Global LNG Trade
Our global LNG coverage identifies the key drivers to changing market dynamics, forecasts the world’s LNG demand and supply to 2030, and explores their impact on LNG contracts and pricing.
Global LNG Outlook:
BNEF’s long-term forecast of LNG markets to 2030.
Setting the scene
The substantial expansion of global LNG demand in 2017 is unlikely to be repeated in 2018 and a further slowdown is expected in 2019-22. However, supply overcapacity in this period looks smaller than previously expected amid delays in the commissioning of new export projects.
From 2023 onwards, demand will grow 4-7% annually and a potential shortage can only be relieved by final investment decisions on new export projects in 2018-20.
The world consumed 285MMtpa of LNG in 2017. This was 25MMt or 9.6% higher than a year earlier – the highest annual growth since Fukushima. Imports rose in 19 of 29 LNG importing countries.
In 2018, we expect the demand growth rate to slow down to 7.2%, adding 20MMtpa, to reach a total of 305MMtpa. China will still lead in terms of growth, despite a relatively modest rise compared to last year. South and Southeast Asia will experience their strongest annual growth in recent years, becoming another major growth engine in 2018.
From 2019-2022, we expect:
1. Growth to slow down further with demand stabilizing in the 314-330MMtpa range.
2. Modest growth in China (when new Russian gas pipelines are commissioned) is offset by nuclear restarts in Japan.
3. Average utilization of export plants in 2021, when supply overcapacity peaks, would likely be 81%, which is better than expected earlier.
Our assessment methodology in high and low demand scenarios varies by country. Bloomberg clients have access to our full demand and supply scenarios at the country and region level, as well our evaluation of LNG project likelihood and what it means for future capacity.
Contracts and Pricing
The global LNG market appears over-contracted from 2018 to 2020, based on our base-case demand scenario. To meet contractual commitments, some buyers can possibly offtake cargoes and resell them.
Continuous demand growth will create a need for signing new contracts. In our base-case, we estimate the maximum demand for new contracts growing from 13MMtpa in 2022 to 297MMtpa by 2030 (assuming the demand is fully met with term contracts). On the supply side, final investment decisions need to be taken by 2020 to have new capacity online post 2025, when the market is under-supplied. Given these two issues, we see a revival in the contract signing activities in 2020.
Europe: Although over-contracted until 2022, Europe could be the largest LNG contract demand market, with 94MMtpa of uncontracted demand in 2030.
China will have 40MMtpa demand uncontracted in the coming decade, making it the second-largest potential market for signing term contracts.
Rest of Asia: South Korea and India follow with uncontracted long-term demand at around 32 and 30MMtpa by 2030. Pakistan and Taiwan follow with 22MMtpa and 17MMtpa uncontracted demand by 2030, respectively.
Risks in the LNG market
LNG buyers' risks in a buyer's market.
Seven Risks for LNG Buyers
Ashish Sethia, Bloomberg New Energy Finance
As the global LNG market enters a long phase of sufficient supply, buyers are enjoying low prices but still face significant risks.
1. Increase in underlying benchmark - crude oil price. Oil prices impact LNG markets, as significant volumes of contracted LNG are benchmarked to the Japan Crude Cocktail price in APAC and Brent in other countries. If oil rebounds, LNG prices will rise as well, although more slowly than they have done in the past.
2. Higher volatility on Henry Hub prices. Exposure to U.S. gas prices can be hedged, although liquidity in the long term is lower than oil markets. Moreover, Henry Hub has been historically more volatile than oil.
3. Potential losses due to take-or-pay commitments. U.S. LNG contracts are akin to a call option for buyers. If U.S. LNG is cheaper, buyers offtake cargoes from there, but if U.S. LNG is out of the money compared to oil-indexed contracts or spot LNG and buyers do not want the U.S. supplies, they have to pay a fixed fee to U.S. liquefaction terminals.
4. Threat to substitutes. Natural gas/LNG competes with coal, renewables and nuclear (particularly in Japan, Korea and Taiwan) as a source of power supply. Low coal prices, falling costs of renewable energy and the restart of idle fleets of power plants (like nuclear reactors in Japan) can have an adverse impact on LNG demand in a country.
5. Currency fluctuations. Currencies in importing countries can depreciate, thus partially or fully wiping out gains due to a fall in commodity/LNG prices. This is particularly true in the case of oil and currencies of crude-importing nations, as there is generally an inverse relationship between oil prices and currencies of such countries. Thus when oil is cheap, LNG prices are low, however, the dollar becomes more expensive against the local currency.
6. End-product pricing. LNG/gas demand is also sensitive to the market conditions of the end-product it is used to generate. For example, if there is an oversupply in the fertilizer market and end-product prices are low, the demand (and hence the willingness to pay a high gas price) could be limited.
7. Cheaper spot LNG than contracted purchases. With low demand and high supply, LNG bought through old contracts (when commercial terms were fixed in a demand>supply environment) could be significantly more expensive than the spot market. In such a scenario, buyers may have to reduce offtake from contracts and may either risk incurring take-or-pay charges, or a fixed fee (in the case of U.S. supplies) – unless the seller is willing to waive them off.
The U.S. is solidifying its role as a global LNG exporter, and for the first time was a net exporter of natural gas for every month of the year in 2017.
Dominion Cove Point Readies As Second U.S. LNG Exporter
Anastacia Dialynas, Bloomberg New Energy Finance
On February 28, 2018 Dominion Energy exported the first cargo of LNG from its Cove Point liquefaction facility in Lusby, MD. Given current fair value futures curves, exports from Cove Point will be priced attractively for sale into Asian and European markets this year.
Dominion Cove Point benefits from a proximity to Appalachian shale gas. The terminal receives gas from Williams’ Transcontinental pipeline (Transco) and TransCanada’s Columbia Gas Transmission pipeline (TCO). Delays facing Transco’s Atlantic Sunrise Expansion Project coupled with strong winter gas demand on the East Coast resulted in northeast gas trading at a premium to Henry Hub throughout winter. Transco Zone 6 forward prices closed at $11.12 per million British thermal units for February contracts, $7.45 above Henry Hub.
Nevertheless, winter gas demand has abated as spring approaches and Atlantic Sunrise is scheduled for completion this summer, so northeast gas prices have fallen and April contracts are currently priced $0.13 below Henry Hub. Looking ahead, Cove Point LNG appears economic for export. LNG in Asia is currently trading around $7.55 through the end of summer, which BNEF estimates would result a short-run marginal cost netback of $2 after taking into account liquefaction and shipping costs.
Positive netbacks of $1.5-3 from Cove Point are expected to continue through 2018 based on fair value forward curve pricing.
To calculate shipping cost components for LNG exports from the United States, Bloomberg clients have access to the LNG Shipping Calculator on the Terminal.
- Calculated shipping costs and seller netbacks to 15 destinations, with customizable assumptions such as destination market prices, vessel specifications, or shipping logistics.
- A comparison calculator for spot and future netbacks for up to three destinations.
- Automatic updating of spot prices and forward curves with Bloomberg Terminal data.
Asia will continue to import 70% of the world's LNG leading up to 2030. How will its role continue to evolve and shape the future of LNG?
What Asian LNG Buyers Want
Maggie Kuang, Bloomberg New Energy Finance
Opinions differ on when the Asian LNG market will rebalance – some expect that as soon as the early 2020s while others expect the mid-2020s.
New export capacity, scheduled to come online in 2018-2020, will provide sufficient supply until 2025.
1H 2018 Global LNG Outlook, BNEF
The decision by OPEC and its allies last year to cut oil production pushed Brent to over $60/bbl. However, most people agree that the sufficient production flexibility of U.S. shale oil will keep oil prices within a narrow range ($50-60/bbl) for the foreseeable future. This is also suggested by Brent futures for deliveries up to March 2024.
1. More infrastructure is needed to unlock demand in emerging Asia.
We agree that investments in pipeline and gas power generation assets will help unlock the demand potential constrained by a lack of infrastructure.
2. Destination flexibility remains on LNG buyers' agenda.
Currently, 91% of Asian LNG contracts are destination-restricted in 2017, and this will remain as high as 75% even by 2020. Destination flexibility is also needed to create a liquid trading hub in the long run.
3. Small supply projects will have a golden opportunity.
Small projects are best positioned for the next chapter in the global LNG story, with a golden opportunity to dominate future supply.
Panelists at Singapore International Energy Week agreed that the era of mega LNG projects is over and that smaller projects are now more viable. Selling smaller volumes through term contracts becomes more realistic in the evolving LNG market. Also, there is growing interest from private equity and hedge funds in small LNG projects.
4. Spot indexation (JKM and SLlnG) gains interest in Asia.
The Gas Asia Summit organized a survey on ‘what indexation is most attractive to buyers for new supplies?’ The participants who voted for an Asian hub price were seeking an indexation that could best represent where the Asian LNG price should be.
They argue that oil indexation does not reflect gas fundamentals, while European gas and U.S. gas do not reflect the dynamics in the Asian gas market.
5. Will an Asian LNG hub help remove the Asia price premium?
Many participants at the LNG Producer-Consumer Conference 2017 in Japan believe that an Asian LNG hub will remove Asian LNG price premiums.
This belief is based on a theory that a liquid trading hub will be priced indifferent to delivery locations.
People look to the oil market as an example of how a future LNG market might develop with regional trading hubs for LNG, so that prices generally move in tandem with each other. The price difference will more or less resemble logistic costs. However, oil makes a poor comparison to LNG.
Where do you think the North Asia spot LNG price will be this summer (May - July)?
Eastern Australia Averts Gas Crisis
Maggie Kuang, Bloomberg New Energy Finance
Eastern Australian LNG producers will continue to export less than contracted volumes, after agreeing to divert gas to the domestic market (52PJ/yr or ~0.9MMt in 2018).
While this may mean that there is little risk of a domestic gas shortage this year, it will put pressure on exports, which will be further exacerbated as demand from its largest buyer, China, is expected to accelerate.
Longer term, the gap may be filled by LNG imports or gas transmission from western Australia, at around $8/MMBtu (A$10/GJ).
The three eastern Autralian LNG projects – APLNG, QCLNG and GLNG have struggled to export contracted volumes since the start of their operations two years ago.
This trend will continue for the next few years, despite an expected increase in gas production in the period, because exporters have agreed to divert gas to the domestic market following government intervention.
The growth in China’s LNG demand, observed in 2017, is likely to continue in 2018-19 and will support spot LNG prices. Keeping promises to the domestic Australian market will be at the expense of an opportunity to increase LNG exports.
Total LNG exports from the three projects during 2018-25 will range between 21-23MMtpa against total commissioned capacity of 25.3MMtpa.
As depletion of conventional gas in the region speeds up from 2024, eastern Australia will face a greater shortage of 431PJ (7.1MMtpa) of gas by 2030. This requires the region to either drill more costly coal seam gas, start importing LNG or build gas transmission from western Australia.
The West-East Gas Pipeline is expected to result in an average delivered gas price of $8/MMBtu (A$10/GJ) to the east coast, which makes it a reasonably viable proposal compared to the full cost of imported LNG.
All these options paint a future of more expensive gas for eastern Australia.
The old days of <$4/MMBtu (<A$5/GJ) wholesale gas seem to be over.
How have LNG exports disrupted Australia's local energy market? Learn more in this Future of Energy Summit video.
Which research area is of most value to you?
- Short-term fundamentals of the global LNG market
- Country-level deep-dive reports
- Sector dynamics: power, heating, transport, industries
Russia, the world’s biggest gas exporter, has relied on pipeline supplies of LNG to Europe as a major source of income. It now aims to build LNG plants from the Baltic region to its Pacific coast to take on the world's biggest producers of LNG.
Putin Blesses Multibillion-Dollar Bet on Russia Competing in LNG
Elena Mazneva, Bloomberg News
As Russia’s President Vladimir Putin oversees the official start of a $27 billion liquefied natural gas plant in the snow-covered tundra of northern Siberia, his mind may wander to its biggest competitor more than 3,000 miles away in Qatar.
While the two regions may have vastly different climates, Putin is determined to make Russia’s Arctic competitive in the fuel that turned Qatar into the richest nation per capita. In December 2017, he witnessed the loading of the first custom-built icebreaking tanker from the Yamal LNG plant in a region that potentially contains more gas than the Persian Gulf, flanked by a delegation that included the energy minister of Saudi Arabia.
Yamal LNG project’s port of Sabetta last March. Source: Novatek
Operator Novatek PJSC announced the start of production at Yamal LNG in December last year, in which Total SA, China National Petroleum Corp. and China’s Silk Road Fund also hold stakes. The world’s coldest LNG plant has come online within budget and on time, in an industry where that is the exception rather than the rule, even under U.S. sanctions imposed three years ago.
“Together we managed to build from scratch a world-class LNG project in extreme conditions to exploit the vast gas resources of the Yamal peninsula,” Patrick Pouyanne, chief executive officer of Total, said in a statement. “With remarkably low upstream costs, Yamal LNG is one of the world’s most competitive LNG projects.”
Russia, the world’s biggest gas exporter, has for decades relied on pipeline supplies of the fuel to Europe as a major source of income. It now aims to build LNG plants from the Baltic region to its Pacific coast to take on the biggest current and future producers of the super-chilled fuel delivered by tanker, including Qatar, Australia and the U.S.
Putin ended state-run Gazprom PJSC’s monopoly on LNG exports five years ago to support the industry, previously represented by a single plant off the Pacific coast producing some 10 million tons per year. His government also freed LNG from export taxes, which are at 30 percent for Gazprom’s pipeline supplies abroad, or almost 434 billion rubles ($7.3 billion) for the state budget in the first nine months of 2017.
Yamal LNG project’s port of Sabetta last March. Source: Novatek
Other tax breaks, including on gas extraction, make Arctic LNG competitive in any market, even taking into account higher transportation costs, according to the nation’s Energy Ministry. The region’s plants may use a shorter Northern Sea Route to Asia for the five months of the year when icebreakers can still operate, thanks to which Putin aims to gain a greater foothold in the Arctic.
Saudi Arabian Energy Minister Khalid Al-Falih will witness the feat of engineering that Yamal LNG represents for the first time, having failed at a previous attempt during the summer last year when bad weather prevented him from landing. The Gulf state, which seeks to replace oil with gas for power generation, is looking at investing in Novatek’s future LNG projects in the Arctic, Al-Falih’s counterpart Alexander Novak said last October.
Novatek, which holds 50.1 percent of Yamal LNG versus 20 percent for Total and 29.9 percent for the two Chinese partners, has said it accumulated enough Arctic resources to produce more than 70 million tons of LNG per year, approaching the current capacity in Qatar, the world’s biggest producer of the gas cooled to minus 160 degrees Celsius (minus 260 Fahrenheit).
Yamal LNG plant’s site. Source: Novatek
Novatek will send its first Yamal LNG cargo to China in recognition of its support and growth as a key consuming region. Chinese lenders agreed to provide $12 billion to the project, the lion’s share of the budget, as the nation is on the verge of surpassing South Korea to become the biggest buyer of LNG after Japan.
The second cargo may follow shortly after with a third tanker on its way to the project’s port of Sabetta, where temperatures can fall as low as minus 28 degrees Celsius in the winters. Three production units of 5.5 million tons per year each are planned at Yamal LNG, with the second seen starting in the third quarter and the final one in early 2019. Novatek is also mulling a fourth smaller train of as much as 1 million tons by then. More than half of the project’s fuel will go to Asia.
Yamal LNG’s production is sold under long-term contracts on Asian and European markets, predominantly under oil-indexed price formulas, according to Total, which will buy 4 million tons annually from the project.