Cairn Energy — SNE larger but phased

Cairn’s resource estimate of 563mmbbl represents a 19% increase from the previous estimate of 473mmbbl. Given the success of appraisal drilling and the interference test results, we believe an increase was expected by the market – we had been too optimistic in using FAR’s estimate of 641mmbbl.

However, the headline increase in resources is offset by some negative factors, the most prominent of which (for shareholder value) is the phased nature of the development and the wide (and uncertain nature) range of FPSO production rates.

Reservoir information

According to Cairn, 30-40% of the resource base (169–225mmbbl) is believed to sit in the high-quality S500 lower sands, which will be easier to develop.

The remainder sits in the S400 upper sands, which are good quality, but are distributed across thinner layers over a greater area and are not as well connected as the lower sands, making production and recovery here more difficult.

The first phase of the development will concentrate on the easier S500 sands and defer production from the S400 sands to later phases, although an unspecified number of S400 wells will be included in Phase 1. We postulate these wells will be used to monitor further production from the upper sands to enable a better understanding of how to best exploit them.

The interference test carried out on the upper sands between SNE-5 and SNE-6 as part of the recent appraisal campaign has confirmed to Cairn what its models were predicting. It found that connectivity is good along a north/south orientation in line with the direction of the sedimentation waves, but that it was more limited in an east/west direction between SNE-3 and SNE-4.This will make an efficient sweep from waterflooding more challenging and some areas of the upper sands may end up without pressure support.

In addition, Cairn will not be able drill wells across the full extent of the upper sands as it will avoid the edges of the reservoir where the sands thin out to feather edges as well as the area immediately below the gas cap. As a result of this, Cairn estimates that recovery from the S500 lower sands will between 30% and 40%, but in the 20s% from the upper S400 sands.

Cairn expects “up to 240mmbbl” of resource to be developed in the first phase with a plateau rate of between 75mb/d and 125mb/d. While the range of plateau rates seems odd at first glance, it is easier to understand given the phased development. Looking at the charts below (from our analysis of the offshore Norwegian fields, where data is available and of high quality), it is clear that any production rate that would drain more than about 12-14% of the lower reservoirs in the initial phase is less likely. Here we take the lower reservoir resource range suggested by Cairn management (169-225mmbbl), with the balance coming from the upper reservoirs.

In this light the relatively lower production rates than we had previously modelled become more logical. For the lower reservoirs and the focus of phase one, the exploitation range of 12-14% would equate to 56-86mboe/d and it is therefore unlikely that plateau rates well above this range (of say 105mb/d or more) would be exceeded in our view.

Exploiting the larger 323mmbbl remaining reserves in later phases (on a 10-14% exploitation range) would imply rates of 71-142mb/d.

Our base assumption is that the FPSO is built initially with a capacity of around 100mb/d, allowing a second phase to increase upon the first phase rates, which are constrained by reservoir management at around 80mb/d. However, it would make sense for the FPSO to be built to allow material expansion for the second phase. This extra hull space could then be used (subject to future appraisal, engineering and gas markets) to house expanded production units for oil or gas. This approach would minimise initial capex while giving the company a fuller value for upside options.

Comparing the old vs new production profiles implies that our previous assumptions on production rates (based on a non-phased development) were too high.

We note that this production profile is similar to that suggested by Premier Oil and Rockhopper Exploration (RKH) for their phased development of Sea Lion (for which RKH management has estimated 2C contingent resources of over 500mmbbl and a first phase recovering 220mmbbl).

For modelling purposes, capex and opex guidance for SNE ($12/bbl and $10-14/bbl, respectively) was largely in line with previous estimates. We have moved our capex to be in line with company guidance of $2.3bn pre first oil and lowered absolute opex given the lower plateau rates we have reduced.

Implications on financing SNE

Assuming a 40% WI (current WI) and $2.3bn pre-first oil capex, Cairn’s net cash outflows during development will total $920m and average $230m (if we assume four years from FID to first oil). This is a substantial outflow.

We continue to assume Cairn farms down the asset for a partial development carry (now in 2020) for an assumed return for the farm-inee of 15%. This would take CNE’s stake down to 25%, reducing the capital burden during development and taking the project further towards first oil before any additional equity spend is required. This would also take the project closer to first oil and potential access to any RBL facility. Of course, the longer that Cairn holds on to the project, the higher the price that could be realised (from any sale/farm-down) as it moves towards first oil.

The CFO mentioned that analysts may assume a project finance funding of SNE of about 50% equity and 50% debt. Our modelling implies this may not be particularly easy just using RBLs given the flat (low) forward curve. As a result we would expect the company to rely more on corporate debt (or other sources such as vendor financing and export credit agency financing) than RBL if it were to seek to debt-fund the project more than one year before project start-up (which we assume in early 2024). The table below lays out what the gross RBL facilities may be for phase one.

EnQuest released an operational update on 23 August, significantly downgrading production guidance for H217 and the full year, primarily as a result of underperformance of the Kraken ramp-up. Commissioning of the facilities, which are driving artificial lift for the reservoirs from start-up (70% water cut), has taken much longer than expected and EnQuest is continuing to ‘tune’ the equipment. While Bumi (FPSO contractor) has reduced its rates during this time, it does have a detrimental effect on production in 2017 and into 2018. We had expected the field to reach plateau early in 2018, but now expect it to take into H218.

EnQuest also announced that it expects to achieve a capex saving of $100m “as a result of the drilling of DC3 being completed three to four months earlier than planned and lower market rates for the subsea costs”.

Premier has indicated that the FPSO is due to sail from the shipyard in the coming days and is therefore on track for first production in December. It has also reiterated the confidence it has in field production rates and the belief that the FPSO has a capacity of 60mb/d. There is therefore upside to the official guidance of a 50mb/d plateau (we continue to model 55mb/d plateau rates for the moment).

The Norwegian fiscal regime notably rewards a balanced portfolio where taxes on production cash flows can be offset by development tax losses. Therefore having a single development in Skarfjell makes little sense in our view (and would have made a good candidate for non-core asset sale in the future).

However, the Cairn team was more enthusiastic about the UK and Norwegian exploration programme in the interim results, mentioning a targeted 10 wells by 2019 targeting c 1.2bnboe at an average WI of 35%. This kind of programme could unlock a portfolio of assets that would be more material to develop and potentially sell at a later date.

Two wells are planned in the Norwegian North Sea by the end of 2017 (Tethys and Raudåsen). Tethys is around 100mmboe but success here could de-risk 250mmboe of other prospectivity as Cairn controls a great deal of surrounding acreage. Acreage it holds in the Norwegian Sea could be interesting and is well concentrated to take advantage of any exploration success.

As a side note, (and three weeks before the parliamentary elections) Reuters has recently reported that the opposition party (Labour) in Norway has called for a debate on Norway’s generous tax regime on oil drilling due to climate change concerns. According to a Reuters report, the Labour representative on the Finance Committee (Marianne Marthinsen) has suggested changing rules on the tax rebate on exploration drilling. There are apparently no intentions to alter rules in the next parliament, but it is suggested that a broad discussion should be held. For now, we see little impact for current exploration in Norway, but it should be noted by investors. In terms of oil exploration success, the current rules for a 78% tax rebate on exploration drilling have had a massive effect on Norway, allowing smaller, more innovative companies to take risks on more frontier areas, building Norway’s contingent and proved reserves since its introduction in 2005.

A measure of this success (in terms of wells) is demonstrated in Exhibit 12, which shows a large uptick. Despite the country’s high tax rates for development, the exploration rebate helps encourage large players to remain in the country, we believe.

Cairn was recently awarded Blocks 7 and 9 in Mexico, which lie on trend with the recent Zama discovery by Premier. Cairn holds 30-65% of the blocks with more than 1bnbbl of prospectivity across the blocks (according to the management). The company bid high prices for the blocks (relative to other blocks) but said it was entirely happy with the bids, and will continue to look to add further. Wells are likely in 2019-20, when two wells are required per block.

We do not value the Mexican acreage, but note that Premier’s shares increased by $83m on the day of the success (12 July 2017) at Zama (where it holds 25%).

We have made a number of changes to the modelling following the interim results and EnQuest’s operational update on Kraken. Primarily, these relate to SNE production and costs estimates which, unsurprisingly, have moved following the development plan changes.

Elsewhere, Kraken volume and capex estimates have moved, Catcher capex has been adjusted and we have brought forward spend on Skarfjell given the more positive sentiment from Cairn in the results. We have also accounted for exploration spend in Norway and Mexico in coming years (although Mexican exploration is too far out to include in our valuation at this time). We await further updates on timing of Norwegian wells, but include five in our RENAV, assuming an average prospect size of 100mmbbl (vs 120mmbbl indicated by Cairn over the entire programme).

Cumulatively, these contribute to a reduction in our contingent valuation to 195p/share (from 196p/share), and a RENAV of 205p/share (from 200p/share).

With the start-up of Kraken (despite the commissioning issues) and ramping up Catcher in late 2017, Cairn will become a production company. Even so, the weight of development costs at SNE and Skarfjell and continuing to fund exploration wells internationally means that Cairn will not be producing sustainably positive cash flows until after the major development capex of SNE is over, and may be delayed further with continued development of any discoveries. Ways of reducing this burden include farming-down of SNE, or a sale of assets as and when buyers willing to pay a price the management would accept can be found. Cairn has a history of returning cash to shareholders when appropriate and we would expect the company to repeat this in time.