How Long Can the Offshore Upcycle Last? Part 2
Part 2 | How Gas Projects Are Adding to the Offshore Orderbook
The first article looked at deepwater oil. This one turns to natural gas.
The work created by gas projects extends well beyond liquefaction plants. An FLNG vessel is a major piece of floating offshore infrastructure in its own right. Offshore gas developments also require platforms, subsea systems and export pipelines. Even onshore LNG projects generate fabrication work for large shipyards and offshore construction bases, which often build liquefaction and utility modules. Qatar's North Field expansion, LNG Canada, Mozambique LNG and Coral North FLNG, and Argentina's proposed FLNG projects are all creating or preparing work across that chain.
Gas processing can generate sizeable EPC awards as well. In August 2026, ADNOC Gas awarded contracts worth about $8.2 billion for phases two and three of its Rich Gas Development programme, covering gas-processing and NGL-fractionation facilities.
These projects cost billions of dollars, take years to build and are expected to operate for decades. Why are companies and resource holders still approving so much gas infrastructure while renewable capacity is expanding and governments continue to pursue lower emissions?
1. Since the War in Ukraine, Buyers Have Paid More Attention to Where Their Gas Comes From
LNG investment was already recovering before 2022, so the war in Ukraine did not start the current construction cycle. The sudden loss of much of Europe's pipeline supply did, however, force buyers to reassess the risks of disruption and over-reliance on a small number of sources. The IEA says contracts of ten years or longer have accounted for 75% of LNG volumes contracted since 2022. Developers need long-term cash flow to finance large liquefaction projects, while buyers want some supply secured in advance. Long-term offtake agreements have therefore regained importance.
Once built, a pipeline generally offers low transport costs and stable deliveries, but its origin and destination are fixed. LNG cargoes can be diverted, and buyers can purchase from several exporting countries. Europe used that flexibility after 2022 to replace a substantial share of the Russian pipeline gas it had lost within a relatively short period.
LNG has its own points of vulnerability. Cargoes from Qatar and the United Arab Emirates that pass through the Strait of Hormuz represent almost one-fifth of global LNG trade. Disruption in 2026 temporarily removed close to 20% of global supply and pushed Asian and European prices to their highest levels since early 2023. Shipping makes it easier to diversify suppliers, but it does not remove the risks created by concentrated export facilities and maritime chokepoints.
Many buyers are now combining a broader supplier base with long-term contracts rather than relying heavily on one pipeline or exporting country. For developers, sufficient long-term offtake remains central to financing and final investment decisions. The Ukraine shock did not create the underlying demand for this LNG cycle, but it gave supply security much greater weight in procurement and investment decisions.
2. European Demand Is Falling, but Asia and Power Markets Are Still Growing
Europe remains a declining gas market. The IEA expects European demand to fall by about 8% between 2024 and 2030, while global demand rises by roughly 9%. Asia-Pacific accounts for around half of that growth, with China alone contributing about a quarter. Industry and power generation are the main sources of additional demand.
Asian LNG demand is highly price-sensitive. When spot prices surged in 2022 and 2023, some buyers reduced imports and power producers or industrial users switched back to coal and other fuels. New supply from the United States, Qatar and elsewhere could revive some of the demand that high prices suppressed. But prices low enough to encourage consumption also weaken returns on new liquefaction projects. Import growth in Asia will depend on price as well as the construction of terminals and pipeline networks.
Gas is tied more directly to the power market than oil. The IEA expects global electricity demand to grow by an average of about 3.6% a year from 2026 to 2030, led by industry, electric vehicles, air conditioning and data centres. Renewables and nuclear power are projected to supply about half of global generation by 2030, yet gas-fired output is still expected to rise by around 2.6% a year. With total electricity use expanding, a larger renewable share can coexist with more gas-fired generation.
The balance differs from one market to another. Where grids and storage are keeping pace, a larger share of new load can be met by renewables. Where demand is rising quickly and the system lacks sufficient flexibility, gas-fired plants may still be used for balancing and firm supply. In countries with limited domestic gas and few pipeline options, that can mean additional LNG imports and investment in receiving terminals, pipelines and upstream gas developments.
Data centres are also pushing up electricity demand, but AI did not set the current LNG build-out in motion. The IEA expects global data-centre electricity use to rise from about 415 TWh in 2024 to roughly 945 TWh in 2030. In the United States, data centres could account for nearly half of the increase in electricity demand through 2030. By 2035, renewables are expected to meet about half of the worldwide increase in data-centre consumption, while gas-fired and nuclear generation each add around 175 TWh.
Only the share served by gas-fired power becomes gas demand. The effect will be more direct in the United States and other markets that already have extensive gas networks and generating capacity. Elsewhere, it will depend on how quickly grids, storage, nuclear plants and renewables are built. Treating every unit of data-centre demand as future LNG consumption would materially overstate the effect on offshore orders.
3. A Large Supply Wave Is Under Construction; the Next Round of Projects Is Less Certain
Many LNG projects approved over the past several years are now under construction. Onshore plants require liquefaction units, compressors, storage tanks, jetties and large modules. Offshore gas developments need production facilities, subsea pipelines and other underwater systems, while some remote resources are being developed with FLNG. This work has already produced a substantial backlog for yards, module fabricators and oil and gas EPC contractors.
The IEA's latest LNG capacity tracker shows that projects already at FID or under construction could add about 345 billion cubic metres a year of export capacity between 2025 and 2030—the largest expansion the industry has seen. Even after construction starts, these projects still have to pass through fabrication, installation, commissioning and ramp-up. The associated engineering workload will not disappear quickly.
The commissioning timetable has become less predictable. Disruption in the Strait of Hormuz in 2026 also affected gas facilities in Qatar. The IEA now expects the shock to delay the previously anticipated easing of global LNG supply by at least two years. Sanctioned projects will continue to be built, but their start-up dates and the volumes reaching the market are less certain than they appeared a year ago.
The supply wave had always carried a risk of oversupply. In its 2025 base case, the IEA estimated that the global LNG market could have around 65 billion cubic metres a year of surplus supply by 2030. The subsequent Middle East disruption changed the schedule for some projects and for the recovery of available capacity, so that figure should no longer be treated as a firm outcome. A mismatch between Asian demand, import infrastructure and new supply remains possible; the timing is simply harder to call.
Projects already under construction should support part of the engineering workload for the next few years. Owners considering the next group of LNG and FLNG developments will wait for clearer evidence on prices, Asian import growth and long-term contracting. If the market absorbs the new supply without prolonged pressure on inventories and prices, more gas fields, FLNG units and liquefaction modules will be sanctioned. If it does not, FIDs and contract awards will slow.
Oil and gas are both contributing to the offshore orderbook, but the turning points will not necessarily arrive for the same reasons. Deepwater oil depends heavily on project breakevens and producer capital allocation. LNG also depends on long-term contracts, import infrastructure and the pace at which new capacity is absorbed. The third article will move to the orderbook itself and examine the changes in project costs, producer spending, yard capacity and contract awards that would indicate the upcycle is nearing a turning point.