PERTH/LONDON (Reuters) - Locked into hefty discounts for nearly a decade, producers of super-cooled liquid natural gas could triple their earnings as surging demand gives them the upper hand in contract reviews with big buyers in Asia.
In what was still a fledgling market in competitive LNG tenders, Japanese, South Korean and Chinese buyers secured deep discounts in deals largely done five to eight years ago.
LNG prices were falling and sellers gearing up to fund billions in new LNG plants jostled to lock in 20-year deals.
Yet with global gas prices now more than double 2010 levels at $19 per million British thermal units (mmBtu), buoyed by Japan’s nuclear crisis and China’s appetite for energy, producers have ambitious hopes for renegotiating such contracts.
A taste of what could come was seen in a deal concluded by Malaysia’s Petronas PETR.UL which tripled the price South Korea’s Kogas (036460.KS) will pay for LNG from its Tiga plant through 2027.
“The Tiga deal will serve as a guide price for others and it will be interesting to see what Qatar does given that Petronas got a deal below the magical 14.85 percent (of oil) price,” one source said.
That level reflects the international price of long-term LNG supply adopted by top producer Qatar as well as Australia in recent years.
Buyers on the other side of price reviews currently under way include Kogas, Japan’s Tokyo Gas (9531.T), Tokyo Electric Company (9501.T) and Kansai Electric (9503.T) and China’s National Offshore Oil Company (CNOOC) (0883.HK).
Buyers and sellers are tightly guarded about the commercial terms of their contracts, yet industry sources expect major price hikes given market conditions.
Not only has demand from Asian and South American countries surged but supply has been constrained by unrest in Yemen, sabotage in Nigeria and curtailed exports from Egypt and Indonesia due to higher domestic use.
“The market is going to be so tight this year, there is just no need for (sellers) to concede,” said Tony Regan, an LNG analyst with Tri Zen International in Singapore.
LNG output rose 1 percent last year but that was after a rare fall in 2012 - just the fourth ever - as production fell by 1.6 percent to 238 million tonnes.
There hasn’t been a slump of that size since 1980-1981 when Algeria halted exports to the United States in dispute over prices.
Producers stand to boost annual earnings by hundreds of millions of dollars if they can match the prices which Petronas achieved with Kogas.
Woodside, Australia’s largest exporter of the fuel, is among the sellers that could benefit most.
It could rake in up to $1 billion in additional pre-tax earnings next year from just two supply contracts from its Pluto LNG plant, according to Reuters calculations and industry analysts.
Under the two contracts it supplies Japan’s Kansai Electric and Tokyo Gas with 3.25-3.75 million tonnes of LNG per year. Woodside currently earns $7-8 per mmBtu, a price which industry watchers say could double in renegotiated deals.
Woodside is also in negotiations with China’s CNOOC which gets LNG from Woodside’s North West Shelf plant for just $3.25 per mmBtu.
Britain’s BP (BP.L) is also expected to raise the price it charges CNOOC for 2.6 million tonnes per annum (mtpa) of LNG from Indonesia’s Tangguh LNG plant.
With oil prices back up to $110 a barrel following the 2007-2008 global financial crisis, part of the aim of producers in contract reviews is to scrap or amend price caps linked to the price of a barrel of crude.
Oil price caps have held down the price which producers in Yemen, Russia’s Sakhalin 2 venture, Indonesia, Australia’s North West Shelf and until recently Malaysia’s Tiga could fetch under long-term contracts.
The caps also meant producers lost out as crude oil prices surged from $40 in 2005 to $147 per barrel in 2008 in one of the biggest commodity price rallies in history.
Woodside’s deal with CNOOC supplied from its North West Shelf LNG plant includes an oil cap of just $25 per barrel, the industry’s lowest.
Petronas struck a new pricing formula with Kogas at 13 percent (of the price of Japanese crude oil imports, or JCC, a regional benchmark), according to one source with knowledge of the deal.
Kogas will pay around $13.50 per mmBtu when crude oil trades at $100 a barrel including a fixed premium of $0.50 per mmBtu, said two other sources with knowledge of the deal.
That marks a steep jump from the contract’s previous terms of $4-$5 per mmBtu tied to an oil price cap of $40 a barrel.
Smarting from years of poor returns, Yemen launched its price review with Kogas for a 2 mtpa, 20-year supply deal by proposing a 15-percent link to JCC, two industry sources said.
Yemen and other producers are likely to strike renegotiated deals at $10 to $14 per mmBtu, depending on terms of the legacy contract, said Karthik Sathyamoorthy, head of Asia Pacific at oil and gas consultancy Galway Group in Singapore.
On a typical cargo of 140,000 cubic metres, that could mean an additional profit of up to $40 million per shipment.
For BP, future annual earnings from its Tangguh project in Indonesia could rise by as much as $500 million, although Chinese buyer CNOOC has responded to Tangguh’s initial renegotiation terms with a lower counter-offer, several sources said.
CNOOC is currently paying $3.45/mmBtu due to an oil price cap of $38 a barrel, which BP aims to scrap in favour of an uncapped market rate.
Indonesia also wants any new price applied retroactively to 2013 sales, an industry source added, which could require CNOOC to pay the Tangguh stakeholders an additional $1.5 billion in rebates for deliveries made last year.
“(China) can afford it. They are importing LNG along the coastal market and they are paying for gas at Asian market prices,” BP Asia-Pacific President William Lin told Reuters late last year.
Russia’s Sakhalin 2 LNG export plant, which earns less than $3 per mmBtu on some deals, has offered 14.7 percent of JCC in its first round of contract reviews with Tokyo Gas and Tokyo Electric Company, sources said.
On the other side of the table, producers seeking ambitious mark-ups face buyers in Asia who are keen to cap surging gas import bills, led by Japan’s energy ministry.
It aims to set a ceiling price for LNG imports estimated at $13-14.50 per mmBtu. The exact level it sets will be determined by the lowest price Japanese utilities achieve in price reviews with long-term suppliers.
Buyers are also armed with the knowledge that while market terms currently favour sellers a tide of new supply from Australia, the United States, Canada, Russia and East Africa is expected to hit the market between 2016 and 2021.
That means importers such as Japan and South Korea which have traditionally had few ready alternatives could see up to 350 mtpa in additional LNG in the years ahead.
Any additional cash that producers do generate is unlikely to spur much new investments, however, as companies around the globe come under pressure to rein in spending and return cash to shareholders.
“You’re going to see companies distribute a lot of that additional income back to shareholders, which is what we are seeing in the industry at the moment,” said Neil Beveridge, an oil and gas analyst at Bernstein Research in Hong Kong.
“More companies are pursuing share buybacks, dividend payouts, which is what investors are looking for.”
Additional reporting by Niluksi Koswanage in Kuala Lumpur; editing by Jason Neely