Global Commodities: Rising LNG supply underscores need for demand-side infrastructure
The desk interprets the recent commentary from J.P. Morgan as underscoring the critical intersection of rising LNG supply and the need for enhanced demand-side infrastructure in emerging markets. Per the full note, the commentary highlights a slowdown in demand from established markets, which, coupled with infrastructure challenges, limits significant growth in LNG consumption. This scenario suggests a need for increased flexibility in the U.S. natural gas market, particularly through enhanced storage and production capabilities. As a result, the desk anticipates a potential shift in market dynamics that could influence currency movements, particularly in energy-linked pairs.
What the desk is arguing
J.P. Morgan's podcast featuring Greg Shearer, Otar Dgebuadze, and Nina Fahy discusses rising global LNG supply, demand slowdowns in key established markets, and infrastructure challenges limiting demand growth in emerging LNG markets. The team concludes that these dynamics warrant higher flexibility in the US natural gas market through storage and production adjustments.
Where it sits in our coverage
We have no internal coverage data on the relevant currencies or natural gas targets. However, the commentary aligns with a broader view that supply-side expansion without complementary demand-side infrastructure creates price volatility risks. Our consensus would lean toward bearish medium-term US natural gas prices due to oversupply, but the need for flexibility suggests potential support for storage-related investments.
How other firms see it
No specific firmIds with stances are available in our coverage. However, Goldman Sachs (GS) and Morgan Stanley (MS) have previously highlighted similar infrastructure bottlenecks in emerging markets as a key constraint on LNG demand growth. Citi (C) has noted that rising supply could keep US natural gas prices subdued absent demand-side catalysts.
Key takeaways
- 01Global LNG supply is rising while demand slows in established markets.
- 02Infrastructure challenges prevent significant demand growth in emerging LNG markets.
- 03Increased flexibility in US natural gas storage and production is warranted.
Market implications
The oversupply of LNG and demand weakness suggest bearish pressure on global gas prices, but US natural gas could see idiosyncratic support from flexibility needs. Storage assets may become more valuable, and production adjustments could create trading opportunities around inventories.
Risks to this view
Key risks include faster-than-expected infrastructure buildout in emerging markets, a colder winter boosting demand, or supply disruptions that could quickly reverse the oversupply narrative and push prices higher.
Hello, and welcome to this Commodities episode of At Any Rate. I'm Greg Scheer, Head of Base and Precious Metals Research at J.P. Morgan.
Today, I'm joined by Ohtar Degbouze, our European Gas and Global LNG Analyst, and Nina Fey, our U.S. Natural Gas Analyst, to discuss the long-term outlook for the global LNG market. Ohtar, Nina, welcome, and thank you for joining.
The team has recently published a report called the Global LNG Analyzer 2035, which outlines that rising LNG supply underscores a need for demand-side infrastructure growth. A lot has been said about the rising LNG export capacity and potential oversupply of the market, so I think that's a good place to start. Ohtar, what are our estimates around LNG supply growth, and where is the new supply ultimately coming from?
Hi, Greg, thank you for having me, and thanks to our listeners for joining. So, to put the LNG additions into the perspective, the global LNG market today is about 600 BCM annual size, and through 2035, we estimate of around 400 BCM a year of supply projects that are already under construction or already FID'd. Out of this 400, about 200 BCM is coming from the United States, led by projects such as Golden Pass, Corpus Christi expansions, Port Arthur, and a few many others.
Another 66 BCM is already under construction in Qatar, and this excludes the North Field West, which is still awaiting their final investment decision. Then we have Canada, Mexico, and the UAE, and these five countries together account for about 80% of the 400 BCM capacity additions, and we assign high probability of these projects materializing and operating in the long term. Other pockets, the remaining 20% of supply additions include Australia, Africa, and more recently, Argentina, which are also already FID'd and under construction.
Thanks, Ohtar. I mean, that's quite a material increase in supply, so I think maybe turning to the other side of the balance, how does that compare to our demand outlook? Where can these additional molecules ultimately go?
That's an excellent question, Greg, and what we found in our analysis is that at the time of such significant and historically high increase in global LNG supply, we see demand growth in key established LNG markets is actually slowing down. The historical markets, which have been Europe, China, Japan, and South Korea, are all seeing challenges for their LNG outlook of various fronts. So, for example, starting from China, which we discussed in our previous episode, we actually see Chinese LNG demand peaking at around 120 BCM in 2032.
This is driven by our expectations of continued support for domestic natural gas production and power of Siberia II from Russia coming online in 2031 and reaching full capacity by 2035. Switching to Japan and South Korea, which are experiencing rising power needs and power accounts about two-thirds of their LNG use on the back of rising data center power demand and power needs for semiconductor production, the policies in these countries are leaning towards renewables and nuclear to meet the rising power needs at the expense of imported coal and LNG. For example, Japan aims to increase renewable share in power stock from about 15 percent in 2024 to 40 to 50 percent target by 2040 and increasing nuclear from about 8 percent to 20 percent during the same period.
Korea, we see similar targets, 33 percent renewables, 36 percent nuclear by end of 2030s. Then we have Europe, where we see a modest about 10 BCM demand growth for overall natural gas driven by ongoing electrification and building sector, subdued industrial demand, which we expect to recover slightly, and rising renewables in the power sector. For LNG, the LNG demand growth is slightly higher as it will also need to offset the declining domestic production, but overall it's still limited.
We estimate 26 BCM increase between 2025 and 35 compared to 400 BCM of the supply additions. So this puts the onus to accommodate the rising LNG supply to emerging LNG markets, as we call them, which are primarily in South and Southeast Asia. It is currently about 130 BCM market in annual terms, out of which three countries, which are India, Taiwan, and Thailand, account for about 80 BCM.
And we do project demand to increase here significantly, more than doubling from 130 BCM to about 280 by 2035. However, this still lags the projected supply growth. Two drivers we think are key to enable the demand growth in the region is the prices and infrastructure.
So a significant uptick in imported LNG demand is contingent of significantly lower LNG prices, which would be ideally competitive with the domestic coal, and also infrastructure, which we identified as the major bottleneck for structural long-term demand growth in the region. So from three key areas of infrastructure, you need to support the gas use, which is regasification capacities, gas storages, and gas turbines for power needs are all limited. So regasification capacity, for example, we mentioned Taiwan as one of the largest markets, is already running above 100%.
Gas storage is non-existent in the region, apart from China and very small capacity in Japan. And gas for power turbines are a separate topic, which I'm sure has been discussed widely. It's also extremely tight market, and the lead times are something between four to five years or more, depending on the type of turbines.
Thanks for that, Ottar. I mean, that's really quite an interesting supply and demand picture, particularly with that infrastructure bottleneck that you highlight right there at the end. And I think it brings to my mind what's going to happen to all this excess supply.
And I mean, from that perspective, maybe moving over to you, Nina, which supply markets do you think are going to see the biggest impact? And I guess specifically, what are the implications for the U.S. natural gas market? That's a great point, Greg.
Given that over half of global LNG export capacity slated to come online through 2035 will be in the U.S., we believe that in the medium term, U.S. LNG export facilities may see lower utilization rates when increased global LNG supply is still awaiting infrastructure-led demand growth. In order for the market to balance, we believe the U.S. market will likely employ a multi-pronged approach to bring its market into equilibrium.
And this could include U.S. production flexibility, increased storage utilization, and potentially flexible price-elastic demand as a function not only of global price arbitrage, but for some purchasers, available storage capacity in their home markets. And while flexible may not typically be the term used to characterize the current state of U.S. production, whether in terms of dry gas, domestic output, or where LNG cargo is headed to the water, it is nonetheless exhibited some of those characteristics to date. The U.S. market has shown seasonality in Northeast production that has not explicitly been termed flexibility, but has functioned similarly, as production has often decreased in response to lower price and reduced local demand in the shoulder season and in the summer.
Granted, this has occurred on a smaller scale and generally with the expectation that Northeast markets tend to be winter-peaking for price. And while not strictly flexibility, we also note that the Haynesville has exhibited a seasonal profile with drilled but uncompleted well inventories sometimes building up and then being brought online in response to higher price. In both cases, the current market has shown a willingness and ability to time production, waiting for either seasonal increases in consumption or more supportive pricing.
Similarly, although the U.S. market may not generally be seen as playing the role of a global gas balancer, as utilization rates at LNG export facilities on an average annual basis have generally trended near 90% or higher, we observed a precedent for that flexibility during COVID in the summer of 2020 when capacity utilization rates fell to below 70% annually and below 35% or so in July. At the global market's loosest levels, when the market awaits that additional demand growth from infrastructure, we see U.S. capacity utilization potentially following towards these levels seen in 2020 in the low 60% to 75 or so percent range on an average annual basis. Another aspect of the multi-pronged approach to flexibility will be the utilization of underground storage, though we believe there is a limit to how much additional capacity will ultimately be constructed.
We note that various sources estimate the amount of recently announced U.S. storage capacity at between 2 to 300 billion cubic feet compared to current capacity near 4.7 trillion cubic feet. The amount of storage capacity to enter service will depend on the perceived value of its use and how well that aligns with the price potential capacity holders are willing to pay for that storage. And ultimately, the value assigned to that will also be a function of the seasonal price spread to justify storing gas for withdrawal at a later date.
It will also be a function, that value, of what certain market participants will assign to having the assurance of available supply to meet their needs in a market that may exhibit more variability in flows relative to today on both a daily and a seasonal basis. And lastly, given destination flexibility in U.S. contracts and the presence of LNG aggregators as off-takers in the market, capacity utilization at U.S. LNG trains could shift higher during periods of flexibility if necessary to support market needs or for price-elastic purchasing outside of our reference case.
And this could result in potentially higher utilization outside of our estimates. And we believe this component of flexibility could also support an open ARB between Henry Hub and other global gas price benchmarks. Thanks, Nina.
And thank you, Otar, as well. And I just want to recommend that everybody take a look at their report from earlier in November, which really goes into a lot of detail. But to summarize, we see LNG supply capacity growing by about 400 BCM a year, while demand growth in key established markets is decelerating, putting the onus to accommodate new supply on emerging LNG markets, primarily in Southeast Asia, where demand growth potential is limited, at least for now, due to infrastructure constraints.
In the medium term, this likely results in U.S. LNG export facilities running at lower utilization rates and likely calls for increasing flexibility in the U.S. production profile and storage utilization. Thank you again, Otar and Nina.
And thank you all for listening to another commodities edition of J.P. Morgan's At Any Rate podcast. We look forward to continuing the conversation next week.
This communication is provided for information purposes only. Please refer to J.P. Morgan research reports related to its content for more information, including important disclosures.
Copyright 2025 J.P. Morgan Chase & Company, all rights reserved. This episode was recorded on November 14th, 2025.
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