The Global Gas Market in 2025

Portfolio players get the game. They snap up longer-term LNG supplies for stability while flipping sales on shorter deals or spot to chase the best margins.

Portfolio players' LNG contract share has climbed steadily from 26% in 2016 to 37% in 2020-2024, and hit 42% in 2025. That relentless upward trend hands them control of market flexibility.

Post-2022 price spikes, buyers hesitate on long-haul commitments, scared of overpaying if prices drop. Portfolio players fill the gap. Their buy side now dominates new volumes with deals pushing 15 years. Sales side stays nimble under 11 years. Net result? Wider open positions for trading firepower.

Will portfolio players keep widening that gap to dominate trading flows or start matching sales durations as buyers seek more security?

Global gas markets will need more LNG, and the US intends to be the price-setting supplier when they do.

FIDs in US LNG projects reached an all-time high in 2025. Exports averaged 14–15 bcf/d in 2025, up from 12 bcf/d in 2023. This reflected confidence in three things the US uniquely offers at scale: low cost gas, regulatory support, and the ability to deliver projects that buyers trust.

What does this mean? The next wave of LNG is already spoken for, and a big chunk of it is American. That strengthens energy security, but it also means the market will not reward every marginal project elsewhere.

In this business, the winners are the ones who build before the shortage turns into a glut. The US just did that again.

Together with the US, Qatar accounts for 70% of the LNG capacity coming online by 2030. But unlike higher cost projects elsewhere, Qatar does not need tight markets to make the economics work.

Qatar’s LNG production held steady at 77 mtpa in 2025. The more significant development was forward capacity. The bulk of its next decade of LNG supply is already under construction and largely sold. That is the real advantage.

The North Field expansions advanced steadily, without the drama that dogs mega-projects elsewhere (e.g. Mozambique). The lesson was uncomfortable for some. If you have low-cost gas, disciplined execution, and locked-in buyers, you can ignore a lot of noise.

QatarEnergy's North Field East expansion will add 32-33 mtpa, with North Field South adding another 16 mtpa, bringing total capacity to 126 mtpa by 2027. The subsequent North Field West expansion will add a further 16 mtpa, reaching 142 mtpa by 2030. The majority of this capacity is already committed under long-term contracts.

That is why Qatar ended 2025 in a familiar position. Not loud. Not flashy. Just very hard to compete with.

Africa entered 2025 as an established LNG exporting region. What changed during the year was the composition of players and the design of new LNG plants.

New LNG projects increasingly feature cross-border partnerships, where neighboring NOCs team up alongside international operators and independents. Take the Greater Tortue Ahmeyim project which delivered first LNG in 2025. BP and Kosmos Energy partnered with Senegal’s Petrosen and Mauritania’s SMHPM. This multi-country ownership model may gain traction.

New capacity also moved from single-site onshore megatrains to floating and modular designs that cut security risks, shorten timelines, and boost financing confidence. GTA Phase 1 uses a FLNG vessel, while Mozambique’s Coral North builds on Coral South’s offshore model to sidestep onshore risks.

Offshore/modular designs with aligned partners took away some attention from larger, onshore projects with higher execution and security risk.

Nigeria did not have a dramatic year. That was the point.

Across the year, the focus shifted to fundamentals. Pricing moved closer to cost recovery. Domestic pricing frameworks were adjusted, wholesale CNG prices were set at around $1.57 per MMBtu, and payment discipline improved. Power sector arrears were confronted, not ignored, with a $2.7bn equivalent bond approved to clear verified legacy debts and another $120mn in gas to power payments released by year end. That alone changed producer behavior.

Volumes responded. Nigeria’s gas production continued a steady three year climb, with daily average output reaching 7.59 bcf per day in July 2025. That was roughly 10% higher than 2023 levels and about 9% above the 2024 full year average, confirming a gradual but sustained recovery.

The quality of production improved alongside volumes. Gas flaring continued to decline, falling to 7.16% in mid 2025, down from 7.55% in 2024 and 7.38% in 2023. More gas was captured, sold, and monetized instead of burned off, reinforcing the shift toward a more functional domestic gas system.

Infrastructure projects finally advanced after years of delay. The AKK pipeline crossed the River Niger, clearing one of its most complex engineering bottlenecks and unlocking northbound gas transport. More than 50 gas utilisation and flare commercialisation projects advanced through permitting. Project flow restarted. Shell took FID on a $2bn upstream gas project, expected to add about 350 mmscfd of gas processing capacity once developed. None of these were silver bullets, but together they reduced friction.

The industry broadened too. Nigeria’s CNG push moved from policy to hardware. Around 100,000 vehicles were converted, including 16,000 trucks, 4,600 tricycles, and over 500 buses. The rollout was supported by 369 conversion centres, 68 operational auto gas stations, another 150 under construction, and 27 mother stations linked to mini LNG supply. Total investment in the CNG programme reached $1bn, creating an estimated 10,000 direct jobs and 70,000 indirect jobs.

In 2025, Nigeria’s gas sector became more predictable, more bankable, and harder to dismiss. For a market long defined by volatility, 2025 delivered credibility through boring progress. That is how turnarounds actually start.

Between 2020 and 2023, LNG EPC costs rose over 30%, driven by inflation and supply chain constraints. In 2025, investment thresholds tightened sharply.

Projects with breakeven costs above $8–9/MMBtu struggled without long-term contracts locked-in, while brownfield and modular projects near $5–6/MMBtu advanced quickly. Boards prioritized schedule certainty and capital efficiency over scale. Venture Global is the poster child here, delivering projects faster and cheaper than traditional LNG majors through modular design and tight execution.

In 2025, capital followed results, not pedigree. Bringing LNG online on time and on budget now trumps brand or balance sheet size.

This was the year methane intensity (amount of potent methane gas leaked during LNG production and transport) stopped being mere ESG buzzwords and moved into contracts.

Buyers wrote it into contracts as a must-meet clause. Several LNG buyers in Europe and Asia began establishing methane intensity requirements as part of supplier qualification, with 0.2 percent of upstream production emerging as a key benchmark aligned with industry best practice standards such as OGMP 2.0 Level 5. The EU's binding maximum methane intensity value will be set by 2029 for implementation in 2030.

Lenders tied funding to verified low-leakage proof. Sellers realized emissions performance could determine market access, not just public perception.

What surprised me was how fast things changed once momentum built. Projects didn't get axed outright, but sloppy emitters got sidelined from top deals.

When a country can add hundreds of gigawatts of generation capacity in a single year, it resets the conversation. Gas remains critical in China, but the benchmark for “cheap power” moved.

China installed over 300 GW of solar in 2025, bringing total capacity above 1 terawatt.

That matters because gas now increasingly plays a balancing role in China rather than baseload. LNG imports continued, but tolerance for high marginal pricing dropped.

Gas demand did not disappear. Its negotiating position did.