LONDON (Reuters) - Qatar is sweetening its gas sales pitch to lock-in long-term Asian buyers before a wave of new suppliers from the United States, Australia, and east Africa snatch market share and deflate prices.
Up to now, importers like Japan and South Korea have had few major supply alternatives to the tiny Gulf state, whose liquefied natural gas exports represent about a third of global supply.
But in a growing market for LNG, gas condensed for shipment to markets pipeline supplies do not reach, nearly 30 million tonnes a year (mtpa) of U.S. gas is already sold to Asia.
Some 350 mtpa more will come on stream from the United States, Canada, east Africa, Russia and Australia in the years ahead - more than doubling worldwide output.
Buyers in the Pacific have shunned Qatar’s high asking prices, and China and India are also hesitating over plans to sign new long-term deals.
Qatar now hopes to lure leading buyers back by offering cheap teaser deals lasting a few years, backed up by more strategic 20-year sales, sources familiar with the negotiations say.
“The Qataris have made good money over the years, but the joy ride is over,” said one source of the world’s lowest cost LNG producer.
LNG pricing is still closely tied to oil. It is expressed as a “slope” based around a $100 per barrel oil price, where a million British thermal units (mmbtu) of LNG costs a percentage of that per-barrel price, plus a small fixed dollar amount.
“They are now offering three-year deals priced at 13.5 percent slope, while their long-term price is more around the 14.6-14.7 range,” an industry source with knowledge of the matter said.
Long-term LNG deals have been priced at a slope of 14.85 percent in recent sales from Australia and Papua New Guinea - more evidence Qatar is looking to undercut rivals.
Poor demand and oversupply has driven gas prices down in Europe while in South America’s subsidised energy markets, a lack of creditworthy buyers makes direct 20-year deals risky.
The United States, a market which much of Qatar’s LNG production capacity was built to supply, has already become virtually self-sufficient thanks to a glut of shale gas, and will soon be competing with Qatar in the Asian market.
Beijing’s desire to improve air quality and a disaffection with atomic power in the region since Japan’s Fukushima nuclear plant disaster in Japan in 2011 are helping to drive demand.
Asian demand is the prize for LNG producers - Qatar has even agreed to supply additional LNG to Chinese and South Korean buyers this winter.
Despite the U.S. competition, Doha remains set on oil-linked pricing and resists contractual devices used by Australian suppliers that protect buyers from oil price spikes.
In 2009, Qatar sold China 5 million tonnes per annum (mtpa) of LNG at a 16.2 percent slope to the Japanese Crude Cocktail (JCC) - one of the highest priced long term deals ever struck. But sources say China has since put off taking up an option to buy a similar further amount, prompting Qatar to drop prices.
“The Chinese signed up to a very expensive deal, Qatar may be offering cheaper prices to prevent Beijing from trying to renegotiate that first deal,” a trade source said.
The latest deals clinched between Russia’s Novatek (NVTK.MM)-operated Yamal LNG project and Chinese and Spanish buyers provide further evidence of downward price pressure.
Yamal last month sold 3 mtpa to Chinese buyer CNPC at an estimated slope of 12.2 percent plus a high fixed premium. Last week, the Arctic project gave Spain’s Gas Natural Fenosa dual-pricing for its 2.5 mtpa, linking supply to prices at the UK’s NBP gas hub and Brent crude oil at a 12 percent slope, an industry source said.
Asian buyers now want hybrid pricing deals that take the sting out of costly crude by linking them to freely-traded gas as well. China’s National Development and Reform Commission (NDRC) has told its LNG buyers not to pay above 14 percent of crude oil for long-term supply, and to go for hybrid agreements where possible, several sources said.
LNG provider BG Group’s BG.L recent deal with China’s CNOOC last year has a hybrid price structure, Credit Suisse managing director of equity research David Hewitt said, with 70 percent oil-linked and the rest tied to U.S. gas benchmark Henry Hub.
Long-term LNG deals linked purely to U.S. gas prices tend to come with a higher fixed premium to oil-linked arrangements - often around $6-7/mmBtu.
Japan’s energy ministry has also moved to cap prices, warning utilities that they will not be able to pass costs on to electricity customers beyond a new ceiling.
For the fiscal years 2013/14 and 2014/15, that ceiling - called the top-runner price - will be set based on the cheapest outcome of contract reviews for those two years.
Those reviews are under way with suppliers such as Australia’s North West Shelf and Pluto projects, Malaysia LNG Satu, Russia’s Sakhalin 2 and Abu Dhabi.
From April 2015, the import price is to partly reflect gas-linked prices amid the projected start of U.S. shale gas exports to Japanese buyers.
One industry source put the 2013/14 and 15/16 ceiling price at $13.00/mmBtu. Others said it could be one or two dollars higher. Whichever is the case, the message to utilities is clear: bring down the price, or lose profits.
Although the emergence of new export hopefuls has affected Qatar’s tactics, potential buyers know Doha will be their main option for five years or more yet until new supplies come.
Buyer reticence to sign up for long term deals has also affected the next generation of LNG projects to feed expected demand growth beyond 2020.
After a spate of go-aheads in the period 2009-2011, not a single one outside the United States has been sanctioned for almost two years. Some developers warn of a looming shortage in future.
“Realism is creeping back into negotiations and buyers realise they need the LNG and that they can’t necessarily afford to wait around for new exporters to get started,” an industry source said.
As another source put it: “If you need LNG now you have to go to the Qataris.”
Additional reporting by Osamu Tsukimori in Tokyo and Daniel Fineren in Dubai; Editing by Andrew Callus and William Hardy