SDX Energy — Record production and material prospectivity

SDX achieved record average entitlement production of 6,980boed in H120, up from 4,062boed for FY19, mainly due to the strong ongoing performance of South Disouq. The two well drilling campaign here was completed during the first half of 2020 and the SD-12X well discovered commercial gas in the Sobhi prospect, estimated at c 24bcf recoverable dry gas resource by management, while a further potential 233bcf across six prospects has been identified. In Morocco, the drilling campaign was completed by March 2020, having delivered seven discoveries from nine wells drilled, while the 10th well, LMS-2, is awaiting testing in order to establish commerciality. The campaign confirmed the prospectivity of SDX’s acreage to the north of its existing core production and development area, with discoveries at OYF-2 and BMK-1, de-risking c 20bcf of P50 recoverable resources.

The company is guiding that oil and gas production for FY20 will be 6,000–6,267boed, down from the June 2020 guidance of 6,750–7,000boed. This reflects the impact of the disposal of North West Gemsa in July 2020 together with the temporary production shut-ins experienced in Morocco. However, this is c 50% higher than actual 2019 production. Moroccan production guidance has been reduced from 6.7–6.9mmscfd to 5.3–6.0mmscfd (in line with our last estimates at 5.95mmscfd). 2020 capex guidance was also reduced by $2m to $26.2m due to the removal of the workover costs from North West Gemsa. The bulk of the capex ($21.9m, unaudited) has already been spent in the early part of the year on the drilling programmes.

An extended well test of the SD-12X Sobhi well (see our May 2020 update for a discussion of the drill stem test results) established that Sobhi holds c 24bcf of recoverable resources. Management anticipates that the well will produce at an optimum stabilised rate of 10–12mmscfd, in line with the nearby producing Ibn Yunus-1X well. Sobhi is expected to be tied into the South Disouq central processing facility (CPF) via a 5.8km connection to Ibn Yunus-1X at an estimated cost of $3.5m, and to commence production in Q121.

Following on from the Sobhi discovery, SDX has undertaken a review of the remaining prospectivity in South Disouq to identify material, low-risk prospects, and has predominantly focused on the de-risked basal Kafr El Sheikh (KES) proven by the successful discoveries in Ibn Yunus and Sobhi. The company has identified 233bcf of recoverable volumes, estimated by management, across six prospects, and dominated by the 139bcf Hanut prospect that was recently identified. The company is planning to start drilling operations in Q2/Q321.

On this basis, SDX is planning to accelerate its drilling campaign, originally expected late 2021/early 2022, into Q2/Q321. This will be subject to the final Ministerial and Parliamentary approval of the two-year extension to the South Disouq exploration area, which has already been approved by EGAS. SDX’s 45% partner, IPR Energy Group, has yet to confirm it would participate in the proposed extension.

If the extension is approved, the 2021 drilling campaign will consist of two commitment wells, Hanut and Mohsen, targeting 165bcf in the Basal KES. Both prospects sit to the south of South Disouq and close to the existing infrastructure. Both also carry management estimated high chances of success for exploration wells, with Hanut on 33% and Mohsen at 51%, because the KES has already been de-risked at Ibn Yunus and Sobhi. A further KES well, Warda, is scheduled for late 2022.

In West Gharib, in the Eastern Desert, the company is planning an infill drilling campaign to recover 2.3mmbbls of contingent resources. Between eight and 10 wells are planned over the next three years, with two to three wells due in 2021 and three to four wells per year thereafter. The operator, Dublin International Petroleum, is seeking a licence extension beyond 2021 to allow this activity to go ahead.

The company’s Moroccan drilling campaign was successfully completed in March 2020, with 10 wells drilled and seven discoveries from nine wells. The testing of the 10th well, LMS-2, is expected to be carried out once a crew can be mobilised post the lifting of COVID-19 travel restrictions in Morocco. The final two wells of the original 12-well programme were deferred to preserve capital, given that the campaign objectives were met with the first 10 wells.

Two of the five close to infrastructure appraisal/development wells were drilled in Q120. The first of these, SAH-5, was sub-commercial and was plugged and abandoned. The second well, SAH-3 encountered 0.5bcf recoverable resources as estimated by management and will be tied into existing infrastructure later in 2020. The two moderate risk wells, OYF-2 and BMK-1, both encountered gas, confirming the extension of the core area to the north and de-risking up to 20bcf of adjacent P50 prospective resources. OYF-2 is assessed by management to hold recoverable resources of 1.3–1.9bcf, with 0.9bcf of gas recoverable from BMK-1. The LMS-2 well, in the Lalla Mimouna concession, was the highest-risk well drilled in the campaign and encountered 10.6m net gas with a porosity of 30.9%. The well needs to be tested to be properly assessed as gas samples from the well indicate a new and different source rock is generating gas of a different thermogenic composition to that seen in the company’s core area. Testing will be carried out as soon as COVID-19 restrictions allow

Management estimates that over 18bcf of de-risked prospectivity sits across five clusters in the OYF/BMK area and is looking to accelerate a four-well drilling campaign in 2021 to confirm this potential. The programme could also include a well to assess the Top Nappe exploration potential, where gas was encountered while drilling LMS-2. This will hinge on a successful outcome for the LMS-2 well test, but the company would then evaluate options for a dual target well to penetrate the Top Nappe and a shallower biogenic target. A re-interpretation of existing 3D seismic has highlighted that the Top Nappe is present across the acreage, including in the core areas close to infrastructure, so confirmation of the Top Nappe concept could increase the resource volumes in the area.

We value SDX using an asset-by-asset net asset value (NAV) derived from detailed discounted cash flow modelling. The core value includes production, development and contingent resources that could be developed, while exploration is valued only if wells are planned and funded in the next 12 months. We apply a 12.5% discount rate given the geographical distribution of the assets and the size of the company. We have updated our short-term commodity prices based on the latest EIA estimates. Our short-term Brent assumptions move from $33.0/bbl to $41.9/bbl in FY20 and from $45.6/bbl to $49.1/bbl in FY21, based on EIA forecasts published in September 2020. Our long-term price assumptions remain in line with the previous note where we presented three scenarios with Brent in 2020 at $40/bbl in our low case scenario, $50/bbl in our mid-case scenario and $60/bbl in our high case scenario, escalated at 2.5% per year resulting in 2022 prices of $42.0/bbl, $52.5/bbl and $63.0/bbl, respectively. We continue to assume Moroccan gas prices of $10.85/mcf in 2020 inflated at 2.5%. In addition to commodity prices, key changes to our updated valuation and estimates include the updated FY20/FY21 production and capex guidance and lower G&A costs.

In Egypt, our updated valuation now excludes North West Gemsa as the company successfully disposed of the asset in July 2020 for net proceeds of $1.6m. At the same time, the updated valuation includes the Sobhi discovery, added to the core NAV since it is a simple tie-back to the CPF. In Morocco, we continue to include the reserves reported at 31 December as per the FY19 annual report as well as the SAH-3 and OYF-2 wells, which were already completed as commercial discoveries during Q120. For 2020 we maintain our estimates in Morocco with a gas production level of 5.95mmscfd for the year, in line with the new guidance of 5.3–6.0mmscfd. Risked exploration includes the BMK-1 discovery and the potential 10bcf located in close proximity to the BMK-1 well, and the LMS-2 discovery. The LMS-2 well indicates 10.6m of net gas reservoir with 30.9% porosity in the well; however, testing is required to determine its commercial potential once COVID-19 restrictions are eased and allow SDX to bring a testing crew into the country. We highlight that at this point we are not taking into consideration the 233bcf prospective resources of potential additional upside that is currently being evaluated by the company in the South Disouq area; however, as these projects develop and become firmer within the SDX budget, we will update our valuation accordingly. All in all, our mid case risked exploration net asset value (RENAV) moves from 40.7p/share to 45.0p/share (+11%), with our core value standing at 37.1p/share, equivalent to 82% of our RENAV, and materially different from the current share price of 17.5p/share. Overall, our core net risked valuation increases by c $11m versus our previous note, predominately reflecting lower SG&A estimates and the inclusion of net proceeds for the North West Gemsa disposal.

H120 included the benefit of production from South Disouq, brought onstream in late 2019, which helped push H120 net revenues to $22m from $15.5m in H119. Meanwhile, with net investing cash outflows easing, and a $1m advance on the North Gemsa asset sale, SDX ended June 2020 with net cash of $9.3m. Unaudited net cash at end 30 September 2020 stood at $9.2m. We forecast year-end 2020 net cash of $11.8m and note that SDX’s European Bank for Reconstruction and Development (EBRD) loan facility of $7.5m remains undrawn. Management intends to extend the tenor and re-establish the full availability of the $10m credit facility. Based on the capex projections that underpin our production forecasts and SDX’s committed exploration programme, the company is fully funded for 2020 and 2021 and we forecast positive free cash flow (FCF) from H220. Given the current capital expenditure plan (based on Exhibit 4), we have brought forward some of the capex for wells to be drilled and connected in Morocco from 2022 to 2021, compared to our previous note. We are still not taking into consideration the capex for the South Disouq wells given that these are still contingent on final Ministerial and Parliamentary approval of the two-year extension to the South Disouq exploration area. We expect FCF in the coming years to be material giving the company headroom for additional investments. As over 85% of cash flows in the coming years will come from the fixed price contracts gas businesses, we currently do not foresee the need for further equity capital, unless incremental growth capex, over and above our forecasts, is dedicated to new projects or acquisitions. Management’s stated strategy is to grow the company both organically and inorganically.