LNG prices: With rising demand, the only way is up
With rising demand for LNG set to outstrip supply for the foreseeable future prices will, inevitably, rise in Asia and in Europe
Global LNG demand is expected to double this decade, but only about 55 million t/y of new liquefaction capacity is scheduled to come on stream by 2015, an increase of less than 25%. The market is tight and growing tighter.
Since 2009, a gas glut in Europe has seen low-priced LNG eating into oil-indexed pipeline gas’s market share. For much of 2011, UK NBP has traded at around $9/million British thermal units (Btu) as a result of adequate gas stocks, higher Russian exports and the ramp up of Qatargas supply.
But the glut of LNG supply is over. Additional production that came on stream in 2009 and 2010 has been absorbed and supply is now very tight. With Australia’s Pluto LNG now starting up a year late, in March 2012, forecast 2011 LNG production has been reduced by about 3 million tonnes. No new liquefaction capacity will now come on stream in 2011, with only another 9.3 million tonnes flowing to markets in 2012 – from Pluto and Angola. This is nowhere near enough, particularly when imports this year are likely to increase by about 75% in the UK, 30% in India and 10% in Japan.
The UK has overtaken Spain as the largest liquefied natural gas (LNG) importer in Europe and is now ranked third globally after Japan and South Korea. Qatar is now, by far, the dominant gas supplier to the UK – primarily Qatargas volumes delivered to South Hook. When spot imports into other UK terminals are included, Qatar’s share of LNG supply to the country hit about 78% in the first half of 2011 – Qatar delivered about 8.8 million tonnes in this period while none of the other suppliers (Nigeria, Trinidad, Yemen and Algeria) individually supplied more than 1 million tonnes.
Spanish LNG imports have declined sharply in recent months ahead of the start up of the Medgaz pipeline. Spanish imports of about 1.7 million tonnes a month in 2010 fell to an average 1.4 million tonnes a month in second-quarter 2011. First Algerian gas flowed through Medgaz in May, resulting in a drop to 1.3m tonnes of LNG imports in June (see Figure 1). The pipeline has a design capacity of 8 billion cubic metres a year (cm/y), but Spain, still rocking from the recession, is unlikely to absorb such volumes in the near future.
European LNG imports were up by 18.5% in the first half of 2011 compared with the same period last year – even excluding the UK and Spain, imports were up by a significant 17.5%. Much of this can be attributed to the ramp up of supply to France’s Fos Cavou terminal, where first-half imports were similar to full-year imports in 2010. Other markets are more subdued, with Turkish imports down by around 500,000 tonnes compared with the first half of last year.
The Netherlands’ Gate terminal (Gasunie/Vopak), in Rotterdam, received its first commissioning cargo in June. The terminal says all of its initial send out capacity of 12 billion cm/y has been sold to five large European suppliers. Gate is linked in the Northwest Europe pipeline system, but may also enable development of new markets such as the supply of LNG bunkers within the Port of Rotterdam. Fully utilised, the facility can import about 9 million t/y.
France’s EdF has awarded engineering, procurement and construction, and tank-construction contracts for its planned Dunkirk terminal (EdF, 65%; Total, 25%; and Fluxys; 10%). The 13 billion cm/y terminal is scheduled for completion in 2015 and Total has reserved 2 billion cm/y of its capacity. Once completed, the terminal will increase France’s LNG import capacity by 20%.
Europe has about 137 million t/y of LNG regasification capacity and imported 65 million tonnes in 2010. By 2015, import capacity could reach 200 million t/y if many of the region’s proposed terminals go ahead. It is unlikely Europe will be importing anything like 200 million tonnes by 2015, with potential demand seen as 160 million to 170 million tonnes by 2020. But there will be nothing like this volume available for European buyers and even securing 100 million t/y might prove difficult.
Is the debate in Europe over nuclear power a distraction, or could it affect LNG demand? Europe has about 170 gigawatts (GW) of nuclear capacity with about 17 GW under construction. But in the aftermath of Japan’s Fukushima nuclear crisis, Germany (20 GW) and Switzerland (3 GW) have decided to phase out nuclear power by 2022 and 2030 respectively – although other countries with significant nuclear capacity, such as France and the UK, have not announced changes to their nuclear programmes.
Germany will not shut down all its nuclear capacity until 2022, but the country’s decision has had an immediate impact – eight nuclear plants off line for safety checks will not be permitted to restart. Initially, Germany will make up the electricity supply shortfall by running more coal-fired capacity, but in the longer term, it will bring on more combined-cycle gas-turbine (CCGT) plants and renewable capacity.
To meet rising gas demand, the 1,224 km Nord Stream gas pipeline from Russia will begin commercial operation in October. Initially, the dual-pipeline project will be able to supply 27 billion cm/y gas, increasing to 55 billion cm/y in September 2012 when the second parallel line becomes operational. This will not all be new supply, as Nord Stream will also carry gas delivered now through other pipelines, but Russia could meet demand arising from the new CCGT plants.
But whether it does could depend on price. There is increasing reluctance by Europe’s big power generators to buy gas under traditional long-term, oil-linked contracts, particularly as electricity markets become more competitive, which could lead to increased interest in more flexibly priced LNG. German plans for LNG terminals at Wilhelmshaven and Rostock, which are on hold, could be revived; or German buyers could import regasified LNG from Belgium, the Netherlands, or France. But with LNG, too, price will be an issue: prices are expected to be considerably higher in 2012 and 2013 than those seen at NBP in 2011.
Many of the price drivers are external, but, fundamentally, LNG demand is growing far faster than supply. Global demand rose by an unprecedented 22% in 2010 and a further increase of 16-17% is expected in 2011. The UK had been expected to show the largest increase in imports (up to 10 million tonnes), but Japan looks set to import at least an additional 6 million tonnes this year.
In the immediate aftermath of March’s devastating earthquake, we forecast Japan might need an additional 5 million tonnes of LNG this year. But since then, Chubu Electric’s Hamaoka nuclear plant has been shut down and none of the nuclear facilities that were off line, or taken off line, at the time of the disaster have been allowed to start up again. Additional demand of 6 million to 7 million tonnes is now forecast this year, and this could be considerably higher in 2012.
Nuclear power plants in Japan usually have a 13 month inspection schedule and, if these are not permitted to restart after their next scheduled maintenance, the country’s entire nuclear fleet could be idle by mid-2012. In preparation, some utilities unaffected by the earthquake, such as Kansai and Kyushu Electric, are already buying additional LNG cargoes. Potentially, in 2012, Japan may require 15 million to 17 million tonnes more than the 70 million tonnes imported in 2010.
In Asia, Japan is not alone in needing more LNG. Imports by South Korea and Taiwan may be up 10% in 2011, but the greatest percentage increase is likely to be from India, where LNG imports may rise by 30% this year. Lower than expected domestic gas production and higher oil prices have stimulated demand for LNG, with Indian companies regularly buying spot cargoes.
Uncertainty in China
There is uncertainty in China, where gas demand is growing very strongly. Term LNG commitments imply the country will import at least 15 million tonnes of LNG this year, up from 9.6 million tonnes in 2010; but low domestic gas prices have forced buyers to postpone some term LNG supply and minimise spot purchases. Our latest forecast is that China will import about 13 million tonnes this year, but this could change if regulated domestic gas prices rise. If this happens, China could overtake India as Asia’s fastest-growing LNG market.
Spot LNG prices in Asia, which opened the year at $11.50/million Btu, hit $15/million Btu in May, as Japanese buyers entered the market to cover summer demand. This drew Atlantic basin cargoes east, but had little price impact in Europe, where high stocks and subdued demand kept NBP around $9/million Btu. But this situation is unlikely to last.
Buyers in northeast Asia will shortly re-enter the market to build winter stocks, probably pushing spot prices for Japanese and South Korean delivery beyond $15/million Btu again – possibly as high as $17/million Btu, or more. In these circumstances, the mention of a cold winter in Europe could result in a sharp increase at NBP to $12/million Btu, perhaps even towards $15/million Btu.
Even if it does not happen this year, prices are heading up. The market is tight and will grow much tighter in 2012. Already some demand is not being met, but by 2015 the market could be short by as much as 100 billion cm/y of LNG.
Relief is not in sight. About 9 million t/y of new liquefaction capacity is due on stream in Algeria in 2013; and about 30 million t/y in Australia, Indonesia and Papua New Guinea in 2014. But by 2014, demand could be 70% higher than in 2010, with supply capacity up by less than 20% – and this demand forecast may prove conservative. Gas is cheap and industrial and commercial buyers are only just beginning to realise how competitive it is with petroleum products. Even in Asia, LNG costs less than fuel oil and is 50-70% cheaper than diesel and gasoline. There is a growing interest in LNG as a transportation fuel, or for marine bunkers.
Post 2015, the supply situation may look a bit healthier. Ten proposed LNG-export projects expect to take a final investment decision this year, which could bring 65 million t/y of LNG on line between 2014 and 2017. The project pipeline has improved significantly this year and it is possible that post 2015 European buyers could be offered US Gulf coast cargoes and that significant volumes could be moving from Canada’s west coast to northeast Asia.
What next for Europe?
What does this mean for Europe? Certainly not a return to $6/million Btu LNG. Despite new liquefaction capacity coming on stream post 2015, demand will continue to outstrip supply resulting in a very tight LNG market until 2020 and into the next decade.
In the meantime, Europe is likely to see its first commercial unconventional-gas production, with several countries holding shale gas resources. Development is focused on Poland, which is thought to hold the largest shale resources in Europe. While some production can be expected this decade, significant commercial shale-gas supply is unlikely until after 2020.
So what should a utility considering building a new CCGT do? Sign up with a piped gas seller and accept an oil linked contract? Buy LNG and risk having to pay a significantly higher price post commissioning? Or wait for shale gas? Perhaps the answer is to seek out a seller prepared to give it a switching option.
Tony Regan, principal consultant, Tri-Zen International, a Singapore-based oil and gas consultancy business with a primary focus on Asia.