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In the ‘Asia-Pacific’ LNG trade the largest buyers have been Japan, with between 70 and 90 Mtpa, followed by South Korea, and Taiwan third.

All are island nations, if not geographically then politically, without sizable domestic sources of natural gas or pipelines bringing it from elsewhere. Recently the Japanese government started bringing back on line the nuclear power plants that had passed their safety inspections (1). In addition GDP growth in Japan has been puny, and seems likely to remain so. Together these factors make Japan a poor prospect for new LNG exporters.

The outlook for growth in Europe is not good either. On the positive side, in the last couple of years a number of countries have become LNG importers, though their purchases will likely remain small.

Hence the question: ‘Where are the Sources of New LNG Demand?’ posed by a recent article in King & Spalding Energy Law, which warned:

Japan predicts its LNG demand is [to] decline – in one estimate, to 77 MTPA in 2020 as compared to 86 MTPA in 2014 (2). Kogas, the second largest LNG buyer in the world after Jera, has also revised its demand forecast downwards. Likewise, demand growth for China has dampened with recently lowered forecasts – in one forecast, by 15 percent for the upcoming few years (3).

Japan’s Jera and Korea’s Kogas, the world’s largest LNG importers, have liquefaction contracts with new U.S. Gulf coast terminals. In October 2015, JP Morgan announced that both were ‘emboldened by surging supply to demand concessions’:

These include breaking away from oil-indexed LNG supply deals, which tend to be costly, and abolishing restrictions that currently bar buyers from diverting or re-selling cargoes. Related: Oil Prices Up On Weaker Dollar, Declining Production

‘Sellers may be forced to offer buyers contract offtake flexibility as demand growth slows, providing continued challenges to producer profitability especially those exposed to lower-tier buyers,’ JPM's head of Asia oil and gas equity research, Scott Darling, wrote in the Oct. 1 report (4).

‘Lower-tier buyers’ are less creditworthy and more likely to default on their contracts, which will further reduce investors’ appetite for proposed LNG export terminals. Prime buyers like Jera and Kogas won’t default unless they or the seller go bankrupt, but in this buyer’s market they will expect contract adjustments, mainly price concessions and the waiving of prohibitions on ‘diverting or re-selling cargoes’.

Both will be unwelcome to an LNG exporter who hoped to sell his uncontracted capacity on the spot market – where prices already have dropped way below his expectations, so he doesn’t want his customers to become competitors. Speaking legally, the LNG exporter can refuse to make contract concessions, but he knows that, should the market improve, he will need his contract buyers’ goodwill to raise prices.

While mentioning the construction of new LNG regasification terminals in China and India, along with a half dozen floating ones (FSRUs) being delivered elsewhere, the King & Spalding authors cited the IEA’s prediction that by 2035 China and the Middle East will be the big centers of demand for gas, including LNG(5). 2035 is 19 years away, plenty of time for all kinds of events to interfere.

But back in 2010 WoodMac had also raised its estimate of China’s appetite for LNG, from 31 to 46 Mtpa by 2020 (6). That enthusiasm has waned, since by November 2015 new forecasts were cutting Chinese natural gas demand predictions between 14 and 28 percent. This had to do with ‘. . . the previously runaway Chinese economy . . . decelerating.’(7)

It also had to do with alternatives. China has arrangements to buy cheaper pipeline gas from Russia and Central Asia, plus extensive domestic gas resources. In other words, China’s energy needs are unlikely to call for much LNG. For now, the high in China’s LNG imports may have been 2014, with 20 or 21 Mtpa. In 2015 it was less, though not much less(8). In 2014 China used only half of its LNG regasification capacity, and some of those terminals have been mothballed.(9) 

Finally, this February we learned that China’s plans to replace coal with natural gas to clean up its air may be scaled back. Another factor blamed for China’s reduced appetite for gas and LNG is its move away from manufacturing(10).

Optimistic predictions about LNG demand in India have been deflated too. In April 2014 Platts reported that demand for natural gas in India was expected to grow at a CAGR of around 7 percent until 2030 ‘due to increases in demand for power generation, fertilizer production and city gas distribution.’(11) Of this, LNG imports were expected to rise as follows:

‘India LNG Market Forecast and Opportunities, 2025’, published in January 2016, reported that Indian LNG imports grew from 8.92 Mtpa in 2010 to 16.9 Mtpa in 2015, ‘thereby exhibiting a CAGR of 13.71 percent during 2010-2015’ (See below). It’s not news that high CAGRs are easily achieved when starting from a low base. More importantly, the 16.9 Mtpa in 2015 was about half Platt’s 2016-17 forecast.

To some LNG enthusiasts that’s no reason to give up; after all, the unfulfilled potential remains. True; but the key to success has been elusive, as explained by a recent study by Poten & Partners, ‘Unlocking the Indian Market’:

The development of the Indian LNG market has seen successes, most notably, the Dahej and Hazira import terminals and their associated imports. But efforts to develop the market have been distinguished by their difficulty. The Dabhol terminal is far underutilized, long after it was finally brought on stream. The Kochi terminal was just completed, but cannot deliver as the offtake pipeline was never built—and there is no indication when it will be. Other proposed import ventures could ring the subcontinent like a necklace, but remain on the drawing board.(12) 

I marked the four existing regasification terminals in red on the map, which came from Poten’s report. It also shows India’s gas pipelines, the two existing ones plus a lot more ‘planned’, unbuilt ones. It is no wonder that the Dahej and Hazira terminals are the only ones doing well; by way of the longest, largest of India’s two pipelines they are connected to most of its inland population centers.

img src="https://d1o9e4un86hhpc.cloudfront.net/images/tinymce/2016/urooounssss.jpg" alt="" width="449" height="461"">

(Click to enlarge)

There are other strange aspects to India’s gas infrastructure. In 2015 India, although often plagued by power shortages, had more than 20 gigawatts of installed gas generating capacity, most not being used. The reason was the cost of imported LNG, which far exceeded the cost of coal; and even though LNG prices had been dropping that year, the utilities had no prospect of recovering the cost (13). It seems that India’s politicians like to provide gas below cost or for free to their constituents.(14) 

The outlook for growth of India’s LKNG imports seems dismal in the short-term and murky in the long-term. In a paper presumably from 2011, Dr. A. K. Balyan, CEO of Indian LNG trader Petronet, predicted that by 2020 India would be the world’s 3rd largest LNG importer, since regasification capacity was planned to rise from 13.5 Mtpa to 47.5 Mtpa in 2015/16.(15) 

But as we know, the regasification capacity of import terminals is a poor indicator of demand; besides, in 2015 India imported less than 17 Mtpa. Nevertheless, another recent report predicted imports to grow to 81.1 Mtpa by 2025 (16). That is far more than even Platt’s predicted, and so far reality has not even been close to forecasts. Related: Oil Back On Track As Markets Dismiss Doha

In December 2015 we were told: ‘The ‘Golden Age of Gas’ Flames Out’. Noel Tomnay, head of global gas research at WoodMac, was describing the continuing slide of LNG prices as ‘a train wreck happening in slow motion’:

Part of the reason is that Asians are turning to another, cheaper fuel source: coal. Power companies in India and elsewhere in Asia are turning back to coal because it’s cheap and domestically sourced. With local coal, there are no huge import bills [for LNG]. Asian power companies are building more than 500 coal-fired power plants this year alone. And more than a thousand are on the drawing board. . . .  Many energy forecasters, including WoodMac, see LNG prices falling below $6 per million Btus, and perhaps as low as $4 per million Btus within a few years.That would lead to some LNG exporters in both the U.S. and Australia shutting down their operations because the price would be below their cash cost. . . . Ironic, isn’t it? The biggest casualty of the war on coal may be the once up and coming LNG industry in the United States.(17) 

Mr. Tomnay may have put his finger on a classic example of government interference producing unintended consequences. The Obama administration launched a war against coal and for LNG exports, which would solve America’s political problems with Russia.

But as the American coal business started circling in the toilet, it threw out a lifeline: lower prices! And some energy buyers picked up on it by buying coal, at the expense of LNG.

Added Mr. Tomnay, hopefully: ‘The global LNG market does not need all this LNG at the pace proposed. As companies confront this reality, a raft of project postponements will follow.’(18) 

Either that or, as one commentator said: ‘Some of these investors are going to get burned.’ (19) If they let themselves be talked into investing in an export project with low-quality sales contracts or no contracts, yes. But I don’t know of such a thing is possible, since most people with millions to invest are not mentally deficient. Moreover, one key criterion applied by the FERC, which has the biggest clout in the LNG terminal approval process, is ‘public need’. Proof of ‘public need’ consists of signed long-term delivery or liquefaction contracts. Personally I don’t find the FERC’s logic irresistible, but it is what it is.

Recent proof of the absence of ‘public need’ can be found in both Australia and the U.S. Woodside Petroleum took a $1.1 billion (Australian) write-off on its share of the postponed but likely abandoned Browse LNG terminal project. This greatly reduced Woodside’s profits, ‘with the company consequently reducing its dividend.’ (20) I have already mentioned the postponement of the fully approved Lake Charles terminal in Louisiana.

Another example of a plan without contracts is the Jordan Cove terminal for Coos Bay, Oregon. Jordan Cove, a $7 or $8 billion greenfield project, has been promoted by Veresen, a Canadian operator of pipelines, power and gas facilities with a market cap of $2.2 billion. So far it has spent two or three hundred million on the convoluted approval process, all while promising to show customer contracts that turned out to be mere ‘Heads of Agreement’, which carry no legal obligations. After a spurt of market excitement over the approval of some of Jordan Cove’s permits, Veresen’s stock (TSX:VSN) has not done well, and on March 11 the FERC, citing Jordan Cove’s obvious inability to show contracts, denied its application because the needed 232-mile pipeline would have caused far more harm to local landowners than its prospects justified. That harm would be caused by the use of eminent domain, which the FERC’s approval would have granted Veresen.

Because LNG buyers are increasingly preferring short-term contracts, if they want contracts at all, the LNG market is expected to increasingly deal in spot cargoes, not long-term contracts; and even those are no longer safe. Last November, for instance, it was reported that one-third of Qatar's export LNG capacity remained unsold. Petronet, India’s LNG importer, had been buying spot cargoes elsewhere because it was saving so much money that it was willing to risk penalties for only buying 70 percent of the LNG called for by its 25-year contracts with Qatar (21). And in China, three buyers have switched to selling LNG cargoes that they had contracted for:

An example is Sinopec, the dominant buyer for Origin Energy's Australia Pacific LNG venture, which is on the cusp of starting production. It is reported to be offering to resell cargoes it has signed up to buy from the Queensland plant.

That means about 70 million tonnes a year of LNG still needs a buyer, which will weigh on the oversupplied Asian market potentially through to the mid-2020s . . . [LNG consultant] Dr Fesharaki describes those holding the contracts as ‘desperate sellers’ that will provide stiff competition for producers seeking customers for new projects.(22) Related: A Lasting Solution To Low Oil Prices

All this may explain why lately, experts worried about the LNG glut are using language as dramatic as the IEA’s back in 2012, about the gas market’s ‘Golden Age’ – but this time to warn of a ‘Dark Age’. Dr. Fesharaki himself has been predicting ‘blood on the battlefield’:

Very bad things will happen in the next two or three years.

In this market, something has to give.

Until you get to the late 2020s you won’t have any kind of supply issues.(23)

By ‘supply issues’ I take him to mean that the developing oversupply will last until the ‘late 2020s’, which must mean 2028 or 2029. It sounds as if Dr. Fesharaki and I are on the same page.

Dr. Fesharaki revealed another big problem that has received little attention, but should. The prevailing assumption about liquefaction and sales contracts has been that they would be between the terminal owner and an overseas gas user. But it turns out that most contracts (including 60 percent of the volume under construction in the U.S.) are not with end users, but with LNG traders who would act as intermediaries for terminals looking for buyers. ‘That would then be dumped on the spot market, leading to a substantial fall in world prices.’ (24)

The other day market analysts at Goldman Sachs put it well:

The struggle to create sufficient demand for LNG shows that energy policies have largely failed to deliver the promised Golden Age of gas.(25)

1. ‘Japan LNG demand expected to fall by 2020 on nuclear restarts, renewables,’ Platts 15 December 2015; ‘Japan’s LNG demand falls substantially’’ OilPrice Intel, February 19, 2016.

2. ‘Japan LNG demand expected to fall by 2020 on nuclear restarts, renewables,’ Platts, 15 December 2015.

3. Philip Weems and Monica Hwang: ‘The Top 10 Questions Facing the LNG Industry in 2016’, King & Spalding Energy Law Exchange, January 12, 2016.

4. ‘JPMorgan paints bleak picture of global gas market in client note,’ Reuters Oct 6, 2015; http://www.reuters.com/article/us-global-gas-lng-j-p-morgan-idUSKCN0S00SF20151006

5. ‘China, Middle East to be New Gas-Guzzlers by 2035’, Bloomberg, Nov. 12, 2015.

6. ‘China’s LNG Demand Forecast Raised by 48% on Growth’, Bloomberg Business, July 26, 2010.

7. ‘NEWS – China gas squeeze; demand may fall as supply ramps up’, and ‘Only the fittest will survive’, ABC News (Australia) 30 Nov 2014.

8. ‘China’s weak natural gas demand cuts into LNG imports’, ICIS, 7 October 2015; ‘Chinese LNG demand falls for the first time on record’, ABC NEWS (Australia), 4 February 2016.

9. ‘The Uncertain Demand of LNG & Natural Gas in China & Asia’, China LNG International Summit, March 2015; ‘Chinese LNG demand falls for the first time on record’, ABC NEWS (Australia), 4 February 2016.

10. ‘China’s Natural Gas Demand Feels the heat from Economic Slowdown’, Rigzone, February 12, 2016.s

11. ‘India’s natural gas demand to double to 516.97 mil cu m/day by 2021-22: Report’, Platts 29 April 2014. The article gave all the numbers in millions of cubic meters: 44.6 Mm3 a day in 2012-13, 143 Mm3 a day in 2016-17 and 214 Mm3 in 2029-30. One m3 is .4049 tons, so I converted the Mm3 numbers to Mtpa by first multiplying the m3 per day by 365, and next multiplying that number by .405 to obtain Mtpa. The amounts cited in the ‘India LNG Market Forecast and Opportunities, 2025’ were 64 Mm3 a day in 2015, which translates to 16.9 Mtpa. At the 2010 starting point the daily cubic meter figure was 33.7, which was 8.92 Mtpa.

12. ‘Unlocking the Indian LNG Market’, A Multi-Client Study, Poten & Partners, 2015.

13. http://www.iea.org/newsroomandevents/pressreleases/2015/june/despite-decline-in-oil-prices-natural-gas-demand-outlook-revised-down.html

14. ‘Why Energy Will Determine India's Future’, Stratfor Analysis, April 8, 2016.

15. ‘Meeting Demand Challenges of an Emerging LNG Market: India,’ Dr. A. K. Balyan, MD, CEO of Petronet LNG Limited, India; undated, but the contents suggests 2011.

16. ‘Demand for LNG in India to Grow at around 17% until 2025. Press Release, TechSci Research, January 2016.

17. ‘The ‘Golden Age of Gas’ Flames Out,’ Wall Street Daily, December 7, 2015.

18. Joseph Markman, ‘Projects’’ Progress Could Mena a World Awash in LNG’, E&P Mag, September 8, 2015.

19. ‘Is the World of LNG going Crazy,’ abarrelfull, 14 August 2014.

20. ‘LNG oversupply could lead to ‘blood on the battlefield’, Business News (Australia) February 26, 2016.

21. ‘LNG Golden Promise Fading for Goldman on Wave of Oversupply’, Bloomberg Business, November 4, 2015.

22. ‘Toil ahead for oil, but expect double trouble for LNG’, Sydney Morning Herald – Business Day, December 7, 2015.

23. ‘LNG oversupply could lead to ‘blood on the battlefield’, Business News (Australia) February 26, 2016.

24. ‘LNG oversupply could lead to ‘blood on the battlefield’, Business News (Australia) February 26, 2016.

25. ‘LNG Golden Promise Fading for Goldman on Wave of Oversupply’, Bloomberg Business, November 4, 2015.

By Wim de Vriend for Oilprice.com

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