Wednesday, 30 November 2016

Decommissioning - changing the mindset

by Elaine Reynolds

£1.1 billion was spent on decommissioning in the UK in 2015, accounting for 5% of total UKCS expenditure that is expected to increase to 12% in 2017. Oil & Gas UK has estimated that decommissioning on the UKCS up to 2025 represents a £17.6 billion opportunity. 

With the UKCS accounting for 50% of the global decommissioning spend over the next 5 years, the North Sea is at the forefront of developing the techniques  to optimise the process and could position itself as a major player in the global decommissioning industry. At a recent conference on the subject hosted by Edison, together with Addleshaw Goddard, the key themes of cost uncertainty and industry collaboration emerged.

The overall cost of decommissioning is still subject to large uncertainties, with the estimated cost now 6 times greater than it was a decade ago. With 94% of the 153 existing UKCS projects in the early planning stages of the process, current figures will change as these projects are refined and this uncertainty is a possible deterrent to new entrants to the basin. In recognition of this, the newly created Oil and Gas Authority (OGA) is working to provide its own estimate of the total cost by the end of 2016, and is also looking to provide effective cost benchmarking to operators during 2017.

A successful decommissioning project should be carried out at the lowest cost while ensuring a safe and environmentally responsible solution. This is different from the schedule and quality driven capital investment projects that the industry is used to dealing with and requires a change of mindset from competitive to collaborative.



Forecast 2016-2025
Source: Oil & Gas UK


For example,the single largest cost component of the decommissioning process in the UKCS is not the topside or substructure removal but well plugging and abandonment
 (P & A), at 47% of the total cost on average. It is estimated that 1,470 wells will be P & A'd between now and 2025 and operators are trying to find ways to minimise the cost of their P & A programmes. In the Southern North Sea a number of operators are looking at decommissioning their assets in batch campaigns to optimise the use of rigs, vessels and accomodation in the most cost effective manner. But, in a sign of the beginnings of a shift to more collaborative behaviours, some operators are considering the benefits and risks of carrying out these campaigns on a cross operator basis, with the potential to bring continuity and cut costs further.

The industry is aware that collaboration has been historically poor and that this must improve to meet the challenges of decommissioning. The presence of the OGA, with its focus on MER UK (maximising economic recovery) should help in achieving this, but only time will tell if the industry can effectively change its behaviours.








Thursday, 24 November 2016

Fortuna LNG deal underlines the structurally higher costs of capital seen by E&Ps

By Will Forbes

We believe the poor record of investment returns for large oil companies over the last cycle (taken as a proxy for the industry) should have far reaching effects across the industry. As majors look to increase their below-WACC ROICs (seen consistently over the last decade), they will demand higher returns for the investment projects. This should mean a continued drive for lowering costs and increasing efficiencies for service companies and a more aggressive negotiation with companies looking to farm-down the projects for funding.

In previous posts, we've highlighted the analysis of farm-downs as a relatively transparent lens through which to view costs of capital in the industry, and an addition to CAPM or other based methods of assessing the costs of capital for the sector we focus on, E&Ps.

The recent Ophir/OneLNG deal is another point to add to this growing picture. Based on disclosures from Ophir, it is contributing its upstream equity and a limited amount of capex in return for 33.8% of the JV. Given expected annual cashflows of $560m and a 60% debt financing (we assume 8% here), we estimate the levered cashflow return for Ophir in 2017 is 38%. The unlevered return is 25%

Importantly, the return for OneLNG is an implied 20% (levered return is 30%), which is towards the top end of the implied IRRs for deals we have analysed.

Implied IRRs for buyers of assets
Source: Edison Investment Research


Floating LNG is still an unproven technology, We may well therefore expect that the return demanded by OneLNG is higher than a comparably sized/risked oil-based FPSO development.

As Ophir have stated, FLNG may well become the standard in much the same way that FPSOs have for oil developments. For the moment however, a 20% return for OneLNG on current assumptions re-iterates that incoming partners require high returns even in developments where geological risk is low. 

In an environment where development partners may require such high returns, what is the business case for high risk exploration?





Majors - failure to make sufficient returns will affect the entire sector in next cycle - raising costs of capital

By Will Forbes

The total shareholder returns of the majors outperformed the NY industrial average since 2000-2016 buoyed by the Chinese supercycle and resulting oil prices. However, the total returns seen by investors have lagged badly in the last decade, as inefficient capital bases in a newer world of higher costs and moderating/falling oil prices dragged on returns.
Source: Edison, Bloomberg
Green line is the New York Industrial average, grey lines are total returns of the major oil companies


At the beginning of a new oil cycle it is right to examine how companies fared in the previous cycle and see what they may do in the next. In this post, we look at  returns made by the majors and how these compare to the WACC. Since 2006, the majority of companies have produced below-WACC returns, and as the chart below indicates, only Exxon has averaged above cost of capital returns over the last five years.


Source: Edison, Bloomberg

This compares to stronger returns from 2000-2008. We believe this was primarily due to the sharply increasing oil prices during that time co-inciding with a capital base built on sub $20/bbl oil. It was only as costs increased the returns turned below WACC and have been consistently below since 2008. As the tide moved out in 2014-2016, the majors were exposed as modestly clothed.


Source: Bloomberg

Companies will have to take proactive steps, especially in the lower oil price environment, to increase these returns to at least above WACC if they are to maintain their value and investor base. Many have taken writedowns which reduces the capital base, but we expect additional work will have to be done to increase post tax operating profits. This can't be achieved purely through cost cutting. If we assume this is achieved purely through new projects introduced into the capital base, this means new projects will have to make sharply higher returns to re-balance this picture.

What returns will new projects have to achieve? In the analysis below, we assume the companies will move from average ROIC (20012-2015) towards WACC through four years of investment. This indicates that any new projects will need to achieve returns of 11-17% on average.
Source: Edison, Bloomberg


How does this effect E&Ps?
If the company funding your project requires a return of X% for its investment, then X% is the marginal cost of capital for the seller.

If the majors (taken here as a proxy for industry as a whole) will be more stringent in investment decisions, it therefore follows that the cost of capital suffered by E&Ps in need of funding will (structurally) rise. This needs to be more fully reflected in the discount rates used to value E&P companies in search of capital.