Over the next 2 years, everything changed dramatically. By late 2021, Russian supply to Europe was falling, ahead of the illegal invasion of Ukraine in early 2022. Maxed out global LNG supply coinciding with unusually low nuclear and hydro output triggered a European gas crisis – and by extension a global energy crisis. Prices went bonkers, spiking to an absurd all-time high over €300/MWh (equivalent to ~$100/MMBtu). They then fell hard later in 2022 and then more steadily over 2023 until bottoming out in March 2024 as supply gradually caught up.

Like any commodity, supply and demand, and perceived future changes or risks to both, fundamentally drive gas markets. But weather patterns can cause big short-term variations. Exceptionally high or low temperature periods – lasting anything from a day to a whole season – can strongly influence gas demand across different geographies, whether for heating, cooling or power. Likewise, gas demand is affected by wind power output in markets like the UK or by seasonal rainfall trends in hydro-dominated markets like Brazil and Norway. 

2024 turned out to be the lowest year of LNG capacity increases for a decade, adding only 2 MTPA of new supply. This, along with colder and less windy weather in Europe, tightened the market steadily from its March 2024 nadir around €15/MWh. The TTF contract for May 2025 delivery peaked as high as €57.3/MWh on 10 February. The market then corrected sharply, falling to just above €30/MWh by the end of April (still relatively high versus historical averages). This correction was part of the wider market fall on trade war fears, but rising US LNG output and warmer European spring weather were also key factors. 

The extreme spikes in 2022 obscure subsequent fluctuations. Zooming in on the past year only below gives a clearer picture of recent dynamics.

The LNG Deluge 

So, after this rollercoaster last 5 years, where next for gas markets? The risk looks increasingly skewed towards lower prices which, being cyclical, are more likely to overshoot on the downside than simply settle at convenient long-term averages. Weak industrial gas demand in Europe and rapidly rising renewable output in China are relevant factors, but the key driver is undoubtedly the flood of LNG supply expansions scheduled to arrive over the rest of the decade. 

The US has turned itself into the world's biggest gas producer and LNG exporter, with 8 terminals coming online over the past decade. And it is not looking back. Over 2025-26 alone, it is set to expand capacity by around half again, adding another 3 terminals. There are still more at the planning stage, although the rate of approvals may well slow down. Over the next decade, the US’ global market share is projected rise from a quarter today to a third of a much bigger market.

This year’s expansion kicked off with a rapid ramp-up of Venture Global's Plaquemines Phase 1 in Louisiana, to be followed by Corpus Christi Stage 3 in Texas, then Plaquemines Phase 2 and Golden Pass, also in Texas, next year. Such a sharp rise in exports makes LNG plants the fastest growth source of US gas demand, which should increasingly support domestic prices. The US Energy Information Administration (EIA) forecasts Henry Hub spot prices to double from ~$2.20/MMBtu in 2024 to ~$4.50/MMBtu by 2026, a level it already touched briefly in early March of this year.

Outside the US, LNG Canada in British Columbia, Costa Azul in Mexico, Pluto expansion in Australia, the Tortue Floating LNG project offshore west Africa and Qatar's North Field East expansion project are also all scheduled to come online over 2025-26. Collectively that means the global LNG market is on track to grow by a further 80 MTPA, or nearly 20% in 2 years, as it heads towards 700 MTPA by 2030. Project delays are always likely, but even so, the volume of new supply looks far higher than incremental demand.

Qatar’s LNG plans are no less ambitious as the US. LNG is the small Persian Gulf state’s national industry. Its entire economy was built effectively on one asset, the North Field, the world's largest single gas field, which is shared over its maritime border with Iran. Its planned East (due online in 2026), South and West expansion projects will collectively nearly double export capacity from 77 MTPA now to 124 MTPA by 2027 and 142 MTPA by 2030. The world’s lowest production costs give Qatar crucial leverage to be competitive at prices that will hurt other producers. That would reinforce its position as a key LNG swing producer, akin to its neighbour Saudi Arabia’s “central bank” role in the oil market.

The LNG market has shown a pattern of multi-year cycles of expansion. Over 2005-10, Qatar’s first round of major investment was the key driver of capacity growth. After a relative pause over 2011-14, the US and Australia then followed suit over 2015-20, before expansion then decelerated again over 2021-24. Now we have the US and Qatar’s respective second phases of major expansion looking highly likely to flood the market. 

The Geopolitics of Gas 

Ensuring security of oil supply routes has been a key pillar of US foreign policy over many decades. With much greater self-sufficiency in oil, the US focus has shifted. After decades where oil was king, the growth of LNG trade means gas is taking over as the world's most geopolitically significant energy source. The current administration has no qualms about exploiting LNG market power under its doctrine of “energy dominance”. To quote JD Vance: “We’re sitting on the Saudi Arabia of natural gas. We’ve just got to unleash that.” LNG deals have become key bargaining chips in trade negotiations.

Of course, using gas as international leverage is nothing new - Putin wrote the textbook. But abundant US gas supply needs a market and Europe remains highly dependent on imports, even with demand is in structural decline. This year to date, over half those LNG imports are from the US. Qatar looks like the only serious supply competition, but is mainly focused on supplying Asia. It is shaping up broadly into a global LNG bifurcation where the US mainly supplies Europe in the Western hemisphere while Qatar and Australia dominate supply to Asia in the Eastern hemisphere. 

Even if Trump’s idiosyncratic peace efforts on Ukraine were to somehow succeed, Russian gas has no realistic path back into Europe. In fact, having conveniently imported Russian LNG since the crisis, the EU now aims to eliminate gas imports from Russia (including LNG) by the end of 2027. With heavy sanctions complicating its LNG expansion, Russia has focused on expanding pipeline supplies to China, which offer a cheaper alternative to LNG. Neither a Ukraine peace deal nor the reconciliation with Iran that Trump also claims to be pursing would bring any immediate jump in supply to Europe, although they would certainly further soften the market. 

It’s probably no coincidence that, just as Trump launched his tariff war, China, the world's largest gas importer, stopped importing US LNG. It was only a relatively small proportion of its total gas imports, but the change still seems symbolic. China’s industrial strategy has focused on energy security, minimising import dependence and dominating clean energy supply chains. It is targeting peak emissions by 2030 (if not sooner) and has a full carbon neutrality goal of 2060, which would require both renewables and gas to replace coal.

China is therefore adopting a three-pronged strategy on gas: 

1. ramp up domestic production as far as possible (it now produces more than Qatar, and twice as much as major European supplier Norway)

2. source lower-cost pipeline gas where available (i.e. Russia), and

3. use LNG for the balance, speeding up or slowing down purchases as prices fluctuate.

Unusually, Chinese LNG imports have been falling recently, even as LNG prices fell. This implies other factors at play – either politically motivated as part of the tariff standoff, or underlying structural changes such as weaker growth or renewable energies undercutting gas demand. Energy security remains ultimately the highest priority, above environmental targets. Strategically, China may prefer increased reliance on coal than needing US LNG at such a sensitive time. But although renewables and battery storage growth will steadily depress the price at which LNG can compete, from next year it may get too cheap for China to ignore.  

But China is far from the only driver of Asian gas demand over the next decade. Rystad Energy projects demographic and economic growth to nearly double Indian gas consumption from 65 billion cubic metres (BCM) in 2023 to 114 BCM by 2040. That equates to around 80 MTPA in LNG terms, i.e. equivalent to all of the big supply increase of 2025-26.

Demand is also growing in the gas-rich Middle East itself. For Saudi Arabia, boosting gas production not only offers cheaper and cleaner domestic power, but saves oil production for higher value exports. The OPEC kingpin is targeting a gas and solar dominated power mix, investing heavily in projects like the Jafurah shale gas field, which would free up a further 350,000 bbl/d more oil exports – nearly half this year’s total increase in global oil demand.

Evolution of Saudi Arabia’s power generation mix. Source: Rystad Energy

Energy investing in a world of low gas prices

So, who will be the winners and losers in a multi-year phase of lower gas prices? What are the wider implications for energy investment?

There are multiple ways to invest in and around the gas value chain, whatever your view on prices. The pace of clean energy expansion is one key variable: all else equal, a slower rollout would support higher gas demand, while faster progress would limit it. This implies that gas-focused investments would provide a potential portfolio hedge alongside renewable investments. However, gas and power markets can also be highly correlated. Moreover, everything points to it being a very risky time to take long gas price exposure. But by the same token, lower prices should benefit buyers and consumers of gas - and often power too. In other words, boosting everyone from households to small businesses to major companies in import-dependent countries.  

Evaluating the likely impact on some key players in the gas value chain:  

1. Gas producers

Specialist gas producers are naturally highly exposed, especially to the extent they rely on spot sales rather than long-term fixed price contracts. This is particularly the case for smaller international or pure play companies without other revenues to fall back on. Where it’s affordable, such companies will usually have active gas price risk management programmes. Hedging can smooth out revenue volatility over shorter periods, but it cannot really protect smaller producers from longer-term price declines. A more effective price risk mitigation strategy, where feasible, is signing diversified multi-year sales agreements with strong offtakers, incorporating robust pricing formulas and take-or-pay clauses.  

As noted above, being the fastest growing source of US gas demand (overtaking industry, power generation and building heating and cooling), rising LNG exports should pull Henry Hub prices higher over time. In theory, that makes specialist US gas producers worth considering. However, the leading players EQT (NYSE: EQT), Expand Energy (NASDAQ: EXE), Antero Resources (NYSE: AR), CNX Resources (NYSE: CNX) and Coterra Energy (NYSE: CTRA) all already look very expensive, trading mostly at or near their all-time highs. In any case, if LNG export demand starts pushing US gas prices higher than Trump supporters would like, don’t rule out some sort of intervention. 

2. LNG developers 

LNG companies with uncontracted volumes are arguably the most exposed to gas price swings, given the $10-20 billion of investment and 5 years typically required to build an export plant. Exporting cheap US gas as LNG to Europe and Asia, where prices have typically been 3-4 times higher, can still be a very lucrative arbitrage. But nothing ever stays easy for too long. Buying, liquefying and shipping the gas (before regasification by the buyer for end use) equates to a typical operating breakeven price of ~$6-8/MMBtu (€21-24/MWh, 50-60p/therm). Of course, this varies according to domestic gas prices, shipping rates, contract structures and financing costs. If prices fall significantly below this level for any length of time, as seems likely especially once the next 80 MTPA has hit the market by 2027, exporters may be forced to curtail shipments.

The longer that happens, the more financial distress that would cause. But prices cannot remain below the US LNG breakeven indefinitely. Lower prices would eventually stimulate more demand particularly from Asian buyers. In the longer-term, that implies a likely convergence in the $8-10/MMBtu range, interrupted by shorter periods of acute shortage or oversupply. At the time of writing, the JKM futures price (contract for June delivery) was around $12.5/MMBtu, up from its February 2024 low of $8.30/MMBtu but down from its peak of over $15/MMBtu in mid-February 2025. 

The contrasting trajectories of two US LNG players demonstrate the impact of different commercial strategies. Venture Global (NYSE: VG), operator of Calcasieu Pass and Plaquemines export terminals, is relatively exposed to spot sales versus long-term contracted cargoes. This has left it more exposed to price risk, while confidence has also been affected by its dispute with major offtakers over sales during its commissioning period. Since its January initial public offering (IPO), its shares in have already plummeted by more than half. 

By contrast, shares in the largest US LNG player by volume, Cheniere Energy (NYSE: LNG), operator of the well-established Sabine Pass and Corpus Christi export terminals, have enjoyed a spectacular run so far this decade, quintupling from ~$50 in 2020 to $250 by early 2025. Cheniere has a tolling business model for over 80% of its output, a fundamentally less risky approach which locks in long-term index-linked (i.e. tied to Henry Hub prices) take-or-pay sales contracts with strong offtakers. With a track record of delivering projects on time and budget, it has been able to generate steady cash flow to service debt, pay dividends and buy back shares. It’s contractual model insulates it from the risk of rising domestic US prices by passing this through to buyers. 

3. LNG-focused integrated energy majors (IOCs)

Gas and LNG have become key strategic pillars for two IOCs in particular: Shell (LON: SHELL) and TotalEnergies (LON: TTE). These big, vertically integrated “portfolio players” produce, buy, ship and sell LNG, both on a spot and long-term basis, enabling them to manage price risk to some degree. The gas downcycle looks likely to weaken their spot LNG sales margins, reduce volatility for their trading arms to manage risk and optimise their portfolios, depress prices for new long-term contracts and make it harder to approve new projects. Of course, their LNG portfolios come as part of wider oil businesses, but those also face their own headwinds. 

4. Gas and power utilities and generators

Big utilities like Centrica (LON:CNA) and SSE (LON:SSE), along with their various European counterparts like Engie (EPA: ENGI), RWE (ETR: RWE) and E.ON (ETR: EOAN), have diversified, vertically integrated and heavily regulated business models, spanning from gas production and renewable power generation to gas-fired power generation, storage and trading through to gas and power supply to residential, commercial and industrial customers. As such, they are simultaneously buyers, users and sellers of gas, and as a matter of policy they avoid excessive market risk by active hedging strategies. 

The effects of lower gas prices will be mixed, but overall mean tougher conditions for utilities. Upstream gas production assets will clearly be most affected. While their downstream supply businesses pass through price risk, this gets more challenging for sustained periods of low prices, given their fixed cost base. Gas-fired power generation and gas peaking utilisation and margins may improve given lower input costs, enabling higher income especially during power prices spikes. However, lower gas prices will often lead to lower power prices. This will also hit renewable generation revenues, unless protected by Contracts for Difference (CfDs) or long-term Power Purchase Agreements (PPAs). Prolonged periods of low prices can also depress volatility, creating tougher conditions for their storage and trading businesses. 

5. Gas supply chain 

Cheaper gas is likely to continue to support demand for and utilisation of gas-fired power plants, in turn underpinning demand for associated equipment. Even after a period of high gas prices, that demand is already extremely strong and the supply chain highly congested. The market values of leading providers like Siemens Energy (ETR: ENR), Schneider Electric (EPA: SU) and GE Vernova (NYSE: GEV), among others, have risen very substantially over the past couple of years as the backlog for key equipment like gas turbines has extended out to half a decade, meaning new orders won’t be delivered until at least 2030. This has led to severe price inflation – with new US gas-fired power generation capacity tripling from under $800/kW to around $2400/kW in recent years, according to the CEO of NextEra Energy, America’s largest electric utility. Higher medium-term gas demand looks unlikely to alleviate these extended lead times and prices for new gas capacity. It seems more likely that new gas-fired power infrastructure will simply be priced and timed out, increasing the demand for renewable and battery capacity which can be installed in much shorter timeframes. 

6. Renewable generators 

In markets where gas and power prices are closely linked, like the UK, merchant power producers will be at particular risk if not protected by long-term structures PPAs or CfDs, where price levels may be either guaranteed or much less volatile. As with gas producers, the proportion of merchant versus contracted exposure will be an ever more important risk factor for assessing the future prospects of wind and solar operators. Low power prices will also depress the prices at which renewable generators can sign new long-term contracts with offtakers. The chart below shows markets where gas has a particularly strong influence on power prices.  

Source: Carbon Brief

7. Storage operators

The gas downcycle is also likely to create challenges for storage businesses, including grid-scale battery operators, where lower gas prices cause lower power prices and lower volatility, impacting the scope to trade spreads. That said, the latter is not batteries’ only revenue source – they also participate in frequency response and capacity markets. Similarly to renewable generators, they can also enter long-term tolling contracts with set price formulas rather than taking full market exposure, or to co-locate with renewables assets which can enable joint PPA structures.  

8. Gas and power consumers

Last but certainly not least, lower gas prices will clearly be very good news for the millions who have endured the opposite over the past 5 years – especially where they pull power prices down too. That includes everyone from individual households to small businesses to industrial and commercial customers across all sectors for whom energy is an important cost input. It would provide an economic boost across whole economies, particularly in Europe, where consumers of all types have been burdened with gas input prices typically 3-4 times higher than their American counterparts. That gap is unlikely to close completely, but would certainly shrink, helping to reduce European industries’ deep competitive disadvantage.