65%. That is the minimum share of a new LNG plant’s expected output that Vietnam’s state buyer must contract for under Decree 100/2025, during loan repayment, for at most ten years. It matters because that one number decides whether 22,524 MW of planned LNG power gets financed, and what Vietnam burns instead. Developers say they cannot finance a plant on it; the buyer says the one plant that runs was over-contracted at it. Both are right. One plant operates, the next megawatt-hour is imported coal, and the retail tariff was cut on 1 November with a shortage forecast for 2027.

2. How the system works

Vietnam runs on coal and water, and it is growing at close to 10% a year. Coal supplies about half of its electricity and swings with the monsoon: more in a dry spring, less once the rains fill the dams. Gas is a small, fixed slice, about 8%, even after the first LNG plants, Nhon Trach 3 and 4, started in January. Domestic gas fields are declining and their replacement, Block B, is a year or more away. So every extra megawatt-hour Vietnam needs is, by default, a coal megawatt-hour, and the coal is increasingly imported: imports have nearly trebled since 2018 and now supply more than half of the coal Vietnam uses.

Everyone sells to EVN, the state utility, or into the operator-run wholesale market. The retail price is set by the government inside a published band, and it moved down on 1 November, to VND 2,160 per kilowatt-hour, about US$82 a megawatt-hour. A new LNG plant cannot sell at that. The ministry’s own 2026 price ceiling for a gas plant, built on gas at US$12, is VND 3,411, half as much again; the fuel alone at this week’s spot LNG price costs well over twice the retail average. Chart C2 lays the whole ladder out.

The trade-off is not affordability against climate, and it is not money: EVN made a record profit last year and is sitting on cash. It is who carries the fuel contract. LNG is bought take-or-pay (paid for whether or not it is burned). A power-purchase agreement that guarantees the plant only a share of its output does not mirror that, so a plant the grid wants to run part-time, a mid-merit plant, cannot be financed. That is the whole dispute; the decree answered it with a percentage.

Read more

46%. That is how much of the cheap gas Indonesia promised its factories by decree actually reached West Java in the first four months of this year; three years ago nearly all of it arrived. The promise itself had been cut to little more than half the 2023 volume. It matters because Indonesia exports a third of its gas while rationing its own industrial heartland, and the cost is paid by people who never see it on a budget line. What follows is who gets the gas, who pays for the cheap part, and what an honest policy would cost.

2. How the system works

Indonesia is a large gas producer running short at home. Two-thirds of its gas stays in the country; a third goes abroad. Industry, fertiliser plants and power stations share the supply, and a growing part arrives by ship: LNG from the export plants in the east, turned back into gas on floating terminals off Java, because the old fields under West Java are running down. Pipelines delivered a third less gas to industry last year than two years earlier; the replacement costs what LNG costs.

The price depends on who you are. Since 2020 a scheme called HGBT (a fixed cheap price for seven industries, from fertiliser and steel to ceramics and glass) sets gas at $6.50 per MMBtu at the factory gate; power stations pay about the same. Other factories pay a published pipeline price, half as much again. Anyone needing more than their ration buys regasified LNG from PGN, the state distributor, at more than double the decree price; PGN was about to charge three times it in June before the President capped it for the rest of the year. Asian spot LNG trades at more than four times it. Four prices, one molecule; Chart C1 lines them up.

The trade-off is the ration against the budget, not affordability against climate. The deficit is capped by law at 3% of GDP and sits just under it, so every dollar given away on gas cannot be given away on fuel. The squeeze will not ease on its own: demand grows, the old fields shrink, the export contracts do not, and the big new fields off Kalimantan are already allocated, mostly to Kalimantan industry and to export. Only a small liquefied tranche can reach Java, because no pipeline does. Java stays short through 2030.

Read more

The chart is useful. It is also responsible for more bad forecasts than any other single exhibit in the industry, because it is routinely read as something it is not. A cost curve tells you what it costs to produce a unit of supply that already exists. A supply curve tells you what it takes to bring the next unit to market, at a point in time, with the capital, permits, ships and buyers that unit actually needs. The two are related. They are not the same thing, and the distance between them is where the marginal barrel lives.

Confusion one: a breakeven is a point, not a price

Ask three analysts for the breakeven of a Permian well and you will get three numbers, and all three will be right. One means the half-cycle cost, the price at which a well already drilled pays back its completion. One means full-cycle, including land, infrastructure and the dry holes. One means the corporate breakeven: the price at which the company covers its cost of capital for discovered undeveloped resources. These can differ by $30 a barrel for the same rock.

The same ambiguity sits inside every LNG “breakeven.” A $6 delivered cost for a US cargo is the long-run number, the one a new train needs. The short-run number for a cargo whose liquefaction fee is already sunk is nearer $4. When JKM was $14 in February, both were comfortably in the money. When it fell toward $5 in the 2020 glut, the long-run number said cancel and the short-run number said lift, and the market behaved according to the short-run number, as it always does.

So the first question to ask of any cost curve is: whose breakeven, over what horizon, and what happens to the units already built when the price falls below it? Usually the answer is that they keep producing, which means the curve you are looking at is not the supply curve at today’s price. It is the supply curve for a world that has not yet invested.

Confusion two: the curve has no clock

A cost curve is a snapshot. It ranks everything that could exist as if it already did, and as if it could be turned on tomorrow. A supply curve has a time axis, and the time axis changes the shape completely.

At the one-week horizon the supply curve is almost vertical. Nearly nothing can respond to price. OPEC spare capacity, a few shut-in wells, some LNG cargoes that can be diverted but not created. This is the world the market lived in from March, when Qatar stopped and there was no next cargo at any cost. The cost curve said US and Australian LNG was cheap and plentiful. The supply curve said both were at full utilisation and the next molecule was three years and $10 billion away. The price went to the demand side because that was the only side with a slope.

At the five-year horizon the curve is flatter, but the costs on it are not the ones in the chart. Rystad put the average breakeven for unsanctioned oil projects at about $50 in its last benchmark and then spent 2025 reporting cost inflation across the board. A cost curve drawn in 2023 described a world that could no longer be built at those prices. The projects that can be built at today’s prices, at today’s rig rates and steel prices and with today’s financing, are a different and shorter list.

The difference matters because the price-setting unit is the one at the margin of the relevant horizon. In a tight market that is the unit that can respond fastest, almost regardless of cost. In a loose market it is the unit that can be cancelled cheapest. Neither is the unit at the top of the cost curve.

Confusion three: the chart assumes a buyer

The third problem is that a cost curve is drawn entirely from the supply side. Demand is a flat line across it. In practice the demand side has its own curve, and in the markets we write about it is the steeper one.

When the LNG price doubled this spring the response did not come from new supply. It came from Pakistani and Bangladeshi utilities going back to fuel oil, Indian fertiliser plants shutting, and Chinese city-gas companies disappearing from the spot market. That is a supply curve too, in the economist’s sense: it is the supply of forgone demand, and it had a price at which each tranche cleared. Nobody draws it, because the data is harder and the clients are producers. But it set JKM for six months, and it is still setting it, and any “the price will fall to the cost of the marginal US cargo” view that does not say when and why those buyers come back is not a forecast, it is a cost curve with a wish drawn on it.

How we read a cost curve

We still draw them. We just ask five questions before believing one.

1. Which cost? Half-cycle, full-cycle or corporate. If the chart does not say, assume it is whichever one made the author’s point.

2. Which horizon? What on this curve can actually respond within the period the question is about? Grey out everything that cannot. What is left is the supply curve for that horizon, and it is usually a small fraction of the picture.

3. What is the utilisation? A cheap unit at 100% utilisation is not marginal supply; it is base load. The marginal unit is the cheapest one with room to move, which can be a long way up the curve.

4. Where is the demand curve? Draw it, even roughly: which buyers leave at which price, and which come back. If the demand curve is steeper than the supply curve at the relevant horizon, the marginal buyer sets the price and the cost curve is background.

5. What is the price of the next unit, not the last? The cost of the final increment that must be built to balance the market in year N, with year N’s costs and lead times. That is the number a forward curve should converge to, and it is almost never the number on the published chart.

What this says about now

In oil, the cost curve has been losing since February and will keep losing until the Gulf comes back. The IEA’s October report has 2026 demand down 2.6 mb/d, observed stocks down about 510 million barrels since the end of February, and Gulf output still some 8 mb/d below pre-war levels in the summer. The UAE left OPEC+ in May and took roughly a quarter of the group’s spare capacity with it. The marginal unit is a shut-in Gulf barrel, and downstream it is a diesel barrel: the Singapore gasoil crack printed a record $83 in September against an $18 average last year. None of that is on a cost curve.

But oil has a date on it that LNG does not. Shut-in barrels come back in weeks, and the IEA already has 2027 supply up 7–8 mb/d and the market in surplus. The moment the strait reopens, oil returns to being a market where the marginal unit is a barrel that can be cancelled, the horizon is long, and the full-cycle cost of the next Permian or Guyanese increment is a decent anchor for the price. We would read the oil cost curve as a supply curve for 2027, not for 2026, with the single caveat that spare capacity is political, not geological, and a cost curve has nothing to say about politics.

In LNG it is the opposite, and will be until Hormuz reopens. The supply curve is vertical at every horizon short of 2028. The marginal unit is a buyer. Any analysis that starts from “US cargoes cost $7, therefore…” has the right number and the wrong curve. The $7 matters only as the floor the market returns to when the demand side stops setting the price, which is a question about ships in a strait and not about cost.

And in power, which we will come to, the confusion is worst of all, because the cost curve everyone uses, levelised cost of energy, does not even pretend to have a time axis. We will say more about that when we get to the marginal megawatt-hour.

What would change our mind

If the LNG price falls to the US delivered cost before Hormuz reopens and Qatar returns, then demand destruction was larger and more permanent than we think, the demand curve has moved out beyond the supply curve, and the cost curve was the right chart after all. If oil spends 2027 well above the full-cycle cost of the next increment with spare capacity still at 3.5%, then something other than cost is setting the price there too, and we will need to find it. We will say so when either happens.

A note on sources: the oil figures are from published bank and consultancy estimates and are cited below. We have not drawn a live cost curve here because the published ones differ by $20 a barrel on the same projects, which is rather the point.

Sources

• IEA, Oil Market Report, August 2026: Gulf output 8.3 mb/d below pre-war in July; cumulative stock draws since end-February.

• IEA, Oil Market Report, October 2026: 2026 demand -2.6 mb/d; observed stocks -509 mb since end-February; 2027 supply +7.7 mb/d.

• Rystad Energy via Air Freight News, 30 Apr 2026: UAE exit from OPEC+ effective 1 May; ~1.5 mb/d of the group’s ~6 mb/d spare capacity.

• S&P Global, 29 Sep 2026: Singapore gasoil crack record $83.02/b on 16 Sep vs $18.16/b 2025 average.

The walk

We build the delivered cost of a US cargo from the bottom. Every number is public or a widely quoted contract term; the ranges are real and we will publish the calculator so you can move them yourself.

The long-run number is what a new US cargo must earn to justify its existence. The short-run number is what an existing offtaker needs to cover before it is better to pay the fee and leave the gas in Louisiana. Both are a long way below $29.50. Before the war they were a long way below the market too: TTF averaged $14.74 and JKM $15.56 in the first half of 2026, roughly double the walk.

So what is setting the price?

Not the cost of the marginal cargo. There is no spare cargo whose cost could set it. Two Ras Laffan trains, 12.8 mtpa, are out for three to five years. The rest of Qatar’s 77 mtpa is physically intact but, in the CEO’s phrase in mid-October, producing “very little,” with force majeure extended into December and Hormuz traffic still about 75% below February levels. Call it 60 mtpa, roughly 15% of world supply, that the market has learned to live without.

The only way a market lives without 15% of supply is for 15% of demand to go away. That is what JKM is measuring. It is the price at which enough Asian buyers stop buying: Pakistani and Bangladeshi utilities that were 70–99% dependent on Qatar and have gone back to furnace oil, Indian fertiliser plants, Chinese city-gas distributors who have simply stopped tendering for spot. Kpler’s early estimate was 4 Mt of annual demand destruction in South Asia at $15, 2–4 Mt in Southeast Asia at $15–20 and close to 10 Mt in China at $15. At $29, the destruction has gone considerably further than that.

This is the point most coverage misses. The marginal unit in the LNG market in 2026 is not a cargo. It is a megawatt-hour of Asian demand that is being priced out, and the price is wherever that buyer’s alternative sits: the cost of running the oil-fired plant, the cost of the coal unit that was going to be retired, the cost of simply not producing urea this month.

The second mechanism: Asia is competing with Europe for the same ship

There is one supplier whose cargoes have no fixed destination, and that is the United States. Around 17.4 Bcf/d, or about 130 mtpa, left the Gulf Coast in the first half of 2026, and almost every cargo is free to go wherever the netback is highest. So the question of who sets JKM has a second answer: JKM must sit above TTF by at least the freight difference between the two routes, or the ships go to Europe.

Right now they are going to Europe. Spark’s front-month US arbitrage points to Europe, and for February and March 2027 Europe pays over $3 per MMBtu more than Asia on a delivered basis, the strongest signal to Europe since December 2022. Europe’s storage went into the war at the lowest level since 2022 and has been refilling at any price. That is why the JKM–TTF spread has been so thin all autumn while both benchmarks sit near $29: Asia is not paying for scarcity relative to Europe, it is paying the same scarcity premium as Europe and then losing the cargo anyway.

So, for the winter that is about to start, the price of LNG in Asia is being set by two things, neither of which is a cost of supply: the willingness of a South Asian utility to burn oil instead, and the willingness of a German trader to outbid a Korean one for a Sabine Pass cargo.

What changes in 2027

Three things, and they do not all point the same way.

Qatar can come back fast, partially. The damaged trains are gone for years, but the other roughly 64 mtpa of capacity needs only the strait. QatarEnergy says it can be back to normal operations within weeks of Hormuz reopening, and it has at least a dozen empty carriers waiting off Ras Laffan to prove it. On top of that, North Field East Train 1, 8 mtpa, is mechanically ready in November with first production guided to the first quarter of 2027, and the CEO expects “a few” more NFE trains through 2027, with the caveat that every one of them depends on getting equipment through the same strait.

The US keeps growing regardless. The EIA has first-half 2027 exports at 18.7 Bcf/d, about 140 mtpa, up from 17.4 in the first half of 2026. Plaquemines is at full rate, Corpus Christi Stage 3 is on six of seven trains, Golden Pass Train 1 is ramping and Train 2 is due at the end of this year. None of this is contingent on anything in the Gulf.

Shipping stops being a constraint. Fifty-five newbuilds arrived in the first seven months of 2026, another 40–45 are due by December and about 95 in 2027. Spot rates have already collapsed from $287,500 a day at the March peak to $25,750 in the Atlantic and $39,000 in the Pacific. Freight will not rescue the Asia netback; if anything the Cape route gets cheaper.

Two worlds

Hormuz normal by mid-2027. Qatar’s surviving 64 mtpa returns, NFE adds 8–16 mtpa, the US adds another 10, and global supply is up something like 15–20% on the 2026 run-rate within a year. The demand that was destroyed does not all come back; South Asian buyers have learned a lesson about concentration and some of the coal that was un-retired stays on. Price falls until the marginal unit is once again a US cargo, because the US cargo is the one that can be cancelled. That puts JKM back on the walk: 1.15 × Henry Hub plus the fee plus freight, call it $9–12 by the winter of 2027–28 with Henry Hub at the EIA’s $3.50. In this world the interesting questions are American: whether 20 Bcf/d of feedgas pulls Henry Hub above $4 and adds a dollar to the whole curve, and whether second-wave US projects can hold a liquefaction fee under $3.

Hormuz constrained through 2027. Qatar stays partial, NFE slips because the equipment cannot get in, and the marginal unit stays on the demand side. JKM trades in a range set by what Asian buyers will pay before switching, which the last six months suggest is somewhere between $18 and $28, with the floor rising every time a European storage auction clears. Coal regains share in Southeast Asia, China’s spot buyers stay absent, and the projects that took FID in 2024–25 on the promise of a tight 2027 look very clever indeed.

The forward curve is leaning toward the first world. Platts notes that implied volatility for winter 2026–27 JKM is 59–70% against 90–95% for TTF, which is the market saying that Asia normalises faster than Europe. We think that is right, but it is a view about a strait, not about gas, and we would hold it loosely.

What we are watching

1. Hormuz LNG transits per week, and each QatarEnergy force majeure extension. This is the whole trade.

2. The JKM–TTF spread against the freight difference of roughly $1.20–1.50. When JKM minus TTF falls below that, US cargoes are going to Europe and Asia is being outbid, whatever the headline price says.

3. US feedgas above 18 Bcf/d, and Henry Hub against $4. Every dollar on Henry Hub is $1.15 on the delivered walk.

4. Chinese spot tenders. The day the Chinese city-gas companies return to the spot market is the day the demand-side margin moves up, not down.

5. NFE Train 1’s first cargo. If it loads on schedule, Qatar’s expansion is real even with the strait half-shut.

What would change our mind

If Hormuz reopens and JKM is still above $20 six months later, we were wrong about demand elasticity: the destruction was structural, the coal is not coming back out, and the market is shorter than the arithmetic suggests. If second-wave US liquefaction fees reprice above $3.50, the long-run walk moves up a dollar and the floor with it. And if Qatar’s surviving trains take months rather than weeks to return, the first world above is a 2028 story, not a 2027 one. We will publish the netback calculator alongside this piece so you can test all three yourself.

Marginal Barrel Lng Netback Calculator V1

25.6KB ∙ XLSX file

Download

Download

Markets do not clear at the average. They clear at the margin.

That’s where prices are set. That’s where forecasts fail. And that’s where money is made and lost.

That is the premise of Marginal Barrel.

A remarkable amount of energy analysis still treats averages as if they matter more than marginal decisions. Average breakevens. Average supply costs. Average demand growth. Useful for presentations, perhaps. Less useful for understanding why prices moved yesterday or where they’re headed next.

The cost of getting this wrong has risen dramatically.

The Margin Has Moved

For much of the last century, finding the marginal barrel was relatively easy.

The marginal supplier sat in the Gulf. The marginal buyer sat somewhere in the OECD. Supply was concentrated. Demand was predictable. Price formation was opaque but not particularly complicated.

That world is gone.

Today’s marginal supply increasingly comes from project developers, private capital and globally traded molecules. A liquefaction train on the US Gulf Coast. A shale producer in the Permian. A floating production vessel offshore Guyana.

And the marginal buyer no longer sits in Frankfurt or Chicago.

It sits in Guangdong. Karachi. Jakarta.

The decision that sets the global gas price may be made by a Chinese industrial consumer declining a spot cargo, a Pakistani utility switching fuels, or an Indonesian power company delaying purchases for another month. These are not side stories. They are the market.

Understanding energy today means understanding who can walk away from the next cargo and at what price.

What Most Commentary Gets Wrong

Three habits dominate modern energy analysis.

First, the obsession with averages.

No barrel is sold at an average price. No cargo clears because an average breakeven says it should. Averages are accounting tools. Markets are marginal systems.

Second, the confusion of cost curves with supply curves.

A cost curve describes what existing production costs. A supply curve describes what it takes to bring the next unit to market. Those are different questions. One requires arithmetic. The other requires capital, permits, infrastructure, shipping and counterparties.

The distance between the two is where most forecasts die.

Third, forecasts without mechanisms.

A price target is not an argument.

A forecast that cannot identify the buyer or seller setting the market is simply a number with excessive confidence attached to it. We’d rather be explicit about the mechanism and wrong about the outcome than the reverse. At least then the mistake is useful.

What We Do

Marginal Barrel starts with a simple question:

Who sets the price?

Every week we take a market problem and push it until we find the answer.

Who is the marginal LNG supplier to Northeast Asia next winter?

What return does a liquefaction project actually need to reach FID?

At what price does Southeast Asia switch from gas back to coal?

What is a producing gas field worth when the assumptions underpinning its contract no longer exist?

The methods are not glamorous. Bottom-up cost curves. Netback analysis. Contract economics. Project models. They are simply the tools that work.

Every piece contains original analysis. Every piece contains a chart. Most contain at least one number you won’t find elsewhere.

Where there is a model behind the work, subscribers get the model.

A Rule We Intend To Keep

Every analysis ends with the same section:

What would change our mind?

Most market commentary treats uncertainty as a weakness. We regard it as a discipline.

If we cannot explain what evidence would invalidate our thesis, then we do not yet have a thesis. We have a preference.

How It Works

A long-form piece every Tuesday morning, Singapore time.

A shorter chart-led note every Friday on whatever moved the market that week.

Free posts remain free. A paid tier will follow once there is enough research and modelling behind the publication to justify it. Subscribers will receive the full analysis, downloadable models and reader-driven research.

Who Writes This

Marginal Barrel is written pseudonymously by a practitioner with two decades across wide spectrum of energy industry.

The anonymity is deliberate.

Energy analysis has too much credentialism and too little accountability. We’d rather be judged on forecasts than biographies, on arithmetic than branding.

The trade-off is obvious. Readers receive no résumé, no conference headshots and no carefully curated list of employers.

Only the work.

That seems fair.

Nothing published here is investment advice. We hold no positions in the markets we write about and will disclose it if that changes.

The marginal barrel sets the price.

Our job is to find it.

What would change our mind? If average costs consistently explain energy prices better than marginal behaviour, then this publication has no reason to exist. We do not expect that outcome. But if the evidence points there, we’ll be the first to say so.