LNG Trumped

Image via Wikipedia

The burst of enthusiasm for shale gas could put LNG on the sidelines of global gas trade

This article appears in the October 2010 issue of Oilweek

By Peter McKenzie-Brown

If you want to understand the performance of global natural gas markets in the next few years, think hockey. On one side the team captain is liquefied natural gas (LNG); on the other natural gas from shale reservoirs (“shale gas”).

The matches are serious, but they are also friendly. Each side is a team of rivals. The squads frequently swap players in and out, but they can play nail-biting games.

Robin Mann’s description of an annual CBM conference in Asia calls the game during two days of play. The first day of the Singapore conference, the president of AJM Petroleum Consultants says, the dominant theme was that “if there is a lot of shale gas development in India, Europe and China, there will be no need for much LNG project development.”

Shale Gas one; LNG zip.

On the second day, however, “the speakers suggested that new LNG projects will be needed no matter how much shale gas is developed in those countries. LNG development might not be as dynamic as people had thought it would be, but the projects now built or on the books to be built will remain viable.”

Game tied.

He cautions, though, that “In the end price will be the deciding factor.” Of course, everything from geopolitics to economics can influence price. This is the recurring theme in the competition between LNG and shale gas.
.
Three Sources of Gas
From the perspective of North American producers, the future of three gas sources (not two) is of interest. The first is the wild success of shale gas production in the US and Canada. The shale gas revolution, as it is called, is largely the result of rapid innovation in such down-hole technologies as horizontal drilling, better bit design, coil tubing, down-hole motors, geo-steering, microseismic, measurement-while-drilling tools and more powerful fraccing systems. It has truly been a revolutionary development.

The second is the evolution of a global market for liquefied natural gas. This development has been decades in the making, and it has eliminated the need for pipelines to tie stranded gas into the world’s industrial markets. To cite the extreme example, Qatar is developing liquefaction facilities for an offshore reservoir with more than a quadrillion cubic feet of proved reserves, and it will be able to deliver that gas around the world for a century or more.
.
The gas industry’s third area of interest lies in the huge conventional gas reserves in Alaska and the Northwest Territories. While companies are proposing expensive pipeline systems to deliver those resources to southern markets, Mann doubts that those proposals will go ahead in the foreseeable future. “Because of the development of shale gas formations like the Montney and Horn River and other with great potential right next to infrastructure and right next to pipelines, and with our existing conventional gas and our exports to the United States going down daily, we have more than enough (gas) for our own (use) so why is it important to build these pipelines? Why are we worrying about anything north of Alberta and BC?” asks Mann.

“Their costs keep going up and up and up, and economics will trump any national sovereignty argument for the Canadian pipeline. Maybe the best way is to develop LNG facilities in the north, but what will the economics of that kind of project be? Will the price of LNG justify building facilities up there? Certainly at the Singapore conference there was no strong feeling that there would be much in the way of LNG exports from North America, apart from a few small projects” like the proposed LNG terminal in Kitimat, BC. The only really positive argument for developing LNG facilities is that the many existing receiver terminals in the world offer a lot of flexibility. Given a Northwest Passage free of ice, you could take Arctic LNG anywhere – if the price were right.
.
Arctic Gas Pipelines: benched.
.
International sketches
While Robin Mann acknowledges the large potential for shale gas development in Asia, especially in China and India, he is sceptical that this will happen in the near term. “North America’s shale gas sector is advanced, it’s more of a mature industry” he says, sketching out the situation around the world. “Europe is in its infancy. In Asia it isn’t even that far – it’s in its beginning stages. People have barely gone beyond looking at resource potential. The idea of unconventional gas in Australia, China, India and Indonesia is still CBM” (coal bed methane) – a resource the North American industry is not heavily investing in anymore. “Europe is more interested in shale gas because they don’t have much CBM.”

One problem those countries face in developing a shale gas industry is “getting the hardware needed to properly develop the resource – getting the right equipment to the right spot and (having) the expertise and manpower to get things developed. That’s why CBM is still on the books in those regions. To manage in the CBM world you don’t need (heavy-duty) frac equipment or (specialized) manpower.”

Here is the kind of problem he is talking about. Huge fraccing jobs for shale gas development in north-eastern B.C. require a great deal of logistical support. Each horizontal hole can require 2,000 to 3,000 tonnes of fine-grained sand as a propping agent. To take on one such project may require a 40-member crew and 20 or more hydraulic compression systems mounted on huge fraccing trucks. This equipment isn’t widely available outside North America, and there are gas-bearing shales around the world that are remote from the kind of sand quarries needed.

Moreover, a great deal of water is required. While the water commonly comes from deep formations, a typical shale gas fraccing job requires a large water storage pit in addition to a string of high-volume steel tanks. According to Dave Russum, an AJM vice president who also attended the Singapore conference, “in India and Australia they are drilling their first holes into shale just to gather information. They aren’t even into pilot projects yet.” Given those realities, Mann concludes that shale gas will not have a large impact on LNG development – at least not initially
.
Geopolitics and the local community
As a domestic source of supply, shale gas is an attractive alternative to imports. For the United States, which has huge trade deficits, it slows down the haemorrhage of US dollars. For Europe it offers a geopolitically smart alternative to Russian supply. Also, governments want this kind of development because it contributes to security of supply
.
In recent years Russia has turned off the taps a couple of times because of disputes with Ukraine over payment. As collateral damage, countries in the European Union were temporarily cut off, too. It is therefore ironic that the best shale gas prospects in the European Union are in the north – especially Poland, Ukraine’s neighbour. In northern Europe, according to Mann, “you can get access to enough land to make a viable shale gas project.” In more developed and densely populated southern parts of the union, this is much harder.

As Europe develops shale gas, geopolitics is again likely to enter the fray compliments of the Russian bear. “Are the Russians just going to sit by and let Poland and northern Europe develop natural gas so they can turn off the taps from Russia?” asks Mann. “I don’t think so. They could retaliate with price, and make shale gas uneconomic.”

So could LNG producers. In fact, rather than shale gas driving LNG out of global markets, the exact opposite could take place, with LNG putting the screws to shale gas development irrespective of its geopolitical and trade balance advantages. Qatar, you will recall, has huge reserves that it can liquefy and deliver cheaply, causing international gas prices to crater and rendering some shale gas projects uneconomic.

Yemen and other exporters could do the same. According to Dave Russum, “It wouldn’t take much of a gas surplus on the oceans to really drop the price of gas in many markets. Although (shale gas) reservoirs can be prolific, gas from shale is not cheap, and whether production is sustainable over time is a real question.”

In addition to the prospect of price competition, shale gas development is likely to face environmental and population density issues in Europe and Asia. Environmental concern is likely to be most intense in Europe, and to echo concerns already being expressed in a number of places in the US. Will fraccing contaminate groundwater reservoirs? Are the chemicals used in development safe? Will shale gas production lead to unintended consequences of the undesirable kind?

The matter of population density ranges from critical in India and coastal China to highly significant in much of the southern states in the European Union, where the industry can’t get access to enough land to develop a viable shale gas project. Shale gas development requires drilling many wells. Multilateral horizontal drilling and fraccing from a single pad can take weeks and even months to complete. These drilling pads are large and operations can be dirty and noisy. Moreover, in densely populated countries good drilling prospects can be covered over with villages, small farming operations, markets and industrial operations. This inconvenient truth is hard to ignore

Game plans
Mann’s assessment of the situation involves pretty raw political analysis of the situation. “In China the communist government would just do it,” he speculates. The country has almost the same landmass as Canada, yet the population is mostly located along a relatively thin band along the east coast. There are many prospective sedimentary basins within the country, which is geologically more like the United States than Canada. “The ones that are now being looked at for shale gas are out in a desert in the western China, where there is virtually a zero population problem and access is not a problem either. None of these projects are commercial yet, they are just at the stages of looking at resource potential, doing some tests, seeing whether they are viable and then going down the road” to development.

Having said that, he recalls an argument from Singapore that “Even if China developed shale gas at the same rate and volume as North America did over the past ten years they would still require LNG because (in ten years) shale gas would meet only around 15% of their total requirements.” That’s a compelling argument against the notion that shale gas will displace global LNG
.
Shale gas development is going to be difficult in most places except northern Europe, potentially China and eventually India. “In India, you do have British law covering land ownership so you do have land issues but you wouldn’t have the same environmental issues as you have in Europe. (Gas producers) could get (to viable projects) if they worked with the local population, most of whom have very low incomes. In much of Europe, where the amount people make on average is much higher and people have a much higher standard of living, it would likely be more difficult to work with local populations.”

Shale gas and LNG can coexist, but as team captains for the gas industry’s two big new hockey clubs there are many ways they can affect price and therefore development. Too much LNG on world markets could hinder development of shale gas in certain parts of the world. A great deal of shale gas development could hinder LNG development in others. But, says Mann, “Either thing could happen. It’s going to depend on geography, on what resources you have, on governments’ want to develop security of supply – a whole bunch of political things can get rolled up into that.”

“North America is a great example,” he concludes. “A few years ago we wanted to have LNG receiver terminals dotting the east coast, the southern coast and the west coast of North America. People didn’t want them. Then all of a sudden by some miracle we ended up with the shale gas revolution and we suddenly found we didn’t need them. So LNG – go away.”

For North America, at least, shale gas was the game changer. Shale Gas five; LNG one.

Losing The Arctic Edge

This article appears in the July 2008 issue of Oilweek.

Canada needs to move quickly to join international rivals exploiting the potential of the Arctic

By Peter McKenzie-Brown
Canada began to explore the far north for oil almost a century ago. In 1911 Jim Cornwall, a northern businessman, saw oil on the Mackenzie River and hired an Aboriginal named Karkesee to look for seepages. Karkesee found several. Later analysis showed the oil to be medium in gravity and low in sulphur.

Cornwall formed a syndicate with two Calgary businessmen and the group engaged T.O. Bosworth, a prominent petroleum geologist, to study the area. During his 1914 expedition, Bosworth staked three claims on behalf of his backers and reported enthusiastically on the area’s prospects. Ironically, given later events, Bosworth stressed that his supporters should take every effort to control pipeline transportation from the North to southern markets.

World War I put a halt to the group’s exploration plans, and by Armistice Day Imperial Oil owned Bosworth’s claims. The company began exploratory drilling along the Mackenzie in 1919, first drilling two salt water wells near Great Slave Lake. Farther down the Mackenzie, near Fort Norman, the third showed oil. Led by Ted Link, who later became Imperial's chief geologist, the crew drilled the successful well with a cable tool rig. Legend has it that Link chose the site by waving his arm and saying, “Drill anywhere around here.”

In August 1920, at a depth of about 1,240 metres, the world's most northerly oil well came in; Imperial put it on production the very same year. Although just south of the Arctic Circle, the Norman Wells field established Canada as the world’s undisputed leader in northern exploration and production, and she retained that title for more than 60 years. Led by Dome Petroleum and a series of attractive federal grants, the industry’s golden age of Arctic exploration in the 1960s and 70s delivered huge natural gas discoveries and a number of small oil finds.

Let’s fast forward to the present. In petroleum terms Canada has become a second-tier Arctic nation. The US, Norway and Russia are all Arctic producers. In recent years, Denmark has done some drilling off the eastern shore of Greenland. Canada is clearly the laggard. Despite skyrocketing oil and gas prices and the many successes of Canada’s golden age, exploration in our Arctic is almost at a standstill.

As if to rub our collective nose in it, Enbridge Inc. and Gaz Metro recently announced that their proposed Rabaska liquid natural gas terminal in Québec had found a secure source of LNG. The source will be Russian energy giant Gazprom, which will deliver cargoes from an Arctic facility in the Barents Sea due to begin deliveries in 2014. By the terms of the agreement, Gazprom and Gaz de France will become equity partners with the two Canadian companies in the $840-million regasification plant.

The Great Abandon: In a sobering presentation to the Canadian Society of Petroleum Geologists, Dave Russum (VP of geosciences for AJM Petroleum Consultants) made a compelling case that Canada has fallen behind its rivals in the development of Arctic oil and gas, and that she needs to catch up. Only five countries have claims to mineral rights in the Arctic – the others are the United States, Russia, Norway and Denmark. 

The United States became a major oil producer at Prudhoe Bay in 1977, and continues to produce from that supergiant field. Last year Norway began producing LNG from its Snøhvit field. Russia, which already has Arctic production in Siberia, will begin producing from Shtokman in the Barents Sea in 2014. And Canada?

This country’s most northerly oil production still comes from the 88-year-old Norman Wells field. A tiny amount of gas production serves a few small towns and villages in the Mackenzie Delta, but this service has as much to do with local development as petroleum economics. When energy prices crashed and Dome Petroleum collapsed in the mid-1980s, the industry decamped from Canada’s Arctic with great abandon. Why? Several concerns have discouraged Arctic exploration for a generation. The main issue is geology. “In the Arctic most of the expected resources are gas,” says Russum, “and they are devilishly expensive to develop. Except for Prudhoe Bay, (the Arctic basins) have pretty much been gas plays, and we expect about 75% of the resource there to be gas. Oil has been the prize. If you couldn’t find oil, you didn’t want to develop there.”

During the last two decades the expense and difficulty of Arctic development was worsened by surplus natural gas supplies in North America. The situation has greatly changed in recent years, says the executive director of the Arctic Institute of North America. Benoît Beauchamp agrees that the Arctic is gas-prone, but says this is no longer an obstacle to development. In recent years natural gas has become recognized as a premium source of energy, although it generally serves continental rather than global markets.

This continental character raises the spectre of Canada’s tradition of bitter disputes over northern pipelines. It now appears that the joint federal and provincial panel evaluating the social and environmental impacts of the present Mackenzie Valley Pipeline proposal – this one put forward by Imperial Oil in 2004 – will delay the environmental decision on the $16.2-billion project by at least another year. This adds to a string of such problems that date back to the mid-1970s.

Like previous proposals, Imperial’s pipeline project has been dogged by setbacks. The company has yet to resolve Aboriginal land access issues or come to an agreement with Ottawa on how to finance the project. According to Beauchamp, construction of this pipeline is critical for renewed exploration in the North. “The announcement of the Mackenzie Valley Pipeline will be the gunshot that starts the race up there. Then there will be a bonanza.”

Beauchamp is more sanguine about Canada’s place in the North than Russum. “It’s true that there hasn’t been much drilling in the Arctic Islands since the 70s, but there is a great deal of interest now in the Mackenzie Delta – no drilling, but seismic and other preliminary work. A few years ago an ExxonMobil/Imperial partnership acquired a large land parcel in the shallow Beaufort, on an extension of the Delta.

That’s likely an oil prospect, and three parcels adjacent to that property will be up for grabs in June. It will be extremely interesting to see how strong the interest is.” As it happened, BP acquired one of those properties for $1.2 billion. The other two went for a mere $10 million combined. Beauchamp expects an Arctic boom. “Interest in the Arctic is mounting. There are very few places left in the world with the potential of the Arctic, and companies need to develop reserves in order to grow. Canada is likely to be a focus because we are a stable country. Corruption is not a problem here, unlike Russia. We aren’t likely to abrogate signed agreements, as the Russians did at Sakhalin Island, for example. The problems in Canada are mostly related to the approval process.

Canada Rules! Russum sees the issue as being somewhat more urgent. “For security, sovereignty and economic reasons, Canada should take an active role in Arctic development.” That’s an opinion shared by Federal Natural Resources Minister, Gary Lunn, who met in May with leaders from the United States, Russia, Norway and Denmark to sort out how best to deal with conflicting sovereignty claims in the Arctic, including Canada’s.

“It is critically important that it’s under our sovereign control so that we set the parameters for the environment and that we make the decisions whether or not even to allow exploration,” Lund said on the eve of the meetings, which were held in Ilulissat, Greenland. “We are going up to reaffirm our commitment on defending and protecting our sovereignty in the Arctic.” On an immediate front, Russum notes that depletion rates have been accelerating in all of Canada’s gas-producing regions. “In every area, particularly those in Alberta, we have seen declines. This is not particularly surprising, given the drop-off in drilling,” but it is an important reason to move back into the Arctic. “Estimates suggest that there might be 10 billion barrels of oil and 181 trillion cubic feet of gas in the Canadian Arctic. With high production rates depleting gas reserves across Canada, we need to be considering all opportunities.”

“Conventional and unconventional gas in southern Canada will not satisfy future North American needs,” he adds. “We have to recognize the need to develop a wide range of energy sources.” Energy is the vital commodity, he says; it equals power. In a rather unCanadian way, he argues that “countries with abundant energy (like Canada?) will control the world. Net consumer countries (like the United States?) will be at the mercy of world economics and politics.”

In the case of natural gas, the Arctic will soon become a particularly important source of supply. According to Russum, a quarter of the world’s undiscovered gas is likely to be there. Looking at the entire transpolar region, 26 geological basins make up the Arctic. Of those, 21 have had some exploration activity, and explorers have found oil or gas in ten. There is commercial production in four basins (two in Russia, one in Norway and Alaska’s North Slope). Two - Canada’s Cameron Island and the Mackenzie Delta – have been the source of minor production volumes. Given the small number of wells drilled and the Arctic’s challenges to development, these results are impressive.

Imagination Beckons: Given the prospects for huge Arctic gas discoveries and the controversy over gas pipelines to the large North American markets – in addition to the Mackenzie Valley line, there have been disputes for 30 years over a line from Prudhoe Bay through the Yukon into the Alberta network – Russum argues that Canada should consider LNG production from the Arctic. “Although there are big problems with sea ice in the winter, these are problems the Norwegians have solved” he says, “and which the Russians obviously believe are solvable. Certainly one ‘benefit’ of global warming is ice shrinkage, which means more open water in the Arctic and a more easily passable Northwest Passage.”

Another advantage of LNG is that producers have more market options – especially since “world demand is now driving gas movement.” This point harks back to the geographical maps that Dome Petroleum made famous in the early 1980s. As those maps pointed out, the Beaufort Sea is roughly in the geographic centre of the developed world. If sea ice were no problem, LNG tankers loading up in the Arctic would find themselves about equidistant from London, New York, San Francisco and Seoul.

Destination decisions for cargoes from that region could be based purely on best price; the calculation of transportation costs would be largely redundant. By contrast, traditional pipelines have a number of drawbacks quite apart from political wrangling. One of those is greater terrorist risk. Others include long timelines, the enormous capital required and the fixed destination. Pipelines from stranded resources don’t have much market flexibility.

Whether developed through traditional pipelines or LNG or both, Russum believes it needs to be done. “In the Canadian Arctic, the long-term costs of frontier gas production are going to be similar to the costs of producing unconventional gas – shale gas, coal bed methane – in large volumes. Imagination will be required for development, and we will need to apply out-of-the-box thinking. If we do this, there is no reason our Arctic production can’t be economically viable in the global market place.”

The resources are there and the technology is available. The world’s hydrocarbon markets have never been stronger. According to Russum, “We used to be the leader in exploring the Arctic, along with the Americans. Now we have a real opportunity. We have to move beyond discussing development. We have to pursue it in an economic, environmentally sensitive and socially responsible manner.” He pauses for effect. “We only have four competitors. Three of them have already proved that Arctic development is viable in this environment.”

The Gas Storage Cycle

Chart #1: This chart compares the amount of natural gas in storage (usually underground reservoirs) in the lower 48 states, over time. The shaded area indicates the range between the historical minimum and maximum values for the weekly series from 2003 through 2007. The pattern is normal, of course. Like squirrels with their nuts, we store natural gas when it’s plentiful and consume it when we need it most.

By Peter McKenzie-Brown

Last fall, the amount of natural gas in storage in the United States set a new five-year record. Since then it has plummeted, and it has dropped more dramatically than at any other time in the last 15 years. The severity of the drop is obscured by the impact of Hurricane Katrina, which distorted the cycle several years ago. As my correspondent Paul Stallion explains,

looking at the numbers you will notice that this winter approximately 30 per cent more natural gas was drawn down from storage than for any other year in the past decade and a half. This fact is somewhat hidden in the chart of seasonal highs and lows, because usage nevertheless stayed within the 5-year average. What isn't mentioned is that the short-term (5-year) average itself is skewed by the hurricane which devastated New Orleans (which is also the reason gas in storage in the last few years could so easily remain so close to the top of that average). Chart #1 is therefore misleading, in terms of how dramatic the recent drawdown has been - which is why no one has yet mentioned it...

The chart also illustrates a key trend. Over three winters, there have been progressively lower supplies as the winter ended. This post suggests that this year less gas in storage is likely to combine with other factors to drive natural gas prices much, much higher than you might expect.

The volumes of gas in storage vary every year. During warm winters we consume less, for example, and during cold winters, more. Sometimes gas production surges, as it has in the south-central United States (Texas, Oklahoma, Louisiana and Arkansas) for the last few years. The combination of warmer winters in ‘06 and ‘07 plus growing supplies help explain the high storage levels of the last few years. The relatively mild summers of the last few years have been another factor. When it’s really hot, you use a lot of gas to generate electricity for air conditioning. Also, last summer liquefied natural gas (LNG) from overseas was cheap, and the US brought in large volumes by the tanker load for storage.

In the last six months, that situation has reversed. This winter was unusually cold in eastern North America, so we have consumed a lot more gas than usual. Also, prices for LNG are now much higher in Europe and East Asia than in the US, so that supply is going elsewhere: US imports have dropped from 4 billion cubic feet (BCF) per day last July to less than half a BCF today. And while the surge in south-central gas supply continues - mostly in Texas - production is in decline everywhere else in North America except Alaska, which isn't connected to any serious markets.

Now, turn your mind to the following chart. In my view, it says important things about the state of natural gas.

Chart #2: The purple line shows NYMEX natural gas prices during the last decade; the brown line shows the performance of the natural gas index (XNG) on the Amex. The XNG is a weighted share price index of the 15 largest players in the US gas business.

In the first half of the last decade, gas prices averaged perhaps $3.50 per thousand cubic feet. In the last five years, they have been around $7. A big increase, but compared to the price of oil, which has risen by a factor of five, not a big deal.

The odd part about chart #2 begins in the winter of 2002. Since that time natural gas prices have had lots of peaks and valleys, but the XNG has climbed steadily. My friend Carlo Magnifico, who provided the chart, puts it like this:

There’s been a steady accumulation of gas shares since 2002. The gas index has not had any really painful corrections like the price of gas has. It’s as though the price of gas doesn’t really factor into the price of gas stocks. Someone knows something. Gassy stocks are the place to be.

Last December this column anticipated the recent run-up in natural gas prices, and the balance of this article supports that call. We are now in a commodity bull market. During those cycles, commodity stocks rise while industrial stocks drop. In another article, I called this the great divergence.

Before I summarize the case for natural gas prices continuing to rise, a comment on one likely cause of this commodity bull. Harvard economics professor Jeffrey Frankel suggested in his blog that a decrease in real interest rates (“real” rates exclude inflation) increases the demand for storable commodities. In his thought-provoking comment, he writes,

If strong economic growth is not the explanation for the large increases since 2001 in prices of virtually all mineral and agricultural commodities, then what is? One wouldn’t want to try to reduce commodity markets to a single factor, nor to claim proof of any theory by a single data point. Nevertheless, the developments of the last six months provided added support for a theory I have long favored: real interest rates are an important determinant of real commodity prices. High interest rates reduce the demand for storable commodities, or increase the supply, through a variety of channels:

• by increasing the incentive for extraction today rather than tomorrow (think of the rates at which oil is pumped, gold mined, forests logged, or livestock herds culled)
• by decreasing firms’ desire to carry inventories (think of oil inventories held in tanks)
• by encouraging speculators to shift out of spot commodity contracts, and into treasury bills.

A decrease in real interest rates has the opposite effect, lowering the cost of carrying inventories, and raising commodity prices, as happened in the 1970s, and again during 2001-2004. It’s the original “carry trade.”

Professor Frankel makes clear that this is only one factor, but I think it's a point worth noting. Keeping that idea in mind, here is the case for a continuing bull market in natural gas prices. Such a market is probably the event that the steady upward performance of the XNG (Chart #2) is anticipating.

1. We are in a bull market for commodities (partly for the reasons Frankel suggested), and a rising tide raises all ships.

2. The gas industry must put enough gas in storage to meet demand next year, and the gas needed will be much greater than it was a year ago. As Chart #1 shows, volumes in storage are now well below last year’s volume, so demand will be much stronger. More to the point, this spreadsheet shows that this winter 30 per cent more natural gas was drawn down from storage than for any other year in the past decade and a half. As Paul Stallion's comments explained earlier, Hurricane Katrina's impact on supply obscures this statistic because it so dramatically dropped the bottom end of the 5-year average.

3. Gas production has been increasing in the south-central US. However, it is in decline elsewhere in the lower 48 states. Also, imports from Canada are unlikely ever to rise to the peak levels of a few years ago - partly because of declining production, but also because of greater domestic demand in Alberta and elsewhere.

4. Prices for LNG have more than doubled since last summer. Some countries are willing to pay $20 per thousand cubic feet, compared to the $9 and change that Americans now pay. This means we are far less likely to see low-cost LNG unloaded at American gasification terminals in the near future. Cargoes will continue to be redirected to higher price destinations, like East Asia.

5. The last factor to consider is the weather - to a large extent an imponderable, but something meteorologists are getting better at forecasting. The US National Weather Service predicts a hotter-than-normal summer this year. On a related note, the usually accurate Colorado State University forecast team "expects an above-average Atlantic hurricane season and may raise its prediction of 13 tropical storms and seven hurricanes when it updates its outlook" this week, according to Reuters.

Either of these factors could have an additional big impact on gas supply. High temperatures mean more need for air conditioning, and therefore more gas demand to fuel electrical generation. Hurricanes could mean shut-in production in the Gulf and in Texas and Louisiana.
Forecasting prices is a mug's game, and I will stay out of that. But I think natural gas prices are going way up from where they are today. To hedge against it, I put a little money here.

Note: Just two days after I wrote this came news of a major natural gas outage at the Independence Hub in the Gulf of Mexico. For several weeks, this will take one BCF per day out of production, worsening the situation described above.