Abramson: The greatest cost pressures are showing up in the most technically complex, sector-specific cost categories. High-end drillship day rates, for example, have risen roughly 50% over the past several years, from the $400,000 range to approaching or exceeding $600,000 for leading-edge vessels.

FPSO costs and lead times have also increased significantly as the limited pool of qualified Asian shipyards operates near capacity, pushing breakevens higher for new developments. Operators are responding by simplifying and standardizing designs, recognizing that bespoke specifications add both cost and schedule risk.

Post-FID, we’re also seeing companies lock in critical supplier slots earlier and apply tighter scope discipline to protect project economics. 

Rose: Companies shouldn’t be sanctioning long-cycle developments based primarily on today’s commodity price environment, particularly when prices may be near the top of the cycle. Leading operators are looking at a much broader set of risks and strategic factors.

Supplier capacity has become particularly important as subsea and FPSO backlogs at tier-one contractors have extended toward the end of the decade. In many cases, slot availability is now a sanctioning criterion, not just price. 

Execution and technical complexity matter as well, which is why boards increasingly favor proven concepts and templated designs over first-of-its-kind engineering.

Geopolitical and supply chain risks also have to be considered, from sanctions and resource nationalism to potential fiscal changes.

The growing role of gas and LNG is another consideration, as global LNG demand can create new pathways to monetize offshore gas resources and influence the economics of a development.

And increasingly, operators are looking beyond the individual asset to portfolio fit and JV alignment, focusing on whether a project creates future tieback opportunities and whether the partners have the necessary capability, financial strength and strategic alignment. 

Offshore: How are operators balancing shareholder demands for capital discipline with the need to invest in large, long-cycle offshore developments that may not generate first production for several years? 

Scheller: Shareholders increasingly view oil and gas as a value investment rather than a growth investment, which puts a premium on returning cash. But that doesn’t mean long-cycle offshore development no longer fits the portfolio.

Leading operators see their best offshore assets as the baseload of the upstream business, the same way an electric utility looks at its large fossil or nuclear plants. While they require significant upfront investment, in return they can deliver low lifting costs, long plateau production and shallow decline rates, generating durable free cash flow for a decade or more. That can complement shorter-cycle shale, which provides flexibility but requires continuous reinvestment. 

The key to reconciling capital discipline with long-cycle investment is applying risk-based portfolio management principles, such as setting strict breakeven hurdles, high-grading to only top-quartile opportunities, and using tiebacks and phased developments to accelerate returns. Offshore developments will continue to have an important place in the portfolio, but the capital commitment has to fit within a framework that delivers cash back to shareholders. 

Offshore: Compared with five years ago and the last offshore downturn, what has fundamentally changed in the economics of offshore project development, and what misconceptions do executives still have about creating value in today's market? 

Abramson: Offshore economics have fundamentally changed since the last downturn. Top-tier deepwater developments, such as Guyana, Brazil presalt and select Gulf of America assets, now break even in the $30-$40 per barrel range, putting them alongside some of the best US shale basins despite their higher upfront capital requirements. That improvement has come from exceptional resource quality, rigorous portfolio high-grading, standardized FPSO and subsea designs, and structural cost management.

At the same time, the misconception is that those gains are permanent. They aren’t. Supply chain inflation, a return to bespoke specifications and organizational bloat, and sanctioning second-tier projects at the top of the cycle can quickly erode that advantage.

Maintaining today’s economics will require operators to exercise the same discipline that created them in the first place. 

Offshore: Looking across key offshore regions, where is the strongest opportunities for investment and project activity over the next five years, and what characteristics make those regions particularly attractive? 

Abramson: There are strong opportunities across offshore regions, but the opportunity looks different depending on an operator’s strategy, capabilities and risk appetite.

For large IOCs with long horizons and diverse portfolios, greenfield developments in places like Guyana and Brazil provide opportunities to develop basins with massive reserves, low breakevens and stable production profiles. Namibia’s Orange Basin shows similar promise, provided operators can overcome structural challenges such as logistics.

Smaller independents and JVs that specialize in other offshore arenas, such as mature, end-of-life assets, can complete acquisitions at attractive prices, operate them with lower cost structures and pursue lower-risk brownfield growth through tiebacks.

Gas is also becoming an increasingly important part of the offshore opportunity. Growing global LNG markets are creating additional demand for offshore gas resources, while energy infrastructure companies are developing new capabilities, including modular and floating ‘fast LNG’ solutions, that can provide different pathways to bring those resources to market.

Ultimately, there isn’t only one offshore basin or development model that creates value. The opportunity is matching the right assets with the right strategy, risk appetite and cost structure.