How Long Can the Offshore Upcycle Last? Part 1
Part 1 | Why Deepwater Projects Keep Moving Without $100 Oil
For years, the oil price has been the offshore industry's simplest gauge of market conditions. Higher prices strengthen producers' cash flow and tend to lift upstream spending. More drilling, more demand for rigs and more work for shipyards and engineering contractors usually follow.
The last offshore boom coincided with a long period of exceptionally high prices. Brent averaged more than $100 a barrel in each year from 2011 through 2013, with a three-year average of about $110.5. The current recovery is different. Deepwater projects have continued to advance in Brazil, Guyana, Suriname and West Africa, bringing more orders for FPSOs, subsea production systems and related engineering work. Yet Brent averaged only about $77.4 a barrel over 2023–2025. Disruption to shipping through the Strait of Hormuz pushed prices sharply higher for a time in 2026, but that was a geopolitical supply shock. By then, the deepwater EPC market had already been strong for several years.
That leaves an obvious question: why are deepwater projects still moving forward when oil has not returned to the sustained highs of the last cycle?
1. The Last Cycle Was Led by Drilling Rigs
During the last offshore cycle, high oil prices made a wider range of resources economic. Producers raised exploration spending, drilling contractors expanded their fleets, and shipyards took a wave of rig orders. In early June 2014, IHS Petrodata counted roughly 160 mobile offshore drilling units under construction or being rebuilt worldwide, up from 131 a year earlier. Many of those orders went to Chinese yards, where the number of rigs under construction had risen by more than 60% year on year.
The market turned abruptly in the second half of 2014. Global oil supply began to outpace demand, US crude production was rising quickly, and OPEC did not make the deep production cuts many had expected. The monthly average Brent price fell from about $112 a barrel in June to roughly $62 in December. The resources had not disappeared, but many projects no longer worked at the new price. Producers cut capital spending, exploration and development plans were deferred, and drilling demand fell. Rigs ordered during the boom were still arriving, exposing the surplus almost immediately.
Over the next several years, large numbers of rigs were idled or cold-stacked, while some orders were delayed or cancelled. The industry entered a long downturn. The boom had been built on the assumption that high prices would last, so it unravelled quickly when that assumption failed.
2. After 2014, Producers Changed What They Were Willing to Fund
The 2014 downturn forced producers to rethink where they put their money. At high prices, some relatively expensive developments could still move forward. Once prices fell, capital shifted towards resources with lower costs and more dependable returns.
The IEA estimates that global upstream oil and gas costs fell by about 30% between 2014 and 2016. Its 2018 Offshore Energy Outlook noted that some investments offshore Norway and in the US Gulf of Mexico, once thought to require $60–80 a barrel to break even, were then claimed to be viable at $25–40. Simpler designs, greater standardisation and lower supply-chain costs all played a part.
That thinking now shows up clearly in company plans. Petrobras has allocated $69.2 billion to exploration and production in its 2026–2030 business plan, with 62% of the target project portfolio going to Brazil's pre-salt. The portfolio carries an average prospective Brent breakeven of about $25 a barrel. In Guyana, ExxonMobil has developed the Stabroek block through a series of FPSO projects. The company says its first four developments all started ahead of schedule and came in under budget.
The mix of offshore orders has changed with it. In the previous cycle, new spending reached exploration first and drilling rigs led the market. In recent years, more capital has gone into discoveries that are already appraised, relatively low-cost and suitable for phased development. That has favoured FPSOs and subsea production systems. The last boom was about finding more oil; this one is more about bringing the best discoveries into production.
3. Slower Demand Growth Does Not Stop New Projects Overnight
Lower costs explain why a number of deepwater developments still work at oil prices in the $60–70 range. But another question remains. With renewables growing quickly and debate continuing over peak oil demand, why commit capital to an offshore field that may produce for twenty or thirty years?
One reason is field decline. The IEA's analysis of production records from roughly 15,000 oil and gas fields found that conventional oil fields decline by an average of 5.6% a year after peak production. Deep offshore fields decline faster, at 10.3% on average. Since 2019, nearly 90% of annual upstream oil and gas investment has gone to offsetting losses from existing fields rather than meeting demand growth.
Not all of that spending becomes a new FPSO. It also covers infill wells, workovers, water injection, production enhancement and modifications to existing facilities. Even if oil demand stops growing, however, today's wells cannot keep supplying the same volumes indefinitely. New projects are still needed whenever losses from mature fields exceed the fall in demand.
If demand falls fast enough, the need for new projects will shrink sharply. Producers are betting that, over the next several years, demand will not decline faster than existing supply and that lower-cost resources will remain competitive even in a weaker market.
4. Why More of the New Work Is Offshore
New supply can come from either onshore or offshore fields, but recent conventional project approvals have become increasingly offshore. According to the IEA, more than 70% of conventional oil and gas projects approved in recent years are offshore.
The shakeout after 2014 removed many high-cost deepwater schemes, but it did not stop deepwater development. Brazil's pre-salt, Guyana and parts of West Africa have changed markedly after years of project experience and cost reduction. These developments still require heavy upfront spending, but they offer large resources and high well productivity. Once an area moves into repeat development, parts of the design, engineering approach and supply chain can also be reused.
Producers rank projects by cost, scale, returns and execution risk; they do not simply choose between an onshore and an offshore label. A large deepwater resource that can be developed in phases may be more attractive than many onshore opportunities. As Brazil's pre-salt and Guyana have moved into repeat development, the workload for FPSOs, subsea production systems, topsides and related EPC contractors has grown with them.
The duration of this offshore upcycle will therefore depend on whether low-cost deepwater projects continue to reach final investment decision, whether Brazil and Guyana sustain their development pace, and whether producers keep allocating capital to long-cycle offshore work. Oil prices still matter because they shape cash flow, financing and investment decisions. But as long as a pipeline of deepwater projects remains profitable at mid-cycle prices, the absence of sustained $100 oil does not mean the offshore run is about to end.
There is another part of the market to watch. Onshore LNG, FLNG and offshore gas projects are also gathering momentum. Why is gas investment rising even as renewable energy expands? That is the subject of the next article.