The Great LNG Bear of 009, and Its Approaching Sequel Jonty Rushforth, Senior Asia LNG Editor, Platts LNG Source: Getty Images Market observers had expected 009 to be a bearish year for liquefied natural gas (LNG). Increased unconventional gas production in the US had already knocked back imports in 00, while a wave of new gas liquefaction capacity was due to come onstream worldwide. In some ways, the observers have been proven right, at least insofar as prices have come down. US Henry Hub front month prices have fallen back from above $.00/MMBtu in July 00 to trade below $3.00/MMBtu in September 009, while the front month at the UK s National Balancing Point (NBP) has seen an even more dramatic fall, from above $1.00/MMBtu in September 00 to below $.00/MMBtu in 009. Spot prices for LNG followed suit. While LNG is a price taker in the Atlantic basin, in Asia Pacific it also responds to local fundamentals. A loss of Japanese nuclear output in 007 had raised gas demand for power generation, while new consumers and robust economic growth among traditional buyers kept demand buoyant across the region into late 00, and spot buyers paid upwards of $0.00/MMBtu. By summer 009, spot LNG prices had fallen considerably. Platts Japan Korea Marker (JKM), an assessment of prices for spot cargoes delivered in the forward month to Japan or Korea, fell to under $.00/MMBtu in May, dipping below NBP hub prices in the UK. But while the market had expected a supply-driven fall in prices, in the end much of that supply did not appear. In fact global liquefaction is lower this year so far than it was at the same time last year, and it looks like it will finish, if not lower, then only a little above last year or flat, Keith Barnett, director of global commodities strategy analysis at Merrill Lynch, said in 0 insight November 009
September. He points to significant problems at plants in Nigeria, production cuts in Algeria, and lesser problems with Asian production. And LNG production units, or trains, have been slower to come on than expected, Barnett says. Why hurry to bring production online, and pay overtime, in the current pricing environment? Low production was evident by the summer, when Anglo-Dutch major Shell reported a % year-on-year drop in LNG production worldwide for its second quarter results. Shell saw both sides of the supply situation, as it has equity in new capacity that came onstream in Russia and Australia, but also saw LNG output from Nigeria plummet due to upstream problems. Excluding Nigeria, Shell s equity production was up 7% year on year in the second quarter, it said. Fellow major ExxonMobil, which does not strip out LNG from the broader gas picture in its quarterly results, said in July that its average gas production in the second quarter was down 5.% year on year, to.013 million cubic feet per day. The company said that new production volumes from project additions in Qatar, the United States and the North Sea were more than offset by field decline and lower European demand. So if supply has dropped back, what has pulled down prices? For LNG, it s primarily been down to a big drop in consumption in Japan, Korea, Taiwan, and to some extent Spain, John Harris, director for global LNG at Cambridge Energy Research Associates (CERA), says. European demand has also suffered from the economic downturn. The US has suffered from supply side weakness, but demand has also been hit there On the whole, price has been demand-led this year. Total Asian LNG imports were already looking lower year on year in the last quarter of 00, although in January 009 they again showed an annual increase, of 5,175 metric tons (mt), or.%. But from then on the decline began in earnest, reaching a peak annual rate of 1.7% in May, a drop of 1.77 million mt over the previous year. Liquefaction trains are not easily turned down; analysts say there is tolerance for perhaps a 5% reduction in output, but not much more. So the fall in previously anticipated Asian 1. Global gas prices, 009. Algonquin City Gate Fwd Mo LNG Japan/Korea Marker UK NBP Fwd Mo SoCal Fwd Mo France PEG Fwd Mo 9 7 $/MMBtu 5 3 1 -Feb -Mar -Apr -May 1-Jun -Jul 3-Aug 7-Sep November 009 insight 1
requirements had to be otherwise accounted for. In 00 Asian buyers had attracted some spot and short-term cargoes across from the Atlantic basin by paying significant premiums to gas hub prices. As spot interest fell back in 009, the Asian premium disappeared. Asian buyers are not paying as much for LNG, says Chris Holmes, vice president at Purvin & Gertz. They want hub prices, so we ve seen LNG prices come down. There s no reason why people should pay the high prices they paid last year. With no premium in Asia Pacific, most Atlantic cargoes stayed west. Between April and July 00, Japan received.1 million mt of LNG from Trinidad, Algeria, Egypt, Nigeria, and Equatorial Guinea. In the same period a year later it received just 3,30 mt from Nigeria and Equatorial Guinea, and none from the other producers. But even after cutting out the crossregional imports, Asian buyers still needed to cut back. They used contractual downward quantity tolerance clauses, which typically allow drops of 5-% in term supplies. That in turn left Asian producers with spare product. With no interest locally, they turned to European markets, and prices reflected that switch in focus. The JKM was flat to the UK s NBP, or showed a discount, for much of the second quarter of 009. With the LNG heading west, the UK in particular saw a rapid rise in imports, facilitated by the commissioning of two major new regasification terminals and the expansion of an existing one. NBP prices fell back, and so the few buyers left in Asia reduced their own price expectations as a result. A Japanese nuclear outage provided some relief for suppliers, followed by a gradual economic recovery in traditional Asian markets, but spot prices struggled to climb much above $5.00/MMBtu. Takayuki Nogami, senior economist for global oil and gas markets at Japan Oil, Gas and Metals National Corp (JOGMEC), summarizes the situation: Asia Pacific demand has plunged, with a double-digit drop, due to the recession. Buyers have reduced imports, LNG spot markets in the Atlantic Basin are bearish, and some new LNG supply has come on stream, flooding the market. That left regional spot prices at $.00-5.00/MMBtu DES [delivered ex-ship] in Asian markets. That is not to say that all is lost and prices will tumble to all-time lows, however. In fact, Asian spot prices seem to have stabilized at about the level Nogami identifies. One reason for that is that the low prices have brought in opportunistic buyers. China, with two new terminals starting up in 009, has seen annual import growth every. Total Asian LNG imports, 00-9. 1 China South Korea Taiwan Japan India mt millions 1/0 /0 3/0 /0 5/0 /0 7/0 /0 9/0 /0 11/0 1/0 1/09 /09 3/09 /09 5/09 /09 7/09 insight November 009
month this year. And India reached its highest ever monthly import volume, at 1.0 million mt, in March, when much of the rest of the region was seeing severe declines. For both countries, spot LNG is considerably cheaper compared to alternative fuels, namely naphtha in India and fuel oil in China. Both of those alternatives have risen steadily since the start of 009, with fuel oil FOB Singapore at around $.00/MMBtu in the summer and naphtha CFR Japan as high as $15.00/MMBtu. CERA s John Harris says that since those buyers have already been brought into the market, lower prices would not attract any more demand for LNG in Asia: Spot buying has been a reflection of low spot prices. If prices were any lower, you wouldn t see any more demand. He adds that sellers are going to be inclined to look at alternative fuels and extract that value. By the third quarter, there were also signs of some recovery in demand in the traditional LNG markets. Taiwan s CPC issued a tender in September for three spot cargoes after staying out of the market for several months. Traders began talking of some spot demand from South Korea as well, although for only for a few cargoes. So could the slight signs of recovery in demand from the traditional markets, combined with opportunistic buying from new markets, pull prices back up in 0? Merrill Lynch s Keith Barnett thinks not: I really don t see anything that can turn the market around. A miraculous recovery in north Asian countries could take some of the pressure off, but otherwise it s going to be a grind as it works out. The problem is that the effect that everyone was waiting to see in 009 is likely to finally come through in 0 instead. The missing gas is heading inexorably towards the markets. Andrew Pearson, head of LNG research at Wood Mackenzie, says: New LNG supply projects have begun to start up, although it will be next year before this new volume has its full impact on the market. Next year we will see a big increase in LNG trade as these new plants ramp up. Already new trains have started up in 009 in Russia, Indonesia, Yemen and Qatar, with more trains scheduled to follow in Yemen and Qatar, and a new project in Peru, in 0. Of those that 3. Oil products vs JKM. 1 Qinhuangdao Coal Minas FOB Indonesia FO 10 FOB Spore Naphtha CFR Japan LNG Japan/Korea Marker 1 1 1 $/MMBtu -Mar 7-Apr 1-Apr 5-May 19-May -Jun 1-Jun 30-Jun 1-Jul -Jul 11-Aug 5-Aug -Sep -Sep November 009 insight 3
have started, some have ramped up production slowly, but could be at full capacity in 0. And it is possible that production problems in Algeria and Nigeria could be resolved by 0, adding further supply. Takayuki Nogami at JOGMEC says that with the new supplies coming on, in addition to those which started this year, LNG fundamentals will be quite anemic in 0, too. He sees spot gas prices in the US and UK in a low range of $3.00-5.00/MMBtu, with spot LNG somewhat at the same level as natural gas spot prices in the US and UK, reflecting weak fundamentals. The problem is that the new LNG coming in has to go somewhere, and the traditional markets are already struggling to absorb the excess this year, before the new wave really impacts. There are new terminals, such as those in China and India, and new floating terminals in Kuwait and South America. But these may not make much of a difference. Purvin & Gertz Holmes says the new terminals are marginal. He adds: What s coming on in production far outweighs that. There s tens of millions of tons coming on. Some of the excess in 009 has headed to Europe, and that trend could continue in 0. But Europe began 009 with low LNG storage levels after Russian pipeline gas flows through Ukraine were cut in the winter. That created a widespread need for gas throughout the summer, but there s no guarantee that the same circumstances will occur in 0. And for Europe to take any more gas, pipeline suppliers would need to cede market space to LNG producers, with little obvious incentive. The European suppliers provide gas on contracts linked to oil prices, which have remained comparatively high relative to spot gas, while any excess LNG heading to the continent would have to take the relevant hub prices. In a contest between the two supply sources, the home team will have the advantage. But instead, several commentators think the bulk of any 0 excess will head to the US, where there is ample spare import capacity. Harris says that if the supply that had been expected had appeared this year, we would have seen much more of it go to the US. With the startup of new projects in the months ahead, we should see much more go to the US, he adds. The US also has a more diffuse and flexible domestic gas market. At the end of the day, the US has the largest most liquid storage capacity to take it, says Keith Barnett at Merrill Lynch. And it also has the shortest investment. Fuel oil vs term, spot LNG. 1 FO 10 FOB Spore LNG Japan/Korea Spot Crg DES S Korea LNG average import price 1 $/MMBtu -Mar 7-Apr 1-Apr 5-May 19-May -Jun 1-Jun 30-Jun 1-Jul -Jul 11-Aug 5-Aug -Sep -Sep insight November 009
cycles for [exploration and production]. So LNG sellers can pummel the US producers for a year or two, and then the producers can pick up the pieces after that. For these billion-dollar LNG projects, you can t really turn them around it s like a supertanker versus a Smart car. For excess LNG in 0 to head to the US, either European import capacity would have to be full, or prices would have to favor the west Atlantic. Particularly during the summer, import capacity is unlikely to be fully used, which leaves price incentives as the likely motivator. And that means that the price for excess LNG worldwide would be set by Henry Hub values. NYMEX futures have already fallen significantly in the last year and more, dropping steadily from the $13.577/ MMBtu high recorded on July 3, 00. At the time of writing (early October) front month futures had recovered from the September lows of mid s to hit $.00/MMBtu, but this is still a relatively low number. Could NYMEX prices recover in the year ahead? One factor that analysts have focused on is the US drilling rate, which has declined in 009 as prices have fallen back. The theory is that that will mean lower production and hence higher prices. Many analysts are putting their hopes on that, that it will push prices up to $7.00/MMBtu in the last half of 0, says Keith Barnett. But he adds: I m not one of those people. He points out that as domestic producers pull back, LNG moves in. And LNG producers may be willing to accept extremely low prices before they blink. Unlike unconventional gas production in the US, much of which is dry, non-associated shale gas, LNG production worldwide is often associated with liquids production. Because those liquids condensate and LPG attract relatively high prices compared with methane, the projects can keep producing even when they receive little income for the LNG itself. For projects such as Qatar s RasGas and Qatargas, and Australia s North West Shelf, it is as if LNG production had zero cost. Essentially shipping is the marginal cost, so prices can be pushed down quite low before there s any incentive to stop producing, Chris Holmes at Purvin & Gertz says. Just how low is quite low? If Henry Hub went below $.00/MMBtu, you would struggle to send LNG to the US, certainly from the Middle East, he says. A floor of $.00/MMBtu may be scant comfort to producers, and there is more bad news on the upside. Although US 5. NBP Winters in $/MMBtu as a percentage of Dated Brent. 30 Winter /11 Winter 09/ 5 0 15 5 1/0 /0 3/0 /0 5/0 /0 7/0 /0 9/0 /0 11/01/0 1/09 /09 3/09 /09 5/09 /09 7/09 /09 9/09 November 009 insight 5
gas producers have been pushing production back, analysts say the trend of late has been to drill wells in preparation for any market turnaround. Barnett says: There are as many as 1,000 wells that have not been completed, and could be started up in as little as three months. They re drilled and cased, but not perforated and fractured. Any US price rise would likely be met by a rapid production response, likely keeping a lid on prices. So hub prices are likely to remain in the $.00-.00/MMBtu range we have seen this year. Spot LNG prices in Asia Pacific might be somewhat above that if there were localized demand, but few analysts see potential for spot LNG to climb back to even early 009 levels. JOGMEC s Takayuki Nogami says there is a low probability of prices at $7.00-.00/MMBtu, barring a severe winter storm, while CERA s John Harris says Asian LNG prices will be between Henry Hub and oil. The 0 price picture therefore looks like a reproduction of 009, but with different drivers. Whereas this year saw a collapse in demand pushing prices lower, the following year will see supply pressuring prices. Any uptick in demand in Asia Pacific is likely to be easily met by the increase in LNG supplies, with buyers bidding against a weak Henry Hub price, and any unmet Atlantic demand fed by the uncompleted US wells. That outlook could hold true beyond 0. Andrew Pearson at Wood Mackenzie says that for the Pacific basin our view is that the market should stay soft for the next few years, until the new wave of supply, currently coming onstream, is absorbed into the market. There is a postscript to that picture, however. While spot LNG prices have bounced along a bottom in 009, producers selling LNG on long-term contracts have had the benefit of oil indexation. Nogami says that if crude prices fell back to $0-50/barrel, term LNG prices would be $7.00-.00/ MMBtu. But if they maintain their current momentum, prices would rise to $.00/MMBtu. LNG projects tend to sell most output under term contracts, so the low price environment will not be hitting LNG producers as much as might be expected, and certainly not as much as those US producers who take Henry Hub pricing. But that disconnect between spot and term LNG pricing may have an impact beyond the current downturn. Pearson points out that the last few years saw very few LNG projects sanctioned, whereas this year and next look more encouraging. Australia s giant Gorgon project has already been sanctioned in 009, while a string of LNG projects in Papua New Guinea and several coal seam gas-based projects in Australia are heading towards final investment decisions in the next year or so. Pearson says that the first wave of this new supply will still attract close to oil parity pricing, probably around 1-15% of JCC, referring to the Japanese Crude Cocktail benchmark. But it will be the projects at the back end of the supply curve which will be put under pressure as the competition is intense and there is insufficient market for all the volume, he says. There are already reports that one recent contract has been signed with an s-curve shape to protect the buyers at oil prices not too much more than the current price. This is evidence that the pendulum is swinging back towards the buyers after many years of a suppliers market, says Pearson. With this, everything is up for grabs. There s a lot more leverage for buyers to dictate whether they buy DES or FOB, include caps or floors, and potentially even take a stake in the supply project. With buyers facing yet another year of paying close to oil prices for longterm supplies of LNG while spot prices reflect weak fundamentals, any increase in their power is likely to mean a significant shift towards flexibility and a weaker oil linkage. And because of the long lifecycle of LNG projects, that shift will affect the market for decades to come. n insight November 009