The Global LNG Market Outlook: Too Many Sellers, Not Enough Buyers Center for Strategic & International Studies

The Center for Strategic & International Studies hosted a talk with Dr. Fereidun Fesharaki, founder and chairman of the FGE consulting group, on Sept. 25 in Washington DC.

He began his remarks with a description of the global LNG market and moved into a region by region analysis of near to mid-term supply and demand forecasts, including predictions regarding some projects currently in the development pipeline.

The full video of his presentation is available at:

At the start, Dr. Fesharaki wanted to make clear that oil and gas are not sister resources, but “second cousins.” The strategies, structures, markets, principles, and understanding of one resource do not translate well into the other.

The oil market, he explained, is like dating. Participants spend a little time with many other market actors, buyers and sellers both shift around looking for the best match, and relationships have an assumption of impermanence. The gas market, on the other hand, is like marriage. By and large, major new sources cannot enter the market without first securing at least some long term take or pay agreements with buyers.

The difference is particularly pronounced in the global market, conducted in LNG, as opposed to domestic and regional gas markets connected by pipeline. Such markets actually have more in common with oil.

The role that gas buyers play as a mandatory project component for new LNG projects underpinned Dr. Fesharaki’s presentation. (In another analogy, Dr. Fesharaki commented on how a new project can just “spray” oil into the market and it will be soaked up, whereas LNG won’t go anywhere until it has an end user. “Sell it first, produce it later.”)

The importance, and risk, of the buyer role is exemplified by some of the LNG projects currently in the pipeline in the U.S. and Australia.


While the project finances were initially calculated at $90 plus per barrel of oil, current lower prices make the burning of oil for electricity cost competitive with LNG when delivered at $70/barrel crude or less. Despite oil prices well below that rate, these projects will continue and have cash flow, because buyers already have substantial sunk cost in infrastructure, and would be obligated to pay the liquefaction cost of the gas if they should cancel the delivery. These projects will continue so long as the cost of liquefaction exceeds the losses associated with using or reselling the gas.


Dr. Fesharaki opined that the Sabine Pass and Corpus Christi facilities could make Cheniere Energy and the U.S. the world’s largest LNG exporters within the next few years.


While some LNG projects are so far into development that they have passed the point of no return, many are not.


“You have the permit?” Dr. Fesharaki asked. “Then you have permission to go and lose money. You cannot get financing without a buyer.”


While $100 million may have been spent on a project to get through the Federal Energy Regulatory Commission (FERC), which seems like a milestone, the main hurdle for financial viability hasn’t been cleared. Liquefaction plants cost at least $10 billion. Permits don’t get projects financed, only customers do. Furthermore, LNG demand is far below what all of the proposed projects would produce.

And even if contracts have been signed for much of the gas from near-complete projects that does not mean the market is lined up. Some gas is purchased for resale, and some is excess capacity.


To complicate matters further, 70 million metric tonnes per annum (mmtpa) of unsold LNG is already on the market. The U.S. and Qatar each account for 25-35 mmtpa of unsold capacity and sold but “flexible” gas. Globally, buyers have contracted for an additional 8-15mmtpa of gas that is beyond their consumption and they want to sell. Most customers will likely find that purchasing the 70 mmtpa is preferable to investing in any projects.

Dr. Fesharaki reviewed the major national players.



Japan is the biggest consumer. Because all nuclear power production was stopped, Japan relies on LNG for 48 percent of its electricity supply, obtaining the balance primarily from coal and oil. Dr. Fesharaki expressed confidence, however, that Japan would more or less make good on its goal of 15-20 percent nuclear and an increase in coal to round out baseload consumption. Meanwhile, LNG would be reduced to 20-25 percent, with possibly 30 percent as the upper tolerance.

Despite this forecast, Japan remains a critical consumer. Beginning in late 2018, when a 5 mmtpa existing contract with Abu Dhabi will expire, Japanese companies will be on the market to replace existing sources. By 2024, about 30 mmtpa will come from new sources, giving Japan a lot of market power in this supply-rich environment. Apparently, many contracts won’t be extended, but instead will be replaced by existing suppliers using existing supplies.

Korea, and KOGAS in particular, are important LNG players today. However, demand will likely decline with new coal replacing gas. Furthermore, KOGAS will reduce consumption as major manufacturing customers take advantage of excess supplies and purchase gas directly. Their existing contracts don’t expire until the 2020’s.

Taiwan’s consumption is expected to grow a little, but only a couple of mmtpa. Some contract replacement would occur in the 2020s.

India and China have similar LNG situations, with both countries’ markets stifled by government price manipulation.


In China the price is now four to five times U.S. domestic prices and new demand growth has fallen from 7 percent to 2-4 percent. The government raised gas taxes in part to subsidize China’s woefully inefficient oil industry (costs of production from $50-65/barrel).


In India, conversely, the price was set at below market rates, so when subsidized gas runs out, utilities and other customers—instead of paying for private LNG—simply shut down until more subsidized gas is available.


Another parallel between India and China is the risk of doing business for LNG exporters. If contract disputes arise (i.e. honoring the original agreed upon price), arbitration isn’t an option, because the respective countries would punish suppliers in the market.
Another unique factor weighing against further growth of China’s LNG demand is its recently signed contracts for gas via pipeline from Russia and central Asia. While many felt that China got the best of Russia last year, the pipeline is already looking like it may not be such a great deal.


Dr. Fesharaki’s analogy for pipelines is that they are an all you can eat buffet. The initial purchase may be expensive, but then one can have as much as can be consumed. Given China’s recent weak growth, the price of admission looks questionable.


The final Asian importers Dr. Fesharaki mentioned were Indonesia and Thailand, which are both fairly new to the market (Indonesia had been an exporter). While both are “decent” to sell to, he characterized them as “undersized”.


Europe isn’t much of a factor, as demand in general seems to be falling, and Russia can flood the market with cheap pipeline gas when it wants to kill competition, nearly eliminating any incentive to sign high cost long term LNG contracts.



The U.S. is the newest major player in the export market. Dr. Fesharaki estimated that between 25-35 mmtpa exists on the market now that was initially sold to middlemen only, not end users. Everyone expected oil prices to go back up, and so a lot of would-be middlemen got stuck with gas contracts.


“Smart guys sold all of it, they are smiling,” he said. “I’m astonished at how many people haven’t sold.”


He estimated that the average U.S.-Japan gas export project to would need, at current Henry Hub prices, $70/barrel an oil to break even (that would go up to $75/barrel if Henry Hub prices rose a dollar from $3.50 to $4.50).

If built, projects currently pending FERC approval would triple the U.S. supply. Though all but one are likely to be approved, he thought most, if not all of the unbuilt 70 mmtpa projects will never come online simply because no one will sign contracts in the current oversupplied market.

Qatar also has 25-30 mmtpa either uncontracted or used to fill short term contracts. Qatar’s biggest advantage over other exporters is that its production costs are so low that it is cost competitive with oil down to $25-30/barrel. Qatar had long been the most important exporter, but “played hard to get” and “created” the U.S. and Australian export markets which drove down prices and created the current glut.

Australia has 5-7 mmtpa existing or nascent unsold supply. Like the U.S. projects on a similar timeline, the Australian projects forecast at least $90-95/barrel oil and will now probably lose money. The projects probably need $65-70/barrel oil to break even. The Australian dollar has declined recently, however, and this may help.


Iran recognizes that even if all of the sanctions are cleared, it has likely missed the LNG boom. Iran has a couple of regional opportunities to supply gas to existing liquefaction facilities whose associated fields are running out of gas (including one in Abu Dhabi, immediately adjacent to a full Iranian field). Dr. Fesharaki suggested that despite the poor economics, Iran would likely build a new LNG export facility of its own, but probably at less than 10 mmtpa capacity.

Mexico, Brazil, and Argentina all have large gas reserves, but also some of the highest cost gas in their domestic markets. For now, it’s cheaper in Mexico to import American gas. While these countries may eventually become exporters, it won’t happen soon.

“We don’t see any projects coming out of Canada for a long long time,” Dr. Fesharaki said. “The gas is there… East Africa, better economics.” In particular, he said environmental and First People’s concerns will prevent project development for the foreseeable future.



Dr. Fesharaki predicted that the current oversupply, including projects nearly online, will work its way through the market by the early 2020s. While he didn’t explicitly attempt to forecast oil prices, he followed the implicit assumption that they would stay low. Should they return to over $70/barrel, U.S. and Australian LNG from existing projects would be cost competitive with oil for producing electricity, and demand growth would likely accelerate substantially.

A common narrative for LNG proponents is the relative cleanliness of gas as a resource. An audience member enquired as to whether this factor would contribute significantly to growth (with the US and China recently announcing a bilateral effort to curb emissions).


Dr. Fesharaki dismissed this line of thinking, saying the only people he knew who thought that way were gas people. For environmentalists, all hydrocarbons emit greenhouse gasses and are all bad. For everyone else, coal is cheaper (and, for the time being, oil is too).


On balance, Dr. Fesharaki believes the global LNG market will carry on for several years at roughly similar volumes as at present, offset by low rates of demand growth and decline. The largest moves in the market for several years will be suppliers competing to replace major contracts, first in Japan followed by Korea and Taiwan.