Offshore: Making a Comeback After the Downturn
- Judy Feder (JPT Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 2019
- Document Type
- Journal Paper
- 27 - 31
- 2019. Copyright is held partially by SPE. Contact SPE for permission to use material from this document.
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Could 2019 be a bumper year for offshore energy development? In just the first few weeks of this year, four discoveries in the UK North Sea and offshore Guyana and South Africa found 1.3 billion BOE—25% of the approximately 5.3 billion BOE high-impact volume discovered globally in the whole of 2018—according to Westwood Global Energy Group. Westwood has identified another 78 high-impact exploration wells either currently being drilled or planned for the remainder of 2019. The expected gross unrisked volume of oil and gas from the 78 wells is 23 billion BOE. More than half the wells are in deep water (Fig. 1).
The consensus among major energy consultancies is that offshore development in almost all areas of the world is making a comeback after the most recent industry downturn. Rystad Energy forecasts spending on offshore projects to outgrow that of onshore shale activities this year. Lifting the equivalent of 120,000 B/D of oil from the Permian Basin would require an investment of $12.8 billion, compared with $3.7 billion for the first phase of the Liza section of the Guyana project, according to Hess Corp. Chief Executive Officer John Hess in a recent Bloomberg article. Hess, which has assets both in shale and offshore, is a partner with ExxonMobil in Guyana.
Wood Mackenzie says that operationally and financially, “all lights are green” for oil and gas companies’ upstream development plans, including offshore development. And, although the International Energy Agency (IEA) reports that only the best projects are going ahead, the definition of “best” has been expanded by the fact that capital investment in some areas (i.e., the US Gulf of Mexico and Norwegian shelf) that once required a breakeven oil price of $60–80/bbl are now claimed to be robust at $25–40/bbl.
Lower costs and faster project delivery are transforming offshore project economics to the point where majors are now generating more free cash flow at $60/bbl than they were 5 years ago at $100/bbl, according to Wood Mackenzie. Applying lessons learned from the downturn, operators have reset portfolios by shedding higher-cost assets and investing instead in higher-return, lower-cost projects. The projects remain lean and phased, with the focus on keeping costs relatively low and cycle time relatively short for continued market sustainability. Executive pay for many operators is now linked more closely to returns than growth. The reset seems to be paying off with improved profitability and cash flow.
Wood Mackenzie points to three themes that have emerged as restricted budgets have driven a more focused approach to prospect selection.
New plays in new basins. With little to no infrastructure and little service sector, frontier prospects need to be big enough to realize economies of scale and need to be brought on stream quickly. In addition to geology, fiscal terms and domestic political support also are important. Wood Mackenzie points to Guyana, Egypt, and Cyprus as deepwater plays with very high-quality reservoirs that have proved both productive and profitable at lower prices for ExxonMobil, Eni, and Eni and Total, respectively.
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