Jon Fredrik Müller and Audun Martinsen, of Rystad Energy, take a look at rising costs and the downturn and share how these two will affect the subsea market going forward.
An illustration of the Johan Sverdrup field center. Image from Statoil.
With high development activity and cost inflation in the industry since 2010, the breakeven prices for subsea developments have increased significantly. With cost levels as in 2014, many of the discoveries not yet sanctioned would be unprofitable at the current oil price regime. So how are the costs reacting to this downturn?
The oil market is currently oversupplied resulting in a sluggish oil price. Going into 2016, Rystad Energy believes the oil price will continue at the levels seen in 2015 and trade in the range of US$35-60/bbl (Brent). However, from 2017 the market balance is forecasted to improve as supply responds to lower prices, and demand is forecasted to continue to grow. Moving towards 2020 the oil price is expected to strengthen significantly, potentially reaching the same price level as seen in 2014 ($100 real).
In terms of supply capacity, the oil and gas industry differs from other industries. In most other industries, one can maintain an established production capacity with a small amount of maintenance. However, the inherent production decline within oil and gas fields results in large continuous investments needed, just to keep production flat at the current level. To be able to grow production and in order to meet growing global demand, significant investments will be required towards 2020. In terms of production growth, there are mainly two sources of growth possibilities – shale/tight and offshore resources. It is Rystad Energy’s view that it is not a question of one or the other. We need production growth from both sources to be able to deliver on projected demand by 2020.
Fig. 1: Cost impacts for
The reduction in offshore activity, in conjunction with growing capacity in many of the offshore segments like rigs, platform supply vessels (PSVs) and anchor handling tug supply (AHTS) vessels, have hit the suppliers hard. Companies are reorganizing, cutting costs and reducing staff, and as a result unit prices are coming down. The cost reduction varies greatly from segment to segment, but overall the cost compression within offshore segments is in the range of 10-25%.
Within offshore rigs, one of the segments that has been hit hardest, rates for large deepwater rigs have come down around 50%. Within the subsea segment, there has also been an increasing number of joint ventures aimed at bringing down costs through increased cooperation between the subsea production systems (SPS) producers and installation companies.
An illustration of the Johan Sverdrup field’s subsea layout. Image from Statoil.
The intense focus on cost cutting among exploration and production (E&P) companies resulted in several development projects put on hold in late 2014 and into 2015. In 2014, Rosebank (Chevron) and Mad Dog phase 2 (BP) were some of the projects that got hit as companies could not prioritize new large cost commitments. Not all projects were cancelled, as they showed potential for significant production additions to a portfolio of falling offshore production. Instead, projects were reassessed for their potential of downsizing or re-engineering in order to cut costs. While this happened, the oil price was falling towards and below the $50 mark. Consequently, investments were cut to a minimum, which, in the end, led to decreasing pricing power among service companies and unit prices started to trend downwards. Subsequently, this has led to a large cost saving potential for the previously shelved projects and Rystad Energy now observes offshore projects to come in at an average of 10-30% lower costs than before the oil price crash.
Figure 1 shows selected offshore greenfield projects that have been recycled or obtained new greenfield cost estimates based on either re-engineering, downsizing or lower service unit prices. As shown, E&P companies have accomplished cost savings of up to 50%, both due to re-engineering and cost reductions. The BP-operated Mad Dog phase 2 is an example where simplification of design and project phasing has translated to cost reductions of close to 40%, however, the recovered volumes will likely be reduced as well. Another example is the giant Statoil-operated Johan Sverdrup development, which has been able to cut more than $1 billion on lower unit prices alone.
Cost reductions have had a dramatic effect on breakeven prices. Prior to the oil price drop, undeveloped offshore projects had an average breakeven price of around $70/bbl. Assuming that a “typical” offshore project’s costs can be reduced by 20% due to cost savings, yields a new breakeven price closer to $55/bbl. The cost compression will significantly enhance the competitiveness of offshore resources, and projects that were not economical a year ago, might now be “in the money” due to cost compression.
Fig. 2: Global E&P subsea expenditure (capex and opex, US$ billion) by market segment
Although Rystad believes that offshore will be an important source of supply growth towards the end of the decade, the current oversupply has impacted offshore investments for the remainder of the market. The short-term activity has been significantly reduced as operators have pushed the brakes and cut back on investments in order to improve cash flows in the low oil price environment. However, the cost compression in the industry is improving the profitability of subsea projects. Figure 2 shows historical and forecasted subsea expenditure (capex and opex) split by market segment. The market has contracted approximately 10% in 2015 compared to 2014 levels of $45 billion. The negative trend is forecasted to continue in 2016 and stabilize in 2017. However, with a tightening of the market balance foreseen in 2017, expenditure in the subsea segment is expected to grow from 2018 reaching $52 billion in 2020, a compounded annual growth rate of 11% from 2017-2020. This is a growth slightly less than the previous growth cycle from 2010-2014 of 12%, and far behind the 25% growth experienced leading up to the financial crisis in 2008.
Figure 2 also illustrates how the different subsea segments are affected differently by the downturn. The subsea services segment, which is primarily subsea inspection, repair and maintenance, is a more stable segment driven by operational expenditure. The SURF (subsea installation, umbilical, riser and flowline) and subsea equipment segment (production systems like Xmas trees and manifolds), which are primarily driven by investments in greenfield developments, fluctuate more and are affected harder by the downturn and project postponements.
The current market downturn is forecasted to be both deeper and longer than the downturn experienced during the financial crisis. The reason for this is that while the financial crisis was a demand driven downturn, the current downturn is driven by an oversupply, which takes longer time to correct. However, Rystad Energy believes that the market balance on oil will become increasingly tighter from 2017 onwards and with the addition of lowered unit costs, the subsea industry is set for a new growth cycle from 2018.
Jon Fredrik Müller is a senior project manager within the consulting department of Rystad Energy, based in Oslo. His main area of expertise lies in the oil field service segments and particularly within offshore related services. He holds a M.Sc. in Industrial Economics from Norwegian University of Science and Technology with specialization in mechanical engineering and finance, including a graduate exchange program at University of Calgary.
Audun M. Martinsen is the product manager and lead analyst of oil field services at Rystad Energy. His fields of expertise include the global offshore and onshore oil service market, E&P cost analysis and supply and demand studies. He holds a MS in marine engineering from the Norwegian University of Science and Technology and University of Berkeley, California. He has broad experience within the E&P and oil service industry with previous engagements at Coriolis, Shell and BW Offshore where he has worked as a lead engineer, product developer, system consultant and analyst.