Monday, 30 January 2017

SDX Energy's acquisition of Circle's Moroccan assets - summary

By Will Forbes

SDX Energy’s accretive $30m acquisition of the Egyptian and Moroccan assets from Circle Oil is a major step to increase the company’s footprint and is in line with its stated ambition to grow (in)organically. The Moroccan gas production in particular is a step-out from its existing base, but provides strong cash flow generation, quick effective payback and the possibility of future high-value development and exploration. The increased working interest in NW Gemsa should boost SDX’s share in FCF in Egypt, and further contribute to costs for the upcoming waterflood programme. We increase our core NAV from 39p/share to 42p/share (RENAV moves from 68p/share to 57p/share) even after some (unrelated) modelling adjustments. Despite a recent increase in the shares, this suggests further upside for investors in a larger company with greater ability to invest in high-value projects in North Africa.

Accretive acquisition

The acquisition should be accretive to shareholder value, despite the share dilution connected with the announced $40m capital raising. The associated working capital connected to the acquisition (as well as not taking on any of Circle’s debt) reduces the effective (core) metrics to $3.5/boe (compared to SDX’s pre-deal metric of $4.6/boe pre-acquisition at 30p/share). We value the acquired assets at $70m (on a core basis), implying that SDX obtained them at a c.60% discount.

Acquisition increases SDX footprint

SDX has always been actively looking to grow inorganically and the US$30m purchase of a 40% stake in NW Gemsa (Egypt) and 75% in Sebou (Morocco) production (including approximately US$18m in working capital) is a strong first move. The new assets are strongly cash generative and could add around $20m of cash flow in 2017 and 2018 (each year, including working capital movements) and with an effective IRR of over 50% and a 1.5 year payback on the acquisition price.

Valuation: Accretive deal increases core NAV to 42p

We have folded the new assets into the existing portfolio, which increases our indicative core NAV to 42p/share (from 39p), while our indicative full NAV (including a risked 7p valuation for the South Disouq exploration well and possible upside from Meseda waterflood) is now 57p/share. SDX is now a larger company with strongly positive cash flows in the near term, and can use these to further explore in Morocco, develop a discovery at South Disouq or to grow further inorganically. It retains the ambition to grow in North Africa towards a production rate of 25-30mboed.

The full note is available here

Friday, 27 January 2017

EnQuest acquisition: ability to extract net economics (NAV) will be demonstrated over time

By Sanjeev Bahl

EnQuest’s agreement to take over operatorship of Magnus, SVT and associated infrastructure is a material operational undertaking, especially when considered in parallel with commissioning and ramp-up of production at Kraken. The transaction will involve EnQuest taking on several hundred onshore and offshore staff and contractors. With this in mind EnQuest’s stage approach which involves taking on just 25% of Magnus and an additional 3% of SVT at the out-set appears to be sensible. The combination of deferred consideration payments, a ‘call’ option on additional equity in the transaction assets and downside protection mechanisms suggest that EnQuest is backing its ability to maximise value from late life assets without exposing shareholders to potential downsides. EnQuest has until 15 January 2019 in order to exercise its option over an additional 75% of Magnus and related transaction assets giving it time to understand the operational complexities as well as study decommissioning options before taking on risk. 
The net economics of the transaction (and net NAV impact) will be largely driven by EnQuest’s ability to reduce opex costs from current levels (we estimate that these may currently be around current spot oil prices)  by increasing oil production and production efficiency, increasing oil recovery (significant potential exists in the Kimmeride Clay where current oil recovery is just 30%) and through deferring and reducing decommissioning costs. From an opex perspective there is a material opportunity to reduce Magnus onshore costs and overheads as well to leverage logistical synergies (supply vessels and helicopters) in order to bring down costs closer to group levels (c.25$/bbl).
Given the size of the Magnus platform (over 70ktonnes), decommissioning is likely to be an important consideration when it comes to deal value. Prior to exercising its option, EnQuest’s liability is restricted to the maximum of 7.5% of BP’s actual post-tax decommissioning cost and cumulative positive cashflows from the transaction assets. On exercising its option, it’s exposure is uncapped on the additional 75% it would acquire of Magnus. 
The deal does come at a price. In the event of option exercise whereby EnQuest acquires 100% of Magnus, 9.1% in SVT, 27% in the NLGP and 11.5% in NPS, BP will receive 100% of net cash flows from the transaction assets until the non-cash consideration of $285m is recovered. This is followed by a BP cash-sweep of 37.5% of net cashflows until a further $1bn is recovered. Shareholders will need to be aware that whilst the anticipated step-up in production from Kraken in H217 will drive a corresponding step-up in cashflow from operations, EnQuest expect it will take around 2 years (at current oil prices and assuming a 3 well programme on Magnus) to see a cash benefit from the transaction assets.  Depending on the tax structure of the deal it does sound like BP is benefiting from EnQuest’s fortunate tax position (we do not expect EnQuest to pay cash tax on Magnus) - BP is divesting of an asset whilst still receiving a significant percentage of transaction asset cashflows in the early years that are protected from cash tax through EnQuest’s historic tax shield.
The transaction highlights EnQuest’s confidence in its ability to drive the recommendations of the Wood Review, maximizing economic recovery from late life assets, and the use of innovative transaction structures in order to facilitate the transfer of mature assets from the hands of the majors to ‘leaner’ operators. EnQuest analyst NAV upgrades are understandable, but we expect there to be significant uncertainty over the pace of opex reductions as well and the timing / cost of decommissioning (we believe the gross decommissioning cost for Magnus and the transaction assets could be well over $700m) which will ultimately drive net economics. With EnQuest now on the verge of producing over 50kboed we expect management focus to shift from growth to operational execution in order to extract maximum value from its expansive asset/resource base.

Wednesday, 25 January 2017

Tullow's cost of capital: Uganda farm-out implies a return for Total of 19%

by Will Forbes

Tullow's Ugandan farm down to Total caused very little market reaction, with analysts calling the deal roughly market neutral. The stock price is now relatively unchanged vs pre-announcement (although this also includes the impact of TEN production cuts announced in the trading statement a couple of days later).

We don't formally cover Tullow, and do not seek to give an investment recommendation. However, we have run our internal numbers on the acquisition with a view to furthering our work on industry implied costs of capital (see previous blog posts on deals including the late-2016 Ophir FLNG restructure).

From the point of view of Tullow, this seems a good deal - reducing its cash outflows for the next few years, reducing its finance risk in the run up to loan re-negotiations and operationally allows it to concentrate on Kenya. This is at the cost of seeing the immediate value in the project fall and a sacrifice of the upside of future NPVs. The market has judged this to be largely a wash.

Source Edison. Note NPVs are unrisked

From Total's viewpoint, its working interest increases to over 50% and gives it further resources and future revenues in an asset it knows very well.

Modelling the movements in the companies cashflows (using current cost and revenue assumptions) allows us to extract the effective return that Total will gain from this deal. Immediate $100m payment (with a further $50m on FID and $50m on first oil), together with a $700m capex carry for Tullow means material outflows before 2020, but a large boost to revenues after first oil. 

These cashflow movements run out to an implied IRR for Total of 19%, which seems high vs others given the stage of the assets. 

As a cross check, we calculated the point IRR for Total's 2012 deal (using contemporaneous assumptions) in Uganda was around 13%. If we now overlay current expectations of costs and production to the 2012 deal, this IRR falls to 10.5% - as can be seen in the empty spot in the chart below. This shows that Total has effectively commanded that its required returns from Uganda investment  have increased markedly in the last five years  (13% in 2012 to 19% in 2017) despite hundreds of millions of dollars of investment and a de-risking of the project

In an era where financially stretched E&Ps are farming out assets for development at implied IRRs of 20% (or thereabouts), we argue that these figures should inform the investor community as to what an appropriate discount rate should be for the sector.

Tuesday, 24 January 2017

Norway awards 56 new licences

By Elaine Reynolds

Norway has awarded 56 new production licences under the 2016 Norwegian APA (Awards in Pre-defined Areas) Licence Round, which covered the more explored areas of the Norwegian Continental Shelf . Interest was strongest in the North Sea area with 36 awards, while 17 were awarded in the Norwegian Sea. Only three awards went in the Barents Sea, reflecting the frontier nature of the basin. Link to awards maps

The awards were dominated by state controlled Statoil and recently merged AkerBP, but a range of smaller independents also consolidated their positions in the region. Statoil picked up 29 awards with 16 as operator, while AkerBP was awarded 21 licences with 13 as operator.  The next largest award however went to privately funded Wellesley Petroleum with eight licences, closely followed by Cairn Energy (operating here as Capricorn) with seven.

 Number of awards

Source: NPD, Edison

 Number of operatorships

Source:NPD, Edison

Wellesley, backed by Bluewater Energy, is focused on exploration in Norway and, prior to APA2106, held six licences in the region as a partner. Having qualified as an operator at the end of 2016, it has now been awarded eight new licences, with three as operator. This puts it alongside ConocoPhillips and only behind Statoil, AkerBP and Shell in the number of operatorships picked up as part of this round.

Cairn also only qualified recently as an operator in late 2015 and was awarded its first operated block, located in the Norwegian Sea, as part of APA 2015. It then picked up three further licences, one as operator, in the Barents Sea in the 23rd Round. It has now significantly increased its presence with these new awards, all located at the northern end of the North Sea, and has added two further operatorships to its Norwegian portfolio. 

Also notable was the award of four new licences to Faroe Petroleum, including two as operator. The company has consolidated its position around its 2016 Brasse discovery, which it is planning to appraise in 2017 and added three new exploration licences, one in the Norwegian Sea and two in the North Sea. 

As yet it is too early to discern any underlying trends in the distribution of these licences, so further analysis will come as companies start to provide details of their strategies. All the licences require initial work programmes of G & G studies or 3D seismic acquisition or reprocessing with exploration drilling not required for between three and four years.

Tuesday, 17 January 2017

2017 Senegal appraisal to kick off in January

by Elaine Reynolds

Cairn Energy confirmed today that it will return to drilling offshore Senegal by the end of January this year, with two firm wells designed to further evaluate its 473mmbbl SNE discovery. The Stena DrillMax is contracted for these two appraisal wells together with multiple follow on options yet to be confirmed but which could include exploration wells in addition to further appraisal.

Cairn has estimated that drilling costs would account for over 50% of the SNE development expenditure, however partner FAR has indicated that the upcoming wells will benefit from significantly lower costs than in the previous campaigns. Although the day rate for the Stena DrillMax is not provided, similar drillship the Stena IceMax is contracted to drill in the Porcupine Basin for Providence Resources at a day rate of $185,000. Meanwhile Seadrill's West Freedom drillship drilled the Mesurado exploration well for ExxonMobil at a day rate of $225,000, substantially reduced from $634,000 on its previous 2016 contract.

The two planned wells, SNE-5 and SNE-6, will be drilled in the southern part of the SNE field between 2016 appraisal wells SNE-3 and SNE-4 and are designed to test the connectivity of the upper reservoir section.

Source: FAR Ltd

The upper reservoirs contain many layers that are finer grained and slightly thinner than those in the lower zone. Although the upper zone produced around 5,400 bopd during the SNE-3 drill stem test (DST), a slight pressure depletion was observed, indicating poorer connectivity and leading to greater uncertainty of recovery from these layers. It should be possible to maintain pressure in some of the layers with waterflooding, however others may have to be produced by depletion. 

Source: Cairn Energy

In order to establish the deliverability and connectivity of the upper reservoir, DSTs will be carried out on both SNE-5 and SNE-6. Following the testing of SNE-5, the well will have permanent gauges left in the upper reservoir. The DST of SNE-6 will be extended to include an interference test ie generating a pulse that should then be registered by the gauges in both SNE-5 and in SNE-3, which had permanent gauges installed in 2016. Successful flow and interference test results would support connected reservoir units and point to a higher recovery factor.

Since the larger part of the SNE gross volume is in the upper reservoirs, a greater upside can be achieved by confirming how much can recovered from these layers. With a 3C STOIIP of 4150mmbbls, a small increase in recovery factor (currently estimated at just under 22% for the full field) can deliver a significant increase in recoverable upside.