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On the road to recovery: part 2

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Oilfield Technology,


Whilst the near-term is defined by persistent oversupply, a changing energy mix in the long-term is projected to result in increased consumption of natural gas. DW anticipates strong natural gas resources to drive production growth from 65.4 million bpd in 2016 to 70 million bpd in 2018, whilst continuing to follow an upward trend through to the beginning of the coming decade. This is in line with BP’s outlook, according to which, gas’ share of global energy consumption is forecast to increase from 24% to 26% over 2015-2035. This increase is likely to be primarily driven by economic and population growth in emerging markets, such as China. DW expects oil production to grow at a relatively slower rate compared to gas – from 89 million bpd in 2016 to 92 million bpd in 2018. According to BP data, oil will see its share of the energy mix decrease from 33% in 2015 to 30% in 2035.

Key growth opportunities lay in the offshore wind and North Sea decommissioning sectors, both in the near-term and the long-term. Cumulative wind capacity is projected to reach nearly 66 GW by 2025, with 1.2 GW of capacity projected to be installed in 2016. Growth in expected capacity additions is anticipated to continue through to 2025, peaking at 11 GW. The UK is forecast to account for the largest proportion of capacity additions between 2016 and 2025 – nearly 16 GW, followed by China, with 11 GW. Successful transferability of skills and assets is possible, given the existing synergies between offshore oil and gas and offshore renewables. This is likely to benefit heavy left vessels providers and engineering businesses.

Similarly, growing from 2015, North Sea decommissioning expenditure is expected to be on an upward trend from 2017. This is due to the severe impact the oil price downturn has had on the economic viability of many North Sea fields. Decommissioning-related expenditure is projected at just over US$1 billion in 2017 and is expected to remain above this level through to 2040, peaking at US$6.6 billion in 2032. The use of single lift vessels on large-scale projects appears to be a more attractive option to the conventional alternative i.e. heavy lift vessels. This can be explained by the more efficient preparation times and relatively lower removal costs that single lift vessels can offer. A notable example is Allseas’ single lift vessel Pioneering Spirit, which performed its first contract – the removal of the Yme platform – in August 2016. Successful adoption of single lift vessels in the long-term will depend on successful removal of the Brent platform, though competitive day rates and operators’ willingness to embrace a move towards more innovative solutions are also important factors.

Commerciality of oil and gas

DW’s Upstream Investment Outlook also presents outputs from its sister report Upstream Capital Projects Study. This new product presents onshore and offshore project economics, including unconventional projects, highlighting major evolutions in Capex per barrel cost. The drop in US shale cost per barrel is largely attributable to a move away from marginal (stripper) wells and a greater focus on productive (core) acreage. Similarly, cost-cutting measures have been a major contributing factor to a lower average cost per barrel for deepwater projects. A combination of project re-engineering and concept re-design are also important influential factors. A continuous focus on fit-for-purpose engineering, and greater operational efficiency, will be crucial for achieving any sustained reductions in costs per barrel and more favourable project economics for operators in the near to long-term. However, further efficiency in cost-structures can be achieved, and this should remain the key focus among service providers in the supply-chain, in order to reduce impacts of future cycles.

Uncertainties

Political tensions, corruption scandals, changes in regulation, and the outcome of the recent referendum in the UK, are among many external factors contributing to industry-wide uncertainty. Whilst these events are unlikely to have a direct impact on the shape of industry recovery, they can create additional market instability and a change in investor expectations and consumer confidence. 2016 was an eventful year, which witnessed some unexpected supply disturbances, following attacks on pipeline infrastructure in Nigeria and wildfires in Canada, causing a marginal rebound in oil prices. Significant price recovery, however, failed to take place. The outcome of the recent referendum in the UK, arguably another unanticipated event, has not had a detrimental impact on the oil & gas industry in the short-term. Nevertheless, whilst an exit strategy with the EU is being planned, wider economic uncertainty remains a primary risk to investor confidence and consumption growth. In the last decades, the UK has witnessed important changes to its dependence on imported fossil fuels. 2013 saw the UK became a net importer of petroleum products, relying on imports from its EU partners, including France and the Netherlands. Since the exit vote, the sterling has depreciated on several occasions, hitting a 31 year low at US$1.26 against the dollar in early October 2016. This has led to higher import costs and more uncertainty over future energy supply. The market is likely to remain unstable, whilst investors and consumers are re-setting their expectations, given that details on UK’s exit deal remain unknown.

Conclusion

Douglas-Westwood’s Upstream Investment Outlook paints a picture of suppressed oil prices, reduced upstream Capex, and persistent oversupply – assuming no OPEC cut – in the near-term. The potential OPEC production curtailment presents two main case scenarios. The market could either witness a fall in oversupply to ~0.6 million bpd in 2017, with a high quota, or the oversupply could be almost eliminated, should the low quota be applied. Provided no OPEC cut takes place, the implied oversupply is projected to fall by 0.9 million bpd in 2017. This will be driven by key onshore and offshore brownfield expansions, which are unlikely to be postponed, given that they are nearing completion.

Whilst oversupply is likely to persist in the near-term, a change in the energy mix is forecast to drive industry activity in the long-term. Robust natural gas production and abundant resources will contribute to a stronger competitive position of natural gas in the energy mix compared to oil. Offshore wind and North Sea decommissioning are two bright-spots, providing promising growth opportunities extending into the next decade. Supply-chain players with less reliance on oil and gas assets are likely to be better placed to seize successful diversification opportunities between sub-sectors.

A greater operational efficiency has been noticed in the industry through project re-engineering and concept re-design. These evolutions represent an improvement in industry behaviour and practices and are likely to continue contributing to lower project development costs in the near future.

Despite near-term market suppression, opportunities should not be ignored, even in times of uncertainty. A potential OPEC production cut in the near-future is likely to result in some oil price recovery and elimination of the supply gap. This, in turn, is likely to result in positive revisions to production and investment targets, resulting in improved economic viability of offshore projects. This could be the beginning of a long-awaited market recovery.

Read the article online at: https://www.oilfieldtechnology.com/special-reports/29122016/on-the-road-to-recovery-part-2/


 

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