Bakken Shale Gas Flaring Highlights Global Problem

• High rates of natural gas flaring in the Bakken shale formation are symptomatic of infrastructure limitations that prevent this gas from reaching a market.
• Although various technical options could reduce flaring from high-output well sites, none matches the benefits of developing large-scale outlets for the gas.

The Wall St. Journal recently reported on the high rate at which excess natural gas from wells in North Dakota's Bakken shale formation is burned off, or "flared."  The Journal cited state data indicating 10.3 billion cubic feet (BCF) of gas were flared there during April 2014. That represented 30% of total gas production in the state for the month.

North Dakota's governor attributed the high volume of gas flared in his state to the great speed at which the Bakken shale has been developed, outpacing gas recovery efforts. Oil output ramped up from 200,000 barrels per day five years ago to just over a million today, in a region lacking the dense oil and gas infrastructure of Texas and other states with a legacy of high production.

Nor is this situation unique to the Bakken. The World Bank has estimated that around 14 BCF of gas is flared every day, globally. Such flaring is a problem for more than governments and other mineral-rights owners that worry about missing potential royalties.  Aside from our natural aversion to waste, flaring natural gas has environmental consequences.

The tight oil produced from the Bakken shale is quite low in sulfur, and so is most of the associated gas, but some of it contains relatively high percentages of hydrogen sulfide (H2S). When that gas is flared, rather than processed, the resulting SOx emissions can affect local or even regional air quality.

Gas flaring also contributes to the greenhouse gas emissions implicated in global warming, although it must be noted that flaring is 28-84 times less climate-altering, pound for pound, than venting the same quantity of methane to the atmosphere.  When annualized, and assuming complete combustion of the gas, North Dakota's recent level of flaring equates to around 6.7 million metric tons of CO2 emissions, or nearly a fifth of total estimated US CO2 emissions from natural gas systems in 2012. That means this one source accounts for around 0.1% of total US greenhouse gas emissions, or somewhat less than US ammonia production.

Why would anyone flare gas in the first place? As the Journal pointed out, the oil produced from Bakken wells is worth significantly more than the gas, although the energy-equivalent price ratio favors oil by more like 4:1 than the 20:1 cited in the article. Still, the economics of Bakken drilling are mainly driven by oil that can be sold at the lease and delivered by pipeline or rail, and not by the associated gas, particularly after tallying the cost of capturing and processing it, and then hoping capacity will be available to deliver it to a market that in the case of the Bakken might be hundreds or thousands of miles away. The characteristics of shale wells, with their steep decline curves, raise this hurdle even higher: Shale gas infrastructure at the well must pay for itself quickly, before output tails off.

There is no shortage of technical options for putting this gas to use, instead of flaring it. An industry conference in Bismarck, ND this spring featured an excellent presentation on this subject from the Energy & Environmental Research Center (EERC) of the University of North Dakota. Among the options listed by the presenter were onsite removal of gas liquids (NGLs), using gas to displace diesel fuel in drilling operations, and compressing it for use by local trucking or delivery to fleet fueling locations. However,  contrary to the intuition of the rancher interviewed by the Journal, none of these options would reduce high-volume flaring by more than a fraction, despite investment costs in the tens or hundreds of thousands of dollars per site.

Even in the case of the most technically interesting option, small-scale gas-to-liquids conversion to produce synthetic diesel or high-quality synthetic crude, EERC estimated this would divert only 8% of the output from a multi-well site flaring 300 million cubic feet per day, while requiring an investment of $250 million. And to make this option yet more challenging to implement, of the 200-plus such locations EERC identified in the state, fewer than two dozen flared consistently at that level over a six-month period. The problem moves around as older wells tail off and new ones are drilled.

Significantly reducing or eliminating natural gas flaring ultimately requires a large-scale market for the hydrocarbons being burned off. That's as true in North Dakota as in Nigeria. While various technical options could incrementally reduce gas flaring from Bakken wells, the highest-impact solutions would be those that promote market creation. That would include fast-tracking long-distance gas pipeline projects or building gas-fired power plants nearby. Absent large new customers for Bakken gas, additional regulations on flaring will either be ineffective or impede the region's strategically important oil output.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Could Diesel Fuel Made from US Natural Gas Compete with CNG and LNG?

The announcement last month of a $21 billion project to capitalize on abundant, low-cost US natural gas should have caught the attention of everyone interested in this resource. As reported in the New York Times, Sasol, a South African energy company, intends to build a 96,000 barrel-per-day gas-to-liquids (GTL) plant in southwestern Louisiana, in conjunction with a new gas processing plant and ethylene cracker. The synthetic diesel fuel produced by this facility would provide a different pathway for shale gas to displace imported crude oil in the US transportation sector, in competition with compressed or liquefied natural gas (CNG or LNG.)

GTL involves a two-step conversion of the methane that makes up the bulk of natural gas into synthesis gas and hydrogen, which are recombined into liquid hydrocarbons by means of the decades-old Fischer-Tropsch (FT) process. GTL is also energy-intensive, with an overall efficiency around 60%. South African companies have vast experience with such synthetic fuels. Sasol are partners in the Oryx GTL plant in Qatar, and their coal-to-liquids plants in South Africa utilize a similar syngas step and the same FT process as GTL.

With the US suddenly perceived to be sitting atop a century's worth of natural gas, mainly in the form of unconventional gas from shale, tight gas formations and coal-bed methane, T. Boone Pickens isn't the only one to see an opportunity to displace imported oil with gas. Yet as attractive as that sounds for reasons of energy security and trade, it isn't obvious whether the public or even fleet operators are willing to switch on a larger scale to a lower-density gaseous fuel requiring both new distribution networks and new or modified powertrains. Only 0.1% of the natural gas consumed in the US now finds its way into vehicles, equivalent to less than 0.1% of US oil demand. Under the circumstances, it would be surprising if someone weren't looking seriously at GTL, one of the few practical ways to circumvent the mechanical and logistical barriers that have impeded the fueling of more US cars and trucks with natural gas.

When I read about Sasol's proposed project, I immediately thought of another, less well-known South African synfuels facility. Since 1992 the Mossel Bay GTL plant has been turning natural gas into gasoline, diesel and other fuels, drawing first on the Mossel Bay gas field and then on newer fields as the original one depleted. Although owned by another firm, the ongoing struggles to keep the "Mossgas" plant supplied are well-known in South African energy circles. I can't imagine Sasol embarking on a project like the one in Louisiana if they had any doubt about their ability to keep it supplied for decades.

Of course volume and price are two very different aspects of supply. A decade ago, conventional wisdom held that GTL required a gas cost of around $1 per million BTUs to be viable. Even with the shale bonanza today's US natural gas price is well above that level. What now makes it possible to conceive of GTL in the US is that the price of the crude oil used to make diesel and other fuels has risen so much higher than that of natural gas. That comparison is more obvious when one converts natural gas prices into their energy equivalent in crude oil. Today's US natural gas price is below the $23 per equivalent barrel that it was in 2001. Meanwhile crude oil has increased from about $26 to $95 per barrel. The drastically improved attraction of GTL becomes even clearer when comparing ten years of wholesale US Gulf Coast diesel prices to natural gas prices using the approximate GTL conversion rate of 10 million BTUs of gas per barrel of liquid product.

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As the chart above reveals, this theoretical GTL margin has exploded since 2009. Yet it also shows that if gas prices returned to the levels we experienced just a few years earlier, the proposed project would encounter significant risks. Perhaps that helps explain Sasol's concept of a larger integrated gas complex with multiple sources of margin, capitalizing on the waste heat from the GTL process and the lighter hydrocarbons it yields as byproducts.

It remains to be seen whether GTL will prove an attractive means of leveraging the US shale gas revolution to back out imported oil. However, if Sasol and others proceed with US GTL projects, anyone eyeing our gas surplus for other purposes, whether in manufacturing, fertilizer production or power generation, would face serious competition linked to the global oil market. That includes potential LNG exporters, who passed an important hurdle with the publication of a favorable analysis by the Department of Energy.

A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation

A Growing Imbalance

This spring I reviewed Robert Bryce's book, "Gusher of Lies," a thorough debunking of the notion that America could or should become energy independent any time soon. In a provocative article in Slate, he has connected the dots between our steadily rising ethanol mandates and the current weirdness in the US petroleum products market, in which wholesale gasoline continues to sell for less than light sweet crude oil, while diesel fuel/heating oil commands large premiums over both. In the process, he explains the short-to-medium-term constraints on attempting to reduce crude oil imports by increasing ethanol production. Although these impediments could be overcome in the long run, doing so would require enormous additional investments in the fuels sector, because it would render obsolete the configuration of virtually every current US oil refinery.

Reading Robert's article triggered two related thoughts. The first was that our present ethanol policy, embodied in the Renewable Fuel Standard (RFS) and the decades-old system of ethanol blending credits and import tariffs, reflects an outdated set of assumptions about the nature of the US motor fuels market. These subsidies and mandates arose during a period in which US gasoline demand was growing steadily at 1-3% per year, US refineries were producing as much gasoline as they could, and US imports of finished gasoline and gasoline bending components were growing steadily. None of these factors has survived this summer's price spike and the ensuing financial and economic crisis. Nor are they likely to recover to their former levels when the economy does, because of the growing emphasis on conservation, fuel economy and alternative transportation fuels and vehicle types.

I've commented periodically on the shifting global balance between gasoline and diesel fuel, but without factoring in the influence of US ethanol output--which has more than doubled in the last two years alone--on this relationship. The Slate article identifies the problems created by pushing increasing quantities of ethanol into a stagnating gasoline market, with upstream consequences for refinery operations and the production of other necessary products such as diesel, heating oil and jet fuel, for which long-term demand looks more robust than for gasoline, both domestically and internationally. With US ethanol output currently running at a level equivalent to 7% of US gasoline demand, it compounds the global weakness of gasoline, at the same time ethanol producers are adversely affected by gasoline's slump.

Markets eventually adjust to such disruptions, and I see several paths by which the US refining industry could accommodate a national energy policy aimed at steadily expanding our use of biofuels from 10 billion gallons per year today to 36 billion gallons by 2022, and perhaps to the 60 billion gallons per year envisioned by the President-elect for 2030. But getting there won't be easy or cheap, and that's a big problem for a segment of the energy industry that, with the exception of a brief surge of profitability several years ago, has generally returned no more than the cost of capital.

To see why this would be so expensive and challenging, you need to know a bit about what happens inside a refinery. All oil refineries separate crude oil into its natural fractions of LPG, gasoline, jet fuel, diesel, and heavier oils. The heart of most US refineries, however, is the Fluid Catalytic Cracking Unit, or "cat cracker", a massive device for breaking down and reassembling the molecules found in "vacuum gas oil" and "coker gas oil"--some of those heavier oils I mentioned a moment ago. The result is high-octane gasoline for blending, along with the precursors for making "alkylate", a key constituent of California-type reformulated gasoline. These units also make some low-quality diesel that is typically either processed further or sold into the bunker fuel market.

A refinery with a big cat cracker is fundamentally a gasoline machine, and there's very little you can do to change that, short of shutting the unit down and replacing it with a big, expensive "hydrocracker", which uses hydrogen generated mainly from natural gas to turn those same heavy gas oils into jet fuel and diesel. The other possible end of the ethanol road for US refiners would involve a huge ramp-up in synthetic diesel production, from gas-to-liquids and/or biomass-to-liquids, followed by a wave of refinery closings to end the growing global gasoline surplus. Either route involves hundreds of billions of dollars of investment, in aggregate, and the usual problems in obtaining the necessary permits and environmental offsets.

The energy industry has often attracted unintended consequences, and this one looks like a dandy: We create incentives and mandates for ethanol to substitute for gasoline (and thus imported oil) and end up driving up not just the price of food from which we make ethanol--notwithstanding claims to the contrary in the latest PR and lobbying campaign from the ethanol industry--but also the price of diesel fuel and heating oil, while having much less net impact on oil imports than we imagined. Biofuels will be a fact of life from now on, and along with CNG and electrified vehicles, they are probably a necessity, with oil production looking unlikely to keep up with long-run demand. The oil industry is already getting on this bandwagon. However, the dislocations this creates would be a lot easier to justify, if the biofuels involved were at least produced from feedstocks and processes that didn't consume food and nearly as much energy as the fossil fuels they are intended to displace.

Conference Highlights

I spent the last three days at the annual energy investment conference held by the sponsor of this blog, John S. Herold, Inc. Many of the panels I attended were overshadowed by the enormous uncertainty about the US financial system and pending bailout proposals, along with the Presidential election, the dynamics of which appear to have shifted again. However, the sessions provided some very interesting insights into an important unfolding natural resource play, along with showcasing some nifty applications of existing technology that could help to narrow the gap between growing global energy demand and the stagnating supply of conventional oil.

The two words that I heard most frequently this week were “shale gas”, the development of which just might facilitate achieving some of Mr. Pickens’s ideas about energy security. This is not the kind of shale that has been touted as a nearly unlimited source of unconventional oil, but rather a layer of natural gas-bearing rock that until recently was very difficult to tap. But as several panelists explained, companies have “cracked the code” for drilling into these deposits and producing flows that compete favorably with conventional gas fields in both output and cost. The result could be a modest gas bubble—a period of relatively abundant US natural gas supplies—though it comes with an inherent price floor not far below current levels. So while it is unlikely to rejuvenate struggling gas-based industries such as fertilizer production, for which $7/MMBTU is still quite dear, it could support expanded natural gas use in both transportation and power generation, where it could yield significant environmental and cost benefits.

One of the two technologies that impressed me was featured on the Alternative Energy panel I moderated. One of the founders of DKRW Advanced Fuels described a clever application of off-the-shelf technology that turns Wyoming coal into unleaded gasoline without releasing the vast quantities of CO2 that have made coal liquefaction look unpalatable. This trick is accomplished by marrying GE’s gasification technology (the old Texaco Coal Gasification Process on which I worked briefly as a young engineer) with ExxonMobil’s methanol-to-gasoline process that operated for 10 years in New Zealand, until the natural gas field feeding it was depleted. The output is 87 Octane unleaded gasoline and a pure CO2 stream that will supply the region’s extensive enhanced oil recovery projects, which will effectively sequester it. This scheme creates a double energy benefit: mainstream liquid fuel from America’s most abundant energy resource, and increased output at some of our aging oil fields. Even better, it looks like this can be accomplished with lifecycle greenhouse gas emissions no worse than from conventional oil.

The other technology that caught my attention was presented by an old friend and former Texaco colleague, who is now the CEO of Compact GTL. Instead of using proven gas-to-liquids technology to unlock “stranded” natural gas reserves—non-associated gas deposits far from infrastructure or markets—he aims to apply it to the problem of “distressed gas.” He defines that as natural gas produced in conjunction with oil in projects for which the cost and logistics of traditional methods for handling the gas have become an obstacle to developing the oil field. Previously, such gas would be flared, but that practice is being phased out on environmental grounds. Turning it into synthetic oil could prove cheaper than re-injecting it into the ground, while also shortening the development cycle of some large oil fields. Another double win, if it proves practical.

With the country still debating the merits of expanded oil drilling and looking to renewable energy sources that have not yet achieved the scale necessary to wean us off imported oil and slash our greenhouse gas emissions, the approaches described above can provide a valuable bridge. They could also be real money-spinners, at a time when other parts of the economy are looking pretty sick.

Ending Oil's Monopoly

In yesterday's Financial Times (subscription required for full text) Daniel Yergin suggested that the current oil price spike is creating a historical "break point" for petroleum that will result in the loss of oil's dominance in the global transportation fuels market. The commentary by Mr. Yergin, the Chairman of Cambridge Energy Research Associates articulated a shift that has become increasingly apparent to careful observers of the industry. His conclusion that oil will "share the transport market with other sources as never before" is almost certainly correct, even if oil prices were to revert to $60 per barrel next week. There is an important corollary to Mr. Yergin's analysis that he didn't explore in his FT op-ed: At the same time that gasoline and diesel will have to share the market with other fuels, the primary sources of transportation energy will also become much more diverse, as well. That has important implications for both national energy policy and corporate strategies.

Consider the supply chain for petroleum products. Oil is extracted from underground reservoirs and transported to refineries that separate it into its familiar product categories, while transforming low value portions of the barrel into high-quality fuels and removing sulfur and other impurities along the way. A modern refinery is a complex, expensive set of hardware, but its functions would still be recognizable to an oilman from the 1930s. Even ethanol has retained this model, with corn going in one end of an ethanol plant and ethanol and its byproducts coming out the other end. The new transportation energy market that Mr. Yergin hints at will shatter this model. Oil and its products--and corn and its fuel products--will play an important role for decades to come, but they will compete with synthetic diesel and jet fuel from natural gas, coal and biomass; biodiesel, ethanol and other alcohols from a wide variety of feedstocks and technologies; and electricity and hydrogen from a multitude of conventional and renewable sources, both centralized and distributed.

This new model will break three effective monopolies: of spark-ignition and compression-ignition internal combustion engines, of gasoline and diesel fuel as the dominant energy carriers for delivering transportation energy--and note that ethanol has so far only piggy-backed on gasoline's monopoly, rather than breaking it--and of petroleum as the source of primary energy for most forms of transportation. While the market shares of all three of these monopolies are in the high 90%'s today, the signposts of change are all around us. Biotechnology promises to break down the cellulosic material that gives plants their rigid structure and turn it into ethanol and other fuels, but it could eventually give us plants that excrete market-ready fuels. Better batteries will give consumers the choice between plugging in and filling up, but they could also facilitate the much wider adoption of renewable electricity from intermittent sources such as wind and solar power. And fuel cells running on hydrogen might yet provide a practical and more efficient way to turn chemical energy into useful work onboard the vehicle, powering electric motors that will become increasingly ubiquitous on all ground vehicles.

A decade ago, this scenario was just that, one possible future outcome of a number of competing trends and uncertainties. Now, thanks to the combination of concerns about climate change and energy security, and the practical problems of $130 oil, some version of it seems more plausible than the unchallenged continuation of those three "natural monopolies" for another generation. Whatever its other faults, the "farm bill" just passed by the Congress over the President's veto takes a step in that direction, by reducing the subsidy for corn ethanol, the so-called Blenders' Credit, from $0.51 per gallon to $0.45 and using the savings to fund a $1.01/gal. direct subsidy for producers of cellulosic biofuel.

As Mr. Yergin points out, oil "is not going to fade away soon." It will take time to turn over car fleets and move new fuel processes out of the laboratory, through demonstration-scale testing, and into full commercial production. But as frustrating as the wait for these new technologies and fuels may seem, while Americans pay $4 at the pump and Europeans pay the equivalent of $8 per gallon, this energy crisis--unlike the one of the 1970s and early 1980s--might just put in place the means of averting all foreseeable future energy crises centered on oil, by reducing the status of oil producers to that of merely one transportation energy source among many.

Peak Preparation

Following on from Friday's posting on the uncertainty about how close we are to a peak in global oil production, I want to focus on a question I think is actually more important: However close we are to a peak--whether it is already here, or 5, 10, or even 20 years away--are we doing enough to prepare for the possibility of one? The short answer is no, but that doesn't mean we aren't doing anything. In fact, many of our strategies for addressing climate change and energy security also provide some insurance against the consequences of Peak Oil or its forerunner, a sustained period in which liquid fuel supply doesn't grow as fast as potential demand, and the oil-market discontinuity that would trigger.

On a basic level, oil is important for two main reasons. It is the source of most of our transportation fuels and many useful petrochemicals and lubricants, and it also accounts for 35% of the world's primary energy production. Preparing for a gap between oil supply and demand requires addressing both of these aspects of oil's value to the economy, and in that regard it dovetails neatly with the concerns about global warming and energy security that are prompting big changes in our energy policies.

For example, while improved energy efficiency is a primary strategy for countering climate change and reducing oil imports, it looks equally important in preparing for a future oil shortfall and price spike. Peak Oil worries could lend urgency to the debate over CAFE and appliance energy standards. At the same time, efforts to expand biofuels production and bridge electricity into transportation via plug-in hybrids and electric vehicles, though driven by emissions and energy security calculations, are also excellent prescriptions for mitigating Peak Oil's impact and even delaying its onset.

There are a few areas in which this one-size-fits-all logic fails. The conversion of solid and gaseous hydrocarbons into liquid fuels--CTL and GTL--looks quite useful from a Peak Oil perspective. Viewed through a climate change lens, however, it looks like an expensive diversion or downright counterproductive. And while natural gas has oddly fallen from favor with those most concerned about climate change, despite its relatively low CO2 emissions, improving our access to gas (imported and domestic) looks like another key leg of the energy security/Peak Oil axis. If Peak Oil is a significant risk, we would certainly not want to face it in the midst of an emerging natural gas crisis.

For me, all of this boils down to effective large-scale risk management. For the next decade Peak Oil remains a big uncertainty, not a given, but prudent planning must take it into account. Where it reinforces other concerns, it may prompt accelerated timetables. Where it conflicts, as on some aspects of climate change, we need a candid debate about which problem looms larger, and which consequences would be most damaging or costly. At a minimum, we should improve our monitoring capabilities, including the means of auditing global production and reserves data for all liquid fuels, not just the conventional oil on which most Peak Oil predictions are focused.

How Near Is the End?

Although Peak Oil has faded somewhat as a "front page" issue this year, after a couple of years in the limelight, yesterday I received a question suggesting that a peak was either imminent or already upon us. That prompted a quick review of global oil production data to see whether there had been any changes that might support that view. I'm generally agnostic on the whole idea of an imminent geologically-driven peak in production, as distinct from one that might occur as a result of OPEC policy or problems queuing up the necessary drilling kit, personnel and investments to keep production rising ahead of demand. As complex as this issue is, however, there is one statistic that I think provides a pretty good barometer for the proximity of a peak; based on that measure, at least, we're not there yet.

Without going through the whole Peak Oil argument again, technical and otherwise, I want to focus on one aspect of peak oil that ought to be fairly non-controversial, among both peak adherents and peak skeptics. The global distributions of oil reserves and current production are remarkably different, as a function of the upside-down economics of the oil industry, in which the low-cost producers constrain their output and the high-cost producers go flat out. OPEC countries (excluding the newest member, Angola) hold 60% of the world's proved reserves but account for only 40% of production. Fundamentally, if there is a geologically-based peak in oil production waiting for us, OPEC is much farther from it than the rest of us, so it must manifest first in non-OPEC production.

So what do the numbers tell us? Has non-OPEC production stalled or gone into decline, as many expect? After looking at the most recent data available from the Energy Information Agency (EIA) of the US Department of Energy, the International Energy Agency (IEA), and the just-released BP Statistical Review, the clear answer seems to be no. Between 2004 and 2006 non-OPEC production grew by an average of 0.5%/year, and the IEA expects growth >1% this year, in a predictably lagged response to four years of sustained oil high prices. I don't see how that would be possible if we were as close to a global peak as pessimists believe.

There are two important caveats about the above figures, and if I didn't mention them, I know my readers would keep me honest. If you subtract from non-OPEC production the contribution of Canadian oil sands projects and the rising output of Angola, the residual trend looks like a plateau, at least over the last three years. But it no longer makes sense to look at non-OPEC supply without including oil sands--which are now a fact of life--just as we routinely include natural gas liquids. For that matter, anyone looking at peak oil ought to be counting the growing contribution of biofuels and any CTL or GTL that comes along, because what matters to the market is total liquid fuel supply, not just conventional oil. As to the change in Angola's status, it highlights OPEC's recent cleverness and reinforces the significantshift in market power that is underway.

The net result of all this leaves us just as uncertain as we were before about the timing of a future peak in "oil" production, but increasingly vulnerable to OPEC's production decisions. While much of that vulnerability is the inescapable result of the maturity of the producing basins in North America and Europe, some of it is self-imposed, and we ought to be doing some serious soul-searching about the consequences of that choice. Improved fuel economy and more biofuels will help, but we could dig our way out of this hole faster with some help from the oil we've chosen to place off-limits to development.

Another Third Way

It's not unusual for big energy projects to be canceled, as the key factors determining their ultimate profitability--project cost, start-up timing, and feedstock and product values--shift. We need to be cautious about reading too much into the cancellation of any individual project. Nevertheless, ExxonMobil's announcement this week that it is terminating its planned Gas-to-Liquids (GTL) project in Qatar seems to reflect issues beyond this endeavor's sensitivity to the construction cost inflation that has hit the entire oil and gas industry. It is a signpost of the competition between alternate outlets for natural gas, and an indication of the direction of gas globalization. The outcome of this trend will determine what Americans pay for natural gas and its derivatives in the future, because of our growing reliance on imported gas from outside North America. It is also relevant to the future price of oil.

There's been a good deal of speculation in the industry about which of the two main approaches for bringing remote gas to market would win, or whether they might co-exist. Liquefied Natural Gas (LNG) had a substantial head start over the modern version of Gas-to-Liquids (GTL), which represents another branch of the WWII German Fischer-Tropsch family tree. Both of these processes turn natural gas into a liquid that can benefit from the transportation and marketing flexibility that crude oil naturally enjoys. However, LNG returns to the gaseous state after delivery, while GTL's products compete directly with petroleum products. So what's at stake here is whether gas deposits too distant to be pipelined to customers will end up augmenting gas supplies, or supplementing global crude oil production. With local gas production falling short of demand in North America and Europe, and with growing concerns about future global crude oil availability, this is an important question.

So what does the cancellation of Exxon's GTL plant in Qatar say about this dilemma? Interestingly, it points in a different direction altogether. Certainly it reflects the increased risk that higher construction costs would raise the project's breakeven relative to crude oil and expose Exxon to losses, if oil prices weaken. But the most significant fact here is that GTL didn't lose out to an LNG project. The 1.5 billion cubic feet per day gas feed for this project is apparently going to stay in Qatar, fueling power generation and supplying feed for chemicals and other industries. Viewed from the perspective of consuming countries, this is the worst possible news. This gas won't be turned into ultra-low sulfur diesel, indirectly shoring up oil supplies, or allowed to compete with other LNG projects, and thus holding down global gas prices. Instead, it will end up competing with gas-consuming industries in North America and Europe, which make petrochemicals, plastics and fertilizer and already face severe cost disadvantages.

This outcome shouldn't surprise us. Developing countries need to get the most income from their resources. Exporting the raw material makes sense, if you don't have the capital--financial, intellectual and human--to turn it into higher-valued products, or if you doubt your ability to gain access to foreign markets for those products. But in a world of transparent global capital flows and falling tariffs, going after that extra value added must look very tempting. The forces of globalization are helping to create a truly global natural gas market, on which we will rely increasingly in the years ahead, because we've chosen to constrain our own gas production by restricting gas drilling. But those same forces have the potential to dry up that global supply, simultaneously starving and outcompeting the developed country industries that would use it.