Conoco sells Senegalese discovery blocks – fair price?
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.
For example , 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 $3bn of $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 is 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.
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.
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%.
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.
