Thursday, 28 July 2016

SDX Energy - Initiation

By Will Forbes

SDX Energy (SDX) is a London/Toronto-listed company with interests in two producing onshore fields in Egypt. Crucially for a small E&P, it will be cash flow positive in 2017 and is unlikely to return to the market for more equity to develop assets. The current work programme (of new wells, workovers and water flood) could see a more than doubling of recoverable volumes and is both cheap and relatively low risk. Once this work starts to bear fruit (later in 2016/17), the low-cost production will put SDX in the enviable position of being able to largely fund development of exploration prospects, while giving it resources and operational credibility to add further assets in Egypt. Our analysis indicates that the share price is more than supported by current operations, giving upside potential for the near-term production increases we see as likely and free exposure to exploration upside.

Meseda and NW Gemsa provide value upside
SDX’s plan to change pumps and institute a water flood at Meseda (50% WI) should take production to over 8mboe/d (gross), while US$8m gross investment at NW Gemsa (10% WI) could see it maintain production for a year or more. After this, the fields should produce free cash flow, even down around US$30/bbl in 2017.

Exploration is a catalyst
This cash flow generation and operational expertise gives the management options. Material, near-term (carried) exploration drilling at South Disouq is targeting 65mmboe of gas/condensate, which would lead to a re-rating for investors if successful. SDX holds a high working interest (55%) and development would likely be low cost and quick (the asset lies close to existing infrastructure).

Valuation: Existing portfolio more than supports price
Our analysis indicates the shares are supported by existing production. Successful re-invigoration at Meseda/NW Gemsa should lead to unlocking further (low-risk) value. Our core NAV of 41p/share includes risked value for the reinvigoration programme but could see further upside (to 56p/share) if the water flood programme is effective (not including risked exploration value at South Disouq). Value from any acquisition(s) will hinge on the size/price and possible upside of the targets, but SDX should be well placed to take part in consolidation within Egypt given the large number of opportunities in-country. Its policy of accepting payments in Egyptian pounds reduces payment risk and funds internal growth in the mid-term, but could limit potential for dividends/other corporate activity in the longer term.

For the full report, click here

Tuesday, 19 July 2016

Porcupine Basin Phase 2

by Elaine Reynolds
The Porcupine Basin is an exploration hotspot, driven both by the interest in Jurassic plays similar to those found in the analogous Flemish Pass basin offshore Canada and in Cretaceous stratigraphic prospects similar to those encountered offshore West Africa. As such, the 2015 Atlantic Margin licencing round has been the most successful to date, with a record number of 43 applications from 17 companies. With Phase 2 of these awards announced in June 2016, we are providing an update to our Exploration Watch on the Porcupine basin published in April 2016. For a more detailed introduction to the basin, please refer to our original note.
While a significant number of the Phase 1 awards went to majors interested in the Southern Porcupine Basin, the 14 licence options awarded in Phase 2 have gone to 11 independent companies. Concentrated to the north of the Phase 1 awards, a number of Phase 2 licences have been awarded away from the basin edges and with a separate area of interest appearing around the Corrib gas field in the Slyne Basin to the north-east of the Porcupine Basin.

Atlantic Margin concession maps

 after Phase 1

after Phase 2
Source: DCENR
Europa Oil & Gas was awarded four licence options and AzEire and Petrel Resources received two, with the remaining eight companies picking up one licence option each. A number of companies have entered the Atlantic Margin for the first time, including Faroe Petroleum, Predator Oil & Gas, Theseus and Ratio Petroleum. The work obligations for these awards mainly involve desktop studies and so offer a low-cost entry to the area for small independents. The licence options terms vary between two to three years before a company must decide whether to convert to a frontier exploration licence (FEL) and commit to more expensive activity such as 3D seismic acquisition and exploration drilling.

The Phase 1 awards were allocated earlier in the year to companies with firm seismic acquisition plans and this has allowed some surveys to be carried out over the summer seismic window in 2016. Woodside has already completed a 1,600km2 3D survey over its LO 16/14, known as Granuaile, in the Southern Porcupine Basin and covering blocks 54/11, 54/12, 54/13, 54/16, 54/17 and 54/18. The company has now shifted its attention north and is in the process of acquiring 2,400km2 3D seismic across an area known as Bréannan, covering its licences FEL 3/14 (in which Petrel holds a 15% WI) and FEL 5/14 (with partner AzEire, 40% WI). In addition, Statoil and ExxonMobil are expected to carry out a 5000km2 3D survey over their six licences in the Southern Porcupine over the course of the summer. This would bring the total seismic acquired in the Porcupine in 2016 to 9000km2, a significant increase on the previous record for the basin of 3,500km2 in 2013.

Slyne Basin: Renewed interest

Four of the licence awards are clustered around Shell’s Corrib gas field, opening up a new area of exploration interest. Two of these licence options were awarded to Europa, with Faroe and Predator picking up one licence each. Any future discovery here could benefit from being tied back to nearby infrastructure.

Please see the full note available on the Edison website: click here

Monday, 18 July 2016

Conoco sells Senegalese discovery blocks - fair price?

By Will Forbes

Conoco's sale of its interests in Senegal can be used as a barometer of industry sentiment and as a yardstick on valuation of the assets.

We believe the deal reached was a fair reflection of the value of the assets given the current environment, where the collapse in the oil price has lead to a re-evaluation within the industry. Conoco may have signalled its intent to sell the assets, but as a result this was an open process where all-comers could have bid. That should inform on a number of levels.

Weaker market or more rational market?Companies have had a torrid time at the end of the cycle and a measure of past investment mistakes could be impairments/write-offs. If we take the financial results for the two participants in 2015, Woodside wrote-off US$1bn of assets (vs US$19bn of PPE) and COP wrote off US$3bn (of US$66bn PPE value). This pain should lead managements to be more conservative in future investment decisions.

This conservatism means companies will be more stringent in investment decisions, and start to demand much higher returns  if they are to improve on historically very poor full-cycle returns. This should be especially true given the uncertain future path for crude, and one where shale oil could place a cap on increasing prices. A more sober approach on asset valuation makes sense.

Deal Summary
  • Conoco's sale of its stake in the Senegalese discovery blocks was announced on 14th July. Woodside agreed to pay US$350m and an adjustment fee of US$80m to backdate the acquisition to an effective date of 1 Jan 2016; 
  • Woodside gets 35% in the Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore blocks and an option to operate the development of discoveries; 
  • Current estimates of gross 2C resources at SNE is 560mmbbl of recoverable oil. The P90-P10 range is 277-1,071mmbbls
  • FAN has had one well drilled in 2014 and has an estimated 950mmboe of oil in place (P50). No further wells have been drilled since 2014;
  • The transaction is subject to government approval and pre-emption rights.

Asset summary
Assessment of the value of the deal rests on a number of factors, not least the volumes used by the buyers/seller and the oil prices expected. Especially given the option to operate the development, we would expect commercial negotiations will have involved significantly more information exchange than the market has available, with Woodside's technical team assessing the data from the numerous wells and performing sensitivities over development concepts and timelines. 

As outside observers, however, we can only go on a limited number of data points. FAR and Cairn have given the market various data from which we can model the development and assess the value of the deal.

Growth of SNE volumes

Source: FAR ltd
  • SNE has had five wells drilled on the structure, with an independent evaluation of resources (via FAR) of 561mmboe at the 2C level (this has increased from original estimates of 154mmbbls pre-drill). Tests of the main reservoirs at SNE-2&3 showed commercial flow rates. 
  • FAN has had one well drilled in 2014 and has an estimated 950 mmboe of oil in place (P50). Given the lack of an appraisal campaign on FAN so far and the speed at which SNE is being chased, we would expect the vast bulk of the value in the deal to be in SNE. For simplicity, we therefore treat the FAN discovery as a free option at this point.

Value and returns
Cairn have given an indication that first oil could be reached in 2021-2023, employing capex of $17-26/bbl and opex of $5-15/bbl. These estimates were given when the field size was 330 mmbbls, rather than the 561 mmbbls now given by FAR. We may expect that the per bbl figures may be lower for the larger field, though how the cost environment reacts over the next few years before FID is uncertain. We therefore assume the mid-case $/bbl figures for modelling, the result of which largely corresponds to Cairn's guidance on NPVs and IRRs given in its February 2016 presentation. 

Note that the figures below are given at FID, presumed to be in 2018/2019. We prefer to look at lifecycle development IRRs - after all, there is a great deal of spending before FID. If we look from 2016 in a $70/bbl long-term world, the project IRR is below 25%.
Source: Cairn

Deal implications
Given the constriction of capital in exploration/development spending, especially given the uncertain cost and oil price future, we would expect that buyers would require relatively high base-case IRRs to enter projects to cushion them against headwinds such as project delays or cost overruns. This is borne out by this deal, where the base-case is well above the typical discount rate used by analysts.

Using the 35% working interest sold by COP, and the $350m purchase price (paid in 2016), we find that WPL's IRR on its purchase is just above 16% (for the 330mmbl case) and just under 18% for the 561 mmbbls case. 

***Update: using Cairn's recently released new guidance (mid-August 2016) on capex the IRR for the 473mmboe case is 21% for Woodside. Breakeven NPV10 is at a long term price of $45/bbl.

Equity investors must now ask how high a return they should demand/assume if a large industry player with access to far greater levels of detail and potential operatorship demands 16-18-21%. 

We estimate COP's IRR on its investment as around 40%, although this is approximate given the confidential commercial terms in its original farm-in deals in 2013. We do know the carrying value as of May 2016 was $250m,  and assume the US$80m adjustment fee is to adjust for capex spend in 2016 (the vast majority of which is on the drilling programme in H116). It seems that COP has achieved a good return on its investment, well above the project IRR, although COP (along with CNE and FAR) have borne the exploration risk to get to this stage.

However, looking back at the return on capital if we account for the expenditures and risks of failure on original SNE and FAN wells, the deal probably doesn't make sense. This is probably not surprising given the deterioration in macro-environment since 2013 when COP entered the project.

Wednesday, 6 July 2016

Tullow - convertible bond issue

By Will Forbes

Tullow has announced it plans to raise $300m of convertible debt (maturing 12 July 2021, with an annual coupon of 5.875-6.625% paid semi-annually and convertible at 30-35% premium to VWAP on 6 July 2016). Given this proposed debt raise, it is worth re-examining the London-listed bonds for E&Ps and see how they have performed in recent months.

Yield to maturity of bonds for London-listed E&P vs Brent

Source: Bloomberg. Note Tullow bonds are green, Premier red and Enquest black. The dotted line is Brent

It is clear that the yields are still elevated from 2015 levels, with both Enquest and Premier both implying much higher risk that Tullow. It is notable that the YTM for Tullow has returned to a similar level seen when the oil price was at a similar level (on the way down), while Enquest and Premier are still elevated, similar to yields seen in late 2015 when oil was around $40-50/bbl