An Ill-conceived Tax Idea

Yesterday we learned that President Obama's final budget proposal includes a plan to raise money for transportation projects and other uses by imposing a per-barrel tax on US oil companies. Here are a few quick thoughts on this ill-conceived idea:

• As I understand it, the tax would be imposed on oil companies, exempting only those volumes exported from the US. The US oil industry is currently in its deepest slump since at least the 1980s. Having broken OPEC's control of prices and delivered massive savings to US consumers and businesses, it is now enduring OPEC's response: a global price war that has driven the price of oil below replacement cost levels. This is evidenced by the recent full-year losses posted by the "upstream" oil-production units of even the largest oil companies: ExxonMobil, Chevron, Shell, BP and ConocoPhillips, particularly in their US operations. The President has wanted to tax oil companies since his first day in office, but his timing here would only exacerbate these losses, putting what had been one of the healthiest parts of the US labor market under even more pressure.
• This tax would also increase OPEC's market leverage, providing a double hit on the cost of fuel for American consumers: We would pay more immediately, when the tax was imposed and companies passed on as much of it as they could, and then even more later when OPEC raised prices as competing US production became uneconomical.
• Focusing the tax on the raw material, crude oil, rather than on the products that actually go into transportation, as the current gasoline and diesel taxes do, is guaranteed to produce distortions and unintended consequences. For starters, exempting exports--a sop to global competitiveness?--would give producers a perverse incentive to send US oil overseas instead of refining it in the US. It would also shift consumption toward more expensive fuels like corn ethanol, which provides no net emissions benefits but has been shown to affect global food prices.
• Singling out oil, which is not the highest-emitting fossil fuel and for which we still lack scalable alternatives, will put all parts of the US economy that rely on oil as an input at a competitive disadvantage, globally, and undermine what had become a significant US edge in global markets. Petrochemicals, in particular, would be adversely affected. The President's staff is well aware that the distribution of lifecycle emissions from oil, and the structure of the industry and markets, make policies focused on consumption far more effective than those aimed at production. This is why his administration's first act in implementing the expanded interpretation of the Clean Air Act to greenhouse gases was to tighten vehicle fuel economy standards. Taxing the upstream industry does nothing for global emissions but makes US producers less competitive, ensuring a return to rising oil imports and deteriorating energy security.

As widely reported, the Congress will not enact a budget containing this provision. It is hard to gauge whether this proposal represents a serious attempt to inject new thinking into the debate on funding transportation upgrades, or is simply one last shot across the bow of the administration's least favorite industry before leaving office in 349 days. It's not unusual for the wheels to come off as a presidency winds down, and this particularly flaky and futile idea might just be an indicator of that.

Disclosure: My portfolio includes investments in one or more of the companies mentioned above.

The LPG Echo of the Shale Gas Boom

• Increased US production of LPG and natural gas liquids is an outgrowth of the shale gas revolution and a key ingredient for translating its benefits into industrial growth.
• The infrastructure investments, export opportunities and price relationships for these liquids represent a microcosm of the similar issues for shale gas and LNG.

An article in the Wall St. Journal last month on the impact of a Midwest propane shortage on farmers trying to dry their corn harvest caught my attention. How could propane be in short supply, when US production is soaring due to shale gas? While it turns out that the shortfall in question was localized and temporary, it prompted me to take a closer look at LPG supply and demand than I have in many years. I found yet another market that is being transformed by the shale gas revolution.

Like most Americans--except for those in the roughly 5% of US homes heated with it-- I normally think about LPG only when I have to change the tank on my barbecue grill. That wasn't always the case; early in my career I traded LPGs for Texaco's west coast refining system. I'm happy to see that some of my former colleagues from that period are still involved and frequently quoted as experts on it. Although the LPG market is obscure to many, it represents a microcosm of the issues of reindustrialization and product exports arising from the recent turnaround in US energy output trends.

In order to follow these developments, we first need to clarify some confusingly similar acronyms, starting with LPG. Although often used synonymously with propane, it actually stands for "liquefied petroleum gas" and covers mainly propane and butane, though some in the industry include ethane in this category. The term reflects the oil refinery source of much of their supply, both historically and to an important extent today.  LPG overlaps with natural gas liquid (NGL)--ethane, propane, butane, isobutane and "natural gasoline"-- that has been separated from "wet" ( liquids-rich) natural gas during processing. NGLs are entirely distinct from the anagrammatical LNG, or liquefied natural gas, which consists mainly of methane that has been chilled until it becomes a liquid. By contrast, NGLs and LPG are typically stored at or near ambient temperature but under pressure to keep them in the liquid state.

LPG and NGLs make up a distinct segment of US and global energy markets, falling between the markets for natural gas and refined petroleum products. They are also linked to these larger markets, both logistically and economically. For example, gas marketers vary the amount of liquids they leave in "dry gas" to meet pipeline natural gas specifications based on price and other factors, and oil refiners blend varying quantities of butane into gasoline, depending on seasonal requirements. Propane and butane are mainly used as fuels, while ethane and isobutane are chiefly chemical feedstocks.

The development of shale gas in the US and Canada has affected the supply of NGLs and LPG in several important ways. First, starting around 2007 increasing shale gas output helped to halt and then reverse the decline in US natural gas production from which US NGLs are sourced. Then, following the financial crisis, diverging natural gas and crude oil/liquids prices pushed shale drillers toward the liquids-rich portions of shale basins like the Eagle Ford in Texas, in order to maximize their revenue. The resulting surge of US NGL production in late 2009 reinforced the decline of US LPG imports that began with the recession. According to US Energy Information Administration data, the US became a fairly consistent net exporter of LPG in 2011.

The current US LPG surplus is around 100,000 bbl/day, out of total production of around 2.7 million bbl/day. That surplus and its expected growth provides the basis for a number of announced LPG  export projects, as well as the anticipated development of new domestic chemical facilities such as ethylene crackers that would consume substantial portions of new supply, particularly of ethane.

The success of those projects depends on significant investments in new infrastructure, including gas processing, NGL fractionators to split the raw NGL into its components, and pipelines to deliver NGL to fractionators and LPG to markets. This is particularly true for the Marcellus and Utica shale gas in the Northeast, from which little or no ethane has been extracted due to limited local demand. Not only is that a missed manufacturing opportunity, but it constitutes a potential constraint on further liquids-rich gas development, since leaving too much ethane in the marketed gas would cause it to exceed pipeline BTU specifications.

In the meantime we're left with a situation that's analogous to the growth of tight oil production from the Bakken  shale. New sources of production have come on-stream faster than the infrastructure necessary to deliver them efficiently to where they can be processed or consumed. That puts a growing US surplus of propane and other NGLs in tension with tight regional markets for these fuels in the Midwest and Northeast, where residential propane prices are running well ahead of last year's at this time.  The resolution of this apparent paradox will depend on which infrastructure and demand projects are eventually completed, and how soon.

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

Making Petrochemicals from CO2

• R&D is under way in Germany to see whether CO2 emitted from power plants or other facilities could become a useful feedstock for manufacturing chemicals.

• This could have several advantages over producing fuels from CO2, while providing modest emission reduction benefits.

A recent article in Chemical & Engineering News described current German research and development work focused on devising new industrial processes for making organic chemicals from CO2. These public/private partnerships capitalize on that country’s long expertise in industrial chemistry and its highly successful chemical sector. They are also extremely timely, not just because of growing concern about steadily increasing levels of CO2 in the atmosphere, but because Germany’s “Energiewende”, which includes the rapid phase-out of nuclear power, appears to be raising the country’s emissions as it relies increasingly on coal for baseload electricity generation.

In my last post I explained why it is unlikely that fossil fuels could be phased out rapidly enough to threaten the current valuations of oil and gas firms. But if carbon-based fuels will be with us for some time, that leaves open the large question of what to do about the CO2 emitted when they are burned, particularly from stationary installations like factories and power plants. The long-mooted approach of carbon capture and sequestration (CCS) still faces significant obstacles in terms of cost and social acceptance. That makes CO2 utilization efforts such as those underway in Germany especially intriguing as a way of turning lemons into lemonade.

It’s impossible to predict today whether any of the CO2 utilization processes that German companies and universities are pursuing will ever become commercial. However, they share some key advantages over “classic” CCS and various efforts to produce fuels and other chemicals from CO2 captured directly from the atmosphere:

1. Producing chemicals, rather than fuels, finesses a fundamental obstacle to recycling CO2. Thermodynamics dictate that reversing the results of combustion requires more energy than the fuels released when burned. As long as most energy globally comes from fossil fuels, it will be hard to come out ahead from an energy, emissions or cost perspective when turning CO2 back into fuels. However, if the output is valuable chemicals, that energy deficit might not be such a hindrance.
2. The target chemicals for these projects, including polyols, polypropylene carbonate, and acrylates, are widely used and have a global market. While most don’t quite fall into the category of premium specialty chemicals, they are unlikely to become as commoditized as motor fuels. So while cost is an important consideration, there’s probably a bit more leeway for a new process to compete and become successful.
3. The scale of production for these chemicals is much smaller than for motor fuels, by orders of magnitude. That means that a company investing in producing them from CO2 can hope to capture meaningful revenue and market share with a manageable scale-up from the laboratory. Yet they’re not so small that a single new plant on a scale large enough to demonstrate CO2 utilization would swamp the global market and destroy the margins that made the investment attractive in the first place.
4. These projects appear to be focused mainly on using the CO2 effluent from other industrial processes or power generation, ranging from 4-14% for power plants and up to 90% for some industrial processes, rather than having to collect it from the atmosphere, where it is present at just 0.04%. Starting with a CO2 concentration 100-1000 times higher than in air entails much less surface area for absorption, and likely lower energy consumption and overall capture cost.
5. Germany is committed to significant CO2 reduction, but the German public seems uncomfortable with the prospect of burying CO2 underground. Lacking large numbers of mature oil fields that could be revived by CO2 injection, a commercial-scale CO2 utilization industry would solve Germany’s problem of what to do with at least some of the CO2 it will eventually want to capture from the country's coal- and gas-fired power plants and other sources. 

As promising as these efforts look, they are unlikely to reduce global CO2 emissions by enough to meet current goals. While chemical markets are big enough to take up some captured-and-converted CO2, they are much smaller than the global fossil fuel consumption responsible for most man-made CO2 emissions. If carbon capture really took off, the volumes of concentrated CO2 involved would require multiple additional large-scale dispositions including enhanced oil recovery, fuel production–perhaps driven by advanced nuclear power–underground burial, and possibly chemical sequestration as carbonate rock.

In the meantime, turning some CO2 that would otherwise end up in the atmosphere into organic chemicals that will end up in more durable products seems worth pursuing. If these processes can become commercial, they will help move us in the right direction, and more cost-effectively than some other approaches receiving large ongoing government subsidies, rather than the modest seed money involved in these cases. I’ll be very interested to see how these efforts turn out.

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

Two Energy Revolutions Vie across the Atlantic

A front-page article in today's Washington Post reported on the trend of energy-related investments in the US by European companies.  This is another aspect of the competing energy revolutions I mentioned a few weeks ago, in my comments on President Obama's State of the Union speech.  Germany's 2000 Renewable Energy Law introduced feed-in tariffs for wind and solar power that have made that country a global leader in green energy implementation, yet it has also become increasingly apparent that this carefully planned transformation paid insufficient attention to the cost of the new energy sources it was embedding at the heart of the German economy.  The Post describes how leading German firms are looking across the Atlantic to invest where energy is cheaper, thanks to the unplanned, largely unanticipated extraction of hydrocarbons from shale. 

The Ludwigshafen, Germany dateline of the article caught my eye immediately.  Having just returned from a family trip to California with a packet of letters I wrote to my parents during a temporary work assignment in Germany in the early 1980s, I had only yesterday re-read the account of my visit to BASF's sprawling petrochemicals complex there.  I recall being greatly impressed by the site, which dwarfed the Los Angeles refinery at which I worked at the time. The BASF facility was part of the post-war boom--the Wirtschaftswunder--that made Germany the economic and industrial center of Europe, where it remains today two decades after reunification and a decade after relinquishing its cherished Deutchmark for the Euro.  Now the company apparently wonders whether Ludwigshafen can remain competitive in a global market dominated by US shale gas.

The divergence of energy prices that worries German industrialists is the result of conscious choices made by that country's government and a set of developments that occurred here largely out of sight of the US government, while its attention was focused elsewhere. In the same decade in which production from shale gas deposits in Arkansas, Louisiana, Oklahoma, Pennsylvania and Texas--output that now sets the price of both gas and electricity in much of the US--was gathering momentum, the German government was negotiating for more imported natural gas from Russia, via a pipeline built by a company led by a former German Chancellor.  It also set up a mechanism for consumers of electricity to fund the payment of up to $0.70 per kilowatt-hour that was necessary to support the initial solar power installations in one of the world's least sunny countries.

German solar tariffs have declined significantly since then, thanks in part to ruinous competition with China-based solar manufacturers.  However, in the aftermath of the nuclear accident at Fukushima, the German government agreed to retire the country's nuclear power plants, which supplied 22% of its electricity in  2010.  New solar might soon be cheaper than new nuclear capacity, but there aren't many energy sources cheaper than an existing, fully-depreciated nuclear reactor, even after allowing for waste disposal and site cleanup.  As a consequence of these policies, German managers such as those at BASF face natural gas prices that are a multiple of those here, along with the prospect of steadily rising electricity rates.  The option to offshore production must seem as obvious for them as it did for US companies in 2005, when US natural gas prices reached $10 per million BTUs.

Of course this comparison is just a snapshot in time; the competition between these two energy revolutions will likely ebb and flow for years.  However, the current energy divergence between Germany and the US should remind us that the cost of energy remains a very important economic parameter, even in highly developed countries.  Measures that inevitably raise it are very likely to bring adverse consequences, no matter how well-intended or carefully justified they might seem.  That's worth considering here, as well, when Congress debates new energy taxes and the administration proposes new rules that could raise energy costs or constrain output. 

Avoiding Commoditization

It's no secret that it's tough to make money in a commodity business. However, that's precisely what most renewable energy companies are attempting to do, by going after some of the biggest, most commoditized markets of all, in fuel and electricity. An article in MIT's Technology Review about a New Zealand biofuels start-up illustrates one path around this trap, by producing specialty products, though there are others, including various branding strategies. Choosing the right strategy may depend as much on where an industry is in its lifecycle as on the actual output of the company's technology.

It wasn't so long ago that even the enormous US gasoline market retained significant non-commodity attributes. Fuel marketers successfully differentiated themselves on service and perceptions of quality, and those that were best at this were able to command an extra penny or two at the pump--a huge uplift in profit margin when gas was under a dollar a gallon. One of the classics in this line was an old Shell marketing campaign focused on "Super Shell with Platformate", implying a unique formulation that delivered more power and more mileage. Only when I started working in the industry did I learn that essentially all gasoline contained Platformate, which was just a brand name for a common gasoline component that had been catalytically reformed to turn straight hydrocarbon molecules into higher-octane ring compounds. Today, with the basic formulation of gasoline set not by refiners but by federal and state environmental agencies, fuel marketers have attempted to differentiate themselves on the basis of infusing branded additives. I'm not sure how successful that has been, outside the niche market of motorists driving high-end vehicles with expensive, high-performance engines.

The New Zealand biofuels company in today's article, LanzaTech, is apparently using tailored bacteria to convert carbon monoxide from steel mill and power plant flue gas into ethanol and useful chemicals. The process is doubly interesting, because although carbon monoxide is not of great concern as a greenhouse gas, it is a major local pollutant, and it can slow the decay of other greenhouse gases and contribute to atmospheric ozone. Producing ethanol puts LanzaTech into direct competition with the rapidly growing output of crop-based biofuels producers, including highly efficient production from sugar cane in the tropics. But by targeting the production of petrochemical intermediates (used to make other chemicals) like butanediol, they can access higher-margin, less-commoditized markets. A facility wouldn't have to produce much of these products, along with the ethanol, to boost its profitability by enough to make a difference.

This strategy could also be beneficial for companies using costly processes for converting cellulosic biomass into fuel, particularly as they scale up from laboratory and demonstration scale, because scale is a key limitation on specialty products. One of the main reasons these products are typically worth a lot more than commodity fuels is that they are produced and used in relatively small quantities, and their markets aren't large enough to attract the biggest competitors. The first industrial-scale gas-to-liquids (GTL) facilities made good margins selling waxes and other specialty products along with the high-quality diesel they produced, but as GTL becomes more mainstream, with plants like Oryx GTL and the giant Pearl GTL in Qatar, that option becomes less valuable.

Biofuel start-ups already face enough technology challenges without focusing all their efforts on making ethanol that can't be differentiated from the output of corn ethanol plants that have been at this game a lot longer and have mastered not only the production process, but also the intricacies of managing their large supply chains--a huge, under-appreciated challenge for cellulosic biofuels. Focusing initially on specialty products, to the degree their technologies allow, would give them time to scale up and work out the kinks, before tackling a market in which cost is everything.