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

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Should Alaska Export More LNG to Asia?

The Governor of Alaska reportedly met this week with officials from the South Korean national gas company to discuss exports of liquefied natural gas (LNG). Ever since crude oil production on Alaska's North Slope ramped up in the 1980s, industry observers have speculated about the ultimate disposition of the significant associated natural gas reserves found with the oil. In a letter filed with the state of Alaska, BP, ConocoPhillips and ExxonMobil, the three main North Slope producers, together with pipeline company Transcanada, recently confirmed their plans for a potential liquefied natural gas (LNG) project, instead of the long-mooted pipeline to deliver the gas to America's lower-48 states. The contemplated megaproject would validate both the scale of Asia's future LNG market and the long-term nature of the US shale gas revolution.

Alaska's North Slope has already yielded 15 billion barrels of oil. Production peaked at over 2 million barrels per day in 1988 and subsequently declined to less than 600,000 barrels per day last year. With around 6 billion barrels of remaining reserves, it's still a very significant field but well past its prime. While the public has focused on its oil output, the producers and the state have long had their eyes on how best to harvest the value of the 35 trillion cubic feet (TCF) of gas dissolved in the oil. In fact, the North Slope complex has produced several TCF per year of gas for years, ranking it among the largest gas fields in the world, but almost all of that gas has been reinjected into the formation to aid oil recovery--and for lack of a market in an isolated and sparsely-populated state.

For decades the default assumption was that a pipeline would eventually be built across Alaska and Canada to link this gas to the existing network feeding the contiguous US. That idea gained traction when US marketed gas production stalled around 2000 and then began to decline. The economics of an Alaskan gas pipeline compared poorly with gas produced along the Gulf Coast, but competing with rising LNG imports looked much more feasible. Then along came unconventional gas, starting with coal-bed methane and culminating with the surge of shale production since 2005. The US gas market now has enough domestic supply to shrink coal's contribution to US power generation by 7% since 2008 and revive gas-intensive industries.

If shale gas were only a short-term phenomenon, as some have suggested, it would be of little relevance to the plans of the North Slope producers. All they'd need to do would be to delay their pipeline for a few more years, and the market would come to them. However, estimates put US shale gas resources at between 482 and 686 TCF--a 60-90 year supply at current shale production rates. And the fact that all three of the main North Slope producers have invested in significant acreage positions and production in US shale basins surely gives them insights into the longevity of those resources.
Nor is time on the side of the Alaskan producers. As oil production declines the economics of the North Slope operation will deteriorate, while keeping the Trans Alaska Pipeline full becomes more problematic. Finding an attractive outlet for the North Slope "gas cap" wouldn't just provide a new revenue source; it could keep oil production going for additional decades.

The LNG option offers several advantages, despite its estimated $45-65 billion price tag and technical complexity. For starters, it cuts roughly 1,000 miles of difficult terrain off the distance that the gas must be pipelined, in this case to a site on the southern Alaskan coast. That location is much closer to Asia, the world's largest LNG market, than export projects intended to ship LNG from the US Gulf Coast. The Asian market is also growing, thanks in part to Japan's post-Fukushima reassessment of nuclear power. The Japanese government has backed away, at least for now, from plans for a firm nuclear phase-out, but it seeks to diversify its energy sources. Among other steps taken in the aftermath of the Sendai quake and nuclear disaster, it has instituted the world's most attractive solar power incentives. Yet Japan's solar resources provide just a few hours of peak output per day, on average, requiring substantial fossil fuel generation to fill in the gaps. Power plants burning LNG are well-suited to that task.

China presents a more complex picture, with its own significant shale gas potential and an energy market expected to add as much natural gas demand by 2035 as all the world's developed countries put together. Considering the scale of eventual demand and the infrastructure necessary to bring China's shale gas to market, it seems likely that the growth of the market in the interim must depend heavily on LNG imports.

Assuming that the state of Alaska presents no obstacles and that US export permits would be forthcoming, because Alaskan LNG exports wouldn't impact US natural gas prices, the main questions that will determine the future of this project can't be answered definitively today. Among these are whether the numerous competing LNG projects being planned and built around the Pacific Rim and elsewhere will saturate the global market in the meantime, and whether the market will provide an attractive price for Alaskan LNG, influenced more by crude oil prices than by US shale gas. The North Slope producers are already immersed in these issues via their other activities, including ConocoPhillips' small LNG plant in Kenai, Alaska, which has been shipping LNG to Asia for more than 40 years. The project timeline provided to the state includes at least three go/no-go decisions along the way as the answers to these questions unfold.

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

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B.C. Aims to Sell Cleaner LNG

I just ran across British Columbia's new provincial natural gas strategy, which includes a specific strategy for expanding liquefied natural gas (LNG) production as a way to mitigate global climate change. That might sound odd to those who are worried--unnecessarily--that gas might be even worse than coal, emissions-wise, but the province seems to have a good grasp of the benefits of replacing coal combustion in Asia with cleaner fuels like natural gas. They've also come up with a unique selling point for their LNG, on the basis that it would be produced using low-emissions electricity and thus have an emissions edge over other LNG sources. Whether this will confer an advantage on B.C.'s LNG by enabling it to collect a premium or capture a larger share of rapidly growing global LNG trade remains to be seen.

This story caught my eye because it fit neatly with one theme of a webinar in which I recently participated at The Energy Collective. Although most greenhouse gas emissions from fossil fuels occur at the point of combustion in a car, truck, plane, train, ship or power plant, the upstream emissions aren't insignificant and can be reduced in some cases by employing renewable energy in their production. Examples I cited in the webinar included an enhanced oil recovery demonstration project in California that employs concentrated solar power to produce some of the steam used to extract oil from an old oil field, and another project to extract geothermal energy from hot fluids brought to the surface as part of the oil production process.

The case that B.C. makes for reducing greenhouse gas emissions from LNG production by relying on the province's bountiful hydro- and wind power resources is a different application of the same principles. That's because whether the energy for cooling billions of cubic feet per day of natural gas to its liquefaction temperature of -162ºC comes from a local electricity grid or from burning some of the gas in a dedicated cogeneration facility, in most locations this adds significantly to the lifecycle emissions of the LNG. One study that I found on the California Energy Commission's site, produced by PACE Consultants, indicates that liquefaction accounts for around 10% of the lifecycle emissions of LNG converted to electricity in an efficient gas turbine power plant. Eliminating those extra emissions by powering a liquefaction plant with green electricity would bring the emissions from LNG much closer to those from pipeline natural gas and increase its advantage versus coal.

So now what B.C.'s LNG projects need is customers in Asia who will put a premium on "cleaner LNG"--presumably in countries that have committed to large greenhouse gas emission cuts that they can't achieve with indigenous fuels. Japan comes to mind, but I'm sure there are others. These customers would also have to be willing to deal with the longer voyage times from Kitimat, northern B.C. to Asia, compared to competing projects in Australia. That extra 1,000 miles or so translates into higher freight costs and a larger tanker fleet, along with somewhat higher emissions from transportation--though not enough to negate the liquefaction advantage. With so many new and expanding LNG projects around the world competing for market share, I'll be very interested to see whether B.C.'s new strategy pays off.

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2011 in Energy: The Year of...

At the start of 2011, I thought the hallmark of the year's energy events and trends might involve regulation, with the White House seeking to implement measures that couldn't garner enough support in Congress to become laws. But for every major new regulation issued, such as last week's release of the new Mercury and Air Toxics Standards for power plants, others were delayed or deferred, including the EPA's effort to regulate greenhouse gases under the Clean Air Act and the agency's proposed ozone standard. Outside of the utilities and other industry groups directly affected by these rules, it seems likely that 2011 will instead be remembered for big, unpredictable events like the Fukushima nuclear accident and the Solyndra bankruptcy scandal, along with several major trends that reached critical mass this year. Anyone attempting to pick the energy story of the year is spoiled for choice.

In my search for a catchy title for this year's final posting, I toyed with "The Year of Solyndra", "The Year of Shale", "The Year of Fukushima", "The Year of Exports", and various other combinations of the energy buzzwords that percolated into our consciousness this year. In some ways, they'd all be apt choices. Here's a quick rundown on why they might merit that kind of recognition, with links to previous postings providing more details on each:

• If 2011 is the year of Solyndra, it's not because of the possibility that the government's $535 million loan to the firm was the result of political influence (cue Major Renault), or even that the Department of Energy is unlikely to recover more than pennies on the dollar in the firm's bankruptcy. Instead, it's because Solyndra highlighted the much broader and deeper problems of a global solar industry that, despite continued demand growth that other industries would kill for, now faces overcapacity and the fallout from the winding down of unsustainable government support. Germany's Solar Millennium is just the latest victim of this trend. Along with BP's exit from the solar business after 40 years, it provides a further reminder that renewable energy firms must succeed not just as technology providers, but as businesses that can earn consistent profits and continue to attract investors.



• Shale gas was hardly new to the scene in 2011; it has been expanding rapidly for several years and now accounts for up to a third of US natural gas production. However, the controversy surrounding drilling techniques like hydraulic fracturing that make its exploitation possible became much more widespread this year, while some scientists raised questions about its contribution to greenhouse gas emissions. Shale gas has the potential to transform nearly every aspect of our energy economy, and probably sooner than renewable energy sources could. That has some folks nervous, while others are eager for shale gas to displace coal from electricity generation, compete with oil in transportation, and revive the domestic petrochemical industry. I suspect we'll see all of those to some extent, provided we don't regulate shale out of the running.



• The aftermath of Fukushima could prove equally transformational, though it remains to be seen whether the ultimate result is safer nuclear power or a global retreat from one of our largest sources of low-emission energy. All but 8 of Japan's 54 nuclear power plants are currently idle, and that nation must shortly decide whether it will eventually restart those units that weren't critically damaged, or shut down the rest and attempt to run its manufacturing-intense economy on a combination of renewables and much larger imports of fossil fuels. The German government's post-Fukushima decision to phase out nuclear energy entirely could provide an even quicker test of the same proposition.



• Another major shift that has been in the news recently involves exports. Although the US has long exported coal and various petroleum products, we could shortly become a bigger, more consistent exporter of many fuels, including liquefied natural gas (LNG), gasoline and diesel. As the reaction in a CBS news segment last week demonstrated, the US public doesn't know quite what to make of this, yet. Becoming a major energy exporter while still importing a net 9 million barrels per day of crude oil is very different than the picture of isolated self-sufficiency that four decades of "energy independence"rhetoric has evoked. We shouldn't be surprised that energy can provide a boost, and not just a drain on our trade balance. This topic requires more public discussion and education, before we see serious proposals to ban such exports--proposals that would make no more sense than banning exports of corn, tractors, or aircraft in an attempt to keep their US prices low.



• It's also tempting to call this the Year of Oil Price Confusion. The news media gradually woke up to the huge gap that had developed between global oil prices and the oil price that Americans tend to watch most closely, the one for West Texas Intermediate crude. Yet despite numerous stories on the storage and pipeline crunch and supply glut at Cushing, Oklahoma, few reporters and networks seemed able to follow through by breaking their old habit of treating the NYMEX WTI price and its gyrations as if it were still the best indicator of the overall oil market. Fortunately, the problem is in the process of being resolved, as pipelines are reversed and more tankage built.



• Finally, there was the administration's non-decision on the Keystone XL pipeline. Observers can read much into this, including the growing influence of citizen activists mobilized via social media. However, if it does nothing else, the Keystone controversy should put to rest the superficial fallacy that anything that improves greenhouse gas emissions is automatically good for energy security, instead of requiring difficult trade-offs. In that context, the prospect that the administration might ultimately turn down the permit for Keystone would be easier to stomach if the net greenhouse gas savings involved amounted to more than a paltry 0.3% of annual US emissions, based on the emissions from incremental oil sands production the pipeline might facilitate, compared to those from the conventional imported oil it would displace.

It was a busy year for energy, and if my short list of top stories missed something crucial, please let me know. 2012 promises to be just as interesting, with a Presidential election, in which energy issues could feature prominently, added to the mix. In the meantime, I'd like to wish my readers in the UK and Commonwealth a happy Boxing Day, and to all a Happy New Year.

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Energy in the Aftermath of the Sendai Quake

Investors and companies around the world are scrambling to assess the impact of the Sendai earthquake and tsunami on supply chains and markets, both within Japan and globally, between the direct damage from the event and the disruption to critical infrastructure in its aftermath. An item I spotted in this morning's Wall St. Journal provided an early clue concerning the potential ripple effects in global energy markets, as Chevron sold a cargo of Indonesian crude to a power customer south of Tokyo. However, it remains to be seen whether demand destruction or the impairment of supply capabilities will dominate over the short, medium and longer-term recovery periods.

The impact on the Japanese power grid extends beyond the shutdown of 9,702 MW of nuclear power capacity, including 2,812 MW at Fukushima Daiichi that will not resume operations for many years, if ever. Some fossil fuel power plants have also shut down, and more than a fourth of the country's refining capacity is down, cutting off a significant supply of power plant fuel oil, along with a wide range of other petroleum products. That helps explain the interest in light, sweet Indonesian crude that can be burned directly in power plants as a replacement for low-sulfur fuel oil. Significant quantities of Indonesian Minas crude formerly came to the US west coast for a similar purpose, when we still had a lot of oil-fired power generation, although the crude was normally processed to remove the valuable light products from the fuel oil before sale to utilities. (My first job in the industry was at a refinery that did just that as part of a contract Texaco had with a southern California utility.)

Burning crude oil for power is a practical stop-gap, and as long as so many of Japan's refineries remain shut for damage assessment and repair, it shouldn't have much impact on the global crude market, since the crude those refineries would have otherwise run is now surplus. That explains the $5 per barrel drop in crude prices this week. However, if demand recovers faster than Japanese refinery capacity returns to operation, much of that extra crude oil will need to be processed in refineries elsewhere around the Asia-Pacific region, to provide the refined product imports that Japan will need.

It's much harder to assess the medium-term situation, because it will be some time before the full extent of the damage to industry, power generation and transportation is known. If more demand was destroyed than the capacity to supply it, then Japan could actually end up with surplus energy capacity until demand recovers, and that would be a bearish factor in global energy markets. If more energy supply than demand was destroyed, as seems possible given the largely agrarian nature of the part of Japan that suffered the worst consequences of the quake and tsunami, then Japan could be importing additional supplies of energy from regional sources for a long time.

I've had several people ask me about the potential of these events to increase Japan's demand for renewable energy, and I think that's a likely outcome. As of the end of 2009 Japan already had the world's third-largest installed solar power capacity at 2,600 MW, to which another 1,000 MW or so was apparently added last year. For Japanese businesses suffering from rolling brownouts, solar power is one of their few options other than diesel generators for becoming more self-sufficient fairly quickly. However, at the scale of the grid, intermittent solar isn't a great substitute for 24/7 nuclear power. With Japan's average solar insolation, it would take about 5,000 MW of solar panels to replace the annual output of a just one of the Fukushima Daiichi reactors (#2, 3 or 4) at an installed cost in the neighborhood of more than $20 billion. That might give a welcome shot in the arm to photovoltaic manufacturers that are still expanding rapidly but have been overly-dependent on faltering European solar incentives. I don't know enough about the Japanese grid to know how easily they could adjust to such a shift from centralized, baseload power to distributed, cyclical generation.

The long-term outcome seems impossible to gauge at this point, and I hesitate to even speculate while the engineers are still working to cool down the damaged nuclear plants. (The American Nuclear Society has a useful site with updates and background on the Japanese reactors.) Much depends on how well Japan's nuclear industry will be seen to have responded to these incidents. Unless these facilities are either rebuilt or replaced with new, next-generation nuclear plants, then Japan's imports of LNG, coal and other fuels could increase significantly, until and unless renewables ramped up enough to make up the difference. Japan is already the world's largest importer of LNG, and it is perfectly situated to absorb the output of the new LNG plants planned for Australia. That could boost global LNG prices for years to come.

Disclosure: My portfolio includes investment in Chevron, which is mentioned above and owns projects and facilities that could be affected by these events.

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Natural Gas and The Gulf Hiatus

With so much attention focused on the boom in natural gas from new shale resources, we shouldn't lose sight of the importance of domestic offshore gas, mainly from the Gulf of Mexico. Although it has been declining for the last decade, offshore production still accounts for about 13% of US gas output. Before the Deepwater Horizon disaster the Department of Energy expected that proportion to increase again to as much as 18% of a larger total. However, if drilling in the Gulf doesn't resume--and fairly soon--not only could that portion of our supply deplete rapidly, but its shrinkage would erase much of the incremental contribution from shale gas, a scenario depicted in the chart below. If that occurred, ambitious plans to capitalize on shale gas to displace coal or imported oil would be nullified, and gas prices would shortly revert to their previous upward trajectory.

Despite the official end of the deepwater drilling moratorium and the recent release of new guidelines to aid the industry in filing for deepwater permits, it doesn't look like drilling has resumed or is likely to do so any time soon. Meanwhile, deepwater drilling outside the US seems to be recovering rapidly. It's almost irrelevant whether the ongoing US offshore hiatus is the result of the complexity of new rules and regulations, inadequate staffing of the reorganized Bureau of Ocean Energy Management, Regulation and Enforcement, or what some believe is a tacit, unofficial moratorium on the part of the administration. Together with the recent withdrawal of plans to lease portions of the Eastern Gulf of Mexico, where significant gas resources had already been discovered, the hiatus threatens to return the US to our previous situation of increasing reliance on LNG imports, in spite of growing shale gas output.

Aside from the gas volumes and the significant number of industry and related jobs involved, there's also a fair amount of government revenue at stake in the form of forgone royalties and bid bonuses. Salazar's announcement indicated new offshore leasing wouldn't resume until late next year, at the earliest. That wipes out at least $500 million of expected bonuses--the figure for 2008 was $6.9 B--and the aggregate production decline resulting from no new drilling would lead to a steadily increasing loss of annual royalties, as existing fields deplete and aren't replaced. Between extended environmental studies, delayed permits, and areas re-designated as off-limits that were expected to be available within the 2007-12 cycle, our offshore energy supplies are looking precarious, and that will eventually influence the price we pay for energy--for both gas and imported oil. Recent polling suggests the majority of Americans understand that.

As I've noted before, no one expects things to revert to the way they were before this summer's massive oil spill. However, if we erect too many obstacles in the way of exploiting the abundant hydrocarbon resources of the Gulf of Mexico--even for natural gas, which although subject to the risk of blowouts presents little or no risk of spills like the one from the Macondo well--the costs will not just be financial; they will extend to our environment and energy security.

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Closed-Loop Energy

This morning I received an emailed press release announcing that the Altamont landfill gas facility in California had been recognized by the state's governor for its achievement in sustainability. What makes this facility unique is that the methane gas generated by the landfill waste is collected and turned into liquefied natural gas (LNG) in a plant run by a joint venture of Waste Management and the North American subsidiary of the Linde Group and then used to power garbage trucks that haul San Francisco's waste to the landfill. That effectively "closes the loop" by turning trash into fuel to collect the trash. It's a clever concept, but I admit to being initially skeptical about the companies' claim that this approach saves 98% of the greenhouse gas emissions from the diesel fuel it replaces. How can that be, when every pound of methane burned in the trucks' engines yields 2.75 pounds of CO2?

The answer to this conundrum lies in the assumptions behind the analysis of the project done by Argonne National Laboratory, which is generally considered the gold standard for lifecycle, or "well-to-wheels" analysis of this kind. Quoting from their report, "At present most of the biomethane generated at U.S. landfills is flared in conjunction with emissions-abatement practices." Since 1996, landfills above a certain threshold have been required to collect methane and other gases produced by the decomposition of refuse and either flare it or put it through a thermal oxidizer to convert the methane to CO2. That's crucial from an emissions perspective, because it reduces the landfill's greenhouse gas emissions by a factor of 21 times versus simple venting. However, the report also states that over 500 projects around the US recover energy from landfill methane, with most either using it to generate power or steam or compressing it and injecting it into natural gas pipelines, where it becomes indistinguishable from the methane produced from natural gas wells. When Argonne confirms that Altamont's LNG emits practically no greenhouse gases, that result is relative to the option of flaring it, not compared to the other uses to which the recovered gas could be put.

The appropriateness of that assumption goes to the heart of the issue of "additionality" that has made the certification of emissions credits so challenging in many cases around the world. In this case, if the Altamont landfill gas in question weren't turned into LNG to fuel San Francisco garbage trucks, would it really be flared or would it be turned into power, as other gas produced at Altamont apparently is? On one level I can't answer that without knowing a lot more about the facility than is provided either on Waste Management's site or in the Argonne analysis. However, it helps to consider that an assessment of any other use of this gas would face the same question; they can't all be compared to each other. There must be a common reference, and going back to flaring, which is the basic standard required under the Landfill Rule of the Clean Air Act, seems the most consistent choice.

With that assumption in hand, and based on Argonne's analysis of the emissions from the different steps involved in producing the LNG, it's perfectly reasonable to claim that at least compared to burning petroleum diesel in Waste Management's trucks, the Altamont LNG is a nearly zero emission fuel. The more interesting question is whether this disposition, with its obvious green PR benefits, is actually the best use of the energy recovered from the landfill. The same Argonne report indicates that the total energy consumption in the landfill gas-LNG-motor fuel pathway is about 8% higher than in the oil well-refinery-motor fuel pathway for diesel fuel. That hints at the possibility that the total emissions reductions from Altamont might be even greater if the gas were used, not to power garbage trucks, but for another purpose, such as generating power to back out electricity imported into the state from coal-burning sources in places like Four Corners, New Mexico. In any case, lest we make the perfect the enemy of the good, what Waste Management and Linde are doing at Altamont is certainly good compared to the default option of flaring all that gas, and the kudos they have received look well deserved.

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Ammonia As An Alternative Fuel?

In the last seven years I've written extensively about a wide variety of alternative fuels, including ethanol, methanol, and higher alcohols like butanol, along with compressed and liquefied natural gas (CNG and LNG), hydrogen, and electricity, but I find I haven't said anything about anhydrous ammonia. It turns out that there is a small but enthusiastic group of people promoting its use as an alternative fuel, going back to at least the 1940s. Much of the recent interest in this stems from the fact that ammonia releases little or no greenhouse gas when burned, and that it's possible to produce it by means that involve minimal GHG emissions throughout its lifecycle. However, when you dig into this a little deeper, you discover that almost all ammonia today is produced by the Haber process, using hydrogen sourced from natural gas. And if that weren't enough of a deterrent, the physical properties of ammonia render it an unattractive candidate for a mass-market fuel.

So-called "green ammonia" would avoid natural gas by substituting hydrogen from electrolysis using wind, solar or other renewable electricity. As long as natural gas remains abundant, it's hard to envision this growing beyond a small niche, because the price of ammonia will ultimately be set by the price of natural gas, which remains a cheaper source of hydrogen than electricity from any source, let alone from expensive renewable power sources. Moreover, electricity is fungible, and the best use of renewable or other low-emission power (e.g., nuclear) is probably in backing out power from higher-emitting sources, rather than diverting it into inefficient production of chemicals. As a result green ammonia, like green power, would require subsidies for at least the near-to-medium term if it is to compete with conventional ammonia, which seems like a crucial prerequisite for competing with conventional fuels. And without green ammonia, the whole rationale for an ammonia fuel-and-vehicle network looks questionable--why not just use the gas as CNG or LNG instead, with a fraction of the headaches?

Even if that weren't the case, ammonia faces serious obstacles as a consumer fuel, compared to either conventional fuels or to many other alternatives. Start with energy density, which is less than half that of gasoline by weight, and about 40% by volume. So a gallon of ammonia would only take you about 40% as far as a gallon of gas, even if you could burn pure ammonia in your engine--and from what I've read it still requires help from another fuel to sustain combustion. (That means two fuel tanks, which constitutes another major hurdle with consumers.)

Then there are the economics. Ammonia itself isn't exactly cheap, if you adjust for its energy content. The price of bulk ammonia for agricultural use appears to be around $550-$600/ton, which equates to $1.55-1.70/gal. But when you factor in its lower energy density, that raises it to at least $3.85/gal. of gasoline equivalent, without any fuel taxes. And while a distribution system exists to supply farms with ammonia, this is a long way from what would be required to fuel anything beyond farm vehicles. Because ammonia boils well below ambient temperature, it must either be refrigerated or stored under pressure, and dispensed through special equipment. And if all that weren't daunting enough for any service station owner considering adding an ammonia pump on the forecourt, the safety aspects of ammonia handling look even worse.

A glance at a typical material safety data sheet (MSDS) for anhydrous ammonia reveals that the recommended exposure limits are very low, under 50 parts per million in air, and the consequences of exposure include caustic burns and much more serious outcomes. Gasoline has its own issues, but spilling some on your hand won't send you to the hospital, and a larger spill or leak doesn't require first responders in hazmat suits. I simply can't imagine any fuel retailer wanting to take on the liabilities that would go along with this, even if there were an attractive margin in it, which there doesn't appear to be.

I concluded long ago that we're heading into a period of much greater fuel diversity, and that certainly seems to be true, with LNG catching on for big-rig trucks and CNG for a few cars but more fleet vehicles and buses, and even hydrogen appearing in a few places for fuel cell vehicles. However, it's very hard to imagine a substance with as many drawbacks as ammonia coming into wide use for consumers or even fleets. Our range of alternative fuel options seems sufficiently broad already, without having to consider a fuel that turns into a poison gas at atmospheric pressure and temperature.

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Pickens Plan, the Sequel

How can you not love T. Boone Pickens? Here's someone who made his fortune in oil, and now he's advising us to switch major parts of the US economy to wind and natural gas. And unlike some of the other concepts for taking a big bite out of our oil consumption, his current idea actually stands a chance of making a significant difference on a timescale of years, rather than decades. At the same time, however, Mr. Pickens has sometimes been a tad bit less than accurate with the numbers he uses to make his points. Remember those ads about the $700 billion per year we were sending overseas to buy oil? Even at its absolute peak in July 2008, reality was more like $500 billion, and the total for 2008 ended up around $385 billion, based on net imports and the average refiner acquisition cost for the year. That's hardly peanuts, but it's roughly half his cited figure. So let's take a look at the key numbers behind his proposal to convert long-distance trucking to natural gas. It's a great idea, though not quite as much of an economic slam-dunk as it might seem when he describes it.

I just finished reading the interview with Mr. Pickens in The American Spectator, published yesterday. The big shift in the Pickens Plan since the first time I examined it in detail is that he has switched his emphasis from using wind to free up natural gas to replace gasoline in cars, to using the abundant natural gas from our enormous shale gas reserves, which are already transforming the US gas and power markets, to replace diesel fuel in big-rig trucks. He is also in the process of lining up the legislative support to nudge this along much faster than market forces alone would. But does it make as much sense as he suggests when he talks about using $4.50 worth of natural gas to replace 7 gallons of diesel fuel at $3 per gallon?

Strictly in energy terms, that 7 gallons might even be a bit low. A million BTUs of gas (roughly 1,000 cubic feet or one MCF) would deliver as much energy to a truck as 7.8 gallons of diesel. And fundamentally, he's right that the recent price relationship between natural gas and crude oil makes gas a tremendous bargain, BTU for BTU. However, the prices he mentions in the Spectator interview constitute an apples vs. oranges comparison from both sides. Even if natural gas remained at a steady $4.50/MCF at the wellhead for the next 20 years, which seems unlikely despite the bounties of shale, that's not what you'd pay at the natural gas pump.

Start with the fact that it costs something to transport gas from the wellhead, wherever that might be, to market. Based on current pricing relationships, if gas starts out at $4.50, then by the time it's sold to a commercial account, which is probably how filling stations would be classified, it could cost as much as $9. And someone has to invest in the equipment to compress it to 3,000 or 3,600 psi and pump it into an 18-wheeler's tanks. Even with tax credits to help, a station owner will need to make a return on that investment, and some profit, too. Add another buck an MCF to cover that, and we're up to $10/MCF, which equates to $1.28/gal. of diesel. For a reality check on this, I took a look at cngprices.com, which shows the locations and pricing for stations selling compressed natural gas (CNG) for vehicles around the country, expressed in dollars per gasoline-equivalent-gallon (GGE). Prices range from roughly $1.25 to around $2, with a few outliers over $3. Since a GGE contains about 10% less energy than a gallon of diesel, you'd have to bump these prices up by about 10% to get the equivalent for a fair comparison.

Under $2 is still pretty cheap, but you shouldn't compare that to the $2.90/gal average retail price of diesel this week. The latter includes federal excise tax of $0.244/gal. and state excise and sales taxes that range from $0.08-0.49/gal. and average $0.281/gal. As best I can tell, CNG is taxed at the federal gasoline rate of $0.183/gal., while states seem to tax it to a much lesser extent than gasoline and diesel, as for example the $0.085/gal rate in Utah, compared to their state fuels tax of $0.245/gal. However, this is only viable as long as demand for CNG is tiny, relative to other fuels. If Mr. Pickens succeeds in displacing large quantities of diesel with CNG, then it will either need to carry a similar tax burden, or the lost revenues must be collected in some other fashion. If you strip out the taxes to get to an apples-to-apples price to compare diesel to CNG, it works out to around $2.50, give or take a dime or two, depending on location. So while CNG is still clearly cheaper than diesel, it's rarely $1/gal. cheaper on a truly comparable basis. This, together with conversion costs as high as the $65,000 per truck that Mr. Pickens cited, might explain why market forces alone haven't led to a rapid switch to CNG-fueled transport.

I've looked at the House bill containing the natural gas vehicle tax credits mentioned in the interview. It would cover as much as 80% of the incremental cost (over the diesel version) of a truck that can only burn CNG or LNG, up to $80,000, depending on weight. It would also extend the $0.50/GGE tax credit for CNG and LNG through 2027. These changes would drastically shorten the payout of an investment in a natural gas-powered truck, even if the per-gallon advantage of CNG appears to be somewhat less than Mr. Pickens suggests. That could move CNG into the truck-fuel market pretty quickly.

The remaining question is what the $7 billion investment Mr. Pickens wants the government to make in this proposition would buy us. He believes that converting the US heavy truck fleet to CNG would save 2.5 million bbl/day of diesel, or about two-thirds of the diesel and heating oil now sold in the US. That would have a much bigger impact on our oil imports than ethanol, although it's hardly an either/or proposition. I'm surprised that Mr. Pickens didn't go on to suggest that this benefit could be leveraged further by utilizing the resulting surplus diesel in diesel automobiles. Given their approximately 30% improvement in fuel economy vs. comparable gasoline vehicles, that could save an additional 750,000 bbl/day of gasoline, while reducing greenhouse gas emissions on those cars by about 20%. If you play all this out, then just under 5 trillion cubic feet per year of natural gas, or less than a quarter of current gas production, could save more than 3 million bbl/day of gasoline and diesel, or nearly a third of our net petroleum imports.

That sounds like a pretty good deal for $7 billion, though it could be made even better if the vehicle tax credits involved were converted into low-interest loans and loan guarantees, instead. If the main impediment to switching to gas is the up-front cost of natural gas conversions and the time involved in recouping that cost, then let's make it much easier for truckers to borrow the money for this purpose, and for banks to lend to them. Giving everyone taxpayer money to induce them to do what we want makes a lot more sense when the government has plenty of money to spend. With the US running large deficits and the private sector holding lots of cash earning next to nothing, we should use our tax dollars as efficiently as possible to achieve the same outcome. Otherwise, Mr. Pickens seems to be on to a sensible idea, and I wish him luck selling it.

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Shale Gas and Drinking Water

Life is full of unintended consequences, and the energy industry is currently dealing with a significant one related to the step-change in US natural gas reserves and production made possible by exploiting gas resources locked up in deposits of a sedimentary rock called shale. The very success of these efforts has placed a decades-old, widely-used drilling technique called "hydraulic fracturing" at the center of a major controversy. In fact, it's hard to find references to fracturing (often called "frac'ing" or "fracking") that don't describe it as a "controversial drilling practice." As best I can tell from delving into the technology involved, the controversy around fracking is largely an artificial one, though that hasn't deterred Congress from holding hearings on it or introducing legislation to regulate it further at the federal level, on top of the state level where it already appears currently well-regulated.

I should preface my comments on fracking by pointing out that I haven't had any direct experience with the practice, either during my time at Texaco or in my studies of chemical engineering, a field that overlaps petroleum engineering extensively, though not in the specifics of this subject. My analysis and conclusions are the result of some research and a lengthy conversation with a former mentor who knows more about fracking from first-hand experience than most of us ever will.

The main concerns about fracking today involve its potential risk to our supplies of drinking water and the adequacy of current regulations to address this. Understanding whether these concerns are justified requires knowing a bit about how fracking works, as well as where drinking water comes from. I could fill up several postings exploring each of those topics, but for the purposes of this discussion let's take a quick look at one of the shale regions at the heart of this controversy, the Marcellus Shale in the Appalachian region of New York, Pennsylvania and the Virginias. In the course of my research I ran across a handy document on groundwater from Penn State. Aside from surface water (lakes, rivers and streams), it identifies the various aquifers in Pennsylvania by type in Figure 4. The key fact from the perspective of fracking safety is that the deepest of these aquifers lies no more than about 500 ft. below the surface, and typically less than a couple of hundred feet down. By contrast, the Marcellus Shale is found thousands of feet down--in many areas more than a mile below-ground--with a thickness of 250 feet or less. In addition, the gas-bearing layers are sealed in by impermeable rock, or the gas would eventually have migrated somewhere else. In other words, the shale gas reservoirs are isolated by geology and depth from the shallower layers where our underground drinking water is found.

Now consider what happens during drilling. As illustrated in this video from the American Petroleum Institute, the drill must go through the layers that might connect to a drinking water source on its way to the gas-prone shale far below. However, before the deeper horizontal portions of the well are fractured to create fissures in the shale through which the gas can flow, the vertical well is cased in steel pipe and cemented to the rock. This, by the way, is already required by law, and it seals off any possible connection with a drinking-water aquifer before the first gallon of fracturing fluid is pumped into the well. That fluid is mainly water, plus a few chemicals, such as surfactants (detergent) and gel to carry the sand used to prop open the fractured fissures. Some of that water remains in the reservoir--isolated from drinking water--and most of it is returned to the surface where it is captured for treatment and either disposal or re-use in another fracking job. As long as the well was completed in accordance with standard practices, the primary risk to water supplies is from surface activities that are already thoroughly regulated and have been for years. Accidental contamination of surface or groundwater would be handled by the appropriate authorities, and a driller would be liable for any damages.

The more I learned about fracking, the more puzzled I became that it has attracted so much criticism recently. After all, the practice was developed in the late 1940s and has been used since then in hundreds of thousands of wells to produce literally billions of barrels of domestic oil and trillions of cubic feet of domestic natural gas. That wouldn't be the case if this were some new, risky practice. In fact, it is an entirely mainstream industry practice that has become so vital to the ongoing production of oil & gas from the highly-mature resources of the United States that a study by Global Insight suggested that restrictions on fracking could cut US gas production by anywhere from 10-50% within this decade, depending on their severity. Similar consequences for oil production would follow. The only thing new here is the clever application of fracking with state-of-the-art horizontal drilling to shale reservoirs that couldn't economically produce useful quantities of gas without them.

The fracking controversy also involves a surprising irony: While many of us recall the old cliché about oil and water not mixing, it turns out that oil, natural gas and water are often found together deep underground--and this is not drinking water I'm talking about. Water is also routinely injected into producing oil & gas wells, either as liquid or as steam, in order to enhance recovery, and many wells produce a lot more water than oil. As a result, the oil & gas industry handles staggering volumes of water every day. By comparison fracking, in which water is only used to prepare a well and is not part of the ongoing production process, accounts for just a tiny fraction of the industry's involvement with water--all already regulated, I might add.

So how do we explain the current ruckus over hydraulic fracturing? Perhaps one reason this old practice is attracting new scrutiny is because it's being applied in parts of the country that haven't seen a drilling rig in decades, where it provokes a similar reaction to the arrival of 300-ft. wind turbines, utility-scale solar arrays, and long-distance transmission lines. But rather than just writing this off as yet another manifestation of NIMBY, I'm truly sympathetic to concerns about the integrity of our drinking water. My family drinks water out of the tap, and I would be irate if I thought we were being exposed to something dangerous. When you examine the science behind fracking and see that, if anything, these wells are drilled and isolated with more care than many water wells (which I understand often aren't cased and cemented to protect the water source from contact with other sedimentary layers) it becomes clear that the biggest potential exposure occurs not underground but at the surface, where fracking is just one of many other regulated industrial water uses, and a fairly small one at that. Thus, whether intentionally or as a result of a basic misunderstanding of how this technology works, we are being presented with a false dichotomy concerning shale gas and fracking. The real choice here isn't between energy and drinking water, as critics imply, but between tapping an abundant source of lower-emission domestic energy and what looked like a perpetually-increasing reliance on imported natural gas just a few years ago.

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Mega Gas Project

I took some pride in Chevron's announcement earlier this week that it and its partners would proceed with construction of the Gorgon LNG plant in Australia. That's partly due to my vicarious interest in this project as a Chevron shareholder, but mainly from my peripheral involvement in the early stages of planning and thinking about it when I worked at Texaco. Prior to merging with Chevron, Texaco held a 25% interest in the Gorgon natural gas field, as did Chevron, ExxonMobil, and Shell. Because of the scale of the resource involved, even that one-quarter share was enough to make Gorgon potentially one of Texaco's most valuable long-term assets. However, the technical complexity of the project, combined with the uncertainties about the future global gas market, made it difficult to create the necessary consensus among the partners about how best to proceed. In retrospect, it probably took the merger to give one party a big enough stake in the project to drive it forward.

At a planned production rate of 15 million tons per year of liquefied natural gas (LNG) and 300 terajoules per day of pipeline gas for use on the mainland, it's a little hard to put the scale of the project in perspective. It works out to around 2.2 billion cubic feet per day of total natural gas delivery, which is equivalent to the entire production of the largest independent US gas driller, Chesapeake Energy Corp., one of the most aggressive developers of the shale gas deposits that are transforming the US natural gas market. If Gorgon's entire output were sent to gas turbine power plants, it would generate around 85 billion kilowatt-hours per year, as much as 32,000 MW of wind turbines or 9 nuclear power plants of 1200 MW each--and over a similar 40 year operating life. However you look at it, it's big.

Among the challenges the field's owners needed to overcome in order to get to this point was a plan for handling the relatively high CO2 content of the gas in the Gorgon field, at around 12%. Even a decade ago, it was becoming clear that such large quantities of CO2 could not simply be vented to the atmosphere. According to Chevron's fact sheet for the project, the CO2 content of the gas will be separated and sequestered in geological reservoirs under Barrow Island, where the LNG plant will be located, and it will apparently rank among the world's largest carbon capture and sequestration (CCS) projects to date, with total storage of up to 120 million tons of CO2 over the life of the project.

Of course, that doesn't negate the entire greenhouse gas impact of such a project, which must be compared to the emissions that would occur if it didn't proceed. Chilling natural gas to -260 °F, at which it becomes a liquid, requires a significant expenditure of energy, typically generated by burning more gas. As a result, the lifecycle emissions of LNG are somewhat higher than those for pipeline gas, though they are still substantially less than from the coal or oil it would displace in power generation in the Asian market for which most of Gorgon's output is slated. According to a recent study by Pace Consultants, the emissions from gas liquefaction, LNG transportation, and re-gasification at destination would effectively increase the lifecycle emissions from a combined-cycle power plant by roughly 22%, compared to one running on domestic (pipeline) gas. However, that result would still come in around 40% lower than the emissions from the best coal-fired power technology without CCS, and 60% less than typical coal-fired power plants.

Technology has also advanced in other areas, since the Gorgon field was first discovered in the early 1980s. The idea of developing Gorgon and the nearby fields such as Jansz and Chrysaor using sub-sea completions, with no surface platform standing above them, is a reflection of how far the state of the art has come since then. The comparison of Gorgon's offshore and onshore footprint to Australia's other giant offshore gas field, the Northwest Shelf, which was developed in that timeframe using then-current technology, is remarkable. As one of the videos on Chevron's Gorgon sitelet points out, the development also had to be done in a manner that was harmonious with the nature preserve on Barrow Island. That complicated the permitting process and added additional years to the development timeline.

And that's really my key take-away for this project. While a variety of factors contributed to Gorgon's requiring something like 33 years from discovery to first production, big energy projects aren't like building a supermarket or office park. Aside from the great patience these efforts require, large sums of money must be spent over a long span of time before the first dollar of revenue can be collected to recoup them. That requires the deepest of pockets and the most meticulous strategic and financial planning. Only governments and the very largest companies--with massive free cash-flow or debt capacity--can pull this off. Moreover, because of the numerous risks associated with geology, permitting and development, a project like this works best when that risk is shared by more than one party, each of which has a portfolio of sufficient size and diversity to absorb the delays that are inherent in such ventures. So while it's true that the oil Super Majors need big LNG projects to bolster reserve replacement and cash flows that are being pinched by the challenges of gaining access to large-scale oil projects in the current environment, the global supply of clean gas from such projects would be much lower, without companies on this scale to develop them. This is a match that is both good for business and good for the long-term decarbonization of global energy supplies.

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