For energy investors, bankers and analysts, there’s only one conversation worth having right now. Shell’s audacious £47bn bid for BG Group has the City smacking its lips in anticipation at a potential £235m windfall, while BG shareholders can look forward to a sizeable premium at 1,350p per share.
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To analysts, the takeover – the largest deal of its kind in more than a decade – is significant for two reasons. First, it could trigger a wave of mega-mergers as multinationals look to boost their reserves and slash capital expenditure (CAPEX) by snapping up smaller diversified oil producers for a song.
Second, the deal underlines Shell’s decision to concentrate on deepwater plays and liquefied natural gas (LNG) at the expense of its North Sea and Arctic operations, further evidence that such projects offer a better return on investment (ROI) for large, integrated operators, at least in the short term.
"The economics of deepwater projects generally involve high upfront capital investment in appraisal and development," notes Adrian Lara, GlobalData’s senior upstream analyst covering the Americas. "However, high CAPEX investment over the life of the project is not continuously required given the higher productivity and estimated ultimate recovery (EUR) of offshore wells compared with onshore.
"Compared with unconventional developments, where wells peak and decline very rapidly and make constant drilling a condition to sustaining production levels, deep-water projects have a more traditional project evaluation approach where, once the CAPEX has been recovered, there is a period of profitable cash flow."
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By GlobalDataHe adds: "Deepwater discoveries in the last five years have been relatively higher compared with those in shallow water or onshore. Most of these projects involved large and experienced integrated international oil companies, accustomed to the price cycles and with margins to manoeuvre for reducing their production costs."
Deep impact: deepwater investment expected to surge from 2016
As production from mature onshore basins and in shallow water declines, deep and ultra-deep oil and gas reserves – those typically situated at a water depth in excess of 2,000m – have become increasingly vital to operators’ bottom line, particularly in light of the slump in the global oil price.
The trend for processors and refiners to get involved upstream is growing.
According to analyst Douglas-Westwood’s World Deepwater Market Forecast 2014-18, deepwater CAPEX will total $260bn from 2014-18, an increase of 130% compared with the preceding five years, driven by the potential for discoveries of large hydrocarbon reserves such as those in East Africa.
However, these discoveries require high levels of capital investment in infrastructure to explore, two examples being the giant Mamba and Prosperidade natural gas fields under development by the US operator Anadarko and the Italian multinational Eni S.p.A offshore Tanzania and Mozambique.
Douglas-Westwood notes that, typically, oil prices of $80 a barrel are needed over the long-term to ensure the viability of the majority of deepwater plays and that several flagship projects, notably Chevron‘s Hadrian and Rosebank developments, have been axed. With exploration and production (E&P) costs averaging in excess of 10% per annum and oil prices depressed, the risks remain high.
"A good economic scenario for a deepwater project in a low price environment is the combination of already identified resources – meaning that no more significant exploration expenditure is required – good well productivity and cheaper equipment and services," explains Lara. "An important aspect to consider is whether a discovery has already been identified in a prospective deep or ultra-deep water area, and whether the engineering project has already been designed and sanctioned.
"This would mean that the risk for these types of projects is significantly lowered in terms of the CAPEX required for exploration; after all, drilling exploratory wells does not necessarily mean future production. In development terms, if the project is coming online by, say, the end of 2015 or 2016, it is possible that some of the contracts could benefit from lower equipment and services prices."
Crunching the numbers: analysing CAPEX expenditure for deepwater projects
The Douglas-Westwood forecast drills down into the components costing for deepwater projects, revealing the level of CAPEX spending required by upstream operators on critical E&P equipment.
Drilling and completion (D&C) represents by far the largest segment of the deepwater market with expenditure totalling over $90 billion, the majority of that spent on subsea well completions. D&C CAPEX is expected to grow at a CAGR of 17% between 2014 and 2018, with the greatest levels of expenditure expected in Latin America due to lengthier drilling and completion times in the region.
Floating production systems (FPS) account for the second largest segment of deepwater CAPEX, with over a quarter to be spent on FPS units and installations. Deepwater expenditure on FPS units will primarily be spent on floating production, storage and offloading (FPSO) units, accounting for almost 80% of forecast FPS expenditure.
Subsea equipment – defined by Douglas-Westwood as subsea production hardware and subsea umbilicals, risers and flowlines (SURF) – accounts for almost a third of global expenditure over the forecast period. CAPEX is expected to total in excess of $35 billion from 2014-18. CAPEX on SURF, also primarily driven by subsea well numbers, and production hardware is set to reach $40 billion.
Finally, CAPEX on trunk lines – pipelines that carry natural gas over long distances- is predicted to hit $25 billion from 2014-18. Regions such as Eastern Europe and the former Soviet Union, the Middle East and Western Europe with historically low levels of deepwater activity will experience major growth over the next five years, primarily due to the installation of major deepwater trunk lines.
Worth their salt: Brazil pre-salt reserves set to drive deepwater investment
With deepwater CAPEX predicted to increase by 14% per annum, I conclude by asking Lara if deep and ultra-deep projects represent relatively safe territory in an otherwise volatile upstream market.
"In the next five to ten years, I think both discovered fields and projects in the initial stages will be brought online," Lara states. "Deepwater exploration can expect to see delays, but its accuracy can also be improved. Technological developments and operating strategies will be key to maximising the productivity and, ultimately, the profitability of these projects. The extended well tests in Brazil have been very successful and this is the basis for the potential in developing other pre-salt fields."
A $300m first-of-its-kind infrastructure project off the coast of Lagos is hoping to maximise local benefit.
Despite potential delays caused by CAPEX costs and local content requirements aimed at creating jobs and promoting enterprise development in regional areas, significant investment continues in Africa and the Americas. The Douglas-Westwood report predicts that Brazilian NOC Petrobras, for example, will continue to invest heavily in the nation’s pre-salt basins, despite recent setbacks.
Lara agrees with this analysis, emphasising the importance of the South American nation’s offshore reserves to Shell’s global ambitions, particularly in light of its expected mega-merger with BG.
"Brazil is a country with a lot of offshore potential and the pre-salt area is the key element in future growth," he confirms. "The country’s oil and gas sector has been affected by a recent corruption scandal involving Petrobras, politicians and contractors. As a consequence, and due to ongoing investigations, a lot of contracting has been stopped and this has resulted in uncertainty around future development and production.
"However, this is more an ‘above the ground’ type of problem. In the end, the resource is there, the development has been planned and there are important economies of scales and flexibility via the experience acquired from the last seven years of testing and developing the pre-salt area."
Lara adds: "BG has a strong presence in Brazil; four pre-salt blocks with a relatively large resource base. I think the Brazil factor made this deal very attractive to Shell. And yes, more mergers can be expected."
