heavy mud-weights required to drill into the over-pressured reservoir. SDX expects to return to Lalla Mimouna in order to re-drill (using a modified well design) or side-track the existing well locations in order to prove up gas deliverability.

More than 60 leads have been identified across the basin, targeting unrisked potential in excess of 60bcf. The majority of these leads will be de-risked by existing or upcoming 3D seismic data coverage. A 240km2 3D seismic survey (named the Guebbas 3D) is planned across the Gharb basin and is due to commence in July 2018, with first data expected to be delivered in October 2018. Should this dataset highlight better targets, up to three wells from the 12-well 2019 drilling campaign could be drilled across the area covered by this upcoming survey (these wells will be drilled towards the end of the campaign to ensure sufficient time for seismic interpretation).

We include 12 drill-ready prospects in our valuation, targeting 20bcf of mid-case unrisked resource. We view the Sebou/Gharb centre wells as appraisal/development wells, given the company’s ability to locate gas-bearing sands on calibrated 3D seismic with more than an 80% chance of success. We include this upcoming, 12-well programme and the yet-to-be-tested Lalla Mimouna discoveries in our core value, albeit with an 80% chance of success to reflect the potential for the discovery of some sand packages that fall below the minimum economic threshold for commerciality.

The discovery of thermogenic gas at Lalla Mimouna provides further confidence that deeper oil or gas potential exists within the pre-Nappe. Existing oil discoveries in the onshore Rharb Basin are small and of poor quality in the carbonate/fractured basement reservoir, but SDX would be targeting larger prospects in the Jurassic/Miocene sandstones below the Nappe. Exploration of deeper potential remains at an early stage and is not included in our valuation at this point in time.

SDX’s current gas production in Morocco matches the requirements of its current customer base, with existing producing wells being choked back to match demand and to ensure prudent reservoir management.

SDX’s current gas customer base is dominated by two large customers: Super Cerame, and CMCP, which combined are forecast to consume approximately 6mmscfd of natural gas. Incremental demand is set to come from Peugeot (located within the AFZ), GPC an affiliate of Super Cerame and smaller offtakers with the potential for a significant step-up in demand if SDX were to enter the power-generation market and supply the Kenitra-based, state-owned ONEE power plant.

We base our market demand forecasts on company analysis of identified natural gas customers and SDX’s connection goals for 2018. Combined, these act as the basis for the company’s 2018 Moroccan sales guidance of an 8–10mmscfd exit rate. Demand analysis suggests that piped gas sales have the potential to increase dramatically over the next two to three years.

We see risk around this step-up in gas demand, as it is unlikely that every identified customer would necessarily switch to gas, while some may already have existing long-term fuel supply arrangements. In addition, negotiating with large-scale state-owned entities adds additional risks and complexity. We have risked SDX’s projected market demand forecasts using a simplistic approach applying a 90% chance of success for existing customer Super Cerame’s second plant, a 50% chance of success for new thermal customers and a 20% chance of success for power plant consumers. Our risked demand profile is shown in Exhibit 14, which implies a 2018 exit rate of just over 6mmscfd, growing to 17.8mmscfd over the medium term.

We constrain our valuation of SDX’s Moroccan booked gas reserves and contingent resource by our expectations of market demand with inclusion of the risk factors mentioned above.

Our modelled Rharb Basin (Sebou and Lalla Mimouna) gross cash flow profile is shown in Exhibit 15 below. Management expects operating costs to be largely fixed, with the asset showing significant operational leverage as production rates increase.

Our updated valuation includes a 100bcf gas development at South Disouq and drill-ready gas prospects targeting 87bcf of mean unrisked prospective resource. We also include the Young oil prospect, drilling for which is planned in 2019. In Morocco, we include our estimates of current discovered resource (following the 2017/2018 E&A programme – excluding Lalla Mimouna until well tested). We also include Lalla Mimouna discoveries and 12 planned 2019 appraisal/development wells in our core valuation, as risks are only around individual wells meeting the minimum threshold for commerciality – we include these at a 75% chance of success.

Other key changes include an increase in our short-term oil price assumptions, which move to $71.1/bbl and $67.7/bbl for 2018 and 2019, respectively. Our long-term oil price assumption remains at $70/bbl Brent (2022).

As a result, our RENAV rises from 65.6p/share to 92.5p/share (+41%), with our core value standing at 79.8p/share. We note that our valuation has a significant core value component at 86% of our RENAV.

A full breakdown of our risked valuation is provided in the table below. We split our valuation between core value, which includes booked 2P reserves, recent discoveries and low risk development upside in Morocco. We include risked development upside at Meseda and Gemsa and risked exploration potential at South Disouq in our risked exploration NAV (RENAV).

The waterfall diagram below shows our valuation relative to the current share price.

Non-executive chairman: Michael Doyle is a professional geophysicist with more than 35 years’ industry experience and was a founding director and chairman of Madison PetroGas from its inception in 2003. Mr Doyle is a principal of privately held CanPetro International. Mr Doyle was previously a principal and chief executive officer of Petrel Robertson, where he was responsible for providing advice and project management to clients throughout the world. Prior to that, he held a variety of exploration positions at Dome Petroleum and Amoco Canada.

CEO: Paul Welch has over 25 years’ industry experience and has held positions at Shell, Hunt Oil, Pioneer Natural Resources, and most recently he was CEO of AIM-listed explorer Chariot Oil and Gas. Mr Welch graduated from the Colorado School of Mines with a master’s degree in Petroleum Engineering. He also holds an MBA in Finance from the Southern Methodist University in Dallas.

CFO: Mark Reid has over 20 years’ experience in numerous sectors including financial services, investment banking and oil & gas. He has had significant exposure to M&A transactions and the equity and debt capital markets. Most recently, between 2009 and 2015 he was finance director at AIM-listed Aurelian and Chariot. Prior to this, he worked at BNP Paribas Fortis and Ernst & Young Corporate Finance advising on M&A, IPO and other fund-raising transactions. Mr Reid has an MBA and is a member of the Institute of Chartered Accountants of Scotland.

Country manager – Egypt: Albert Gress has over 30 years’ experience, primarily in the oil & gas industry, having recently been VP business development for TransGlobe Energy after running TransGlobe's Egyptian Operations. Previously, Mr Gress led Egyptian operations for Cepsa and Devon Energy subsequent to starting his upstream career with Apache in Egypt. He has considerable experience in acquiring oil & gas assets in Egypt. Mr Gress is certified as a public accountant, having spent 10 years with PwC, mostly serving energy clients, in the US and the Middle East, after graduating from a private university in Buffalo, NY.

Country manager – Morocco: Lonny Baumgardner has over 25 years’ experience in oil & gas. His career commenced as a drilling engineer in Canada. Mr Baumgardner started his international experience in Saudi Arabia, and has since worked in Tanzania, Greece, Australia and Egypt. Mr Baumgardner has a broad spectrum of technical, operational and general management experience.

Company specific risks and sensitivities

Generic sector risks and sensitivities

Based on current forecasts of production and capex, SDX is highly FCF-generative – largely driven by high-margin production growth in Morocco but also from the development of South Disouq. Meanwhile, Egyptian oil assets are benefiting from relatively high oil prices in the short term.

SDX remains debt-free, and current forecasts of cash movements suggest significant capacity to increase the pace of investment, pursue value accretive transactions and/or return cash to shareholders.