Tuesday, April 22, 2014

ExxonMobil Confronts the Carbon Bubble

  • Companies and investors are squaring off over the potential impact of government climate policies on asset values, particularly in the fossil fuel industry.

  • ExxonMobil gave its shareholders data and assurances of asset resilience under various policies but dismissed the scenario of greatest interest to sustainability investors.

Last fall I devoted a lengthy post to the notion that future policies to address climate change expose investors in companies producing fossil fuels to a potential bubble in asset valuations. So although I am not an ExxonMobil shareholder, I was particularly interested when the company issued a report last month responding to specific shareholder concerns along these lines. Although the term “carbon asset bubble” did not appear in the report, its references to carbon budgets and the risk of stranded assets in a low-carbon scenario were aimed directly at this emerging meme.

Unsurprisingly, ExxonMobil’s management reassured investors that, “none of our hydrocarbon reserves are now or will become ‘stranded’.” Wisely avoiding past tendencies to question interpretations of climate science, their analysis appears to be grounded in mainstream views of climate change. It focuses on the costs and achievability of an extreme low-carbon scenario, and on the resilience of the company’s portfolio under various climate policies.

Exxon's analysis is based on the company’s latest Outlook for Energy, an annual global forecast broadly similar to the main “New Policies” scenario of the International Energy Agency (IEA). It has fewer similarities to the IEA’s “450″ scenario that underpins carbon bubble claims. The company expects energy demand to grow at an average of about 1% annually over the next three decades–faster than population but much slower than the global economy–with increasing efficiency and a gradual shift toward lower-emission energy sources: Gas increases faster than oil and by more BTUs in total, while coal grows for a while longer but then shrinks back to current levels. Renewables grow fastest of all, producing about as much energy in 2040 as nuclear power does today. As a result of these shifts global greenhouse gas (GHG) emissions peak around 2030 and then decline gradually.

That forecast won’t impress those advocating prompt and aggressive changes in the global energy mix to head off serious climate change, but it is not very different from the most recent global forecast of the US government’s Energy Information Administration. If anything, Exxon expects slower growth of energy and emissions than the EIA.

Ultimately, ExxonMobil's argument that it isn’t running outsized carbon asset risks depends heavily on its estimate of the implicit costs of achieving a much deeper and more rapid transition to renewables, compared to its--and others’--forecasts. It gauges this on the intensity of governments’ future climate policies, expressed in terms of their effective cost per ton of CO2 abated, and on the affordability of such measures to energy consumers, especially in the developing world, where emissions are increasing rapidly.

Without directly disputing the technical feasibility of achieving such large and rapid emissions cuts, the company's management essentially questions whether any government would or could impose the extraordinary costs necessary for that to occur. Their proxy estimate of $200/ton of CO2 for such policies is sobering. Even if the sums that would raise were all efficiently recycled by those governments–a heroic assumption–the resulting diversion of investment and increase in energy costs would adversely affect overall economic development.

The sustainable investor groups that raised this issue with ExxonMobil were apparently disappointed with the answer they got. That's not surprising, but having participated in similar exercises at Texaco, Inc., I think ExxonMobil went well beyond the kind of perfunctory reply the investors might have expected. In particular, it has provided enough data to support a more serious dialog with investors on this subject.

For example, Exxon indicated that it “stress tests” its projects and acquisitions at proxy costs of up to $80/ton of CO2, compared to current levels of $8-10/ton in the EU’s Emission Trading System. Implicit in that is the question of whether investors would reasonably expect them to test projects at $200/ton., which would equate to around $100 per average barrel of oil--roughly today's price--based on the nifty “seriatim” chart at the end of the report.

The document also includes information addressing the resiliency of the company’s assets and operations under a lower-carbon future, with their emphasis on natural gas and a global average cost of production under $12 per oil-equivalent-barrel (BOE). Climate policies would have to raise those costs and shrink the associated revenues very significantly to jeopardize current production, nor are low oil prices generally consistent with a low-carbon world. Investments in future production are another matter, though Exxon refers to the IEA’s 450 scenario to demonstrate how much additional oil and gas development would still be required in the next 20 years, even in a world that was determined to constrain global temperature increases to no more than 2°C.

ExxonMobil’s response to investors will not end the debate over the carbon bubble. While providing a lot of information, the company essentially argued that the extreme low-carbon scenario associated with the risks of a carbon bubble is irrelevant, because it can’t be achieved any time soon, irrespective of the risks associated with current emissions levels. That is close to my own view, but it is unlikely to resonate with those who are more focused on the risks of climate change than on the nuts and bolts of what it would take to avert them.

Interestingly, the company’s report on carbon risks was issued on the same day as the latest iteration of the predicted consequences of further warming from the Intergovernmental Panel on Climate Change (IPCC). In a sense each report provides context for the other, so that investors who accept the IPCC’s analysis can weigh the potential costs of global warming against the cost and scale of the changes that would be required to put the world on a crash program to avert the worst climate-change-related outcomes. They can then buy or sell accordingly.

A different version of this posting was previously published on Energy Trends Insider.

Tuesday, April 15, 2014

ABCs of LNG

  • Current debates over LNG export often ignore its primary benefits, such as enabling gas to be produced for sale to markets beyond the realistic reach of pipelines.
  • It also allows gas to compete with petroleum liquids where energy density is important, such as in powering ships, trains and land vehicles.  
The international reaction to Russia's annexation of Ukraine's Crimean peninsula has put a spotlight on liquefied natural gas (LNG), which was already under debate in the US as a mechanism for exporting increasingly abundant shale gas. Meanwhile, LNG is emerging as a fuel in its own right, rather than just a means of transporting gas from source to market. What links these trends is LNG's capability to enable natural gas to approach the convenience and energy density of petroleum.

The big driver for this is economic: UK Brent crude is currently over $100 per barrel, while natural gas in the US Gulf Coast trades at the energy equivalent of around $25 per barrel. That creates a significant incentive to build LNG plants, despite the recent escalation in their cost. Even after adding the equivalent of $20-30/bbl in expenses for liquefaction, shipping, and regasification to convert the LNG back into pipeline gas at its destination, the opportunity is significant. In Asia, where LNG sells for $14 or $15 per million BTUs, that's still less than $90 per equivalent barrel. And because gas can only be produced if it can be connected to a market, LNG enables more gas to compete in more markets, while providing customers a cleaner and cheaper fuel.

This is not a new technology. Early demonstrations in the 1940s and '50s were followed by commercial-scale plants built to export LNG from Alaska, Algeria and Indonesia, establishing what has since become a global industry. Every LNG plant is designed to take advantage of the fact that at atmospheric pressure natural gas becomes a liquid at -259 °F ( -161 °C)--about 60°F warmer than liquid nitrogen--shrinking by a factor of 600:1 in the process. As long as it is kept below that temperature, it can be stored and transported as a liquid.

That has important advantages over the alternative of compressing natural gas to create a denser fuel. For example, a gallon of LNG has around 2.2 times as much energy (based on lower heating values) as the same volume of compressed natural gas (CNG) at 3,000-3,600 pounds per square inch (psi). A gallon of LNG also has 98% of the energy of ethanol, and 64% that of gasoline. This makes LNG dense enough to transport economically over long distances, unlike CNG.

These differences have a practical impact on the gradual penetration of the transportation fuel market by natural gas. While most natural gas passenger cars are based on the simpler CNG approach, LNG is gaining a foothold in trucking, particularly where the combination of low emissions and denser fuel--yielding longer range--is important.

LNG is also emerging as an option for transportation modes that have had few viable alternative to oil-based fuels, such as in shipping and even rail where electrification is impractical. Replacing ships' bunker fuel with LNG could be a key strategy for responding to increasingly strict international regulations on sulfur and nitrogen oxide pollution from ocean-going vessels.

The environmental benefits of LNG can be significant, when it replaces higher-emitting fuels like coal and fuel oil. Even after accounting for the energy consumed in the liquefaction process-- equivalent to 8% or less of the gas input to a new LNG plant--and in storage and transportation, lifecycle emissions from LNG in power generation are 40-60% lower than those from coal. Its advantage in marine engines is smaller, but still positive at around 8%, while reducing local pollution significantly.

LNG isn't without drawbacks, including "boil-off", the gradual tendency of LNG in storage to evaporate due to heating from the environment outside the insulated tank. In stationary facilities the resulting gas can either be re-liquefied or delivered to meet local gas demand. In vehicles, it is vented after a specified holding time of around a week or more. That makes it more suitable for vehicles that are used frequently, rather than sitting idle for extended periods.

It's worth noting that while LNG is increasingly linked to shale gas in North America, nearly all the LNG currently marketed around the world is produced from conventional gas reservoirs, such as the supergiant North Field in Qatar, or the gas fields of Australia's North West Shelf. That would also be the case for a new LNG plant based on Alaskan North Slope gas, as described in a post here in 2012.

Only a few years ago, government and industry forecasts were unanimous in projecting a large and growing US LNG import requirement, as domestic gas production declined. The number of US LNG import facilities expanded to meet this new demand, but the combination of the recession and the shale gas revolution has resulted in imports shrinking substantially since 2007. The Energy Information Administration now expects the US to become a net exporter of LNG in 2016, including exports from repurposed import facilities. They will join a market that now supplies around 10% of global natural gas consumption and accounts for a third of global gas trade.

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

Wednesday, April 09, 2014

Fuel Cell Cars and the Shale Revolution

  • Although fuel cell cars have perpetually seemed to be the technology of tomorrow, carmakers’ persistence with them could still pay off, as a dividend from shale gas.

  • Significant obstacles remain, including inadequate hydrogen infrastructure and competition from greatly improved vehicle batteries. However, the race is far from over.

As I was working off my reading backlog, I ran across an article in the Washington Post’s “Capitol Business” edition on “Are We Ready for Hydrogen Cars?” Published in conjunction with this year’s DC Auto Show, which I missed, it mentioned a new fuel cell model from Hyundai for the California market, while providing some background on a technology that looked much more like the next big thing a decade ago than it does to many, now.

Any evaluation of the prospects for fuel cell cars to become practical requires discussing the cost of fuel cell components, the infrastructure to deliver H2 to vehicles, and the suitability of various options for storing it safely onboard. However, I was surprised the article failed to mention a new factor that might do more than anything else to improve the odds for this technology: shale gas.

In the mid-1990s, when fuel cell vehicles (FCVs) first appeared on my radar, they seemed like an ideal alternative to the gasoline engines in most passenger cars, offering zero tailpipe emissions and very low lifecycle, or well-to-wheels emissions of all types. Onboard hydrogen (H2) storage, whether as a gas, liquid or chemically adsorbed in another material, enabled higher energy density than then-current batteries, giving an FCV significantly greater potential range than a comparable electric vehicle (EV). And like electric cars, they also provided a useful pathway for bringing energy from a wide variety of sources into the transportation market, which was and still is dominated by petroleum products. Cost and technology readiness were big barriers, along with non-existent retail H2 infrastructure.

Energy remains the key to FCVs, because H2 is an energy carrier, not an energy source. Standing up a competitive fleet of FCV models thus requires plentiful and preferably low-cost energy sources from which sufficient H2 can be produced and distributed. As recently as just a few years ago, this looked like a very tough challenge.

Most H2 used industrially is generated by chemically reforming natural gas. Until recently, US gas production was in decline, resulting in high and volatile gas prices. Generating H2 from electricity looked even worse, because power prices were climbing and seemed likely to increase steadily in the future, as natural gas prices rose and higher-cost renewables were phased in. And with US electricity generation dominated by coal, H2 from electrolysis–cracking water into its components using electricity–looked like a recipe for merely shifting, rather than reducing vehicle emissions.

Like many other aspects of the North American energy scene, this picture has changed radically in the last several years, mainly due to the shale gas revolution. We now have abundant gas at reasonable prices, and this is holding down electricity costs. (Renewables are also reducing wholesale electricity prices, though not necessarily the full cost of electricity, because they still depend on subsidies and mandates that don’t show up in wholesale prices.)

These developments create the potential for cheaper H2 sources than fuel cell developers expected. Moreover, US natural gas prices have diverged from oil prices and are now at a significant discount to oil. Wellhead gas today trades for the equivalent of $25 per barrel, compared to oil at over $100. Gas-derived H2 could end up with advantages in both cost and end-use efficiency over gasoline.

Of course the availability of natural gas isn’t the only thing that has changed for fuel cells in the last decade, from a competitive perspective. Automakers such as GM, Toyota and Honda have introduced various new fuel cell models. The most recent one I had an opportunity to drive was a fuel-cell version of the Chevrolet Equinox compact SUV in late 2007. In the meantime, though, EV models are proliferating.

Unfortunately for fuel cell developers, H2 distribution has had a somewhat checkered history, as the Washington Post article notes. Providing fuel for FCVs is a much more involved and expensive undertaking than setting up a network of recharging points for EVs. How many H2 stations will suppliers build before FCVs appear in large numbers, and how many FCVs can carmakers sell before sufficient infrastructure is available to serve them? California still has just a handful of public H2 stations, after years of development.

Energy trade-offs dominate the competition between FCVs and EVs. The former have longer ranges between refueling than moderately-priced EVs–the Tesla Model S has excellent range–and can be refueled in much less time than even high-voltage EV recharging can achieve. However, FCVs are much more dependent on refueling infrastructure than EVs, which can recharge at home. And thanks to robust federal support for battery R&D and production, including from the 2009 stimulus, along with extremely generous federal and state EV tax credits, EVs have gained significant awareness and initial market penetration since the current administration took office and scaled back federal support for fuel cells.

EVs may have an edge over fuel cell cars, for now, but EV sales remain disappointing and they must compete with more convenient, mainstream hybrid cars, with and without plug-in capability. They must also compete with conventional gasoline and diesel cars that are becoming more efficient every year, reducing EVs’ advantages in operating costs and lifecycle environmental impacts. Given all that, there’s still ample time for another technology like FCVs–or natural gas vehicles (NGVs)–to scale up, if they can reduce costs quickly enough and overcome infrastructure hurdles. Those are big ifs.

Nor is it the case that EVs and FCVs are mutually exclusive in the automotive market. Fuel cell cars are fundamentally electric vehicles, too, and most will likely be offered as hybrids, with regenerative braking and traction batteries. So advances in EV architecture, battery capacity and cost, and safety also benefit FCVs. That makes it seem even likelier that our future vehicle mix will be quite diverse, with EVs and FCVs coexisting with NGVs, various hybrids, and much more efficient gasoline and diesel models than today’s.

A different version of this posting was previously published on Energy Trends Insider.

Thursday, April 03, 2014

Environmental Groups Gear Up to Stop US LNG Exports

  • The Sierra Club and other groups are taking on US LNG exports just when LNG is gaining support as a key response to Russia's aggressive behavior in Ukraine.

  • The science behind their claims does not withstand scrutiny, and their timing couldn't be worse, geopolitically.

A collection of environmental groups, including the Sierra Club, Friends of the Earth and 350.org recently wrote to President Obama, urging him to require a Keystone-XL-style environmental review--presumably entailing similar delays--for the proposed Cove Point, Maryland liquefied natural gas (LNG) export terminal. Given the President’s explicit support for wider natural gas use and the administration's new commitment to our European allies to enable LNG exports, the hyperbole-laden letter seems likelier to rev up the groups’ activist bases than to influence the administration’s policies.

Either way, its timing could hardly be coincidental, coming just as opinion leaders across the political spectrum have seized on LNG exports as a concrete strategy for countering Russian energy leverage over Europe in the aftermath of President Putin’s seizure of Crimea. If, as the Washington Post and energy blogger Robert Rapier have suggested, the Keystone XL pipeline is the wrong battle for environmentalists, taking on LNG exports now is an even more misguided fight, at least on its merits.

Referring to unspecified ”emerging and credible analysis”, the letter evokes the thoroughly discredited argument that shale gas, pejoratively referred to here as “fracked gas”, is as bad or worse for the environment as coal. In fact, in a similar letter sent to Mr. Obama one year ago, some of the same groups cited a 2007 paper in Environmental Science & Technology that clearly showed that, even when converted into LNG, the greenhouse gas (GHG) emissions of natural gas in electricity generation are still significantly lower than those of coal, despite the extra emissions of the liquefaction and regasification processes.

The current letter also implies that emissions from shale gas are higher than those for conventional gas, a notion convincingly dispelled by last year’s University of Texas study, sponsored by the Environmental Defense Fund, that measured actual, rather than estimated or modeled, emissions from hundreds of gas wells at dozens of sites in the US.

It’s also surprising that the letter’s authors would choose to cite the International Energy Agency’s 2011 scenario report on a potential “Golden Age of Gas” in support of their claims. That’s because the IEA’s analysis found that the expanded use of gas foreseen in that scenario would reduce global emissions by 160 million CO2-equivalent tons annually by 2035, mainly through competition with coal in power generation in developing countries, addressing the principal source of global greenhouse gas emissions growth today.

The groups take another wrong turn in suggesting that President Obama increase support for wind and solar power instead of supporting gas. The contribution of new renewables to the US energy mix has grown rapidly, thanks to significant federal and state support, but it remains small. Despite record US wind turbine and solar power additions, shale gas and shale oil added more than 20 times as much energy output on an equivalent basis in 2012, and last year’s gains look similarly disproportional. Simply put, the US isn’t enjoying a return to energy security or becoming a major energy exporter because of renewables. It is counterproductive for renewables to pit them against gas as they have done here.

Experts disagree on how much and how quickly US LNG exports can influence gas markets in Europe and elsewhere. Yet while none of the currently permitted or proposed LNG facilities will be ready to ship cargoes until at least late next year, the knowledge that they are coming will inevitably have an impact on traders and contracts, including contracts for Russian gas in the EU. Whether or not US natural gas molecules ever reach Europe, they can serve a useful role in the necessary response to Russia’s aggression in Ukraine. Attempting to block this for spurious reasons puts opponents in jeopardy of becoming what Mr. Putin in his previous career might have called “useful idiots.”

It’s tempting to speculate on what this new campaign says about the participating groups’ perceptions of how the Keystone XL fight is going. Win or lose, they might soon need a new cause, or face the dispersal of the protesters and financial contributors it has galvanized. Blocking LNG may look conveniently similar--even if similarly mistaken--but I can’t help feeling these groups would gain more traction with their fellow citizens by focusing on what they are for, rather than expending so much energy in opposition.

A different version of this posting was previously published on Energy Trends Insider.

Friday, March 28, 2014

How Can US Natural Gas Reduce Europe's Dependence on Russia?

  • The EU's dependence on Russian natural gas is directly linked to its own gas production, which has fallen faster than EU member countries' demand for gas.
  • While US LNG exports aren't an immediate remedy, due to permitting and construction time lags, the prospect of their availability is already affecting the gas market.
Russia's annexation of Ukraine's Crimean Peninsula has drawn new attention to Europe's reliance on energy supplies from Russia, particularly for natural gas. Lacking the means to force Russia's president to back down, US politicians and leading newspapers have latched onto the idea of exporting shale gas to reduce the EU's vulnerability to an accidental or intentional disruption of these supplies.  The efficacy of this strategy depends on more than the logistics and timing of US liquefied natural gas (LNG) projects.

The European Union is expected to import 15.5 billion cubic feet (BCF) per day of natural gas from Russia this year, roughly half of which would normally be transported by pipelines passing through Ukraine. Worries about the security of these supplies in the current crisis are compounded by Europe's increasing reliance on gas imports from all sources.

While EU gas consumption, based on the union's 28 current member countries, has been essentially flat over the last decade, its production has declined by more than a third, as shown in the chart below. As of the end of 2012, EU self-sufficiency in gas stood at just 35%. The widening of the gap between EU gas demand and production bears a close resemblance to the situation in which the US found itself with regard to crude oil prior to the shale revolution, and it is the main source of Europe's vulnerability in natural gas.

After Russia, the EU's main gas suppliers are Norway and Algeria, primarily by pipeline, followed by LNG sourced from Qatar, Nigeria and other countries.  Russia's leading role in supplying Europe's gas is consistent with its status as the world's second-largest gas producer and largest gas exporter, its proximity to the EU, and its pipeline network developed over multiple decades. Europe's gas supply mix includes ample political risk, but none of the EU's other suppliers are geopolitical rivals like Russia.

The EU has three main options for reducing its dependence on gas imports from Russia. It could shrink natural gas consumption, which is already happening to a modest degree as pricey gas-fired power generation is being squeezed out between subsidized wind and solar power and cheaper coal power, in a mirror image of US trends of the last several years.  This seems inconsistent with the EU's long-term emission goals and its need for gas to back up intermittent renewable electricity generation, so the further scope for this option appears limited, at least for the next decade.

EU countries could also attempt to revive domestic gas production. Europe's conventional gas fields may be in decline, other than in non-EU Norway, but its shale gas potential was estimated at 470 trillion cubic feet (TCF) in the US Energy Information Administration's global shale assessment last year. That's about 40% bigger than Europe's reserves and technically recoverable resources of conventional gas. Uncertainties on this estimate are still large, but it's in the same ballpark with the Marcellus shale in the eastern US, which currently produces over 14 BCF/day.

Unfortunately, initial efforts in Poland's shale have been disappointing, while Germany, France, and other countries have imposed explicit or implicit moratoria on shale gas development. Unless these policies are reversed in the aftermath of the Ukraine crisis, the EU will be unable to grow its way out of its dependence on Russia.

That leaves import diversification as the likeliest path for weaning Europe off Russian gas. This process is underway incrementally, hastened by previous Russian gas brinksmanship. Interest in US gas is understandable on many levels, not least because even after increasing production by around 17 BCF/day since 2006, US shale resources are expected to add another 13 BCF/day by 2020.

Energy experts have been quick to point out that the first US LNG exports won't be available for at least several years, and that companies, rather than governments, are the main parties involved in gas contracts. Customers in Europe will have to compete for US and other LNG supplies with customers elsewhere, especially in Asia, where China's gas demand is growing and Japan's post-Fukushima nuclear shutdowns have dramatically increased LNG imports.

These constraints are real. However, they ignore the ways in which changing the market's expectations about future LNG supplies--and potentially prices--could affect the calculations of Europe's gas buyers today and limit the political leverage that Russia's dominant gas export position conveys. Anecdotal reports suggest that US LNG is already a factor in contract renegotiations in Eastern Europe. As Amy Myers Jaffe of UC Davis and formerly the Baker Institute tweeted a few weeks ago, "it isn't about physical LNG cargo to Europe; it is about US exports promoting market liberalization (and) greater liquidity." 

 A decision by the US government to streamline the permitting and development of LNG facilities wouldn't enable US exports to displace Russian gas in Europe this year or next, but it would put Russia on notice that in the future it must compete in a market in which gas customers in Europe and elsewhere will have much greater choice. That would certainly complicate President Putin's plans.
 
A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Wednesday, March 19, 2014

Making Oil-by-Rail Safer

  • A series of rail accidents involving trains carrying crude oil has focused attention on safety procedures and even the tank cars used in this service.
  • Another concern is the variable characteristics of the "light tight oil "now shipped by rail in large quantities. That isn't the result of "fracking", but of the oil's inherent chemistry.   
The growth of North American oil production from unconventional sources has resulted in a dramatic expansion in the volume of crude oil shipped by rail. Unfortunately, as crude oil rail traffic has increased, so have rail accidents involving crude oil, including the tragic explosion and fire in Lac-Megantic, Quebec last July. That event and subsequent accidents have focused railroads, regulators and shippers on the need to improve the safety of oil-by-rail as quickly as possible.

In the immediate aftermath of Lac-Megantic, the Federal Railroad Administration issued an emergency order on procedures railroads must follow when transporting flammable and other hazardous materials. And on February 21, 2014 railroads reached a voluntary agreement with the US Department of Transportation (DOT) on additional steps, including reduced speed limits for oil trains passing through cities, increased track inspection, and upgraded response plans. These steps have the highest priority, because crude oil loaded in tank cars doesn't cause rail accidents. Every incident I've seen reported in the last year began with a derailment or similar event.

At the same time, the packaging and characteristics of the oil can affect the severity of an accident.  Investigators have focused on two specific issues in this regard, starting with the structural integrity of the tank cars carrying the oil. The vast majority of tank cars in this service are designated as DOT-111--essentially unpressurized and normally non-insulated cylinders on wheels. These cars routinely carry a variety of cargoes aside from crude oil, including gasoline and other petroleum products, ethanol, caustic soda, sulfuric acid, hydrogen peroxide, and other chemicals and petrochemicals.

Their basic design goes back decades, and even the older DOT-111s incorporate learnings from earlier accidents. A growing proportion of the US fleet of around 37,000 DOT-111 tank cars in oil service consists of post-2011, upgraded cars that have been strengthened to resist punctures, but the majority is still made up of older, unreinforced models. The Pipeline and Hazardous Materials Safety Administration (PHMSA) is studying whether to make upgrades mandatory, but some railroads and shippers aren't waiting. Last month Burlington Northern Santa Fe Railway, owned by Warren Buffet's Berkshire Hathaway, announced it would buy up to 5,000 new, more accident-resistant tank cars.

Another issue that has received much attention since Lac-Megantic concerns the flammability of the light crude from shale formations like North Dakota's Bakken crude, which accounts for over 700,000 barrels per day of US crude-by-rail. The Wall Street Journal published the results of its own investigation, reporting that Bakken crude had a higher vapor pressure--a  measure of volatility and an indicator of flammability--than many other common crude oil types.

The Journal apparently based its findings on crude oil assay test data assembled by the Capline Pipeline.  Although a Reid Vapor Pressure of over 8 pounds per square inch (psi) for Bakken crude is higher than for typical US crudes, it's not unusual for oil as light as this. That's especially true where, due to lack of field infrastructure, only the co-produced natural gas is separated out, leaving all liquids in the crude oil stream.

What makes this situation unfamiliar in the US is that domestic production of oil as light as Bakken had nearly disappeared before the techniques of precision horizontal drilling and hydraulic fracturing were applied to the Bakken shale and similar "source rock" deposits. (Note: High vapor pressures are characteristic of the naturally-occurring mix of hydrocarbons in very light crudes, rather than a result of the "fracking" process.) Nor is the reported vapor pressure for Bakken or Eagle Ford crude higher than that of gasoline, a product that is federally certified for transportation in the same DOT-111 tank cars that carry crude oil.

The variability of the vapor pressure data that the Journal's reporters identified for Bakken crude may result from another unfamiliar feature of such "light tight oil". Crude produced from conventional reservoirs, which are much more porous than the Bakken shale, tends to be relatively homogeneous. However, because the Bakken and other shales are so much less porous, limiting diffusion within the source rock reservoir, the composition of their liquids can vary much more between wells.

In any case, vapor pressure isn't the preferred measure of fuel flammability. Actual rail cargo classifications are based on flash point and initial boiling point. These routine quality tests aren't included in Capline's publicly available data. PHMSA initiated "Operation Classification" to ensure that manifests and tank car placards for crude oil shipments accurately reflect the potential hazards of each cargo, based on such measurements. The agency has determined that it hasn't always been done consistently, and DOT issued another emergency order requiring shippers to test oil for proper classification.

As mentioned in an oil-by-rail webinar yesterday, hosted by Argus Media, assigning the proper classification to oil shipments may seem like a bureaucratic concern--it doesn't necessarily affect the tank car type chosen to transport the crude--but it can have a significant impact on operational factors such as routing and the notification of first responders along the route.

There's no quick and simple way to make the transportation of crude oil by rail as safe as hauling a dry bulk cargo like grain. Tank car fleets can't be replaced overnight, not just because of the cost involved, but due to limited manufacturing capacity. However, in the meantime significant improvements can be achieved through a combination of government attention and sustained industry initiatives. Since the new crude streams traveling by rail play a key role in increasing North America's energy security, this is in the interest of everyone involved--producers, shippers, railroads, and not least the communities through which this oil travels.

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

Tuesday, March 11, 2014

Will Shale Oil Growth Lead to New US Refineries?

  • The revival of US oil production is spurring new investments in refineries, including the restart or new construction of small refineries near these resources.
  • How well such investments perform will depend on both the longevity of shale oil production and policies concerning its export.
An article on the revival of some mothballed US oil refineries and the possible construction of new ones provided yet another indication of industry confidence that record growth in oil production from US shale deposits isn't just a temporary phenomenon.  Refineries--even small ones--aren't usually quick-return investments. Restarting one or building a new one requires a positive view of future feedstock availability, product demand and other uncertainties.

The number of US refineries has fallen steadily, from 301 in 1982 to 143 last year. Because this mainly involved the retirement of smaller, less efficient facilities, while larger refineries "de-bottlenecked" or expanded, US refinery capacity actually grew over this period. It's generally cheaper to expand an existing facility, leveraging its infrastructure and experienced staff, than building a "grassroots" facility.

The hurdles facing new refinery construction in the US have been compounded by environmental regulations covering permits, emissions and product specifications. The time when a new entrant could simply distill light crude oil, sprinkle in some tetraethyl lead and other additives, and sell a full slate of refined products is long gone. New refineries in North Dakota, Texas and Utah are apparently focused on producing diesel fuel from the shale, or "tight" oil in the Bakken, Eagle Ford, and Uinta shales, respectively, and selling the rest of their output to other refiners or petrochemical plants as feedstocks .

With diesel demand in the producing areas booming, thanks to the needs of drilling rigs and the trucks that haul water, sand and equipment, as well as oil from leases not connected to pipeline gathering systems, this opportunity could last as long as the drilling-intensive shale development does. In other words, the demand aspiring refiners see appears to be linked directly to their source of supply.

Meanwhile larger plants, such as several of  Valero's Texas refineries, are in various stages of investments to enable them to process more light oil, reversing a multi-decade trend of investment to handle increasingly heavy and sour (high-sulfur) imported crudes. As with the smaller refineries, this shift requires high confidence in the long-term availability and favorable pricing of these high-quality domestic crude oil types.

The reasonableness of that assumption depends on the longevity of tight oil production. Large conventional inland oil fields typically reach peak output within a few years and then decline gradually, with long plateaus. Whether shale deposits, with their distinct geology, will follow the same pattern remains to be seen. Despite a few projections suggesting that tight oil output of the major shale basins could soon peak and decline rapidly, most mainstream forecasts suggest a long life for these resources, particularly as the technology to develop them continues to improve

For example, in its latest Annual Energy Outlook, the US Energy Information Administration (EIA) anticipates US tight oil production reaching 4.8 million barrels per day (MBD) by 2021, before gradually declining back to levels near today's in 2040. By contrast BP's just-released Energy Outlook 2035 sees comparable growth over the next few years but little subsequent decline, with tight oil at 4.5 MBD in 2035. Meanwhile, ICF International recently issued its Detailed Production Report, projecting shale/tight oil production in the US and Canada to reach 6.3 MBD by 2035, including 1.3 MBD from the tight oil zones of the Permian Basin of Texas.

The other big uncertainty concerning the availability of light tight oil for new or expanded US refineries depends on federal export policy, which I addressed in a recent post. This issue is highly controversial. A quick reversal of existing rules would be surprising, though as the New York Times noted, possible compromises under existing law could facilitate an expansion of crude oil exports beyond current shipments to Canada. While unlikely to dry up domestic availability of tight oil, such measures could shrink the current discounts for these crudes, compared to internationally traded light crudes like UK Brent. That seems less of a risk for small, simple, inland refineries than for larger facilities, especially those near coastal ports.

This isn't the first time investors have considered the need for new US refineries. There was similar interest after hurricanes Katrina and Rita slashed Gulf Coast refinery output for several weeks in 2005, though it ultimately led nowhere. If today's circumstances prove more supportive, it will be because the US hasn't experienced anything comparable to the shale revolution since the 1920s and '30s, when rapid oil production growth was accompanied by a wave of refinery construction, though in a very different business and regulatory climate. If that parallel holds, consumers stand to benefit from the resulting increase in competition.

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