May 14, 2018
Authors: Aditya Ravi, Senior Analyst & Lars Mikkel Reiersen, Analyst, Rystad Energy
Edited and Published by Petroleum Review, May 2018 Edition
Offshore developments have benefited significantly from lower breakeven prices over the last four years which have been achieved through downsizing, simplification, re-design, high-grading effects, unit prices and currency gains.
The overall greenfield cost to develop a field in 2015-2017 (normalized by reserves developed) has come down 42% against 2012-2014 numbers, going from $11 per boe to $7 per boe for deepwater developments. Similarly, shelf and onshore developments experienced 31% and 26% reductions, respectively. Deepwater projects exhibited significantly larger cost cuts due to higher margins and greater potential for downsizing without a significant reduction to the amount of reserves developed. Another consideration is how lifting costs have improved during the same period. Brownfield expenditures divided by barrels produced has declined significantly, as operators also put pressure on providers of supply vessels, subsea IMR (Inspection, maintenance and repair), and maintenance and modification services. In 2014, lifting costs were almost $17 per boe for deepwater, $11 per boe for shelf and $4 per boe for onshore projects. In 2017, these costs are approximately 30% lower for deepwater and 20% lower for shelf and onshore fields.
Approximately half of the cost reductions were achieved by E&P companies’ cost-cutting regimes, like Statoil’s STEP program. These regimes pushed for less in-built flexibility, standardized solutions and re-use of already developed solutions. This has in turn stimulated engineering teams to reassess their design approach and made project development and budgeting more predictable with reduced cost contingencies. For field development in oil-driven currencies, where part of the development or operation is supplied locally, significant currency gains can also be attributed to breakeven prices calculated in USD.
The dynamics for oilfield service companies on the other side of the market have changed significantly over the course of the downturn. High grading of rigs, vessels, equipment and labor has returned considerable improvements in breakeven costs. Reductions in service prices, especially from the rig, subsea, and maintenance and operations market segments, have been the result of highly competitive bidding rounds in tenders/re-tenders. This was a natural result of the drop in the amount of projects receiving a final investment decision (FID) from 2014 to 2016 and smaller project scopes, which in turn gave service companies less bargaining power. Thus, E&P companies saw significant cost savings while service companies started to struggle with lower margins. This is still apparent even though offshore sanctioning activity increased by 75% between 2016 and 2017 and the current oil price environment is closer to $70 per boe.
The service providers’ response to the pricing pressure has been capacity reductions in assets, equipment and labor to try to balance supply. This has not been met with great success. A second measure taken by service companies, subsea suppliers specifically, is consolidations in the form of alliances, joint ventures and mergers & acquisitions in order to concentrate the market and reduce competition.
On an initial inspection of Figure 2, we can see five main types of subsea consolidations. The first group concerns companies who want the ability to bid for and deliver integrated solutions for the full EPCI (Engineering, procurement, construction and installation) scope of a subsea delivery by merging the SURF (Subsea umbilicals, risers and flowlines) and SPS (Subsea production systems) silos, exemplified by Technip and FMC technologies joining forces. Secondly, we see SURF companies acknowledging the necessity for engineering capabilities as a way to lock in solutions and suppliers early and therefore have consolidated with engineering companies. Examples here are Saipem, Chiyoda and Xodus joining forces as well as McDermott and Petrofac. The third group is SURF players closing specific offering gaps in order to deliver full EPCI bids. Subsea 7’s acquisition of Seaway Heavy Lifting was seen as an effort to include heavy lift in their product offerings, and TechnipFMC’s acquisition of Plexus gave them complementary wellhead offerings. The offshore vessel market is one of the hardest hit industries in this downturn with several distressed players. Restructuring and scrapping of old vessels is the main motivation behind these consolidations. One example is Subsea 7’s acquisition of the remainder of EMAS and Solstad Farstad merger. Last but not least is the strategic partnerships between subsea players and E&P companies. This is an effort to work more efficiently together as integrated teams with common incentives to reduce cost and non-value-creating activities. This is especially apparent in the North Sea with AkerBP, Subsea 7 and Aker Solutions; TechnipFMC and Lundin Petroleum; and Subsea 7 and Centrica.
Even though these consolidations were implicitly driven by the push for efficiency improvements by E&P companies, we see that there are several other reasons for an increasing number of alliances, M&A and JVs from the oilfield service industry point of view. Cost savings in R&D of new technologies, leaner organizations, standardization of products and expanded offerings are something we are starting to see contours of already.
Historically-independent E&P companies have embraced the subsea alliance structure, exemplified in TechnipFMC’s integrated award on Hurricane Energy’s Lancaster development and Aker Solutions and Subsea 7’s award on Aerfugl by AkerBP. Recently, we have seen this contract structure emerge among E&P majors as well. The latest known award was the competitive FEED given by BP to BHGE and McDermott on the Tortue West development offshore Mauritania and Senegal. Stuart Fitzgerald, executive vice president at Subsea 7, recently estimated that 50% of all 2018 subsea awards will be awarded to integrated solutions. This indicates that several oil and gas companies are welcoming the alliance structure in order to reduce costs and lead-times.
Offshore Sanctioning Activity
The evolution of breakeven prices due to the reasons discussed above has resulted in E&P companies pulling the trigger on many more projects than they were able to during recent years.
Sanctioning activity is set to pick up significantly over the next three years as almost 200 projects (resources more than 50 million boe) are planned to be launched. Sanctioning activity in 2018 is supposed to rise by 190% against what it was in 2017. This number is expected to grow even more in 2019 and decline slightly in 2020.
Offshore approval activity, which hit rock bottom in 2016, started gaining significant momentum in 2017 with 25 projects (resources more than 50 million boe) given the green light. Some of the key projects sanctioned in 2017 include the Leviathan gas field off Israel, the Liza field off Guyana, the Mero (Pilot) and Sepia fields offshore Brazil, Coral FLNG off Mozambique, Mad Dog Phase 2 in the Gulf of Mexico and many more.
Shifting focus towards 2018-2020, some of the big projects expected to lift off the ground include the Mero 2 and Buzios V FPSO developments offshore Brazil, Johan Castberg offshore Norway, the Area 1 and Area 4 LNG projects off Mozambique, the next phases of Liza and Johan Sverdrup, KG-DWN-98/2 off the eastern coast of India, etc.
We also observe a sharp rise in the resource volumes associated with these offshore approvals. The projects that are planned to be sanctioned in 2018 hold a total of 16.6 billion boe reserves, driven in large part by fields lying in water depths less than 125 meters. This number rises to 34.5 billion boe in 2019 and 34.2 billion boe in 2020. Similar to 2018, shallow water developments (<125 meters) account for 52% of the resources developed in 2019 while in 2020, this share rises to 74%. To add perspective to the intensity of this accelerated development, the combined resources being sanctioned over the next three years amounts to a 268% rise as compared to the volumes sanctioned between 2015 and 2017 (see the chart below).
We can also observe the evolution of the half-cycle breakeven prices in the chart above. The weighted-average breakeven price of the projects sanctioned in the years 2018-2020 has dropped to $46.3 per barrel. This amounts to an 8% drop versus the breakeven for projects sanctioned from 2015 to 2017 ($50.2 per boe). The breakeven was expectedly much higher from 2012 to 2014 ($58.5 per boe).
The large amount of resources to be developed over the next three years also calls for significant greenfield investments. The 2018 developments would require E&P companies to invest about $110 billion in well and facility capex from sanctioning to startup. This number reaches $230 billion for projects to be sanctioned in 2019 and $175 billion for the ones in 2020.
The uptick in offshore activity combined with industry consolidations gives reason to believe that backlogs are building up fast for subsea suppliers which will start to push up prices again. Subsea companies exposed to the North Sea, which is leading the offshore comeback, are best positioned to experience incoming contracts at higher rates. This will soon also apply for other regions, like the UK and Brazil, where we expect activity to ramp up.
Senior Analyst, Upstream Research
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Lars Mikkel Reiersen
Analyst, Oilfield Service Research
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