GlobalData’s Adrian Lara sheds light on the kinds of deepwater projects expected to advance while the price of oil continues to fall.
Engineers from Jumbo Maritime deliver 25 MOF caissons for the Chevron-operated Gorgon development offshore Western Australia, in 2012. Photo from Jumbo Maritime.
With oil prices falling below US$70/bbl, sanctioning certain planned offshore developments for development becomes challenged. Capital investment for offshore assets will, however, continue and it is mainly a matter of delays to startup for most projects. Large recoverable reserves coupled with high-productivity wells allows for a large return on investment. While deep and ultra-deep water projects usually have higher development costs, drops in the oil price are also accompanied by reductions in the cost of services, supporting ongoing development.
The commercial risk associated with offshore projects varies depending on the stage of development; a key consideration is whether the project is planned, already under development or producing. GlobalData identifies at least three types of projects when assessing the impact of a permanent low price level:
- projects that have recently started production
- planned projects scheduled to start producing during 2015-2016
- planned projects scheduled to start producing during 2016-2018
The first group of projects has already started production and has the lowest risk because costs are generally limited to ongoing operational expenditures, which are significantly lower. The second and third types of projects have already invested in exploration, appraisal and development, but have not started production. Normally, the ones scheduled to produce in the latest period, 2016-2018, would face the highest risk. Projects that have seen most of the capital expenditure already deployed, generally those in between 2015-2016, will be more costly to halt than to move forward.
Project economics and total capital expenditure is impacted by many factors, including the type of production unit used, drilling and completion times, the development stage and the size of the resource. In the current environment of falling oil prices, service costs will also fall, reducing required capital, but in many cases, not enough to support the commercial viability of projects.
A change in the investment plans of oil and gas companies, due to a lower 2015 average oil price, will see spending limited to projects already under development and planned projects with relatively low break-even prices. Projects that have already contracted construction of producing facilities will most likely continue development, although with some degree of deceleration possible.
In the Gulf of Mexico, there was a revival in pushing forward projects since the Deepwater Horizon oil spill. Recently, a key partnership formed by Chevron, Statoil, Nexen and Hess announced the approval of US$6 billion in support of the Stampede development. Major offshore basins, the Gulf of Mexico, Brazil, and West Africa will all follow a similar logic in continuing their necessary capital expenditure in the operation of producing or already under-development projects.
Natural gas deep and ultra-deepwater projects are traditionally more challenging than crude oil projects, due to the restrictions in transportation that reduces the options for export markets and makes them dependent on gas domestic prices. LNG projects, such as Greater Gorgon in Australia, have a clear advantage in reaching high gas price markets in Asia, countering the negative impact from the fall in the oil price, but increased competition and potential for a lower gas price looms.
Historically, deep and ultra-deepwater projects have experienced cycles in the rise and fall of oil prices. Their development requires a long-term view and, as argued before, pricing fluctuation is generally dealt with through delays, with operators turning to managing producing and already under-development projects. Deepwater operators tend to be well-established and financially sound companies with well-diversified portfolios of upstream assets mitigating risk. Whenever possible, they actively try to redirect their investment strategy towards assets that can provide the highest amount of cash flow. In this context, production assets are given priority over exploration assets that have a less certain flow of associated revenues. It is possible that some new deepwater exploration areas, such as the ones on the Mexican side of the Gulf of Mexico, will face a slowdown in the pace of their exploration and development, or worse, they might not gain the interest of major oil and gas companies if the bidding terms are not attractive enough.
Adrian Lara directs GlobalData’s upstream team in charge of conducting quantitative and qualitative research relating to oil and gas activities in Latin American countries. Lara has several years of experience as an oil and gas industry analyst, having held different positions within the trading arm of Mexican state-owned company Pemex, where he focused on analysis of oil and gas fundamentals in the context of upstream exporting strategies and international trading. Lara was also a visiting research fellow at the Oxford Institute for Energy Studies where his research focused on oil supply scenarios in the Western Hemisphere. Lara has a MS in mineral and energy economics from the Colorado School of Mines, with a specialization in oil and gas from the Institut Français du Pétrole. He has a BA in economics and political science from the Instituto Tecnológico Autónomo de México (ITAM).