SDX Energy — Update 26 July 2016

A combination of new wells, workovers and water flood has the potential to increase net production from SDX’s two producing assets (Meseda and NW Gemsa) materially by the end of 2016. At Meseda, production may double to 8mboe/d while work at NW Gemsa aims to maintain production levels. These measures should increase free cash flow for reinvestment in exploration and development – South Disouq, targeting 65mmboe (best estimate), is likely to be drilled around the turn of the year – and puts the company in a strong position to add inorganically in North Africa.

We value the company on a DCF-basis, using our long-term Brent assumption of US$70/bbl (after a recovery from current levels) and a discount rate of 12.5%. We risk the results of the development programme (workovers and water flood) at Meseda and Gemsa to arrive at a core value of 41p/share (C$0.71/share). This provides a solid foundation for investors well above the current share price of 20.5p/share, which should increase as the results of the workovers and water flood are confirmed with higher production, to 56p/share (C$0.96/share).

Additional value at South Disouq could be material (given a high working interest and cheap/fast development concept) should exploration be successful.

SDX Energy is a rare beast among London-listed E&Ps in being cash-flow positive after 2016. The combination of the current cash position (US$14m post AIM fund-raising) and cash flow from its producing fields means that SDX should be in a sound financial position after the US$17m of capital investment in 2016. Assuming the company proves its technical capability by executing successfully on its plans to boost production at Meseda and Gemsa, cash flow should be enough to largely fund any development at South Disouq (assuming exploration success). Some external capital may be sourced to plug the shortfall if required, though the company has a number of options.

The management has a clear ambition to use the current portfolio as a springboard to grow the company into a much larger player. Its advantaged position (solid relationships with the government, the large number of smaller players in Egypt and the support of shareholders) means it can be a credible acquirer.

The value of the company is heavily dependent on the results of the 2016 work programme, the oil price and the investor’s chosen discount rate. There is value in the shares without the production uplift from the 2016 work programme, though this would increase markedly if we assume a fully successful increase in production. Until the programme is complete, we will risk the results of the capital programme, but note that it is neither expensive nor complicated technically. Our core NAV would move 12% for every US$10/bbl move from our US$70/bbl long-term oil price, while a 2.5% move in discount rate would result in an 8% increase (decrease) in value.

SDX is an AIM and TSX Venture Exchange listed company focused on E&P activities in Egypt, and holds interests in two producing assets (Meseda and NW Gemsa), which produce close to 4mb/d and 8mboe/d respectively (gross). The company has already started a low-cost, high-return programme at each field to increase production materially (at Meseda) and maintain production (at NW Gemsa). It was formed from the merger of Sea Dragon Energy and Madison Petrogas (a private company) in October 2015 and listed on AIM in May 2016.

The tables below indicate the net reserves for SDX, though we expect the work programme and production in 2016 to have a material impact on these numbers.

Meseda is located in the West Gharib area, around 250km south of Cairo and 10km from the Gulf of Suez. SDX holds 50% WI in the field, which came onstream in November 2011.The field contains gross 2P reserves of 12.8mmboe and is currently producing around 4mb/d. The reservoir at Meseda is the Miocene Asl sands, which produce heavy 17-20° API oil from 13 wells and with watercuts approaching 50%.

Fluid production is tied into a central production facility capable of handling 20mb/d. These fluids are then trucked to a Government Petroleum Company (GPC) processing centre 18km away. Produced water is re-injected into the field. With high watercuts that will only increase, a key consideration is enlarging liquids processing capability.

The company carried out a number of studies including geological modelling, a well performance review and sub-surface modelling and identified the potential to improve field development through workovers and water flooding. The wells require artificial lift to produce to surface and SDX believes that most of the electrical submersible pumps (ESPs) used for this purpose are incorrectly sized and/or have mechanical issues. This was due to a one-size-fits-all approach by the previous operator, which resulted in poor performance of the pumps (causing emulsification of the liquids). The company has shown with a test pump in a well that bespoke design can have a marked effect on production.

An 11-well workover programme has been planned for 2016 to remedy this, with the first four-well programme recently initiated. In conjunction with the workovers, the company also plans to drill four infill wells and two water injection wells in order to be able to commence water flooding the reservoir. This leads to a number of possible production scenarios for Meseda that we can value:

The company points to a number of other prospects that could add to production. The Yusr and Rabul prospects have been mapped to the north of the concession and have a combined 1.7-19.9mmboe OIP (p10-p90). The company classifies the potential to be moderate with recoverable volumes of c 2.5mmboe.

The company is also working on possible deeper horizons. The Nubia prospect is in a deeper horizon that produces prolifically in the Gulf of Suez. The company believes it could be the size of Meseda, which would make it around 18mmboe (assuming original Meseda recoverable reserves, rather than reserves remaining as of December 2015).

SDX acquired a 10% WI in NW Gemsa in 2009. The concession consists of three onshore oil fields, Al Amir SE, Geyad and Al Ola, all located in the Eastern Desert close to the Gulf of Suez and around 300km south of Cairo. Together the fields hold gross 2P reserves of 9.43mmboe and currently produce just under 8,000boe/d.

Al Amir SE and Geyad produce from two Miocene age reservoirs, the Shagar and Rahmi sandstones. Both reservoirs contain a number of NW/SE trending faults and the sands tend to thin to the east.

Al Amir SE has been producing since early 2009 and provides the bulk of production from the concession. The field contains 26 wells of which five were still producing from the Rahmi and six from the Shagar at the end of 2015. Two further wells were drilled and brought onstream in H116 and together with workovers on nine wells planned in 2016 is expected to keep production at a plateau of 8,000boe/d. Geyad has also been producing since early 2009 and currently produces over 1,000boe/d from four wells with a higher watercut than that seen in Al Amir SE. SDX commenced water injection in Al Amir SE and Geyad in 2011 and 2012, respectively, to maintain reservoir pressure and increase recovery.

The central processing facility (CPF) at NW Gemsa is designed to handle up to 15mb/d and 20mmscf/d. This is comprised of three 5,000 barrel storage tanks; three-phase production separators with a capacity of 15,000 barrels per day; a three-phase test separator with a capacity of 6,000 barrels per day; a gas boot for oil stabilisation; a gas compression package; a common flare system; oil shipping pumps; a power generation system; an API water separator and lagoon; and a firefighting system. Gas from the separator is dehydrated, compressed and transferred to the Suco gas facility, while NGLs are separated and added to liquids for sale.

Unitisation: The Gemsa field is not totally within the block boundary owned by SDX and as such is subject to unitisation (where an equitable resolution has to be arrived at to share a field’s production over multiple owners/blocks). This has not yet been settled, though the company believes it may be complete by year end. The effect on SDX’s net reserves is not clear, but we do not believe it would be material given the number of wells inside/outside the block boundary. For the moment, we assume existing reserves assumptions in our modelling.

Around US$8m (gross) is being invested in the field in 2016 and again in 2017 to try to keep production at the current levels. After this activity, production may be steady in 2017, but will probably start to decline by 2018, after which we expect little incremental investment. Instead, the field will produce free cash (of between c US$1.5m and US$3m), which the company will reinvest.

SDX acquired 100% WI in South Disouq as part of the 2013 bid round and subsequently farmed-out 45% to its partner IPR (see below). The block sits in the gas prone Central Nile Delta Basin, around 70km north of Cairo. The company has identified the Abu Mahdi prospect on 2D seismic and this was independently assessed by DeGolyer & MacNaughton in December 2015 to contain best estimate gross prospective resources of 313.8mmcf. The prospect is a combination structural stratigraphic trap and the company acquired 300km2 of 3D seismic between March and June 2016 to allow further definition of the prospect so that a target location can be drill ready for the end of 2016. The cost of drilling the well will be fully carried by SDX’s partner IPR, a Dallas-based private company with existing net production in Egypt. The current chance of success (CoS) of 13% is based on the existing 2D data. However, we would expect this to be updated following the interpretation of the 3D seismic where acquisition activities were completed in June. Processing is underway and is anticipated to be completed in September of 2016.

Importantly, in the event of a discovery here, the concession sits in an area of existing gas infrastructure and the company estimates that first production can be achieved around 60 days after reaching TD in the well. As long as the gas does not require too much processing, this should lead to a low capex development that can move into net cash flow generation reasonably quickly.

Egyptian gas prices vary hugely depending on field age, status and location as well as gas type. Associated gas is generally priced very poorly, and offshore gas attains higher prices than onshore. The widening gap between supply and demand has led the government to increase prices for younger fields and new discoveries in an effort to spur investment (and reduce reliance on expensive LNG imports). As a result, industrial prices vary between US$5.4-7.1/mcf, while national grid prices are lower. We assume a mix between national grid and industrial pricing, arriving at an assumed price of US$4.5/mcf.

Assuming this pricing, and around 16% condensates, 2018 average production of 9.3mboe/d would produce around US$107m in gross revenues on our modelling, or US$29m in cash inflows for SDX. This could be attained with relatively little capex (we assume well costs of US$3m), and would easily fund any further capex in the field.

We believe that many investors will be concerned about the receivables situation for SDX, given the heightened perceived risk in Egypt for oil and gas companies. Many companies with material Egyptian production have experienced long-dated receivables balances over recent years (Apache and TransGlobe among them). However, the receivables due to the oil companies in Egypt have shrunk markedly since 2012-13 (eg TransGlobe’s receivable was US$150m in 2013 but now stands at US$22m). The company is happy to receive payments in Egyptian pounds, rather than US dollars; this is important as we note that Circle Oil’s recent announcement stated “US dollar payments from EGPC have continued to be unpredictable and to date there has not been a sustained improvement”. As a result, we do not see the receivables as a great concern for SDX; normal collection for receivables is 30-60 days, well within normal global standards.

SDX had receivables of US$5.7m as at end March 2016 composed of US$5m of trade receivables (US$1.0m for NW Gemsa oil sales, US$0.9m for Meseda service fees and a US$3m receivable linked to Shukheir Marine). This US$3m at Shukheir Marine will be collected once SDX satisfies its work programme obligations at South Disouq; the 3D seismic programme will trigger a full repayment, which is expected to be received before the end of the year.

President Abdel Fattah el-Sisi took office in June 2014 and has overseen a period of relative stability. The country was expected to grow consistently at more than 3% out to 2020 (as of April 2016) according to the IMF.

In March 2016, the Egyptian pound was devalued by 14% against the US dollar (to 8.878) to increase competitiveness, which should help the opex costs for SDX and other oil companies (this rate hovered around 6 from 2006-12). The full effects of recent terror events on tourism and the wider economy may mean the government is keener to get other areas of the economy contributing more.

This still leaves Egypt in the higher-risk category for investment. It is in the lower half of global transparency scores and ease of doing business scores.

In Egypt, there are a large number of small players each participating in a limited number of licences. The falling oil price over the last two years has meant many could be feeling financial distress. This means there is strong potential for consolidation in the country.

SDX is positioning itself as a potential acquirer, and its positive cash flow (even to low oil prices) and supportive shareholder base means that it has a secure foundation for acquisitions.

The company drilled the Manatee-1 well in its West Bakassi Block in Cameroon. In March 2016, it was announced that it encountered 26m of gas bearing pay sands. This gas discovery combined with two others on the block were not deemed sufficiently commercially attractive, and in June the company announced that it was withdrawing from the concession. We expect the company to write-off the investment in this block at the next opportunity.

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: Ahmed Farid Moaaz has over 30 years’ experience in the industry. Mr Moaaz has held senior positions with international oil companies with operations in Egypt, including Suez Esso, Trident and El Wastani. Mr Moaaz is a former deputy chairman for production of EGPC where he was responsible for supervising and directing drilling production and petroleum engineering of all joint venture companies operating in Egypt.

We value E&P companies using an asset-by-asset NAV derived from detailed DCF modelling. 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 18 months. SDX is a producer, and despite the lower oil prices it generates free cash flow. This puts it in a good position vs peers and should provide investors with a level of comfort and valuation floor.

We apply risking that aims to take account of geological, technical and commercial uncertainties. If a company lacks funding or production that could provide cash for development, we assume a dilution of its WI to get through appraisal/development in anticipation of the reduction in value due to financing. This dilution is impossible to accurately estimate, and so we arbitrarily apply a 50% commercial CoS (this is consistent across our coverage universe) for unfunded development – this is not the case for SDX given its cash flows. As such, our normal overall CoS applied for unfunded appraisal/development projects would therefore be materially lower than any geological CoS for exploration.

We assume real US$70/bbl long-term inflated for Brent (after a recovery from current prices), with country and field specific assumptions to cover quality discount, transport costs and other factors. In particular, we assume a 9.5% discount to Brent for the light oil at NW Gemsa, and a larger discount for the heavier oil at Meseda (decreasing as oil increases).

Scenarios: the company is investing NW Gemsa and Meseda with new wells, workovers and water flood. These strategies have the potential to increase production and value markedly, but the outcomes are not certain. As a result, we (incrementally) break down the value of each of these strategies to enable investors to adjust for their own risk estimates. We expect to see substantial signs of success of the work programme in H216, with results more fully visible in 2017.

This analysis indicates that the current share price of 20.5p is supported by the current cash position, the base case at Meseda (natural declines from now) and NW Gemsa 1P reserves totals 26p/share (C$0.45/share). This leaves substantial upside possible for investors within the core NAV, driven mostly by additional production at Meseda. The exploration well at South Disouq (planned for Q416) could add very materially to the company value, and we expect an update on the prospect (particularly the CoS) once 3D seismic analysis and interpretation is complete.

As a producer, the assets are exposed to the current oil prices to a greater extent than long-dated exploration. The oil price has been volatile of late and there is a great level of uncertainty over what the long-term price of oil may be. As a result, we show two types of sensitivity. The first shows the cash flow sensitivity to oil pricing in 2016-18, with a longer-term NAV impact of oil pricing.

We assume the gas prices in Egypt are on a long-term basis and are not affected by any oil price changes. As a result, the value of South Disouq will be largely un-affected by oil price movements.

The WACC employed is key and we would encourage investors to be happy in the rate they choose to employ. We believe the financial position of SDX, with free cash flow from 2017, means it should be assessed on a notably lower WACC than other peers engaged in equity-funded exploration.

We made a detailed assessment of E&P costs of capital that implies the equity costs are well above 15% in the E&P space, and so reducing its need to source external capital is a key point in keeping costs of capital down.

It is clear that the work programme in 2016 could see a step change in the value and cash flows. It is useful to see this impact, we think. If we assume the Gemsa workovers are successful enough to de-risk this fully, and that the water flood programme could move the CoS from 40% to 80%, and move the discount year to 2017, the core NAV could move from to 41p/share (C$0.72/share) to over 70p/share.

We would also note that the value of the company in the long term will be built on cash flows denominated in Egyptian pounds, and that investors will eventually need to see this value moved to US dollars to realise any value (through dividends for example). We explicitly assume that there is no further movement in currency rates over this time and that US$/EGP are essentially fungible; that may not be the reality.

After the merger with Madison and the AIM listing, the company has 79.4m shares in issue. There are also 611k warrants outstanding, which expired earlier in July 2016.

In March 2016, the company held US$8.7m in cash and had no debt. In May, the company listed on AIM and raised £7.6m (US$11m) at 18p/share, leaving it with US$14m in cash. An additional US$1.4m of working capital adds to the financial position. As can be seen below (using the position at December 2015), the vast bulk of these resources are in US dollars, insulating it from the recent UK pound move following the Brexit vote. Indeed, the weaker UK pound reduces the G&A overheads (in US dollars).

The question is how this cash will be deployed. We model net capex in 2016 to be US$16.7m, with the split as follows:

2017 capex expectations – revolves on South Disouq results

The company’s cash flow is sensitive to prevailing prices. Given the cash flow requirements to develop any successful exploration it is important that investors are comfortable that the company can fund capital investment at a range of oil prices and scenarios.

Capital investment in 2017 should be notably lower at the producing fields in 2017 as the vast bulk of workovers and water flood work should have been completed. This leads to capex in NW Gemsa and Meseda at under US$2m in 2017, and a move to free cash flow generation. In fact, the company will be generating free cash flow in 2017 from NW Gemsa and Meseda even at Brent of around US$30/bbl.

Importantly, if the South Disouq exploration well is successful and development capital is as we currently model, the company could require capital during 2017 (once we consider the timings of cash flows during the year of investing capex before resulting cash flows). In our base case of higher production at Meseda and NW Gemsa, this is not likely to be a large amount, but investors should be aware of this possibility.

If successful at South Disouq, we expect the management to look to develop the field as quickly as possible, with gross capex of [US$32m], or a net capex of [US$17m] in 2017. This compares to expected cashflow generated from NW Gemsa/Meseda (assuming successful well interventions at both fields) of US$8m (including central company costs). We expect South Disouq production to add a further US$10m in cash flow during the year, but even with this contribution, it is possible that there is a cash flow mismatch in 2017, whereby cash flows are not enough to fully fund investment in 2017, especially given phasing considerations.

There are a number of avenues the company can pursue to overcome this:

Debt: With NW Gemsa and Meseda throwing off plenty of excess cash, the company may look to raise some debt to cover the development expenditure at South Disouq. As an example of how affordable this may be, if the company raises US$10m of bank debt (which should be enough to cover the shortfall) at an interest rate of 15%, the EBITDA (ex-South Disouq earnings)/interest cover in 2017 is 9x. Even if we assume a Brent price of US$43/bbl in 2017, this falls to 6x, while in a worse scenario (of US$43/bbl and Meseda and NW Gemsa programmes having little effect on production), this falls to 0x, but recovers quickly in 2018.

As long as debt markets are open, we would expect this to be the first option examined. This is complicated by having cash flows from production in Egyptian pounds, which are not as easy to convert to US dollars as other currencies. We would expect any debt to be originated in Egyptian pounds, though the market is likely more difficult and the resulting interest rate could be higher than the company could attain in other markets. However, we believe that 15% is on the conservative side and the company may be able to attain rates below 10%.

Delay/prolong development: SDX is the operator of South Disouq and are therefore has veto over the timelines of the development (albeit with agreement of its partner). The company could therefore look to match its cash outflows with cash inflows. This would negate the need for external cash flows, but would reduce the NPV of the project.

Farm down of South Disouq: With very low capex intensity and quick development at attractive gas prices, we model that South Disouq has a project IRR of over 70% (and over 35% even if we double both opex and capex). As a result, it should be an attractive project for a partner. Should SDX look to reduce its holding in return for a total net development cost carry (in the first two years of major capex in this instance), it would still retain the vast majority of the value. If the incoming party requires an IRR of 25%, it would sacrifice a 13.5% gross working interest (or a fifth of its current working interest of 55%). Importantly, because of the carry, it would retain over 90% of the value. This option has the potential to lead to delays given the farm-out process is not typically the fastest to complete.

Equity: Given the cost of equity is likely to be the highest of all options, we expect this to only occur if the other options were not available or the share price after the discovery had reacted extremely positively. Given the financial position of the company, we do not expect this to be required.