Australia revisits transnational natural gas pipeline

Platts' "The Barrel" blog has an interesting post looking at the history of natural gas pipeline proposals in Asutralia, including the last plan to pipe gas from the Northern Territory to the eastern states (which face an impending shortfall now most of the coal seam gas being extracted is destined to be sent offshore in the form of LNG), which the gas potentially coming from both offshore fields and shale gas projects in the dead heart - Australia revisits transnational gas pipeline.

Australia is no stranger to the idea of transnational or even international pipelines when it comes to solving the vexed issue of getting enough gas to its eastern seaboard, home to its biggest cities.

Australia currently has two separate gas pipeline networks in the west and east of the country which supply markets of around 1 Bcf/day and 1.6 Bcf/d respectively. A much smaller, also separate, network in central Australia services the Northern Territory capital of Darwin. ...

The latest proposal for a transnational interconnection between Australia’s pipeline networks was initially aired in recent months by former Chief Minister of the Northern Territory Terry Mills, as part of his efforts to secure the future of Rio Tinto’s alumina refinery at Gove. In February, just before being ousted in a party room coup, Mills secured a deal under which Gove would be supplied with gas from Eni’s Blacktip offshore field, heralding a project which would include the construction of a A$500 million pipeline to the plant. ...

That call has now been taken up by Australia’s largest pipeline operator APA Group, manager of 14,120 km of pipeline infrastructure. One of APA’s assets is the 1,600 km Amadeus Basin to Darwin gas pipeline, which was the world’s third-longest when it was completed in 1986 at a cost of just A$380 million. ...

A raft of international oil and gas industry heavyweights have taken a foothold in northern and central Australia’s nascent shale sector over the past few years. Companies including Chevron, ConocoPhillips, Statoil, Total and BG Group have secured farm-in agreements and pledged investments of more than $1.55 billion in Australian shale, according to the US Energy Information Administration. The EIA has estimated that Australia has 437 Tcf of technically recoverable shale gas reserves, ranking the country sixth highest in the world.

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HUGE CAPEX = FREE CASH FLOW ? NOT IN SHALES

Energy Policy Forum has an interesting article by Deborah Lawrence Rogers about the financials of the companies frantically scraping the bottom of the barrel in the Bakken - HUGE CAPEX = FREE CASH FLOW? NOT IN SHALES.

Taking a universe of 5 shale companies, some primarily with shale gas assets and others with shale oil, it is of note that there has been a significant deterioration of free cash flow since 2010. But what is even more interesting is that some of these companies are reporting that net income has been growing though free cash is falling.

Not wishing to bore everyone with an esoteric discussion of financial statements, it is of note that when a company shows a growth in net income with a concomitant deterioration of free cash flow, it may be an indicator that management is taking aggressive steps to boost earnings artificially. Not always. But possibly.

So how much deterioration has there been in free cash flow? It is impressive.

When you adjust the figures to include capital expenditure (and dividends where appropriate), their free cash available is negative. Significantly negative.

This is highly problematic because if a company cannot generate cash from operations then it has to go outside and get the monies through borrowings or equity offerings. In other words, debt or dilution for investors.

Free cash flow of Continental Resources, a big player in the Bakken, has dropped from ($430M) to ($2.4B) since 2010, all of it negative. And Continental is not the only one. Devon Energy’s free cash flow has dropped from ($1.2B) to a significant ($3.5B) over the same time frame. Range Resources, who are drilling primarily in the Marcellus, booked a negative free cash flow of ($556M) in 2010 and this has deteriorated to ($1.0B). Kodiak Oil and Gas, another Bakken player, had negative free cash flow in 2010 of ($170M). It has now deteriorated to ($1.0B). Chesapeake is interesting because its free cash flow for 2012 ($3.3B) is now roughly equivalent to its level in 2010, ($3.4B). But over the last two years Chesapeake has liquidated approximately $13 billion in assets with no commensurate gain to free cash flow. Management still needs to move outside the company to generate cash to continue operations. And yet, shareholders have had their underlying assets disappear to the tune of $13B to pay down debt.

Clearly there is a pattern here of severe deterioration. But that is not all. CAPEX has exploded during this time which means that companies have spent enormous sums of money drilling wells that are not providing enough cash to continue drilling operations on their own. Not even close. For instance, Continental’s CAPEX grew from $1.0B to $4.1B. Devon’s CAPEX grew from $6.4B to $8.2B. In total, these 5 companies spent approximately $56B in capital expenditure since 2010 while the free cash generated from this $56B spending spree is non-existent. In fact, it is worse than non-existent because it is alarmingly negative.

This is not sustainable. It could be argued that it is not even moral. It is a failed business model of epic proportion. While companies could make the argument at one time that this was a short term downtrend, that no longer holds water because this pattern is long term.

The most troubling aspect of this is that we are fast tracking exportation of this commodity in spite of the glaring financial anomalies. It is extraordinary that some members of Congress proclaim whole heartedly for fiscal responsibility while turning a blind eye to fiscal irresponsibility among their campaign donors and promoting exportation.

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The shale gas revolution: is it already over?

Ugo at Cassandra's Legacy has a post on the shale gas "revolution" (I always liked Suart Staniford's description of the boom as the "frantic scraping of the bottom of the barrel") - The shale gas revolution: is it already over?.

The production of natural gas in the US has not been increasing for about two years. Fitted with a Gaussian function, it shows a peak in the second half of 2012 and, from then on, a tendency to decline. Decoupled in its various components, the data show that shale gas production is still increasing, but not fast enough to compensate for the decline of conventional gas production.

Are we already seeing the end of the "shale gas revolution"? It is too early to say but, surely, these data agree with the viewpoint of those who had been seeing the whole story as a short lived financial bubble. (see, e.g., a recent series of statements by Arthur Berman)

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US shale boom starts to fade

The SMH has an article opining that prospects for US shale oil production are fading - US shale boom starts to fade.

For the past three years, the boom in the US shale oil industry has outstripped all expectations. Production surged far faster than any forecasts; drillers raced to secure space in new pipelines to get their crude to market. Now, at the periphery, that may be changing - at least for a while.

News from two of the country's less developed shale plays in Colorado and Ohio last week offer a reality check for the wave of euphoria that has washed across the industry. The stumbles mark a break from the past few years, when nearly every new project was an overnight success and output grew and grew.

On Thursday, Ohio, home to the Utica shale, finally released annual data on 2012 production that showed the state pumped less than 700,000 barrels of oil from its shale wells -- barely enough to fill a small oil tanker. North Dakota's Bakken shale pumps more than that every day. Even state officials said it the result was "lower than initially estimated."

The day before, NuStar Energy LP had said it would shelve a plan to reverse a pair of underused refined products pipelines to ship crude from Colorado's Niobrara shale oil play to Texas. It failed, twice, to garner enough commitments from potential customers to justify investing in the conversion. Neither development was a surprise to industry experts, and both were likely affected by extenuating circumstances.

A growing preference for rail shipments likely dimmed interest in long-term commitments to use NuStar's pipeline. Ohio's shale may yet offer up large volumes of liquid gas and condensate, if drillers can find new ways to coax it out.

Yet taken together they offered a sign that the flush of enthusiasm and rush of investment that piled into shale fields from one coast to the other has hit a curve. While the basic technologies of hydraulic fracturing and horizontal drilling was enough to coax an unexpected gusher of oil from shale rock in many regions, these more challenging seams may require incremental innovation to unlock.

Platts has an article boosting the prospects for the shale industry finding more plays like the Eagle Ford in Texas - Did the shale revolution already find its biggest oil field at the Eagle Ford?.

In case you didn’t catch it, investment house Credit Suisse had a wonderfully informative conference call for their clients last week on how they see the future of the shale revolution that has engulfed the oil patch in the last decade and become hyper-active especially in the last several years.

Among the bank’s conclusions: shale is a vital component of current US production which is growing at a huge clip — CS sees as much as 10 million b/d of US oil production in the next several years, up from 6.5 million b/d last year. CS also noted consistently improving well results from big plays such as the Permian Basin in West Texas and Bakken Shale in North Dakota.

Moreover, it’s not only the upstream that is exploding, but also companies that supply the technologies to eke out more oil in less time. Even ancillary services are exploding, such as technologies that can treat and dispose of water — a crucial component of well fracturing. And all this will require many billions of investment dollars into a shale economy still years away from the mature development stage.

But one other thing Credit Suisse said, which echoes the sentiments of many in the industry, was that it was “skeptical” a new large field on the order of the Eagle Ford Shale in South Texas would happen. The Eagle Ford is one of the most prolific shale fields which boasts an estimated 943,000 b/d of liquids production and is forecast to produce 1.6 million b/d by late 2018. Instead, Credit Suisse said existing areas with “stacked” pay targets — i.e., layered formations –are better bets right now. When you consider how far industry has come in the last five years alone, it seems almost reactionary to make such a statement. And Credit Suisse is far from alone in that view: many executives share it — even from top shale producers.

Five years ago, the Eagle Ford Shale hadn’t even been discovered, at least not officially. Although a few companies were out there quietly working the field, it was Petrohawk Energy that announced a gas find there in October, 2008. By that time, other shale fields had already been discovered — the Haynesville in Louisiana, a gas field; the Bakken oil field in North Dakota; and of course, the granddaddy of them all, the Barnett in North Texas which sparked the widespread move by operators to shale exploitation in the early 2000s, although the field’s first wells were drilled in the early 1980s.

The Oil Drum has a skeptical look at the endless treadmill of drilling that shale oil / gas extraction requires- Is the Typical NDIC Bakken Tight Oil Well a Sales Pitch?.

In this post I present the results from dynamic simulations using the typical tight oil well for the Bakken as recently presented by the North Dakota Industrial Commission (NDIC), together with the “2011 average” well as defined from actual production data from around 240 wells that were reported to have started producing from June through December 2011.

The use of the phrase “Typical Bakken Well” by NDIC as shown in Figure 01 is here believed to depict what is to be expected from the average tight oil well.

The results from the dynamic simulations show:

If the “Typical Bakken Well” is what NDIC recently has presented, total production from Bakken (the portion that lies in North Dakota) should have been around 1.1 Mb/d in February 2013.
Reported production from Bakken by NDIC as of February 2013 was 0.7 Mb/d.
Actual production data shows that the first year’s production for the average well in Bakken (North Dakota) presently is around 55% of the “Typical Bakken Well” presented by NDIC.
The results from the simulations anticipate a slowdown for the annual growth in oil production from Bakken (ND) through 2013 and 2014.

...

The production developments in Bakken and other tight oil plays are very much a function of monthly additions of producing wells, developments in well productivity, decline rates (for the growing population of “older” producing wells), development in costs, strategies deployed by the companies for development of their acreage, adequate infrastructure and not least the developments/expectations for the oil price.

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LNG exports from Canada and the US get closer

The SMH reports that LNG exports from North America are starting to look likely - the gas age is in full swing - US and Canada step on the gas.

JUST hours after the Canadian government approved its third export gas project, another US export gas project, this time in Texas, has moved closer to getting a green light. The approvals come as concern is mounting that a large rise in North American gas reserves on the back of the shale gas boom will undercut much of the optimism of Australia's gas exporters over projects being developed off Western Australia and in Queensland.

Australia is set to be one of the world's largest gas exporters in the next five years, although growth prospects beyond that are being hurt by the increase in export projects vying for approval in North America.

On Tuesday Shell won approval for a project it is promoting in British Columbia, on Canada's west coast, which includes PetroChina, Korean Gas and Mitsubishi Corp as shareholders. Both PetroChina and Mitsubishi are participants in export gas projects in Australia.

As well, the US Department of Energy granted Pangea LNG approval to begin exports from its south Texas project. Pangea has been authorised to export up to 8 million tonnes annually of liquefied natural gas for 25 years.

Shell, also, has joined another consortium planning to export gas from Georgia, in the US south.

The inability of large vessels to use the Panama Canal always meant that gas exports from the US could only be exported to Asia from the west coast and Alaska, but that will change from late 2015 when the canal's capacity rises after a $US5.5 billion ($A5.28 billion) expansion.

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BHP's Shale PR boom gathers pace

I speculated recently that some of the gushing press in Australia about the US shale gas boom was being driven by BHP. This weekend's SMH has a column which indicates this theory is spot on (as the author is transparent about who was feeding him information) - Shale boom gathers pace. I think the key takeaway from this one is that shale oil is uneconomic below $80 a barrel - so there is one (starting) floor price in the new age of unconventional oil.

MY TRIP to Texas as a guest of BHP and my subsequent talks in New York with economists, analysts and investment bankers in New York about America's shale oil and gas production boom meanwhile underlined that BHP Billiton got its biggest shale deal in the US right. The growing consensus on Wall Street is also that the US shale boom is a global economic and geopolitical game-changer.

BHP's first purchase of shale gas leases in Arkansas for $US4.6 billion was fully valued at the gas price of the day, and the $US2.84 billion write-down the group announced in August was arithmetically generated as US shale gas production soared, and US gas prices plunged.

The group's subsequent $US15 billion takeover of US group Petrohawk at 65 per cent premium to Petrohawk's market price could produce an asset valuation uplift this financial year that more than compensates for the first write-down.

BHP can still earn returns of more than 20 per cent by developing gas wells in Arkansas, but it is aiming instead to increase production of oil and other liquids that are roughly four times more valuable by 15 per cent in 2012-13 by redirecting the vast bulk of its $US4 billion shale capital expenditure budget to Petrohawk's oil and liquids-rich fields in Texas.

In New York, the big bulge-bracket banks are all doing their sums on the shale boom. One estimate of the value transfer from the rest of the world to the US is already $US900 million a day as US domestic production grows and imports fall. That's an amount equal to 2.2 per cent of raw GDP, but what the US does with the income windfall is the key, as it was here during the commodities boom. To the extent that the new income finances consumption of imports, for example, domestic benefits of the boom will be lower.

The US will certainly benefit from cheap domestic gas that will deliver cost benefits to heavy industries including petrochemical plants and power stations, but the horizontal drilling and rock-fracturing technology that is freeing up shale gas and oil will ultimately generate sweeping global changes.

Shale oil can be commercially exploited at oil prices as low as $US80 a barrel, and as shale oil volumes rise, oil price spikes in response to accelerating growth in demand that work to slow demand again will be much less frequent. Shale oil, in other words, is going to raise the maximum speed limit of the global economy. I will have more about the amazing shale boom and BHP's piece of it in coming columns.

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Fracking: A new dawn for misplaced optimism

The Independent has a jaundiced look at the shale gas boom in the US - Fracking: A new dawn for misplaced optimism.

You would think we were swimming in oil. The International Energy Agency's (IEA) latest World Energy Outlook forecasts that the United States will outstrip Saudi Arabia as the world's largest producer by 2017, becoming "all but self-sufficient in net terms" in energy production. While the "peak oil" pessimists are clearly wrong, so is a simplistic picture of fossil fuel abundance.

When the IEA predicts an increase in "oil production" from 84 million barrels a day in 2011 to 97 in 2035, it is talking about "natural gas liquids and unconventional sources", which includes a big reliance on "fracking" for shale gas. Conventional oil output will stay largely flat, or fall.

The IEA has been exposed before as having, under US pressure, artificially inflated official reserve figures. And now US energy consultants Ruud Weijermars and Crispian McCredie say there is strong "basis for reasonable doubts about the reliability and durability of US shale gas reserves". The New York Times found that state geologists, industry lawyers and market analysts privately questioned "whether companies are intentionally, and even illegally, overstating the productivity of their wells and the size of their reserves." And former UK chief government scientist Sir David King has concluded that the industry had overstated world oil reserves by about a third. In Nature, he dismissed notions that a shale gas boom would avert an energy crisis, noting that production at wells drops by as much as 90 per cent within the first year.

The rapid decline rates make shale gas distinctly unprofitable. Arthur Berman, a former Amoco petroleum geologist, cites the Eagle Ford shale, Texas, where the decline rate is so high that simply to keep production flat, they will have to drill "almost 1,000 wells" a year, requiring "about $10bn or $12bn a year just to replace supply". In all, "it starts to approach the amount of money needed to bail out the banking industry. Where is that money to come from?"

In September, the leader of the US shale gas revolution, Chesapeake Energy, sold $6.9bn of gas fields and pipelines to stave off collapse. Four months ago Exxon's CEO, Rex Tillerson, told a private meeting: "We're making no money. It's all in the red." The worst-case scenario is that several large oil companies at once face financial distress. Then, says Berman, "you may have a couple of big bankruptcies or takeovers and everybody pulls back, all the money evaporates, all the capital goes away."

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Deutsche Bank: Don’t bet on the IEA's prediction of U.S. oil dominance

Reading the pages of the Business Spectator in recent months I've noticed a seemingly endless stream of articles by Robert Gottliebsen claiming the US "shale gas revolution" will result in US energy independence, a resurgence in US domestic manufacturing and the demise of Australia's LNG export industry (unless the unions are crushed and construction costs dramatically lowered).

I usually just write these sort of crazed ramblings off as some sort of PR campaign on behalf of BHP in particular (someone needs to give Marius Kloppers some good press) and the mining and energy industries in general, as they fight the endless battle of capital against labour.

Maybe I'm missing something but from my high level understanding of the US gas industry, the natural gas "cliff" predicted by the likes of Julian Darley never eventuated courtesy of the shale gas boom - however US gas production isn't making new highs (so where is the glut people keep claiming exists ?) - instead the price collapsed due to a combination of manufacturing moving offshore (particularly gas intensive industries like fertiliser and chemicals) and the recession in the US causing demand to slump. Should the US return to growth and industry return based on the lure of cheap gas I think we'll find gas prices climbing rapidly again.

The IEA gave this sort of delusional thinking (US energy independence ahoy !) more momentum recently with the new World Energy Outlook report echoing Citibank's claims earlier this year that the US will soon be the world's leading oil producer (again, thanks to shale oil). Its probably worthwhile remembering that 10 years ago the IEA was claiming global oil production would now be over 100 million barrels per day (currently it stands at 90 million barrels per day, with significant contributions from biofuels and natural gas liquids).

Technology Review has a look at the report - Shale Oil Will Boost U.S. Production, But It Won’t Bring Energy Independence.

The idea that the U.S. could overtake Saudi Arabia, even temporarily, is a stunning development after years of seemingly inexorable declines in domestic oil production. U.S. production had fallen from 10 million barrels a day in the 1980s to 6.9 barrels per day in 2008, even as consumption increased from 15.7 million barrels per day in 1985 to 19.5 million barrels per day in 2008. The IEA estimates that production could reach 11.1 million barrels per day by 2020, almost entirely because of increases in the production of shale oil, which is extracted using the same horizontal drilling and fracking techniques that have flooded the U.S. with cheap natural gas.

As of the end of 2011, production had already increased to 8.1 million barrels per day, almost entirely because of shale oil. Production from two major shale resources in the U.S.—the Bakken formation in North Dakota and Montana and the Eagle Ford shale in Texas, now total about 900,000 barrels per day. In comparison, Saudi Arabia is expected to produce 10.6 million barrels per day in 2020.The shale oil resource, however, is limited. The IEA expects production to start gradually declining by the mid-2020s, at which time Saudi Arabia will reclaim the top spot. ...

The other potential issue is whether opposition to fracking in local communities might put the brakes on shale oil development, Sears says. Concerns that fracking will contaminate drinking water have led to objections in some areas, as have concerns that shale oil requires far more drilling wells than conventional oil production. Even if the U.S. is able to quickly develop its shale oil resource, it isn’t likely to be enough to completely eliminate oil imports. The IEA expects that the U.S. will still import 3.4 million barrels per day in 2035. The U.S. consumes nearly 19 million barrels per day, leaving a gap of more than 7 million even at the expected peak in shale oil production in the mid-2020s. However, the IEA expects the gap will be reduced partly by increased use of biofuels and natural gas in transportation, as well as improved vehicle efficiency, which could lower demand for oil.

The IEA does conclude that the United States will nearly be energy self-sufficient by 2035, but that’s after offsetting oil imports with exports of coal and natural gas. To be truly energy independent, the United States would have to invest in technology for converting natural gas and coal into the liquid fuels needed for transportation, or have other technical breakthroughs, such as improved batteries or biofuels, that would quickly reduce the demand for oil.

The Globe and Mail reports that Deutsche Bank analysts aren't convinced by the IEA's predictions for US oil production - Don’t bet on U.S. oil dominance.

An influential report arguing that the U.S. will soon become the world’s largest oil producer made a lot of headlines, especially in Canada where the implications are huge.

Too bad its findings are wrong, argue the energy analysts at Deutsche Bank.

It’s not that the oil isn’t there, but the conditions needed to develop it are lacking, Deutsche Bank analysts Paul Sankey, David Clark and Silvio Micheloto write in a note entitled ‘Why the U.S. WON"T surpass Saudi Arabia as Number 1 oil producer.’ (The emphasis is the authors’. And if you’re wondering if these guys know what they are talking about, Mr. Sankey has been ranked No. 1 for the last two years by Institutional Investor for coverage of integrated oil companies.)

A combination of U.S. policy restricting exports and sagging domestic U.S. demand for oil products will keep prices soft relative to the rest of the world, making the projects needed to create the huge U.S. supply growth uneconomical, they wrote Thursday in their critique of the report by the International Energy Agency which pointed to a huge shift toward North America in oil production.

“We don’t think the U.S. can become the largest oil producer in the world. Why not? Price, cost and returns. None are really dealt with by the IEA.”

OilPrice.com has an interview with longtime shale gas critic Arthur Berman - Shale Gas Will be the Next Bubble to Pop - An Interview with Arthur Berman.

The “shale revolution” has been grabbing a great deal of headlines for some time now. A favourite topic of investors, sector commentators and analysts – many of whom claim we are about to enter a new energy era with cheap and abundant shale gas leading the charge. But on closer examination the incredible claims and figures behind many of the plays just don’t add up. To help us to look past the hype and take a critical look at whether shale really is the golden goose many believe it to be or just another over-hyped bubble that is about to pop, we were fortunate to speak with energy expert Arthur Berman.

Arthur is a geological consultant with thirty-four years of experience in petroleum exploration and production. He is currently consulting for several E&P companies and capital groups in the energy sector. ...

Oilprice.com: How do you see the shale boom impacting U.S. foreign policy?

Arthur Berman: Well, not very much is my simple answer.

A lot of investors from other parts of the world, particularly the oil-rich parts have been making somewhat high-risk investments in the United States for many years and, for a long time, those investments were in real estate.

Now these people have shifted their focus and are putting cash into shale. There are two important things going on here, one is that the capital isn't going to last forever, especially since shale gas is a commercial failure. Shale gas has lost hundreds of billions of dollars and investors will not keep on pumping money into something that doesn’t generate a return.

The second thing that nobody thinks very much about is the decline rates shale reservoirs experience. Well, I've looked at this. The decline rates are incredibly high. In the Eagleford shale, which is supposed to be the mother of all shale oil plays, the annual decline rate is higher than 42%.

They're going to have to drill hundreds, almost 1000 wells in the Eagleford shale, every year, to keep production flat. Just for one play, we're talking about $10 or $12 billion a year just to replace supply. I add all these things up and it starts to approach the amount of money needed to bail out the banking industry. Where is that money going to come from? Do you see what I'm saying?

Oilprice.com: You've been noted suggesting that shale gas will be the next bubble to collapse. How do you think this will occur and what will the effects be?

Arthur Berman: Well, it depends, as with all collapses, on how quickly the collapse occurs. I guess the worst-case scenario would be that several large companies find themselves in financial distress.

Chesapeake Energy recently had a very close call. They had to sell, I don't know how many, billions of dollars worth of assets just to maintain paying their obligations, and that's the kind of scenario I'm talking about. You may have a couple of big bankruptcies or takeovers and everybody pulls back, all the money evaporates, all the capital goes away. That's the worst-case scenario.

Oilprice.com: Energy became a big part of the election race, but what did you make of the energy policies and promises that were being made by both candidates?

Arthur Berman: Mitt Romney, particularly, talked about how the United States would be able to achieve energy independence in five years. Well, that's garbage.

The Oil Drum also has some cynical words about the potential of shale gas - Tech Talk - Global Oil Supply .

One of the headlines this week from the IEA Report suggests that the United States will be the top global oil producer in five years. Yet back in DeSoto Parish in Louisiana, where the Haynesville Shale discovery in 2008 started the bonanza, revenues are now falling and school board budgets are strapped as the end of the glory days are beginning to appear.

Just this week Aubrey McClendon said that Chesapeake’s prospects for oil in Ohio, where Chesapeake had high hopes for the Utica Shale, are now dim. It is easy to look at one of the large maps showing all the shale deposits in the United States that the Oil and Gas Journal include in their print editions, and to be carried away (as the IEA apparently are) with the vast acreage that is shaded on the map. Unfortunately, as we can see, reality tells another story. The size of the resources have been measured in the past, and with the best plays being given preference, the recognition of decline rates and unprofitable wells have not yet been given the prominence in the popular press that they will ultimately draw.

It seems unrealistic to anticipate the levels now being projected for future North American production of oil. Nevertheless, these projections do tend to crowd conflicting stories on the subject out of the spotlight. Further, if the predictions for American production gains, even in the short term, turn out to be optimistic, then the impacts may be even more exaggerated than is currently appreciated. Consider that OPEC now expects that North America will continue to provide the greatest y-o-y increase in supply over other nations, and there are in fact, few other nations that will contribute much more in the next year.

Stuart at Early Warning also has a post on the IEA report - IEA: US To Be World's Largest Oil Producer. Plus Energy Bulletin has a set of links to commentary too - Commentaries on the IEA WEO 2012 - peak postponed? - Nov 14.

I am less persuaded myself that using a thousand oil rigs to generate an extra one million barrels per day of oil is necessarily a sign of a large and long-term sustainable increase in US oil production (as opposed to, say, frenzied scraping of the bottom of the barrel). But, still, I'm not certain beyond a reasonable doubt just how deep this particular barrel can be scraped.

At any rate, one thing that is interesting is that the chart above shows the US second peak just reaching 10mbd of oil, and yet the US will be the largest producer of oil. Since the IEA says Saudi production is currently at 9.5mbd and Russia at 10.75mbd, the implication is that neither Russia or Saudi Arabian production will increase at all between now and 2020 when the US will surpass them.

Apparently, the strategy of massed hordes of drilling rigs fracking for shale oil can only be of benefit in the United States.

It used to be Saudi Arabia that was used to fill in the wedge between desired supply and expected demand in official energy projections. Apparently the agencies have now accepted that Saudi Arabia cannot or will not increase production and the US is now being assigned the role of supplier of last resort for future energy projections.

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The One And Only Place Fracking Is Causing Water Contamination

Bloomberg has a report on an EPA investigation into fracking for shale gas - Fracking Is Safe—Except in Wyoming.

Louis Meeks, a hay farmer in Pavillion, Wyo., holds a mason jar under a faucet in his house and turns on the water. It’s a demonstration he’s given to a slew of neighbors and government officials. The water, drawn from his backyard well, is cloudy and smells like diesel. “Would you want to drink it?” he asks.

Meeks blames the bad water on fracking, the process in which thousands of gallons of water are mixed with sand and chemicals and blasted underground to free natural gas.

After sampling and analyzing his water, the U.S. Environmental Protection Agency last December issued a preliminary report citing the Pavillion area as the one—and only—place in the nation where fracking is causing water contamination. Far from thanking Meeks for raising the alarm, his neighbors in the town (population: 231) now say he’s responsible for driving real estate buyers and business away. “It was instantaneous, like the spigot was turned off,” says Ginny Warren, describing how sales at her restaurant dried up. “I’m stuck with a property that I couldn’t give away if I wanted to.”

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Shale Gas Assets - Overpriced Or a Liquid Turn for Mining Giant BHP?

The Oil Drum has a look at BHP's expensive foray into North American shale gas production - Shale Gas Assets - Overpriced Or a Liquid Turn for Mining Giant BHP?.

Australian mining giant BHP has lost a quarter of its former market capitalization since its acquisition of US shale acreage from Petrohawk and Chesapeake last year. The company is keen to point out that worldwide economic conditions have impacted the price and volume of the commodities that BHP extracts and sells on a global basis. BHP’s US shale gas assets are part of its declining performance. Having paid a whopping $19bn for the shale plays in 2011, BHP now faces serious write downs. Ruud Weijermars and Matthew Hulbert ask the serious question whether the lost value simply is a result of changed market conditions - or was the acreage already worth much less at the actual time of its purchase by BHP?

BHP management concedes it is currently assessing the near-term gas price effect on the value of its gas properties acquired last year from Chesapeake (CHK) and Petrohawk (HK). To many industry analysts this is no surprise; the economic fundamentals of US shale gas production and reserves were already questioned long before the BHP sales went through. Petrohawk had never managed to earn any operational profit from its shale gas assets over its 15 years of operations. HK sold gas below the full-cycle production cost and its accumulated losses amounted to some $1 billion when the company was bailed out by BHP last year.

In short, Petrohawk was a ‘precursor’ to Chesapeake’s recently publicized cash-flow crunch predicament. The lack of access to financing, combined with overleveraged debt and lack of operational earnings from gas wells meant one thing: sell assets quickly. One can confidently conclude that HK shareholders were remarkably lucky to receive a very handsome price – twice the market value - for their distressed gas assets in June 2011.

In our opinion, a significant portion of HK’s formerly ‘approved’ gas reserves more likely than not was overdue for downgrading to ‘contingent’ resources by the time of their sale to BHP. In ball park terms, that’s the difference between gas assets that can be produced commercially at current prices, and those which can’t ...

The core of the problem with shale acreage valuation is that the net present value of gas reserves has become as volatile as the gas price itself. But companies have been slow in exercising due diligence if not outright reluctant to depreciate assets. In spite of the low gas prices in 2009, 2010 and 2011, companies like Chesapeake and Petrohawk continued to aggressively book proved undeveloped reserves (PUDs). Both Petrohawk and Chesapeake needed these new reserves on their balance sheets - without these reserve additions, they would have landed into collateral default. And although SEC rules mandate companies must duly impair PUDs when overall project cost have become uneconomic, PUDs now account for nearly half of CHK’s (and former HK’s) proved reserves. Chesapeake’s reported proved reserves comprised 42% PUDs in 2009, and the proportion grew to 47% in 2010, and settled at 46% in 2011.

Oddly enough, once a company has sunken the cost for well development of a PUD, the developed proved reserves need only be impaired if the annual cash flow turns negative, which would require gas sales to dip below operating expenses. In the well’s subsequent life-cycle, SEC rules leave room for continued classification of a well’s resources as reserves, as long as annualized cash flows remain positive. This encouraged companies to continue quickly sinking cost in wells that may not, in fact, ever have been economic (on a full cost basis) in the first place. By doing so, companies quickly 'prove' the reserves of a new shale gas play, and the acreage value rises. This also means that many US shale gas companies have essentially ignored full cycle economics. The sunk cost game continues even today.

Investors still appear prepared to bear the cost, but may not be fully aware of the additional risk.

With gas prices plummeting, the SECs former ’premium label’ of proved reserves has lost its stable foundation. In fact, full cycle economics for the majority of US shale gas plays has been largely negative for the past four years. The SEC has been lenient and one might speculate that overly aggressive reserve reporting appeared an affordable governance risk for shale gas operators. There has been no favourable gas price for adding proved reserves, yet unconventional gas companies have booked reserves by operating aggressively on a sunk cost basis. As a result, US shale gas investments have now become less secure than the reported reserves suggest – something investors seem to haven glossed over far too lightly.

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Santos produces first shale gas in Australia

The Business Spectator reports that Santos are getting some positive market feedback after expanding into shale gas in inland Australia (supplementing their natural gas and coal seam gas production) - Santos pins hopes on first shale gas.

Oil and gas producer Santos says Australia's first commercial shale gas well is ready to go into production, helping to boost supply and keep prices stable in eastern Australia.

Santos said its Moomba-191 well in the Cooper Basin was now producing dry gas after the company reported an increase in underlying first half profit and maintained its full-year production guidance on Friday. ...

Chief executive David Knox said shale gas flows from the Moomba well were a significant milestone in the company's program to unlock the vast unconventional gas potential of the Cooper Basin that straddles the South Australian and Queensland border.

"The shale well result has been an outstanding result for us and potentially for eastern Australia for the very long-term future," Mr Knox told analysts on Friday. ...

"The share price is up because of the surprisingly good flow rate that they're getting at their Moomba 191 shale gas well," Mr Wood said. "You can start to talk about some very large numbers on the back of that, but it's very early days. Certainly this flow rate was better than we were expecting."

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Exxon pulls out of Poland shale gas

Reuters has a report on Exxon's giving up on shale gas extraction in Poland - Europe shale push shaken by Exxon's Poland pullout. The FT also has a report - Poland shale: Exxon exit.

Europe's most ambitious shale gas plans were in disarray on Monday after U.S. major ExxonMobil announced it would pull out of exploration projects in Poland.

Poland's lucrative reserves had spurred hopes of transforming Europe the way a shale boom has left the United States brimming with supplies, potentially turning the Poles into net gas exporters.

That was until March, when a government report revealed the country's likely reserves were about one-tenth the size of previous estimates.

At the weekend, Exxon, which earlier this year cautioned that commercial production of Polish shale was at least five years away, said it would not go forward with exploration.

"The move is not surprising given that Poland's shale potential is still unclear," JBC Energy analysts said in a note on Monday.

A spokesman for Exxon in Poland said the company has not decided yet what it would do with its exploration licences. It controls four and jointly holds two with France's Total .

Poland has granted 112 shale exploration licences to ExxonMobil, Chevron and other firms, even as some countries, including France and Bulgaria, have banned shale exploration pending further environmental studies.

The Poles are keen to wean themselves off their heavy reliance on coal and imported Russian gas, partly due to environmental commitments they face as a European Union member nation.

"Exxon realised that commercial extraction was not possible with currently available technology. This is a general problem in Poland that shale rocks are too tight to allow extraction," an industry source said, asking not to be identified.

Abundant shale gas production in Poland poses a potential threat to Russia's supremacy in Europe, where it supplies a quarter of the gas used in the EU. ...

Poland had high hopes for shale after a study by the U.S. Energy Information Association in 2011 estimated Polish reserves at 5.3 trillion cubic metres, enough to cover domestic demand for some 300 years.

The government's study in March slashed estimates for recoverable shale gas reserves at 346 to 768 billion cubic metres.

Reuters also has a report on Exxon's disastrous experience with shale gas in the US - Exxon CEO says low U.S. natgas prices not sustainable.

U.S. natural gas prices are too low to allow the energy industry to cover the cost of finding and producing new supplies, the head of top producer Exxon Mobil (XOM.N) said on Wednesday.

Record production, thanks to new technologies that tap natural gas trapped in shale rock formations, pushed U.S. natural gas prices to 10-year lows below $2 per million British thermal units (mmBtu) in April, though prices have since rebounded.

"The cost of supply is not $2.50. We are all losing our shirts today," Rex Tillerson, chief executive officer of Exxon Mobil, said in a presentation at the Council on Foreign Relations.

Gas prices have risen over 50 percent since April's lows, and were up more than 5 percent on Wednesday to nearly $2.95 per mmBtu.

Still, prices remain well below the $4-$5 level that makes drilling in pure natural gas fields profitable. Most producers have moved over to more lucrative oil and liquids-based plays to fetch higher prices, which has begun to put a slight dent in U.S. gas production.

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Shale Gas: The View from Russia

While I wouldn't view Dmitri Orlov or Gazprom as unbiased observers of the global gas industry, this post at Club Orlov is quite thought provoking - Shale Gas: The View from Russia.

The official shale gas story goes something like this: recent technological breakthroughs by US energy companies have made it possible to tap an abundant but previously inaccessible source of clean, environmentally friendly natural gas. This has enabled the US to become the world leader in natural gas production, overtaking Russia, and getting ready to end of Russia's gas monopoly in Europe. Moreover, this new shale gas is found in many parts of the world, and will, in due course, enable the majority of the world's countries to achieve independence from traditional gas producers. Consequently, the ability of those countries with the largest natural gas reserves—Russia and Iran—to control the market for natural gas will be reduced, along with their overall geopolitical influence.

If this were the case, then we should expect the Kremlin, along with Gazprom, to be quaking in their boots. But are they?

Here is what Gazprom's chairman, Alexei Miller, recently told Süddeutsche Zeitung: “Shale gas is a well-organized global PR-campaign. There are many of them: global cooling, biofuels.” He pointed out that the technology for producing gas from shale is many decades old, and suggested the US turned to it out of desperation. He dismissed it as an energy alternative for Europe. Is this just the other's sides propaganda, or could Miller be simply stating the obvious? Let's explore. I will base my exploration on Russian sources, which is why all the numbers are in metric units. If you want to convert to Imperial, 1 m3 = 35 cubic feet, 1 km2 = .38 square miles, 1 tonne = 1.1 short tons).

The best-developed shale gas basin is Barnett in Texas, responsible for 70% of all shale gas produced to date. By “developed” I mean drilled and drilled and drilled, and then drilled some more: just in 2006 there were about as many wells drilled into Barnett shale as are currently producing in all of Russia. This is because the average Barnett well yields only around 6.35 million m3 of gas, over its entire lifetime, which corresponds to the average monthly yield of a typical Russian well that continues to produce over a 15-20 year period, meaning that the yield of a typical shale gas well is at least 200 times smaller. This hectic activity cannot stop once a well has been drilled: in order to continue yielding even these meager quantities, the wells have to be regularly subjected to hydraulic fracturing, or "fracked": to produce each thousand m3 of gas, 100 kg of sand and 2 tonnes of water, combined with a proprietary chemical cocktail, have to be pumped into the well at high pressure. Half the water comes back up and has to be processed to remove the chemicals. Yearly fracking requirements for the Barnett basin run around 7.1 million tonnes of sand and 47.2 million tonnes of water, but the real numbers are probably lower, as many wells spend much of the time standing idle.

In spite of the frantic drilling/fracking activity, this is all small potatoes by Russian standards. Russia's proven reserves of natural gas amount to 43.3 trillion m3, which is about a third of the world's total. At current consumption rates, that's enough to last 72 years. Russian gas production is constrained by demand, not by supply; it is currently down simply because Eurozone is in the midst of an economic crisis. Meanwhile, US production has surged ahead, for no adequately explored reason, crashing the price and making much of it unprofitable.

Let's compare: Gazprom's price at the wellhead runs from US$3 to $50 per thousand m3, depending on the region. Compare that to shale gas in the US, which runs from $80 to $320 per thousand m3. At this price, the US cannot afford to sell shale gas on the European market. Moreover, the overall volume of shale gas being produced in the US, even given the feverish drilling rate of the past couple of years, if cleaned up, liquified, and shipped to Europe in LNG tankers, would not be enough to book up just the LNG terminal in Gdańsk, Poland, which is currently standing idle. It seems that Gazprom has little to worry about.

The US, on the other hand, does have plenty to worry about. There has been much talk already about groundwater pollution and other forms of environmental destruction that accompanies the production of shale gas, so I will not address these here. Instead, I will focus on two aspects that are just as important but have received scarcely any attention.

First, what is shale gas? Ask this question, and you will be told: “Shut up, it's methane.” But is it really? The composition of shale gas is something of a state secret in the US, but information about the gas produced from the nine Polish shale gas test projects did leak out, and it's not pretty: Polish shale gas turned out to be so high in nitrogen that it does not even burn. Technology exists to clean up gas that is, say, 6% nitrogen, but Polish shale gas is closer to 50% nitrogen, and, given high production costs, low yields, rapid depletion and low wellhead pressure, cleaning it up to bring it up to spec (which is 1% nitrogen) would most likely result in a net waste of energy.

Even if shale gas is low enough in nitrogen to burn, the problems do not end there. It may also contain hydrogen sulfide, which is toxic and corrosive and has to be removed before the gas can be stored or injected into a pipeline. It probably contains toluene and other organic solvents—ingredients in the fracking cocktails—which are carcinogenic. Lastly, it may be radioactive. All clays are mildly radioactive, and shale is a sort of heat-treated clay. While Barnett shale is not particularly radioactive, Marcellus shale, which has recently been the focus of frantic drilling activity, is. Thanks to Marcellus shale gas, radioactive radon gas is being delivered directly to your kitchen, via the burners of your stove, or to a power plant smokestack upwind from where you live. This is expected to result in increased lung cancer rates in the coming years.

Second, why is shale gas being produced at all? Natural gas prices have fallen through the roof, and are currently around $2 per thousand cubic feet. This works out to around $70 per thousand m3. If shale gas costs from $80 to $320 per thousand m3 to produce, it is unclear how one might make any money with it.

But perhaps making money with it is not the point. What if shale gas is just a PR campaign (with horrific environmental side effects)? Going back to what Alexei Miller said, what if the entire point of the exercise was to increase the capitalization of shale gas exploration and production companies? The number one company in shale gas is Chesapeake Energy, the owner of the Barnett basin and a major player in the Marcellus basin. This company almost went bankrupt in 2009, but then managed to claw its way back to profitability in 2010 and 2011 by drilling, and drilling, and drilling, and then drilling some more. Sixty percent of their revenue is from drilling operations. And now there is a scandal involving Chesapeake Energy's (former?) chairman, Aubrey K. McClendon, who apparently awarded himself a stake in each well his company drilled, used them as collateral for billions in loans, and used the loans to bet that natural gas prices will go up (they haven't). In the meantime, natural gas drilling rig count has dropped to a ten-year low. Given that shale gas wells deplete very quickly, it looks like the shale gas boom is over.

But now that it's over, what was it, exactly? It appears to have been something like the dot-com bubble: companies with no conceivable way of turning a profit using hype to attract investment and drive up their valuations. Since 2008, various kinds of hype-based market manipulations have become the staple of economic life in the US, and so this is nothing new or different.

One interesting question is, What sort of bubble will the US attempt to blow next, if any? There is the Facebook IPO coming up. Facebook is a ridiculous time-waster and, as such, seems a bit overpriced. Are we going to attempt blowing up another dot-com bubble? Another round of subprime mortgages does not seem to be in the works. What's a bubble boy to do? If there are no more bubbles to blow, then it's back to just plain printing money.

So this whole shale gas thing didn't work out as planned, did it? But could it have? Had it turned out to be much better in every way, could it have swung geopolitical influence away from Russia and Iran and back toward the US? Alas, no.

You see, there is no such thing as a global natural gas market. Yes, there are some LNG tankers sailing about, but that is very much a point-to-point trade. There is a closed North American market, a European market, and another market in the Asia-Pacific region. These markets do not interact. The North American market and the European market could have potentially shared just one producer: Qatar. Qatar once wanted to export LNG to the US, but then decided to export it to Europe instead, generating less of a loss, because European gas prices are substantially higher. And the reason Qatar is dumping natural gas in Europe is because it has gas to dump: its northern gas field is a very “wet” field, with a substantial percentage of natural gas condensate. Qatar's OPEC quota is 36-37 million tonnes of oil per year, but natural gas condensate is not considered to be oil and is not covered by OPEC quotas. Exploiting the condensate loophole allows Qatar to export 65.7 million tonnes: 77% over quota. The LNG is just concomitant production, and Qatar can afford to export LNG to Europe at a loss. This is a juicy bit of trivia, but really something of a footnote: an exception that proves the general case: there is no global natural gas market.

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Feds Link Water Contamination to Fracking for the First Time

ProPublica has a look at a new study of fracking fluids contaminating underground water in the US - Feds Link Water Contamination to Fracking for the First Time.

In a first, federal environment officials today scientifically linked underground water pollution with hydraulic fracturing, concluding that contaminants found in central Wyoming were likely caused by the gas drilling process.

The findings by the Environmental Protection Agency come partway through a separate national study by the agency to determine whether fracking presents a risk to water resources.

In the 121-page draft report released today, EPA officials said that the contamination near the town of Pavillion, Wyo., had most likely seeped up from gas wells and contained at least 10 compounds known to be used in frack fluids.

“The presence of synthetic compounds such as glycol ethers … and the assortment of other organic components is explained as the result of direct mixing of hydraulic fracturing fluids with ground water in the Pavillion gas field,” the draft report states. “Alternative explanations were carefully considered.”

The agency’s findings could be a turning point in the heated national debate about whether contamination from fracking is happening, and are likely to shape how the country regulates and develops natural gas resources in the Marcellus Shale and across the Eastern Appalachian states.

Some of the findings in the report also directly contradict longstanding arguments by the drilling industry for why the fracking process is safe: that hydrologic pressure would naturally force fluids down, not up; that deep geologic layers provide a watertight barrier preventing the movement of chemicals towards the surface; and that the problems with the cement and steel barriers around gas wells aren’t connected to fracking.

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Australia's Gas Pains

The Wall Street Journal reports that entry into the gas age is not without pain fopr would be exporters of Australian natural gas - Australia's Gas Pains.

Seven LNG projects now under construction in Australia are expected to cost 140 billion Australian dollars (US$144 billion). By 2020, Australia could produce as much as one quarter of the world's LNG—up from less than a tenth today—making it one of the world's top two producers alongside Qatar.

The price of such rapid growth will be high. Resource workers are expensive and will become more so as the market for labor remains tight. Woodside Petroleum has already seen cost overruns of US$3 billion at its giant Pluto LNG project in Western Australia, partly because of labor shortages.

The soaring Australian dollar, up 65% against the U.S. dollar since the worst of the financial crisis, is also pushing up the cost of business for resources companies.

Australia-listed Oil Search said last month the dollar's rise has pushed up the budget on its Papua New Guinea project, operated by Exxon Mobil, by US$700 million, or nearly 5%.

BernsteinResearch says the cost per ton of Australian LNG could average as much as US$4,000, compared with about US$1,000 at Apache's Kitimat project in western Canada.

For Australia's LNG projects, politics are an unwelcome obstacle. There are moves at federal and state levels that could limit gas extraction on vast tracts of land deemed critical to the country's agricultural production. That shouldn't affect existing projects, though it could temper expansion—which actually could help Australia avoid the worst labor shortages.

Meanwhile, pressure is building to get the Australian projects up and running soon. Qatar—which produces some of the world's lowest-cost LNG—has a moratorium on further development of its gigantic North field in order to preserve its longevity. But the self-imposed ban ends in 2013.

The ABC reports that Inpex are optimistic about their project going ahead - Inpex LNG venture tipped to attract investors.

A senior economist says he expects Inpex will have no trouble in securing investors for its planned multi-billion dollar gas project in Darwin. The Japanese company announced yesterday that it had already sold its total projected liquefied natural gas output from the proposed operation.

A final investment decision on the project, to pump gas from the Timor Sea to Darwin via a 900 kilometre pipeline, is yet to be announced. But it is believed Inpex hopes initial construction work will begin in March.

Macquarie Bank senior economist Brian Redican says investors are likely to view the project as a low-risk venture. He says a surge in oil prices in recent years means Inpex is in a strong position to secure investors. "Because petrol prices and energy prices are so high, they are actually extraordinarily profitable at the moment," he said.

The Australian has yet another report on the prospect of the US exporting LNG from shale gas - US to enter LNG export market amid domestic supply glut. It will interesting to see the reaction in the US if local gas prices converge with those in Asian export markets (the same unpleasant adjustment that is beginning in Australia already).

AUSTRALIAN gas exporters had better watch out - there's a new kid on the block. The US could emerge as a major competitor to Australia’s burgeoning gas-export market, challenging the viability or expansion plans of close to a dozen Australian liquefied natural gas projects, according to Noel Tomnay, the head of global gas at UK-based energy consultancy Wood Mackenzie.

Traditionally an importer of gas, the US is experiencing a domestic supply glut owing to heavy investment in the production of shale gas in states like Texas. That’s depressing US gas prices and prompting some companies to investigate the potential of terminals on the US coast geared for export to take advantage of higher prices abroad.

Cheniere Energy recently signed two long-term gas supply deals with offtakers, including with BG Group, as it presses ahead with plans to build the first LNG export terminal in the US. Last month, Cheniere said it has enough supply locked into long-term contracts to start construction of a proposed LNG export terminal in Sabine Pass, Louisiana, in 2012.

Tomnay told Deal Journal Australia: "We’re of the view that North America will have 20 million tonnes of LNG capacity maybe as early as 2018. Consequently, that will remove potential market share for Australian LNG projects."

Investment totalling more than $140 billion has been earmarked for new Australian LNG terminals focused mainly on Asia since 2007, which could catapult Australia ahead of Qatar as the world’s largest LNG exporter within a decade. In the latest development yesterday, Japan’s Inpex signed 15-year deals to supply five Japanese utilities with $US70 billion ($68.3bn) worth of LNG from its proposed Ichthys project in the Northern Territory.

The other risk facing would be LNG exporters to Asia is China taking its first steps towards producing shale gas - Chinese shale gas find may cut LNG demand
.

ROYAL Dutch Shell has found shale gas in China, prompting fears that the country could develop enough domestic supply to limit imports of liquefied natural gas. An official at PetroChina, Shell's partner in the region, told Reuters that results from two wells had been positive.

In less than a decade shale gas has transformed the US from gas shortage to a point where companies are planning to export LNG, fundamentally altering the dynamics of the international gas market. Existing LNG producers had hoped that higher demand from China would offset the decline in imports to the US.

Shale gas is obtained by hydraulically fracturing rock, which requires large quantities of water and chemicals. There is concern among environmentalists that the process can contaminate groundwater supplies.

Analysts have predicted shale gas could supply up to half the natural gas produced in North America by the end of this decade.

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US Gas-to-Liquid Plant Planned By SASOL May Cost $10 Billion

The WSJ reports that South African coal to liquids company SASOL is looking to build a GTL (gas to liquids) plant in Louisiana, using the (at least currently) cheap supply of shale gas as feedstock - Gas-to-Liquid Site May Hit $10 Billion.

Sasol Ltd., a chemical company long known for squeezing motor fuel out of coal, is now turning its sights on the glut of natural gas in the U.S.

South Africa-based Sasol on Tuesday announced plans to build a plant in Louisiana, at a cost of up to $10 billion, that would convert natural gas into diesel fuel for trucks and other vehicles.

The company's board last week approved an 18-month feasibility study for the project, which would be constructed on land adjacent to Sasol's existing chemical facility in Calcasieu Parish, La.

If given the final go-ahead, the plant would be the first in the U.S. to use "gas-to-liquids" technology. Once seen as futuristic, the technology has gained traction in recent years as discovery of gas supplies have outpaced that of oil.

"The initial numbers look positive," said Ernst Oberholster, Sasol's managing director of new-business development, who stood alongside Louisiana Gov. Bobby Jindal at the company's Louisiana complex when the decision was announced.

What makes the U.S. an attractive location for such a project is the low level of natural-gas prices in the country. Benchmark futures have hovered between $3 and $6 per million British thermal units for two years, well below prices paid by consumers in Europe and Asia.

Sasol would buy the natural gas from suppliers using long-term contracts, convert the gas to liquid fuel and then sell that fuel to blenders, who wouldthen sell it for the open market.

The project is the latest to address what to do with a surplus of natural gas caused by the boom in drilling in shale-rock formations in places like Texas and Pennsylvania. Energy investor T. Boone Pickens and natural-gas producers such as Apache Corp. have promoted the use of natural gas as a road-transportation fuel, one that would be cleaner burning than oil-based alternatives. In addition, some companies have put forward plans to export gas out of the U.S. in cool-liquefied form.

Sasol's idea is one of the most ambitious, because it would essentially put natural gas on par with higher-priced crude oil as a key raw material for transportation fuels. And diesel prices trickle down into the cost of consumer goodseverywhere because the fuel is mainly used in trucking. So far this year, retail diesel prices in the U.S. are up 16%, even as the economy grows more fragile.

Sasol officials estimate that a plant producing 96,000 barrels a day of diesel, and some jet fuel, would cost $10 billion to construct. They say they could opt for a smaller facility, however.

By converting natural gas into a liquid, the fuel could be used without retrofitting vehicles or creating new fueling infrastructure, an issue that would affect motorists using compressed natural gas as Apache and Mr. Pickens have advocated. The proposed site in Louisiana is close to Gulf Coast natural-gas fields and is crisscrossed by pipelines that could be easily linked to a new facility, Mr. Oberholster said.

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