Demand for subsea equipment holds, but macro headwinds remain

By Mark Adeosun, Westwood Global Energy Group

Subsea engineering, procurement and construction (EPC) award value in 2025 closed at c.US$17 billion, a 20% YoY decline, underpinned by 53 field final investment decisions (FID), c.230 subsea tree units, c.2,200 km of subsea umbilical, riser and flowline (SURF), and c.1,560 km of pipeline. Contracting activity was stifled by the lower-than-expected oil prices and high supply chain costs, which negatively impacted E&P’s investment appetite. 

The subsea EPC cost index rose by approximately 25% in 2025 compared to the 2021 baseline but was 14% lower compared to 2024. In parallel, selected operators increased their E&P budgets by about 69% compared to 2021, reflecting a continued commitment to project development despite rising costs. 

However, the average oil price in 2025 declined by 20% relative to the 2021-22 average of US$85.9/bbl. This price contraction has placed pressure on operators’ free cash flow, prompting a renewed focus on cost efficiency across the value chain. This led to a revision of the development timelines for projects such as Repsol’s Polok and Chinwol fields offshore Mexico and PTTEP’s Lang Lebah offshore Malaysia, with operators citing high supply chain costs and the need for project optimization.

In response, the supply chain is under increasing pressure to adopt new approaches and deliver cost reductions of approximately 15-20% from the 2024 subsea EPC cost index. This level of continued cost revision is considered essential, given the expectation of a persistently oversupplied oil market and continued downward pressure on oil prices.

While E&P companies sanctioned major subsea developments that required floating production systems in 2025, such as ExxonMobil’s Hammerhead development (Guyana), bp’s Tiber (US Gulf), Shell’s Gato do Mato (Brazil), Eni’s Coral Norte (Mozambique) and Petrobras’ SEAP II (Brazil), subsea contracting was widespread with several subsea tieback projects. Those tieback projects included Equinor’s Fram Sor, Johan Sverdrup Phase 3 and Isflak, all offshore Norway; ConocoPhillips Previously Produced Fields project (Norway); Chevron’s Gorgon Stage 3 (Australia); Beacon Offshore’s Shenandoah South (US Gulf); and Shell’s Mina West (Egypt). And E&Ps continue to utilize existing infrastructure.

Looking ahead, the demand for subsea production equipment is forecast to remain strong over the next five years, providing up to $90 biilion in EPC contracting opportunities for the supply chain during 2026-2030, with subsea trees demand estimated at c.1,300 units, averaging 260 units annually. However, challenges remain, as an oversupplied oil market, which is expected to reach 3 MMbbl/d in first-quarter 2026, the highest since 2020, continues to put downward pressure on oil prices, which will limit investments by E&P companies, which are poised to stay capital-disciplined, leading to project delays and deferred investment. 

In 2026, Westwood anticipates subsea EPC spend will total c.$17 billion, mirroring investment levels seen in 2025. However, the number of field FIDs could increase 13% YoY, totaling 60, as unit cost is projected to continue its downward trend, as seen since second-half 2025, to support planned investment.

Beyond 2026, contracting opportunities abound across all regions, with exploration successes in the Eastern Mediterranean Sea, offshore Brazil and Namibia, including the recently acquired Mopane discovery offshore Namibia by TotalEnergies from Galp Energia, which could progress in the latter years of the forecast.

Long-delayed projects, such as Equinor’s Bay Du Nord (Canada) and Wisting (Norway), Woodside’s Browse gas development (Australia), Shell’s Bonga SW (Nigeria), and Inpex’s Abadi development (Indonesia), are expected to be sanctioned before the end of the forecast. However, these projects are susceptible to delays should downward pressure on oil prices continue, given an oversupplied oil market.